Exxon Mobil Primary Cementing Manual

Search and Navigation Tools This file contains the entire Primary Cementing Manual. The manual is divided into sections and appendices. The sections and appendices are listed in Bookmarks (see left-side of screen). There is a “Master” Table of Contents. Each section also contains a “section” Table of Contents. All of the sections are linked together and all references within the document are linked. There are five basic methods of navigation or search capabilities: •

Scrolling – Use the scroll bar on the right side of the screen to page down through the document.

•

Bookmarks / Hyperlinks (Links) – Bookmarks are links to other sections within this manual or direct links to other reference materials (e.g., OIMS). To reference a link: Select the (

) tool from the toolbar. Move

over the referenced section

number until the “hand” becomes a “pointing finger” (

). Press the left

mouse button and the referenced section will appear on the screen. To return to your original place in the text, click the “right” mouse button and press go back. •

Word Search – Click

on the toolbar and a “find” dialog box will pop

up. Enter the term(s) you want to search for within the current open document. •

Search Engine – (Currently not available in this document). Click or press the ‘Search Tool’ topic (last item in the Bookmark section) or Ctrl+Shift+F. A dialog box will appear, listing all sections and manuals containing the search criteria.

•

Toolbar – Click buttons on the toolbar to scroll through the pages and to return to previous views.

Primary Cementing

Company Use Only

Foreword This manual contains standards and practices which ExxonMobil Development Company (the "Company") believes are generally more stringent than those customary within the industry. The particular circumstances in which these standards and procedures are applied may differ and care must be taken to ensure that their application complies with applicable law and is appropriate under the particular circumstances in which they are applied. THE COMPANY MAKES NO AND DISCLAIMS ALL WARRANTIES OR REPRESENTATIONS, EXPRESS OR IMPLIED, OF ANY KIND WITH RESPECT TO THESE STANDARDS AND PROCEDURES, INCLUDING FITNESS FOR A PARTICULAR PURPOSE, AND THE COMPANY, ITS AFFILIATES, AND THEIR DIRECTORS, OFFICERS AND EMPLOYEES SHALL NOT BE LIABLE FOR DAMAGES, WHETHER DIRECT, INDIRECT, INCIDENTAL, SPECIAL, EXEMPLARY OR CONSEQUENTIAL, REGARDLESS OF CAUSE, AND ON ANY THEORY OF LIABILITY WHETHER IN CONTRACT, STRICT LIABILITY OR TORT, ARISING IN ANY WAY FROM ERRORS OR OMISSIONS IN, OR THE APPLICATION OR MISAPPLICATION OF THESE STANDARDS AND PROCEDURES, EVEN IF APPRISED OF THE LIKELIHOOD OF SUCH DAMAGES OCCURRING. The use of these standards and procedures for work which is under contract with the Company or its affiliates does not relieve the contractor from any obligations assumed by the contract or from complete and proper fulfillment of the terms of the contract. Reference in these standards and procedures to any specific product, process, or service by trade name, trademark, manufacturer or otherwise, does not constitute or imply an endorsement or recommendation.

This document is the property of ExxonMobil Development Company. Unless otherwise noted, no part of this publication may be reproduced or provided to outside parties without written permission from ExxonMobil Development Company - Drilling Technical Manager. Additional copies can be obtained from the Drilling Technical Library.

Acknowledgements This manual was prepared under the direction of the ExxonMobil Development Company - Drilling Technical Applications Group. Questions or recommended changes should be directed to Glen Benge.

Updates/Revisions

R

Primary Cementing Manual Updates/Revisions Sec.

Date

All

Mar 2004

Replaces EPR Cement Slurry Design, May 1985; Mobil Primary Cementing Course Manual; and EPR Primary and Remedial Cementing, December 1984

13.1.2

Oct 2004

ISO 10426-4: Cements and Materials for Well Cementing - Part 4 Methods for Atmospheric Foamed Cement Slurry Preparation and Testing

October 2004

Descriptions

Company Use Only

U/R - 1

Master Table of Contents

Master Table of Contents Revisions/Updates Section 1

Cement Basics

2

Cement Additives

3

Cement Testing

4 5

Service Company Laboratory Responsibilities and Testing Guidelines Factors Influencing Slurry Design

6

Specialty Cement Systems

7

Gas Migration

8

Lost Circulation

9

Mud Removal

10

Cement Calculations

11

Liner Cementing

12

Plug Cementing

13

Operational Requirements and Specifications For Cementing Services

14

Cementing Equipment

15

Design Checklist

16

On Location Guidelines

17

Good Cementing Practices

18

Cement Sheath Evaluation

Appendices A

Information Sources

B

Glossary of Terms

C

Subject Index

March 2004

Company Use Only

TOC - i

Section

Primary Cementing Cement Basics

Scope This Section covers the manufacturing, chemistry, and classification of cement. Discussion includes mix water requirements and the relationship of strength development to the water/cement ratio.

Company Use Only

Cement Basics

1

Table of Contents Figures ............................................................................................................... 3 Tables................................................................................................................. 4 ExxonMobil Requirements ............................................................................... 5 1. Cement Basics ............................................................................................ 6 1.1. Required References ............................................................................... 6 1.1.1.

API-American Petroleum Institute.................................................................. 6

1.1.2.

ISO-International Standards Organization ..................................................... 6

1.2. History....................................................................................................... 6 1.3. Manufacturing .......................................................................................... 7 1.3.1.

Manufacturing Processes .............................................................................. 7

1.3.2.

Wet Process.................................................................................................. 7

1.3.3.

Dry Process................................................................................................... 8

1.3.3.1.

Kiln Operations ....................................................................................... 8

1.4. Composition ............................................................................................. 9 1.5. Chemistry................................................................................................ 10 1.5.1.

Material Consistency ................................................................................... 10

1.5.2.

Reactions .................................................................................................... 10

1.6. Classification of Cements ..................................................................... 10 1.7. API and ISO Standards and Specifications.......................................... 11 1.7.1.

API Water Content ...................................................................................... 11

1.7.2.

Effects on Water Content on Strength ......................................................... 12

1.8. Additional Considerations..................................................................... 13 1.9. API Cement Availability ......................................................................... 13 1.10.

Common Specialty Cements.............................................................. 14

March 2004

Company Use Only

Section 1 - 2

Cement Basics

1

Figures Figure 1.1: Wet Process ................................................................................................ 8 Figure 1.2: Dry Process................................................................................................. 8 Figure 1.3: Compressive Strength vs. Water Ratio ...................................................... 13

March 2004

Company Use Only

Section 1 - 3

Cement Basics

1

Tables Table 1.1: Kiln Reaction Products ................................................................................. 9 Table 1.2: Composition of Cement ................................................................................ 9 Table 1.3: Water Content ............................................................................................ 12

March 2004

Company Use Only

Section 1 - 4

Cement Basics

1

ExxonMobil Requirements Section Number

ExxonMobil Requirement

There are no ExxonMobil requirements in this Section.

March 2004

Company Use Only

Section 1 - 5

Cement Basics

1. 1.1.

1

CEMENT BASICS

REQUIRED REFERENCES

This Section lists Practices and Standards that are generically referenced and assumed part of this document. Unless otherwise specified herein, use the latest edition.

1.1.1.

API-American Petroleum Institute

API Spec 10A

Specification for Cements and Materials for Well Cementing

API RP 10B

Recommended Practice for Testing Well Cements

1.1.2.

ISO-International Standards Organization

ISO 10426-1

Cements and Materials for Well Cementing - Part 1: Specification

ISO 10426-2

Cements and Materials for Well Cementing - Part 2: Testing of Well Cement

1.2.

HISTORY

The use of cements or cement-like materials can be traced back to early times in Greece, Egypt, and Italy. Early brick making relied on forming and drying out clay materials held together with straw. The straw was used to give the "brick" strength and resistance to cracking. Between bricks or other building materials, like wood, mortar was added to seal the buildings. The mortar also consisted largely of clay materials. During Roman times, it was discovered that by heating the clay, the resulting brick was much stronger and would last much longer. It was also discovered that by using a mixture of calcium oxide, silica, and water, the brick would be much stronger. The calcium oxide was obtained by burning limestone. Pozzolan or flyash was obtained from near the town of Pozzuli, Italy, thus the origin of the name. Prior to finding that the heating process increased the strength of bricks, Rome had laws limiting the height of buildings to no more than one story. Following the discovery, building surged in Rome to include many structures that are still standing and in use today. The Roman Coliseum and the Aqueducts are examples of structures incorporating the newly discovered "cement." The knowledge of how to make cement died with the fall of the Roman Empire. Mortar was still in use, but burning brick to improve strength was largely lost. In 1824, Joseph Aspdin, an English brick mason, filed a patent for a process to manufacture "Portland Cement." The material he patented was named Portland Cement after the Isle of Portland, off the coast of England, due to its resemblance to the

March 2004

Company Use Only

Section 1 - 6

Cement Basics

1

stone quarried there. Joseph Aspdin knew that Portland stone was highly valued as a building material, and by calling the new product Portland Cement, he was insinuating its high value. Early cement manufacture was a batch operation where the materials were placed in an oven and heated to the proper temperature. This was a small process, very time consuming and led to wide variations in the quality of the finished product. There was little control over the temperature and time the materials spent at temperature. Fredrick Ransome patented the rotary kiln in 1885. With these two inventions, the manufacture of Portland Cement began in earnest, and today is globally the widest used building material.

1.3.

MANUFACTURING

The technical definition of cement is "a powder of alumina, silica, iron oxide and magnesia burned together in a kiln, finely pulverized and used as an ingredient of mortar and concrete." The manufacture of cement takes limestone (or other source of lime) and mixes it with clays and iron oxide. The mixture is burned together in a rotary kiln at temperatures between 2600-3000°F (1427-1649°C). The components literally melt and as they exit the kiln, cool and form clinker. The clinker is then ground together with gypsum (to control the setting) and Portland Cement is formed.

1.3.1.

Manufacturing Processes

The two processes for the manufacture of cement are wet and dry. Figures 1.1 and 1.2 outline the two processes. The main difference is the preparation of the raw materials prior to introduction to the rotary kiln. After the clinker is formed, the two processes are identical. After the clinker is cooled, it is ground with a small amount of gypsum and sometimes a grinding aid. The gypsum is required to control the reaction of C3A within the cement. The grinding process is important to the type of cement being produced. Finer grinds will tend to set faster, require more mix water, and will have a higher reaction rate than those with a coarser grind. The cement must be properly cooled after it is manufactured. This allows for heat dissipation as well as release and absorption of various gasses. The clinker-cooling step occurs at a controlled rate to better manage these changes. In peak times, it may be possible to receive cement that has not been properly cooled, and can arrive on location at temperatures above 150˚F (66˚C), which will have a major effect on the reaction rates and the effects of the various cement additives.

1.3.2.

Wet Process

In the wet process, the limestone is crushed and stored while the clay and shale is crushed and mixed with water. This removes impurities and large pieces. The limestone is added to this mix to form slurry, which is evaluated for proper chemistry and then fed to a wet grinding mill. The ground mixture is then fed to the rotary kiln.

March 2004

Company Use Only

Section 1 - 7

Cement Basics

1

The wet process could potentially form a more consistent cement than the dry process. It requires additional energy to dry the components. This is a costly process and is not used to a great extent in the manufacture of Portland Cement.

Figure 1.1: Wet Process C alcareous M aterials

C rushers

S ilica

W et G rinding M ill

A rgillaceous M aterials

1.3.3.

G ypsum H oppers

C orrection B asin

S torage B asin

C linker C ooler

K iln

C linker H opper

C linker G rinding M ill

G ypsum H oppers

G rinding A ids

S ilos

Packaging

G rinding Aids

Dry Process

In the dry process, all of the components of the cement are ground and stored in separate tanks. The materials are evaluated, intermixed, ground, and then fed to the rotary kiln. It is evident that the wet process could potentially form a more consistent cement, but requires additional energy to dry the components. This is a costly process and is not used to a great extent in the manufacture of Portland cement. Most cement manufacturing is done with the dry method. As noted, the main differences in the processes are the preparation of the raw materials prior to introduction to the rotary kiln. After the clinker is formed, the two processes are identical.

Figure 1.2: Dry Process Calcareous Materials

Crushers

Silica

Proportioner

Argillaceous Materials

1.3.3.1.

Wash Mill

Grinder

Rotary Kiln

Clinker Cooler

Clinker Grinding Mill

Gypsum Hoppers

Storage

Cement Silos

Packaging

Grinding Aids

Kiln Operations

As the cement moves down the rotary kiln, the temperature of the material increases. This causes a number of chemical changes to the raw materials. Table 1.1 lists the chemical changes that occur at each stage.

March 2004

Company Use Only

Section 1 - 8

Cement Basics

1

Table 1.1: Kiln Reaction Products Temperature Range

Reactions

100°C

Evaporation of any unbound water

500°C

Dehydroxilation of clay minerals

900°C

Crystallization of products of clay dehydroxylation and decomposition of CaCO3

900 - 1200°C

Reaction between CaCO3 or CaO with Aluminosilicates

1250 - 1280°C

Beginning of liquid formation

1280+°C

1.4.

Additional liquid formation and generation of cementitious materials

COMPOSITION

Cement is composed primarily of four components: C3S, C2S, C3SA, and C4AF. Table 1.2 lists the composition of cement and the relative concentrations of the components along with the other minor materials found in a typical cement. The four major components and their relative reaction rates and contribution to strength is also included.

Table 1.2: Composition of Cement Relative %

Reaction Rate

Strength Contribution

C3S - Tricalcium silicate

55

Fast

High

C2S - β-dicalcium silicate

22

Slow

High

C3A - Tricalcium aluminate

8

Very Fast

Low

C4AF - Tetracalcium aluminoferrite

7

Fast

Low

Gypsum

1

Sulfates

3

MgO - Magnesium oxide

3

Other

1

Chemical Compound

In Table 1.2, the abbreviations for the four major components of cement use C as an abbreviation for calcium. Depending on a number of chemicals and manufacturing variables, the concentrations of the four main components can vary.

March 2004

Company Use Only

Section 1 - 9

Cement Basics

1.5.

1

CHEMISTRY

1.5.1.

Material Consistency

The chemistry of Portland Cement is quite complex, as the raw materials used are not pure and therefore the final product will vary from batch to batch. Proper testing of the cement for use on location is critical. When cement is obtained from a single manufacturer, the variations in the cement will be much less than when comparing results from different manufacturers or from different manufacturing sites. Because of the variations in raw materials, cements from different manufacturers or manufacturing sites cannot be intermixed. This is particularly important if a rig is moving from country to country, where the cement in the tanks may be taken from one well to another.

1.5.2.

Reactions

Cement does not dry out as it sets, but reacts with the water in the system to form a variety of crystalline structures. This chemical reaction is exothermic (gives off heat), called the heat of hydration. The heat generated by the chemical reaction can be used to identify top of cement in a well using temperature logs. Depending on the mass of the cement and amount of water and other diluents in the cement, the heat generated can vary from a few degrees to as much as 75°F to 100°F (24°C to 38°C). C3A is the fastest reacting of the constituents of cement. This reaction is controlled through the addition of gypsum in the manufacturing process. The reaction of the small amount of gypsum with the C3A forms ettringite crystals that control further hydration of the C3A. Adding more gypsum to the cement can result in high concentrations of ettringite, which leads to thixotropic behavior in cements.

1.6.

CLASSIFICATION OF CEMENTS

Cements are classified by how finely the material is ground, and to a lesser extent, the chemistry of the cement. The American Society of Testing and Materials (ASTM) classifies cement by Type, from Type I to Type V. Type I is the most common construction cement. Type III is more finely ground, and is often considered the winter grade cement because of the faster setting times. The API uses letter designations for cements (currently from Class A to Class H). Most ASTM Type I cements will meet the requirements for Class A cement. Type III cements correspond somewhat to Class C, although there can be slight chemistry differences. There are no ASTM types corresponding to API Classes D through H. These classes are specifically manufactured for the oilfield. Oilfield cement is also classified within API based on the chemistry of the cement. A component known as C3A (tricalcium aluminate) is one of the fastest reacting materials in cement. This compound is linked to gel strength - the ability for a cement to be thixotropic, and resistant to sulfate attack. Cements with a C3A content less than 3% are considered to be high sulfate resistant (HSR). Cements with less than 8% C3A are classified as moderate sulfate resistant (MSR) cements. The majority of Class G and H

March 2004

Company Use Only

Section 1 - 10

Cement Basics

1

cements fall in this category. Ordinary grade (O) cements are available as Class A or C, with Class C having up to 15% C3A. C3A content becomes important in two specific applications. For wells requiring thixotropic cement, often the C3A content should be above 6% for the system to function properly, particularly if the thixotropic property is being obtained from a reaction with gypsum (calcium sulfate hemihydrate). For deepwater applications, using cement with a C3A content of at least 6%, and preferably 8%, will produce cement that reacts faster, giving higher early strength. This can be critical in the high cost operational environment of deepwater. Virtually, all of the cement used in the oil industry are Classes A, C, G, and H. Classes D, E, and F are cements with retarder blended into them, and have not been manufactured for several years. Class B cement is similar to Type II, which limits the amount of C3A in the cement for sulfate resistance, but is not usually available.

1.7.

API AND ISO STANDARDS AND SPECIFICATIONS

The API and ISO specifications for cement are found in API Spec 10A or ISO 10426-1. These specifications list the tests to be performed on neat cement with no additives. The purpose of the specification test is to evaluate the "raw" cement for specific chemical and performance requirements. It is through this testing that cement is classified as Class A, Class G, etc. The tests are highly specific and no variance from the testing protocol is allowed. Specification testing is only performed on the base cement with no additives. There is no one test used for a particular well. Most day-to-day cement testing is based on testing standards developed by API. The standards are found in API Recommended Practice for Testing Oil Field Cements, API RP 10B. This same document has been adopted as an international standard through ISO (ISO 10426-2). These documents contain standard recommended testing procedures for evaluating cements and cement slurries. The test methods differ considerably from specifications for cement because they allow the use of cement additives, encourage changes to the test, and make some attempt to follow field conditions. It is not the intent of API to simulate well conditions. The goal of the API is to develop a standard set of test procedures to allow comparison of results between various labs. API procedures may be modified to match the particular well conditions and mixing methods used. While the tests outlined in the API and ISO publications are applicable to field work, it is the responsibility of the engineer to determine the applicability of a particular test and to determine if the results have meaning to a particular well.

1.7.1.

API Water Content

All API and ISO cements are manufactured to meet a certain set of chemical and performance specifications, as found in API Spec 10A and ISO 10426-1. These specifications call for mixing each class of cement with a particular amount of water for the performance testing. It is this amount of water that is the basis for the "normal" density of the API cement slurries. When a service company mixes a cement system at a particular density, they are falling back on the API water content. The API recommended mixing water for specification testing is shown in Table 1.3.

March 2004

Company Use Only

Section 1 - 11

Cement Basics

1

Table 1.3: Water Content

API Class

% Mix Water

Slurry Density (lb/gal)

A

46

15.6

C

56

14.8

G

44

15.8

H

38

16.4

Table 1.3 does not imply that Class H cement cannot be mixed at a density other than 16.4 lb/gal. It states that for specification testing, the cement must meet the performance criteria when mixed with that amount of water. It further means that cements mixed at the API water content will have some free water development, unless treated with an additive to eliminate the free water. Mixing an API cement with more mix water (thus reducing the slurry density) will result in the following: •

Increased free water

•

Slightly reduced strength

•

Increased pumping time

None of these effects are necessarily bad, depending on the well requirements. Sufficient strength to perform any well operation can easily be obtained from slurries mixed at below the above densities, provided appropriate additives are used to modify the slurry properties.

1.7.2.

Effects on Water Content on Strength

The ultimate strength development of any cement is determined by the concentration of the following components: •

Inert filler

•

Cement

•

Water

Inert fillers are largely a dilution effect and as the concentration of the filler increases, there is a corresponding reduction in strength. Water content follows a similar trend, but does not act solely based on dilution. A minimum of 23% - 25% water is required to hydrate the cement. Without this minimum amount of water, the cement reactions cannot take place. At higher concentrations of water, the cement will begin to settle out, and excessive water separation will occur. Figure 1.3 is a representation of the relationship of ultimate (28 day) strength to water content of the slurry. For this figure, solids settling in the cement were prevented.

March 2004

Company Use Only

Section 1 - 12

Cement Basics

1

Figure 1.3: Compressive Strength vs. Water Ratio

1.8.

ADDITIONAL CONSIDERATIONS

A cement that meets API or ISO specifications should serve as the base for all of the slurries pumped by ExxonMobil. This gives the assurance that at least the base starting material has been manufactured to a set of standards. It also provides the operations with a base material that will require fewer additives and should be more predictable. Most Service Companies do not list API cements, but rather generic terms such as "Standard, Premium, or Premium Plus." These generic terms can be linked back to a particular cement. A Premium cement at one location will not necessarily be the same Class of cement at another location. The Service Companies, as a legal method to limit liability, have adopted these generic terms. If a service company offers an API cement, then the cement would be required to meet the API specifications at their facility. This cannot always be assured, so generic classifications have been incorporated to limit this liability. Note: There is nothing wrong with the cement, simply the service company is not guaranteeing the material will meet the API specification at the time of sale. This is not of particular concern - the concern is for performance of a cement system that has been designed for the well rather than the base cement performance.

1.9.

API CEMENT AVAILABILITY

API cements are available globally, though not all cements are available in all locations. API Class A cement is usually available globally, as it is usually manufactured as a construction Type I cement. Class C cement is found primarily in West Texas. Class H

March 2004

Company Use Only

Section 1 - 13

Cement Basics

1

cement is primarily located in the Gulf Coast of the United States, though it may be found manufactured in Germany and distributed from there. The most common API oilfield cement is Class G. It is manufactured globally and found in almost every location except the Gulf Coast of the United States. The Class G cement used in West Africa is usually brought in from Europe. One major manufacturer of Class G cement is Dykerhoff. The cement from this plant is exported throughout Europe, Africa, and even into South America.

1.10. COMMON SPECIALTY CEMENTS There are two cements available that do not have an ASTM or API designation: high alumina cement and commercial lightweight. High alumina cement is highly resistant to CO2 attack and can survive extremely high temperatures. These cements are similar to those used to manufacture the bricks used in fireplaces. This cement is highly specialized and requires special additives to allow it to function in the field environment. It is further discussed in Section 6.6. A common cement available in the United States Gulf Coast area is TXI Lightweight. This cement is a special blend of Portland Cement and pozzolans that are inter-ground at the cement plant. The cement is designed to be mixed at a base density of 14.8 lb/gal. TXI Lightweight cement offers a number of advantages over other oilfield cements. TXI Lightweight, when mixed at the design weight, has superior strength development to a conventional oil well cement mixed with pozzolans or other extenders. As a manufactured lightweight cement, it is not subject to the blending inconsistencies associated with more conventional blended cements. This cement has been used alone, as a blend with API Class H cement, and as a basis for foamed slurries.

March 2004

Company Use Only

Section 1 - 14

Section

Primary Cementing Cement Additives

Scope This Section covers the various families of cement additives. Specific service company's additive names have not been included, but where appropriate, a generic classification of the additive family is noted. This section is intended to give an overview of common additives, usage, and interactions with other additives. Important points are made when to use silica in slurry design (see Section 2.13).

Company Use Only

Cement Additives

2

Table of Contents Figures ............................................................................................................... 4 Tables................................................................................................................. 5 ExxonMobil Requirements ............................................................................... 6 ExxonMobil Recommended Practices ............................................................ 6 2.1.

Required References........................................................................................ 7

2.1.1. API-American Petroleum Institute .............................................................. 7 2.1.2. ISO-International Standards Organization .................................................. 7 2.2. General ............................................................................................................ 7 2.3.

Cross-Reference Tables................................................................................... 8

2.4.

Accelerators ..................................................................................................... 8

2.4.1. Calcium Chloride (CaCI2) ........................................................................... 8 2.4.2. Sodium Chloride (NaCI) ............................................................................. 9 2.4.3. Seawater.................................................................................................... 9 2.4.4. Sodium Silicate .......................................................................................... 9 2.5. Other Methods of Acceleration ......................................................................... 9 2.6.

Retarders ....................................................................................................... 10

2.6.1. Lignosulfonate Retarders ......................................................................... 10 2.6.2. High Temperature Retarders.................................................................... 11 2.6.3. Retarder Response with Temperature...................................................... 11 2.6.4. Cellulose Materials................................................................................... 11 2.6.5. Specialty Retarders.................................................................................. 11 2.6.6. Other Retarders ....................................................................................... 12 2.7. Dispersants .................................................................................................... 12 2.8.

Fluid Loss Additives........................................................................................ 12

2.8.1. Bentonite.................................................................................................. 13 2.8.2. Cellulose .................................................................................................. 13 2.8.3. Synthetic Polymers .................................................................................. 14 2.8.4. Effects of Salt........................................................................................... 14 2.8.5. Other Fluid Loss Considerations .............................................................. 14 2.9. Extenders ....................................................................................................... 14 2.9.1. 2.9.2. 2.9.3. 2.9.4. 2.9.5. 2.9.6.

March 2004

Bentonite.................................................................................................. 15 Attapulgite ................................................................................................ 15 Chemical Extenders ................................................................................. 15 Pozzolan .................................................................................................. 16 Fume Silica .............................................................................................. 16 Hollow Microspheres and Ceramic Spheres............................................. 16

Company Use Only

Section 2 - 2

Cement Additives

2

2.9.7. Nitrogen ................................................................................................... 16 2.10. Weighting Agents ........................................................................................ 17 2.10.1. Barite ....................................................................................................... 17 2.10.2. Hematite and Ilmenite .............................................................................. 17 2.10.3. Sand ........................................................................................................ 17 2.10.4. Micromax ................................................................................................. 17 2.10.5. Specialty Systems.................................................................................... 18 2.11. Free Water/Settling Control ......................................................................... 18 2.12.

Gas Migration Control ................................................................................. 18

2.13.

Lost Circulation ........................................................................................... 19

2.14.

Silica ........................................................................................................... 20

2.15.

Antifoams & Defoamers............................................................................... 21

2.15.1. Antifoams................................................................................................. 21 2.15.2. Defoamers ............................................................................................... 21 2.16. Salt (NaCl)................................................................................................... 21 2.17.

Latex and Latex Stabilizers ......................................................................... 22

2.18.

Other Additives............................................................................................ 22

2.19.

Liquid Additives ........................................................................................... 23

2.19.1. Metering ................................................................................................... 23 2.19.2. Density Control ........................................................................................ 23 2.19.3. Storage .................................................................................................... 24 2.20. Dry Additives ............................................................................................... 24

March 2004

Company Use Only

Section 2 - 3

Cement Additives

2

Figures Figure 2.1: Additive Response..................................................................................... 11 Figure 2.2: Cement Fluid Loss..................................................................................... 13

March 2004

Company Use Only

Section 2 - 4

Cement Additives

2

Tables Table 2.1: Additive Function Overview ........................................................................ 26

March 2004

Company Use Only

Section 2 - 5

Cement Additives

2

ExxonMobil Requirements Section #

Topic

ExxonMobil Requirements

There are no ExxonMobil requirements in this Section.

ExxonMobil Recommended Practices ExxonMobil recommended practices for additives and materials are found in the following:

Section #

ExxonMobil Recommended Practice

2.9.3

For job planning purposes, a cement slurry containing a silicate extender should be designed to be in place before reaching the point of departure on the thickening time curve.

2.12

1.0 - 1.5 gal/sk latex is sufficient to prevent gas migration.

2.19.1

March 2004

Metering of liquid additives on location should not depend on a pump stroke counter. Use of a dump tank or mass flow meter is preferred.

Company Use Only

Section 2 - 6

Cement Additives

2. 2.1.

2

CEMENT ADDITIVES

REQUIRED REFERENCES

This Section lists Practices and Standards that are generically referenced and assumed part of this document. Unless otherwise specified herein, use the latest edition.

2.1.1.

API-American Petroleum Institute

API RP 10B

2.1.2.

Recommended Practice for Testing Well Cements

ISO-International Standards Organization

ISO 10426-2

Cements and Materials for Well Cementing - Part 2: Testing of Well Cement

ISO 10426-3

Cements and Materials for Well Cementing - Part 3: Testing of Deepwater Well Cement Formulations

ISO 10426-4

Cements and Materials for Well Cementing - Part 4: Methods for Atmospheric Foamed Cement Slurry Preparation and Testing

2.2.

GENERAL

Basic cements have limited properties. Depending on the water ratio, the cement will have a fixed thickening time and strength development. Modifying the properties of the cement to meet the requirements of the well is basic to the design of a cement job. There is considerable mystique generated by the service companies around cement additives. Knowing the "code names" of the various additives is not important, but understanding the general function of the various materials should improve the understanding of why a particular additive is being used. Regardless of the additive, there must be a technical reason to use the material in a cement slurry. There are some situations when one material may be required to aid the functionality of another. An example of this would be the use of a dispersant with a fluid loss additive. The two materials have a synergistic effect when used together, allowing for a reduction in the amount of each to achieve a particular property.

March 2004

Company Use Only

Section 2 - 7

Cement Additives

2.3.

2

CROSS-REFERENCE TABLES

A cross-reference table of cement additive names and general function category is maintained by World Oil. It is available at the following website: www.WorldOil.com. The tables can be found under "Engineering Data Tables," under References. The site maintains the following cross-reference tables: •

Acidizing

•

Casing

•

Cementing

•

Drill Bits

•

Fluids

•

Fracturing

•

Tubing

2.4.

ACCELERATORS

Accelerators function to shorten the thickening time of a cement slurry and can aid in early strength development. Accelerators do not have any effect on the ultimate strength of a cement. In general, almost any inorganic salt will accelerate the set of cement. The exact mechanism is not well understood, but it is believed the salts act as a catalyst rather than being incorporated into the chemical reactions of the cement.

2.4.1.

Calcium Chloride (CaCI2)

The most widely used and most common accelerator in cement is calcium chloride (CaCI2). It is generally used at concentrations from 1% to 3%. Concentrations above 3% can cause gellation problems and unpredictable results. Calcium chloride should not be used with silicate extenders. The system will form a calcium silicate gel structure that is highly thixotropic. If the cement stops moving, the slurry will gel immediately and terminate any further pumping. Calcium chloride is available in two dry forms: 77% grade and anhydrous 96% grade. On a per pound basis, the 77% grade has only 80% of the calcium chloride as the anhydrous 96% grade. Service companies should have the two grades separately labeled and coded to prevent confusion between the laboratory and bulk plant. Calcium chloride can also be pre-hydrated in the mix water. This will increase the temperature of the water. This temperature increase should be pre-tested in the laboratory. Dry calcium chloride will also increase the temperature of the slurry. One pound of material will increase the slurry temperature of a barrel of slurry approximately 1°F (0.6°C).

March 2004

Company Use Only

Section 2 - 8

Cement Additives

2

Calcium chloride is also available in liquid form at a concentration of approximately 33%. When used in the liquid form, there is no temperature increase in the mix water and very little increase in the slurry temperature. A concentration of 0.4 gallons per sack is equivalent to approximately 2% dry calcium chloride.

2.4.2.

Sodium Chloride (NaCI)

When used at concentrations below 5%, sodium chloride (NaCl) will act as an accelerator. From 5% - 10%, NaCl is essentially neutral with respect to thickening time. Above 10%, it will act as a retarder. The maximum acceleration from NaCl occurs at approximately 3% concentration by weight of water (BWOW). Sodium chloride is not as strong an accelerator as calcium chloride. This can be beneficial when small changes in CaCl2 concentration make a large difference in the thickening time of the slurry.

2.4.3.

Seawater

Most seawater reacts much like a 3% NaCl solution. Seawater contains more salts than just NaCl. Seawater salinity can change seasonally due to increased runoff from nearby rivers. It is always advisable to obtain a sample of seawater from the rig for cement testing. Seawater will also vary dramatically depending on the source. For example, the water in the Caspian Sea has a much lower salt content than found in the open oceans. The water in the North Sea tends to have a higher magnesium content than found in more southerly areas. For offshore work, it is often useful to use seawater in combination with calcium chloride. The resulting slurries will have a short thickening time and rapid strength development. Using seawater at higher temperatures will require the addition of excess retarder. This situation can be avoided by using drill water or freshwater at temperatures above 150°F (66°C). Note: NaCl concentration is based on the weight of water rather than by weight of cement (BWOC).

2.4.4.

Sodium Silicate

Both the liquid and solid versions (sodium silicate and sodium metasilicate) will act as accelerators. This is a secondary property of the material as the primary action is as an extender.

2.5.

OTHER METHODS OF ACCELERATION

Heating the mix water will accelerate the set of the cement. This can be necessary in cold climates where the dry cement temperature may be below freezing and the resulting slurry temperature is too cold to properly hydrate. Hot mix water can be a hazard in warmer climates if the water temperature has not been taken into account during testing.

March 2004

Company Use Only

Section 2 - 9

Cement Additives

2

Mix water temperature is particularly important in overall cement testing on a seasonal basis. During the summer months in the Gulf of Mexico, the seawater temperature can be as high as 80°F (27°C). In the winter, the water temperature drops into the 55°F (13°C) range. This temperature variance must be taken into account during testing.

2.6.

RETARDERS

Retarders will extend or lengthen the thickening time of a cement slurry. These materials are critical for proper placement of cements in most wells. The retarders can effect the early strength development of a cement. Retarders are broken into several general classes. These include the following: •

Low temperature - used generally below 200°F (93°C)

•

High temperature materials - for use above 200°F (93°C)

•

A variety of other retarders designed for a specific purpose

Usually, retarders are sugars or lignin-type materials. Other retarders include NaCl in concentrations exceeding 25%, many organic compounds, fluid loss additives, dispersants, and some gelling agents. Newer synthetic retarders allow for long pump times while still obtaining compressive strength. This can be especially important when cementing long liners when the temperature at the top of the liner may be less than the bottomhole circulating temperature. Retarders will act in synergy with many other additives and care must be exercised when designing the slurry to account for all of the interactions of the various additives.

2.6.1.

Lignosulfonate Retarders

Calcium lignosulfonate is one of the most common retarders. It is used primarily at lower temperatures. Calcium lignosulfonate is closely related to sodium lignosulfonate, which is used as a dispersant for drilling fluids. In cements, the calcium form is more effective and predictable. Lignosulfonates are byproducts from paper manufacturing during the separation of cellulose from wood pulp. The lignin that holds the wood together is degraded and dissolved with a hot-acid sulfate solution. Depending on the wood, time of year harvested, and degree of reaction, the quality of the lignosulfonate will vary. There can be considerable variation in different lots of lignosulfonate retarders. This is one reason the absolute concentration of retarder can vary from lot to lot, even though the cement remains the same. A characteristic of lignosulfonate retarders is the exponential increase in retardation with small increases in retarder concentration. Figure 2.1 demonstrates above a certain threshold, a small increase in retarder will greatly increase the thickening time. This effect will vary at different temperatures, and with various retarders, but is common to all lignosulfonates.

March 2004

Company Use Only

Section 2 - 10

Cement Additives

2

Thickening Time

Figure 2.1: Additive Response

Additive Concentration

2.6.2.

High Temperature Retarders

High temperature retarders are modified sugars, blends of sugars and other materials, or organic acids. Calcium glucoheptonate is a common high temperature retarder, derived from glucose. The same cautions for usage of lignosulfonate retarders apply to the high temperature retarders.

2.6.3.

Retarder Response with Temperature

It can be difficult to obtain reproducible retardation at certain temperature ranges. At approximately 212°F (100°C), the change is made from using a low temperature to a high temperature retarder. At this temperature, either very high concentrations of low temperature retarder are required, leading to unpredictable behavior, or low concentrations of high temperature retarder are required, again leading to unpredictable behavior. Diluting the high temperature retarders to make them less sensitive at this temperature range is one method used by service companies to reduce these effects.

2.6.4.

Cellulose Materials

Most cellulose fluid loss additives will retard cement. As these materials often require the addition of a dispersant, the synergistic effects of the two materials can retard cement.

2.6.5.

Specialty Retarders

Some specialty retarders allow for retardation at high temperature, yet still provide good strength development at lower temperatures. These retarders are designed for use in long liner situations, or areas where long columns of cement are required.

March 2004

Company Use Only

Section 2 - 11

Cement Additives

2.6.6.

2

Other Retarders

Many contaminants found in water can retard cements. In the fall, decaying vegetation will add tannins and lignins to the water, resulting in retardation. Many weed killers used will retard cements. It is important to know the water source for mixing the cement, and evaluate the water during cement testing.

2.7.

DISPERSANTS

Dispersants modify the rheology of the cement by reducing the viscosity of a cement slurry. This allows mixing a system with less water, thereby increasing the density of the system. Dispersants are often referred to (incorrectly) as turbulence inducers. Cement rarely is placed in turbulent flow, and dispersants should not be used to attempt to modify the slurry viscosity to allow turbulent flow. Several materials act as dispersants, such as salt, and lignin-type retarders. The primary dispersant used in cements is a formaldehyde condensate of lignosulfonic acid. Dispersants can enhance the effectiveness of fluid loss additives and can reduce the amount of fluid loss additive needed. These materials also act synergistically with lignosulfonate retarders. Unless reduced water, as with a kick off plug, or fluid loss is needed, dispersants are usually not required. Dispersants are one of the most over used cement additives, and are generally sold to make the cement mix easier. Many service providers will sell dispersants as giving the ability to mix a particular slurry at a higher rate. While this may accomplish that goal, excessive dispersant usage will result in high free water and solids settling in the cement.

2.8.

FLUID LOSS ADDITIVES

Fluid loss additives are used to reduce the flow rate of water out of a slurry into a permeable zone. This helps prevent slurry dehydration, which can lead to a buildup of cement particles across from a permeable zone. Depending on the application, fluid loss values can range from 1,200 (no control) to less than 50 mL/30 min. Fluid loss additives are very expensive, and are one of the most over sold materials in cementing. A common mistake with fluid loss control is the design of a lead slurry with no fluid loss control, followed by a tail slurry that contains very good fluid loss control. Unless there are concerns over gas migration, or other technical design considerations, this practice should be avoided. Except in the case of gas migration, there is no benefit to very good fluid loss control in a tail system, if there was no need for it in the lead slurry. Polymeric fluid loss additives have been developed that require much lower concentrations, and can have a minimal effect on slurry rheology. These fluid loss additives are usually run in combination with a dispersant. Figure 2.2 is an illustration of cement fluid loss across a permeable zone, illustrating the build up of cement filter cake.

March 2004

Company Use Only

Section 2 - 12

Cement Additives

2

Figure 2.2: Cement Fluid Loss Primary Cementing

Permeable Zone Heavy Cement Filter Cake

Thin Impermeable Cement Filter Cake

Low Fluid Loss

2.8.1.

Uncontrolled Fluid Loss

Bentonite

A very common fluid loss additive is bentonite. While bentonite is used primarily as an extender, when used in lightweight slurries it will also impart some fluid loss control. A system containing 4 - 6 % bentonite will have an API fluid loss below 400 mL/30 min. If the same slurry were extended with a silicate extender, the fluid loss would exceed 1,200. The advantage of fluid loss control in bentonite extended slurries is often overlooked in favor of more convenient silicate extenders. If fluid loss is required, additional materials must be added, increasing both the cost and complexity of the slurry.

2.8.2.

Cellulose

Cellulose derivatives are common fluid loss additives. These materials will lower the fluid loss, but will viscosify the cement and will also retard the set of the slurry. Cellulose derivatives such as hydroxyethyl cellulose (HEC) or other long-chained polymers derived from cellulose are widely used. These materials function by

March 2004

Company Use Only

Section 2 - 13

Cement Additives

2

viscosifying the water phase in the cement, thus slowing the filtration rate. They may also act as pore blocking agents in the cement filter cake.

2.8.3.

Synthetic Polymers

Several recent advances have been made in the area of synthetic polymers used as fluid loss additives in cement. These materials are very long chain polymers and function to plug the pores of the filter cake and inhibit fluid movement. Synthetic polymers can be manufactured to close tolerances, are more expensive than other materials, but are generally more effective at lower concentrations. They do not tend to over retard the cement or adversely effect the rheology of the slurry. Latex is a common synthetic polymer that will provide excellent fluid loss control, along with many other properties such as increased flexibility of the slurry and prevention of gas migration. Latex concentrations should be in the 0.75 - 1.0 gal/sack range, and should be based on fluid loss results. Some service companies base latex concentrations on other parameters, and generally recommend concentrations much higher, approaching 1.5 - 3.5 gallons per sack.

2.8.4.

Effects of Salt

Salt (either calcium or sodium chloride) will adversely effect most fluid loss additives. Most of the fluid loss additives are sensitive to salt concentrations, and will not function as well, or at all in high salt slurries.

2.8.5.

Other Fluid Loss Considerations

Because of the retarding action of many polymeric fluid loss additives, use of the additives at low temperatures will result in a slurry that will not set in a reasonable period of time. This can be a particular challenge in deepwater, low temperature environments. Specialty materials have been developed to address this specific area. Fluid loss additives often need a dispersant to be effective. The addition of a dispersant to most polymeric fluid loss additives will increase their effectiveness, and may increase the effective temperature range. Only a minimal amount of dispersant should be required to obtain the desired results. Fluid loss control can also be achieved by the introduction of gas or foam to the slurry. This results in a three-phase system (cement, water, and gas) that will have a lower fluid loss rate than the original slurry. There is insufficient data as to the degree of control obtained from introducing the gas to the system, but in all of the testing to date, the fluid loss is lower with gas entrained systems.

2.9.

EXTENDERS

Extenders are materials and systems that allow the cement slurry to be mixed at a lower density without excessive free water development. They also function to increase the yield of the slurry, thus requiring less cement for a given volume. Because using extenders essentially "dilutes" the cement, properties of strength development, fluid loss, thickening time and free water will be effected.

March 2004

Company Use Only

Section 2 - 14

Cement Additives

2

Extenders can be broken into two distinct groups, ones that extend through absorbing water, and ones that extend through having an intrinsic lower density.

2.9.1.

Bentonite

The most common extender is bentonite, which functions by taking up excessive water in the system. This will reduce the slurry density, but will also result in lower strength and longer pump times. Fortunately, bentonite can impart fluid loss control, thus reducing the effect on fluid loss. Bentonite can be used as a dry material blended with the cement, or can be pre-hydrated and used in the mix water. If pre-hydrated, the yield obtained from the bentonite is greatly increased. As a general rule, 1% pre-hydrated bentonite is approximately equal to 4% dry blended. Bentonite should be pre-hydrated in fresh water to obtain the full yield from the material. Use of salt or seawater is not recommended for pre-hydrating bentonite. Not all bentonite sources are the same. Some bentonites will not meet the API requirements and have additional materials added to improve the water absorbing ability of the bentonite. These are called beneficiated bentonites, and should not be used in cement. The small amounts of beneficiating agents can adversely effect cements, and have led to cement failures in some systems. Only non-beneficiated bentonite should be used in cementing.

2.9.2.

Attapulgite

Also called saltwater gel, attapulgite can be used as an extender Attapulgite does not absorb water like bentonite, and obtains viscosity by thread-like pieces. The yield of attapulgite is independent of salinity, dependent on shear. Unlike bentonite, attapulgite will not impart fluid loss slurry.

2.9.3.

in cements. shearing into but is highly control to the

Chemical Extenders

Sodium metasilicate works by forming a gel structure with the calcium in the cement. This also absorbs water, but will not impart any fluid loss control to the system. These materials can be used at much lower concentrations than bentonite, typically in the 1 2% range, giving an operational advantage in some operations. Silicates are also available in liquid form, which can eliminate the need to dry blend the system. There are special considerations with the use of silicate extenders with respect to thickening time testing. Silicate extenders build a unique gel structure in the cement. If the gels are broken during placement, it can effect the strength development of the cement. The point at which the gel structure begins to form is called the point of departure (POD) on the thickening time curve. If pumped past this point, the cement strength will reduce, but also the cement will severely gel if pumping is stopped. The POD is defined as the point where the cement begins to set. On the thickening time curve, it is the point where the viscosity begins to increase off of the baseline. The laboratory should report the POD and the time to 30 Bc. For job planning, the cement should be in place before the POD. See Section 3, Figure 3.3.

March 2004

Company Use Only

Section 2 - 15

Cement Additives

2.9.4.

2

Pozzolan

Pozzolan materials are commonly used as extenders because their density is much less than cement. Pozzolans are available either as a natural pozzolan, or as a flyash, that is a byproduct of burning coal. In either form, the material is a finely ground powder having some cement-like properties. Pozzolans typically contain high concentrations of silica, and allow the use of lower concentrations of added silica in high-temperature applications (see Section 2.13).

2.9.5.

Fume Silica

Extremely fine silica, termed fume silica, is collected as a waste product in pollution control systems in some industrial operations. Some sources of fume silica are extremely fine, to the point of being almost a smoke-sized particle. This extreme fineness requires very large amounts of water to wet the material. Fume silica has also been recommended as a preventative for gas migration, as its small size can fit into the pores of the setting cement, thus blocking the advance of gas through the matrix.

2.9.6.

Hollow Microspheres and Ceramic Spheres

Specialty extenders, with densities less than the density of water, make up a special class of extenders. While the materials serve to lower the density of the slurry, they do not require the addition of large amounts of water. They function by reducing the density through their very lightweight. Two ultra-lightweight materials available are hollow ceramic spheres and hollow glass microspheres. The hollow glass microspheres are a manufactured product, while the ceramic spheres are obtained by separating very lightweight portions of flyash through flotation. Both materials have a pressure limit above which the sphere will collapse, releasing the trapped gas inside. This will cause a rapid increase in slurry density if this occurs. The glass microspheres are available in a variety of pressure ranges. The higher the pressure resistance, the thicker the wall of the microsphere. This increases the density of the material, requiring more of the additive to obtain very low densities. Also, as the wall thickness increases, the cost of the material increases. Coupled with the need for additional material, these slurries can be very costly. Care in design and application of these materials is essential. The slurry must be designed for bottomhole conditions of pressure, which can require the surface mixing density be less than the final in-place density. This lower density at surface takes into account the crushing of the beads under downhole conditions.

2.9.7.

Nitrogen

The final extender in the group is nitrogen or other gas. While used for a variety of other purposes, introducing gas into a slurry will reduce the density and extend the slurry. The complexity of design and other properties of these systems are covered in Section 6, Specialty Cement Systems. The specialty extenders and foam offer several advantages because they do not require additional water, and thus do not dilute the base cement as much as conventional extenders. Because of this, compressive strength development will be much better with

March 2004

Company Use Only

Section 2 - 16

Cement Additives

2

these materials. Because of their very lightweight, slurries can be made much lighter than with conventional materials. Densities as low as 8 lb/gal can be readily obtained. The lower limit for conventional extenders is approximately 11.5 lb/gal.

2.10. WEIGHTING AGENTS Weighting agents are materials that have a high density and when added to cement will increase the density of the slurry. These materials have varying particle sizes, and care must be exercised in design to assure there is no settling of the weighting agent in the slurry. Weighting agents normally only aid in increasing slurry density, and then only if well conditions merit (such as cementing in high-density environments). Weighting agents do nothing to enhance drilling capacity with kick-off plugs, and in fact will serve only to dilute the cement and can result in lowering the strength of the plug.

2.10.1. Barite Most commonly used to weight mud systems, barite has limited use in cements. Barite requires large amounts of water to wet the surface, and therefore has limited use in cement slurries. Barite can be used in combination with other weighting agents to help limit free water development and settling.

2.10.2. Hematite and Ilmenite Both hematite and ilmenite are heavy iron ores that have large particles. This makes the materials more efficient than barite for weighting cement slurries. Hematite has a higher specific gravity than ilmenite, but ilmenite has a larger particle diameter, making it easier to mix very high-density slurries.

2.10.3. Sand Sand, not silica flour, can increase slurry density up to one (1) lb/gal without adverse effects. At high temperatures, the incorporation of 35% sand will aid in prevention of strength retrogression.

2.10.4. Micromax Micromax is essentially a liquid weighting agent. Consisting of very finely ground magnesium oxide, the material is sold in liquid form and can be used to weight cement slurries. This material has been used successfully in many remote locations where dry blending is not available, and on exploration wells where slurry density had to be increased unexpectedly.

March 2004

Company Use Only

Section 2 - 17

Cement Additives

2

2.10.5. Specialty Systems Covered in more detail in Section 6.4, these include Schlumberger's DensCRETE* systems. These are not casual additives or systems and require close control of blending and field mixing.

2.11. FREE WATER/SETTLING CONTROL Free water or free fluid is caused by a separation of the water and other liquids in a cement slurry. This can lead to a channel on the high side of an inclined wellbore, problems with solids separation, gas migration, etc. Free water control agents help prevent this problem by either viscosifying the slurry or complexing the water within the cement matrix. Normally, viscosifying the slurry results in a system that can be difficult to mix at surface. Additives are available that do not take effect until a specific temperature has been reached. These materials allow free water control without sacrificing surface mixing. Similar to free water, solids settling will cause a segregation of the solids in the slurry, resulting in pockets of lightweight slurry within the cement column. There can be solids settling without the generation of free water. Normally, settling agents function by increasing the viscosity of the system. As with free water control, many additives are available that have a delayed hydration allowing for improved surface mixing. Often the use of a free water control or settling control agent can be eliminated by proper slurry design. These materials become unnecessary if the slurry has not been over-dispersed, and has the proper combination of other materials. As with dispersants, simply mixing the slurry at a slightly different density may eliminate these materials.

2.12. GAS MIGRATION CONTROL Gas migration following slurry placement is responsible for much of the sustained casing pressure found in wells throughout the world. Gas migration may be prevented through a number of mechanisms, and there are additives to address each of the mechanisms. Gas migration is not well understood in cementing and there are a number of conflicting theories as to the reason gas migrates through cement. Of all the different materials available, it appears those that reduce the fluid loss of the cement, and minimize the period of time the slurry remains fluid before setting are the most effective. There are few additives more expensive than gas migration materials. Latex is one of the most common additives available, and works by reducing the fluid loss of the slurry, plugs pore throats, and interacts with any gas entering the system. Generally, 1.0 - 1.5 gal/sk of latex is sufficient to prevent gas migration in any application. Many designs call for the addition of 2.5 - 3.0 gal/sk of latex. These designs are excessive and not necessary. The latex concentration can be based on the concentration of latex required to obtain less than 50 cc of fluid loss, and generally this concentration comes out at .75 - 1.0 gal/sk.

March 2004

Company Use Only

Section 2 - 18

Cement Additives

2

Gas generating agents that react with the cement to produce hydrogen gas are highly effective at preventing gas migration. These materials are finely ground aluminum powder and generate the gas as the cement is placed. Care must be exercised to not batch mix any gas generating material at surface. This can result in the generation of hydrogen gas in the batch mixer. As with the gas generating agents, foamed cement has been shown to prevent gas migration. Other materials that reduce the shrinkage of cements have been shown to be effective as gas migration control. These materials function in combination with other mechanisms like fluid loss control to maintain slurry volume. An example of systems that have a reduced "shrinkage" are Schlumberger's CRETE* designs. A more detailed discussion of these materials is found in Section 7, Gas Migration.

2.13. LOST CIRCULATION Major lost returns occurs when the wellbore pressure exceeds the integrity and a fracture is created. The integrity is equal to the rock stress holding the two faces of the fracture closed (minimum stress). Integrity is built by pressing the fracture wider to increase the closing stress, then packing the fracture with solids to sustain the width. If the width achieved is adequate so the increased stress exceeds equivalent circulating density (ECD), losses stop. If not, the ECD will press the fracture wider and losses continue. Cement is not effective in stopping losses unless the required increase in integrity is small. Cement particles are essentially the same size as barite so it flows into the fracture as freely as mud. In contrast, lost circulation materials (LCM) pills become very resistant to flow down the fracture because of their high fluid loss rate. As the pill dehydrates, the solids remaining in the fracture become unpumpable and the fracture trip cannot grow. Fluid loss is the key to this process. The fluid loss of most cements is low enough that it does not dehydrate greatly as it flows down the permeable face of the fracture, and does not become resistant. The small amount of width that is achieved may result in only a 100 - 200 psi increase in closing stress. In field operations, returns often increase when the circulating cement arrives at the loss zone. However, this only occurs when the ECD is only slightly higher than the integrity and the 100 - 200 psi of stress that can be built with cement is adequate to support the ECD. The loss zone must also be permeable so the cement can dehydrate. If a significant increase in integrity is required, or if the loss zone has low permeability, the losses should be treated with more effective procedures prior to running casing. Since the effectiveness of cement cannot be predicted, pretreatment with LCM is preferred if cement returns are critical. The effectiveness of the cement may also be enhanced slightly by adding LCM to the slurry. Lost circulation materials in cement are typically larger than those used in drilling fluids because particle size is not constrained by nozzles or other restrictions. Cellophane flake is the most common material, though ground coal and gilsonite are also used. Because cement slurries are already crowded with solids, it is not possible to add a significant concentration of LCM and yet remain pumpable. Cellophane is usually mixed at only 2 - 3 ppb (0.25 lb/sk), which does not greatly improve its effectiveness in stopping losses. Higher concentrations of granular materials may be used in lower weight cements (70 ppb), but the slurry will still not be as effective as an

March 2004

Company Use Only

Section 2 - 19

Cement Additives

2

LCM pills due to the low fluid loss created by the pore throat plugging efficiency of fine cement particles. Schlumberger is marketing a material called CemNet used as either a pre-spacer additive, or placed in the cement. The fibrous material cannot be dry blended into the cement as it will plug the transfer lines. It is added directly to the mixing tub, by hand, in concentrations of approximately 0.5 - 0.75 lb/sk. Because of the hand addition method, precise concentrations cannot be controlled. The material is being sold on a cost per barrel treated, and in some markets can be quite expensive. Results to date indicate good results with the material.

2.14. SILICA At temperatures exceeding 230°F (110°C), the crystalline structure of cement changes. The resulting structure will be higher in permeability and have lower strength. This reaction is called strength retrogression. To prevent strength retrogression, silica is added to cement, which reacts to form more stable crystalline forms at high temperatures. Many sources quote 230°F (110°C) as the initiation temperature for strength retrogression. Many cements do not exhibit strength retrogression problems until well above 260°F (127°C), while others may show signs of degradation below 230°F (110°C). For the purposes of design, a 230°F (110°C) is used, however, specific well conditions and designs that reduce the water content of the cement can be successfully used up to 250°F (120°C). Silica sand (70 - 140 mesh) and silica flour (less than 200 mesh) are used to prevent strength retrogression. Silica flour will react faster due to the higher surface area of the material. For most systems, a concentration of 35% is required to prevent strength retrogression. The 35% concentration will give a calcium-to-silica ratio in the final cement of approximately 1:1. For systems incorporating pozzolans, the silica concentration can be dropped to 20%. This is because the pozzolan contains silica. Below 230 - 250°F (110 - 120°C), silica acts as a filler, diluent and slight weighting agent. At one time, silica was added to cement for kick-off plugs, but it has been determined this gave no benefit to the cement, and in many cases resulted in a more friable system. Strength retrogression does not necessarily cause operational problems due simply to the loss of compressive strength. Over time, the cement strength may retrogress from 3,000 psi to as low as 500 psi, but even this low strength is sufficient to maintain casing support. The problem begins to arise due to the increase in the permeability of the cement. Permeability can increase from 0.001 mD in a standard cement, up to 0.5 mD in a fully strength retrogressed slurry. This can lead to problems with zonal isolation, fluid movement and other well problems.

March 2004

Company Use Only

Section 2 - 20

Cement Additives

2

2.15. ANTIFOAMS & DEFOAMERS Two general classes of materials aimed at reducing the air entrainment of cement slurries are antifoams and defoamers. The two materials are not interchangeable and have different functions. Rarely are the two used in the same slurry, and rarely are they both available on location.

2.15.1. Antifoams An antifoam works by changing the surface tension of the water and preventing foams from forming. As such, it is added to the mix water, or dry blended into the cement prior to mixing. The materials will prevent the formation of a foam, but once a foam is generated in a system, will do little to disperse or eliminate an existing foam. Most of the agents used in cement are antifoam materials. If not used properly, antifoam agents can become foam stabilizers at high concentrations. As noted, an antifoam will do little to eliminate a foam that is in place. The tendency in the field is to add large amounts of antifoam directly to the mixing tub to eliminate a foaming problem. The high concentration in the mixing tub can result in stabilization of the existing foam. One of the reasons the foam appears to reduce is no new foam is being generated in the tub, and the existing foam is gradually dispersed.

2.15.2. Defoamers Defoamers work by eliminating existing foams. As noted, these are not readily available and not normally used. In the event of a severe foaming problem, a SMALL spray of diesel onto the surface of the foam will generally result in elimination of the foam.

2.16. SALT (NACL) Sodium chloride salt is a unique additive because it changes in how it effects cement depending on the concentration. At concentrations below 5% by weight of water (BWOW), salt acts as an accelerator. This will hold true whether the salt is added to the cement slurry, or is used as part of the mix water as in the case of mixing a cement with seawater. At concentrations from 5 - 10%, salt has very little effect on cement properties. It acts as neither an accelerator nor retarder. Many service companies have sold salt in this range for properties ranging from expansion to durability. Above 10%, and up to saturation at 37%, salt will act as a retarder, with the retardation effects increasing with concentration. Salt is used for acceleration at low concentrations, primarily in the form of seawater. Because calcium chloride is more effective and predictable, sodium chloride is rarely used as an accelerator in its place. At concentrations around 10%, salt can be used as a dispersant and expansive additive. The expansion obtained from salt is low, and is dependent on how the

March 2004

Company Use Only

Section 2 - 21

Cement Additives

2

laboratory test is performed. If a cement system containing 10% salt is cured in a fresh water bath, the system will show expansion due to the uptake of water through osmotic pressure. Conversely, the same system when cured in a bath containing salt water will not show appreciable expansion, and can show shrinkage if cured in a salt saturated water bath. There is no reason to pay for 10% salt to get an expansive property. Higher concentrations of salt are used primarily for salt formations. Salt zones will not bond to fresh water slurries, as these slurries will tend to dissolve the salt at the cement formation interface. Adding approximately 24% salt to the slurry will prevent dissolution of the interface. It is not necessary to salt saturate the cement to prevent dissolution of the interface to salt formations. Large amounts of salt, above 24%, will adversely effect most common cement additives. Fluid loss additives do not function well in high-salt environments, and typically to get good fluid loss control, large amounts of additive were required. These materials tend to be retarders, resulting in an over-retarded slurry. By using lower concentrations of salt, less fluid additive may be required, which results in a better slurry design. Several additives have been developed that work better in high-salt environments, but still benefit from the lower concentration of salt.

2.17. LATEX AND LATEX STABILIZERS Latex is one of the few additives that can have a long-term effect on the set cement properties. When used at high concentrations (exceeding two gallons per sack), latex can change the flexibility of the cement and will effect the Young's Modulus of the set cement. Latex has use in preventing gas migration and functions very well for longterm isolation of the well. The normal recommended concentration for latex is 1.0 - 1.5 gallon per sack. Concentrations above this level should only be run if specific, long-term mechanical properties are required. Latex often requires an additional stabilizer, particularly at high temperatures or in systems containing salt. The stabilizer extends the effective range of the latex, and if used properly, can reduce the amount of latex required for a particular application.

2.18. OTHER ADDITIVES There are several additives while used in special situations, are not part of usual slurry design. These materials include: •

Gypsum - Added in high concentrations (50 - 60%) for slurries to be exposed to a Permafrost formation. May also be used at concentrations from 10 - 12% to impart thixotropic properties or give positive expansion of the slurry.

•

Surfactants - Used for foamed cement, surfactants are also recommended in some gas applications for entraining formation gas as it enters the annulus. Shell evaluated the use of surfactants in cement for gas migration prevention and found the technique to be very effective provided a number of design criteria

March 2004

Company Use Only

Section 2 - 22

Cement Additives

2

were met. With the development of improved gas migration materials, this practice is now rarely used. •

Fibers - Used to aid in tensile strength or cement stability. These materials cannot be dry blended, as they will plug the bulk line. They must therefore be added by hand at the mixing tub. Normal usage range is 0.25 - 1.25 lb/sk. Fibers have been put into cements that are used for temporary wellbore lining. This involves setting a cement plug in the open hole that contains the fibers, then drilling a hole through the center of the plug. This acts to stabilize the formation and allow further drilling. The fibers do not prevent cracking of the cement during drill out, but hold the pieces together, preventing them from falling into the hole.

2.19. LIQUID ADDITIVES Cement additives are generally available in either liquid or dry form. Liquid additives are often used for offshore and remote locations that may lack blending facilities. These materials may also be used where the mix water will be premixed with the required additives. This reduces the variability in dry blending, and can improve quality control on location. The convenience of liquid additives must be weighed against two operational concerns - metering and density control.

2.19.1. Metering Liquid additives, when used in a continuous mix operation, must be properly metered into the mix water. This is accomplished either through dump tanks, where a given volume of additive is added to a tank of mix water, or through metering the additive directly into the water as it is mixed with the cement. The liquid additive pump systems must be properly calibrated and checked prior to the job. Many service companies depend on a pump stroke counter from the additive pump to calculate additive flow rate. This method of metering is not acceptable in ExxonMobil operations. Experience in Eastern Canada offshore showed this method of additive metering can be off by as much as 30%, due to the limitations of counting pump strokes on a pump. If the line is plugged, additive viscosity is too high, or the suction of the pump is plugged, there will by no indication to the operator that the additive is not being delivered to the mix water. The pump will continue to cycle, but no material will be delivered. The preferred method is to use either a dump tank, where the additive is seen going into the water, or by using a mass flow meter to measure the additive flow when the additives are being directly pumped into the mix water line.

2.19.2. Density Control Because the additives are in the mix water, density control on jobs using liquid additives is critical. If the slurry is mixed light (too much mix water), the amount of additives per sack is also increased. In the case of a retarder, not only will the cement run long because of the lower density, it will also have more retarder in the slurry, further

March 2004

Company Use Only

Section 2 - 23

Cement Additives

2

increasing the retardation. If mixed heavy, there will be a lack of retarder that can lead to premature setting of the cement.

2.19.3. Storage Liquid additives need to be protected from cold temperatures. Depending on the additive, freezing of the additive can destroy the function. This is particularly true with latex type materials. Other additives can crystallize out and settle in the container. Very high temperatures can lead to additional reactions within the liquid additive, especially if it is a mixture of several components. In one instance, the manufacture temperature of the additive was 110°F (37°C), but the location temperature exceeded 125°F (51°C). (The additives were stored near a flair on a platform.) This resulted in continued polymerization of the additive, rendering it too viscous to remove from the drums. Liquid additives, if stored in buckets, should be regularly mixed to prevent settling. A better alternative to small buckets is to store the material in a larger tote that can be circulated with a small pump.

2.20. DRY ADDITIVES Most land and many offshore operations use dry additives, which require dry blending. All systems using silica for temperature stability must be dry blended before being sent to location. Depending on the local operations, the dry blending operation will take place at the service company facility, at the cement manufacturing plant, or a centralized blending facility. Blending at the manufacturing plant is common practice in Norway, and centralized blending at a facility in France is used by Schlumberger to preblend their CRETE* systems for use throughout Europe, West Africa and parts of the Middle East. The most common operation is dry blending at the site. Systems with dry blended additives will be more consistent when mixed outside the design density. Because the additives are blended with the cement, changes in water content will not alter the relative concentration of the additive. It is important to obtain a consistent blend, and proper dry blending techniques are essential. The service company should have a quality procedure in place for control of the dry blending process. The procedure should include: •

Proper storage of additives - Sack additives should be protected from humidity and condensation.

•

Isolation of additives - The lot number of the additives being used for a single job should be identical if possible. It is common practice to isolate additives for critical cement jobs.

•

Weights and scales - The additives must be weighed properly. This requires the use of a calibrated scale.

•

Blending process - The bulk plant operation should have a process where the additives are layered or sandwiched into the cement. The best method of obtaining a quality blend is to place one-third of the cement in the weigh batch

March 2004

Company Use Only

Section 2 - 24

Cement Additives

2

blender followed by one-half of the additives. This is followed by another onethird of the cement, the remainder of the additives and finally the remainder of the cement. •

Blending and blend movement - The process should include a minimum of three bulk moves of the cement. This means the cement must be blown from the weigh batch tank to a separate holding tank, then back to the weigh batch blender (or a second tank) and finally to the truck or transport. This would constitute the three-move minimum.

•

Sampling and sample retention - There should be a process in place for sampling the blend on the last movement through an in-line sample device. The process should also include a written retention time for the samples. Typically, samples of blends are retained for 30 days.

•

Labeling - Proper labeling of the cement samples is equally important. The labeling should include the blend composition, lot numbers of additives and any other identifying information. The additives in the blend must be traceable back to an identifiable lot.

March 2004

Company Use Only

Section 2 - 25

Cement Additives

2

Table 2.1: Additive Function Overview

Water Requirement

Decrease

=

More

=

Early Strength

Higher

x

Longer

Durability

x

=

=

=

Weighting Agents

Salt

Gas Migration

LCM

Free Water Control

= =

x

x x

=

x

More

=

x

=

=

=

x

x

x

=

More Less

=

Better

=

x = x

Improved

x

x

x =

Company Use Only

x =

x =

Less More

March 2004

x

Shorter

Worse Free Water

x

x

Worse Fluid Loss

=

=

x

x

Less Ultimate Strength

=

=

Lower Thickening Time

=

=

Less Viscosity

Sand

Retarder

Increase

Dispersant

Density

Accelerators

Effect

Extenders (Bentonite, Pozzolans, etc.)

= = Major Effect; x = Minor Effect

=

x

x =

x =

x

Section 2 - 26

Section

Primary Cementing Cement Testing

Scope This Section provides an overview of basic cement testing. Individual cement tests are identified, and a brief discussion of how the test is performed, required information needed to perform the test; data interpretation and test limitations are included.

Company Use Only

Cement Testing

3

Table of Contents Figures ............................................................................................................... 5 Tables................................................................................................................. 6 ExxonMobil Requirements ............................................................................... 7 ExxonMobil Recommended Practices ............................................................ 7 3. Cement Testing ........................................................................................... 8 3.1. Required References ............................................................................... 8 3.1.1.

API-American Petroleum Institute.................................................................. 8

3.1.2.

ISO-International Standards Organization ..................................................... 8

3.2. Introduction .............................................................................................. 8 3.3. API and ISO Standards and Specifications............................................ 8 3.4. Cement Testing Overview ....................................................................... 9 3.5. Thickening Time....................................................................................... 9 3.5.1.

Information Needed to Perform the Test...................................................... 10

3.5.2.

Test Description .......................................................................................... 10

3.5.3.

Data Interpretation....................................................................................... 10

3.5.4.

Test Limitations ........................................................................................... 12

3.5.5.

Considerations ............................................................................................ 13

3.6. Compressive Strength ........................................................................... 13 3.6.1.

Information Needed to Perform the Test...................................................... 13

3.6.2.

Non-Destructive Sonic Strength .................................................................. 14

3.6.3.

Destructive Test .......................................................................................... 14

3.6.4.

Strength Testing Overview .......................................................................... 15

3.6.5.

Test Limitations ........................................................................................... 15

3.6.6.

Considerations ............................................................................................ 16

3.7. Cold Temperature Testing..................................................................... 16 3.7.1.

Information Needed to Perform the Test...................................................... 16

3.7.2.

Test Description .......................................................................................... 16

3.8. Free Water............................................................................................... 17 3.8.1.

March 2004

Information Needed to Perform the Test...................................................... 17

Company Use Only

Section 3 - 2

Cement Testing

3

3.8.2.

Test Description .......................................................................................... 17

3.8.3.

Data Interpretation....................................................................................... 18

3.8.4.

Test Limitations ........................................................................................... 18

3.8.5.

Considerations ............................................................................................ 18

3.9. Fluid Loss ............................................................................................... 19 3.9.1.

Information Needed to Perform the Test...................................................... 19

3.9.2.

Test Description .......................................................................................... 19

3.9.3.

Data Interpretation....................................................................................... 20

3.9.4.

Test Limitations ........................................................................................... 21

3.9.5.

Cost Versus Performance ........................................................................... 21

3.9.6.

Considerations ............................................................................................ 21

3.10.

Settling ................................................................................................. 21

3.10.1. Information Needed to Perform the Test...................................................... 21 3.10.2. Test Description .......................................................................................... 22 3.10.3. Data Interpretation....................................................................................... 22 3.10.4. Test Limitations ........................................................................................... 22 3.10.5. Considerations ............................................................................................ 22

3.11.

Density ................................................................................................. 22

3.11.1. Information Needed to Perform the Test...................................................... 22 3.11.2. Test Description .......................................................................................... 22 3.11.3. Data Interpretation....................................................................................... 23 3.11.4. Test Limitations ........................................................................................... 23 3.11.5. Considerations ............................................................................................ 23

3.12.

Gas Migration/Gas Tightness............................................................. 23

3.12.1. Information Needed to Perform the Test...................................................... 24 3.12.2. Test Description .......................................................................................... 24 3.12.3. Data Interpretation....................................................................................... 24 3.12.4. Test Limitations ........................................................................................... 24 3.12.5. Considerations ............................................................................................ 24

3.13.

Transition Time ................................................................................... 24

3.13.1. Information Needed to Perform Test............................................................ 24 3.13.2. Test Description .......................................................................................... 25 3.13.3. Data Interpretation....................................................................................... 25

March 2004

Company Use Only

Section 3 - 3

Cement Testing

3

3.13.4. Test Limitations ........................................................................................... 25 3.13.5. Considerations ............................................................................................ 25

3.14.

Wettability ............................................................................................ 26

3.14.1. Information Needed to Perform Test............................................................ 26 3.14.2. Test Description .......................................................................................... 26 3.14.3. Data Interpretation....................................................................................... 26 3.14.4. Test Limitations ........................................................................................... 26 3.14.5. Considerations ............................................................................................ 27

3.15.

Rheology.............................................................................................. 27

3.15.1. Information Needed to Perform Test............................................................ 27 3.15.2. Test Description .......................................................................................... 27 3.15.3. Data Interpretation....................................................................................... 27 3.15.4. Test Limitations ........................................................................................... 28 3.15.5. Considerations ............................................................................................ 29

3.16.

Compatibility ....................................................................................... 29

3.16.1. Information Needed to Perform Test............................................................ 29 3.16.2. Test Description .......................................................................................... 29 3.16.3. Data Interpretation....................................................................................... 30 3.16.4. Test Limitations ........................................................................................... 30 3.16.5. Considerations ............................................................................................ 30

3.17.

Additional Compatibility Tests........................................................... 30

3.18.

Strength Development at Top of Liner .............................................. 30

3.18.1. Information Needed to Perform Test............................................................ 30 3.18.2. Test Description .......................................................................................... 31 3.18.3. Data Interpretation....................................................................................... 31 3.18.4. Test Limitations ........................................................................................... 31 3.18.5. Considerations ............................................................................................ 31

3.19.

Test Timing .......................................................................................... 31

March 2004

Company Use Only

Section 3 - 4

Cement Testing

3

Figures Figure 3.1: Slurry Cup ................................................................................................. 10 Figure 3.2: Thickening Time Curve (2 Slurries) ........................................................... 11 Figure 3.3: Point of Departure ..................................................................................... 12 Figure 3.4: Free Water ................................................................................................ 18 Figure 3.5: Fluid Loss Test .......................................................................................... 19 Figure 3.6: Cost Versus Performance.......................................................................... 21 Figure 3.7: Viscometer ................................................................................................ 28 Figure 3.8: Viscometer Data ........................................................................................ 28

March 2004

Company Use Only

Section 3 - 5

Cement Testing

3

Tables Table 3.1: Representative Compatibility Data.............................................................. 29 Table 3.2: Testing Summary........................................................................................ 32

March 2004

Company Use Only

Section 3 - 6

Cement Testing

3

ExxonMobil Requirements Section #

ExxonMobil Requirement

There are no ExxonMobil requirements in this Section.

ExxonMobil Recommended Practices ExxonMobil recommended practices for testing that deviate from standard API and ISO protocols are found in the following:

Section # 3.5

ExxonMobil Recommended Practice Thickening times should be reported as time to 70 Bc.

3.5.4

The API tables should not be used to determine heat up rate. The actual time to bottom should be calculated.

3.5.4

The maximum heat up rate for thickening time testing is one hour.

3.6.4

The recommended method for determining strength development is with a ultrasonic cement analyzer (UCA).

3.13.4

The transition time cannot be measured or determined from a thickening time curve, regular Fann 35 rheometer, or other high shear device.

March 2004

Company Use Only

Section 3 - 7

Cement Testing

3. 3.1.

3

CEMENT TESTING

REQUIRED REFERENCES

This Section lists Practices and Standards that are generically referenced and assumed part of this document. Unless otherwise specified herein, use the latest edition.

3.1.1.

API-American Petroleum Institute

API Spec 10A

Specification for Cements and Materials for Well Cementing

API RP 10B

Recommended Practice for Testing Well Cements

3.1.2.

ISO-International Standards Organization

ISO 10426-1

Cements and Materials for Well Cementing - Part 1: Specification

ISO 10426-2

Cements and Materials for Well Cementing - Part 2: Testing of Well Cement

ISO 10426-3

Cements and Materials for Well Cementing - Part 3: Testing of Deepwater Well Cement Formulations

ISO 10426-4

Cements and Materials for Well Cementing - Part 4: Methods for Atmospheric Foamed Cement Slurry Preparation and Testing

3.2.

INTRODUCTION

This document attempts to take the aspects of common cement testing and presents them in a simplified format. The document is not intended to be a definitive treatise on cementing or cement testing, but as an informative resource on testing.

3.3.

API AND ISO STANDARDS AND SPECIFICATIONS

API and ISO specifications for cement are found in API Spec 10A or ISO 10426-1. These documents present the tests that are to be performed on neat cement with no additives. The purpose of the specification tests is to evaluate the "raw" cement for specific chemical and performance requirements. It is through this testing that cement is classified as a Class A, Class G, etc. The tests are highly specific, and no variance from the testing protocol is allowed. Specification testing is only performed on the base cement with no additives. These are no tests used for a particular well. Most day-to-day cement testing is based on a set of testing standards developed by the American Petroleum Institute (API). The standards are found in the API Recommended Practice for Testing Oil Field Cements, API RP 10B. This same document has been adopted as an International Standard through ISO as ISO 10426-2. These documents

March 2004

Company Use Only

Section 3 - 8

Cement Testing

3

contain standard recommended testing procedures for evaluating cements and cement slurries. These test methods differ considerably from specifications for cement because they allow the use of cement additives, encourage changes to the test, and attempt to follow field conditions. It is not the intent of the API to simulate well conditions. The goal of the API is to develop a standard set of test procedures to allow comparison of results between various labs. API procedures may be modified to match the particular well conditions and mixing methods used. While the tests outlined in the API and ISO publications are applicable to field work, the engineer is responsible for determining the applicability of a particular test and determining if the results have meaning to a particular well.

3.4.

CEMENT TESTING OVERVIEW

Using the API standards as a base, performance testing determines if the properties of a particular slurry meet the requirements of the well. As well conditions merit, it may be necessary to modify or custom design a test to properly evaluate a slurry for a particular application. A test example would be stirring a slurry at atmospheric conditions for some period of time to simulate batch mixing on surface. Several tests outlined in the API Recommended Practices are reviewed. Each test identifies the information required to properly run the test, a description of the test, test limitations, data interpretation and important considerations. Also included are some tests, while not having an API or ISO procedure, are common enough to be included in the table. This information is not meant to limit any specialty testing required for actual well conditions. Description of Individual Cement Tests - A more detailed description of individual cement tests follows. Each explanation includes a brief description of the purpose of the test, the required information needed to perform the test, and a detailed description of the test. Limitations of the test are described along with a summary of important factors.

3.5.

THICKENING TIME

The thickening time of a cement is the time required for a slurry to no longer be pumpable at a particular temperature and pressure. This test is required for every slurry to be pumped. A slurry that has obtained 70 Bc should be considered set. A Bearden Unit of Consistency (Bc) measures of the consistency of a cement slurry when determined on a pressurized consistometer (see Section 3.5.2).

March 2004

Company Use Only

Section 3 - 9

Cement Testing

3.5.1.

3

Information Needed to Perform the Test

Well depth (MD and TVD) Bottomhole Static Temperature (BHST) Bottomhole Circulating Temperature (BHCT) Casing size and pump rates (or time for cement to reach TD) Required Job Time

3.5.2.

Test Description

The thickening time test is a dynamic test, meaning the slurry is moved or stirred for the duration of the test. The only other dynamic test performed on cement is a rheology test. All other cement testing is done in a static condition. The thickening time test is performed on a consistometer, which utilizes a stainless steel slurry cup placed in an oil bath. The sample is heated to temperature and pressure while continuously stirring. Inside the cup is a stationary paddle attached to a spring mechanism. The outer portion of the cup turns, and as the slurry begins to thicken or set, maintaining the paddle in a stationary position requires increasing force (see Figure 3.1). This force is measured as a deflection of the spring and converted into Bearden Units of Consistency (Bc) according to the requirements of API Spec 10A.

Figure 3.1: Slurry Cup

Slurry Cup

Paddle

3.5.3.

Data Interpretation

Figure 3.2 is a graph representing the thickening time curves for two slurries. Both slurries have a thickening time of 120 minutes (2:00) to 100 Bc, but exhibit considerable difference in the thickening time curve. One slurry remains very thin for the entire run, and sets in a very short period of time. The second slurry begins to gel shortly after the test has begun, and continues to thicken gradually over time. The second slurry should be redesigned, as it can cause considerable problems during placement.

March 2004

Company Use Only

Section 3 - 10

Cement Testing

3

Figure 3.2: Thickening Time Curve (2 Slurries) 120 100

Bc

80 60 40 20 0 0

10

20

30

40

50

60

70

80

90 100 110 120

Time (min.)

The laboratory personnel are the only ones that routinely see the thickening time curve, and are, hopefully, sufficiently skilled to recognize a slurry that gels with time. The graph is normally not included in any of the laboratory reports. To address the problem, it is preferred the lab report the time to 30, 50 and 70 Bc. In this way, an approximation of the thickening time curve can be made. The shorter the time between these values, the more "right angle" the set of the cement is said to be. Most labs report the time to 70 Bc as the thickening time. Some laboratories will take the test to 100 Bc, which is in line with the specification test of neat cement. For ExxonMobil operations, the time to 70 Bc should be reported as the thickening time. During the thickening time test, the motor may be turned off for 5 -10 minutes after the cement reaches test conditions. This is to simulate the dropping of the plug and can indicate if there is a gellation problem with the slurry. Following the shut-down period, the viscosity of the slurry should not go above 50 Bc. The shut down is not part of the standard test, is not contained in the API procedure, but is part of the standard ExxonMobil testing procedure given to the service companies. The shut-down period need only be applied where applicable during the job. For example, when pumping a tail cement, the cement will not have reached test conditions when the plug is dropped. Including a shut-down period in this test would not be necessary. Lightweight slurries, particularly those containing silicate extenders, may have a very long thickening time. The true thickening time of these slurries is related to the point in time when the slurry begins to thicken, called the point of departure. The point of departure is where the viscosity of the slurry begins to move away from the baseline. With silicate slurries, it is possible to continue to pump the slurry beyond its "thickening time" because the crystals formed in the cement are not strong enough to prevent breakage by the consistometer blade. The results of pumping one of these slurries well beyond the point of departure will be a reduction in the strength development. An analogy to this would be in making whipped cream. Initially, the system will be thick, but if mixing continues, butter will be formed and the remaining liquid will separate. If a silicate extended system is mixed too long, the resulting slurry will have the consistency of cottage cheese. The slurry will also be very thixotropic, and any shut down of the

March 2004

Company Use Only

Section 3 - 11

Cement Testing

3

pumps on location after the point of departure could result in an early termination of the job. Figure 3.3 illustrates a silicate slurry that has a point of departure at approximately 50 minutes. The time required for the slurry to reach 70 Bc is in excess of 2-1/2 hours. This can be critical on location because if the pumps are shut down for any reason after 50 minutes, the slurry will gel very rapidly and end the cement job.

Figure 3.3: Point of Departure

120 100

Bc

80

Point of Departure

60 40 20 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 Time (Min)

Note: The point of departure is only critical for slurries containing silicate extenders.

If the job calls for batch mixing the slurry, the thickening time test can be modified to simulate surface mixing of the slurry. The test is performed in the same instrument, but for the anticipated mixing time, no heat or pressure is applied to the cement. The surface mixing time is not figured into the thickening time. The thickening time is reported as the time the temperature and pressure is applied to the slurry until it sets.

3.5.4.

Test Limitations

The thickening time test is performed by taking a slurry and heating it to the test temperature at a particular rate. The heat-up rate should be determined by the anticipated pump rate on location, and the amount of time it will take to get the slurry to the bottom of the well. The same schedule will also control the pressure placed on the slurry. It is critical the tables in API RP 10B not be used for this determination. The API tables took an average of about 500 wells surveyed between 1986 and 1989 and determined an average time to bottom and the average mud weight. These are the averages that appear in the tables. Many service company lab programs simply extrapolate the temperature, time, and pressure based on the tables. For many wells, the heat-up rate is too slow, and can lead to a cementing failure if used. When calculating the heat-up rate, use the actual time to bottom, or one hour, whichever is less. This is part of the ExxonMobil requirements found in Section 4.3.2.

March 2004

Company Use Only

Section 3 - 12

Cement Testing

3

After the cement reaches the test temperature and pressure, the slurry remains at these conditions for the duration of the test. In an actual well, the cement would be going up in the annulus to a lower temperature and lower pressure. A standard thickening time test does not take this into consideration, and tends to make the test slightly conservative.

3.5.5.

Considerations

1. Temperature, pressure, and heat-up rates are very important for a valid test. Always calculate the rate to bottom and do not depend on the API tables. 2. Request the time to 30, 50 and 70 Bc from the lab. 3. Use caution with silicate extended slurries. reported.

3.6.

Request the point of departure be

COMPRESSIVE STRENGTH

This Section covers "normal" strength testing for wells with static temperatures at or above ambient temperature. Additional consideration is given to cold temperature testing and is covered in Section 6, Specialty Cement Systems. The compressive strength test determines the force required to break an unconfined cement sample after it has been cured at temperature for a given time-period. The test may also be performed in an ultrasonic cement analyzer that utilizes sonic signals and calculates an equivalent strength from the signal. This is referred to as the sonic strength, but in field practice there is normally no distinction made between the two test results. Because of the difference in the conventional compressive strength test and the non-destructive test, the description that follows is in two parts. The non-destructive test has become more common. Normally, the test is performed by field laboratories, except where cooling of the slurry below room temperature is required. Strength testing of cement has the largest standard deviation of any cementing test. The variability in the test results can be as much as +/-75% and normally runs about 50%. Due to this variance, performing a direct comparison of two slurries based only on strength development is highly suspect, and is not recommended.

3.6.1.

Information Needed to Perform the Test

Well depth (MD and TVD) Bottomhole Static Temperature (BHST) Top of liner temperature Top of tail cement Mud weight

March 2004

Company Use Only

Section 3 - 13

Cement Testing

3.6.2.

3

Non-Destructive Sonic Strength

This test is performed on a device called an ultrasonic cement analyzer (UCA). The UCA consists of a slurry container housed in a heating jacket. The slurry is heated to the test temperature in four hours, and held at a pressure of 3,000 psi. The UCA is capable of curing samples at pressures up to 20,000 psi if desired, but pressures other than 3,000 must be specifically requested. The test cell contains an ultrasonic transducer and receiver. The transducer sends a signal through the cement and the time required for the signal to travel through the sample is measured. Based on a set of computer algorithms, an equivalent compressive strength is calculated. The UCA will give the user a plot of strength versus time, and is very useful in determining WOC times. (The signal sent through the cement is essentially the same signal used for the ultrasonic cement evaluation logs, like the CAST V, USIT, or other ultrasonic tools.) The UCA depends on the computer algorithms to calculate strength based on the transition time of the sonic signal. The algorithms change with cement density and to some extent additives in the cement. The UCA appears to give a lower strength number by about 20% than a comparable destructive test, but is more reproducible than the destructive test.

3.6.3.

Destructive Test

The conventional compressive strength test is a destructive test where a 2" x 2" x 2" cube is prepared by pouring a slurry into a mold. The mold is placed under water in an autoclave and heated to the test temperature in four hours. The test is performed at a curing pressure of 3,000 psi. The sample remains at the temperature and pressure for a predetermined time period, typically 8, 12, or 24 hours. The sample is removed from the mold and crushed on a hydraulic press. The force to crush the sample is divided by the cross sectional area of the sample and the result reported as the compressive strength in psi. This test is a destructive test and requires multiple samples of data in more than one test period. The test also relies on the calibration of the hydraulic press, loading rate, and the expertise of the press operator. Because of the variability in equipment and the cement itself, the reproducibility of compressive strength testing is very poor. Each of the molds on a destructive test can make two cubes. The cubes are next to each other, poured out of the same mix of cement. Due to the variance in the test, the force required to crush each cube can vary by 75% or more. A compressive strength number will only give an indication of the order of magnitude of the strength. A cement slurry with a reported compressive strength of 1,200 psi has the same strength as one with a 1,800 psi strength. The accuracy of the test is not sufficient to distinguish between these results. There is no benefit in paying more for incremental compressive strength gain.

March 2004

Company Use Only

Section 3 - 14

Cement Testing

3.6.4.

3

Strength Testing Overview

Strength testing is a static test normally performed at a single temperature and pressure. The curing pressure most commonly used for the test is 3,000 psi. This pressure does not correspond to the pressures actually seen in the well, and merely serves as a standard for testing. Curing pressure can have an effect on the rate of strength development, but is normally not a concern except in cold temperature testing. Temperature is the most important variable in determining strength development, and usually the test is performed at too high a temperature. It is common lab practice to test all slurries at the BHST of the well. For lead cement slurries, the cement will never be exposed to the BHST, and testing at this temperature gives overly optimistic results. Additionally, the tail slurry will not see the BHST of the well for some time, and thus test results, if performed at BHST, will be optimistic as well. (See Section 4.3.3 for calculation methods.) •

For general testing purposes, it is recommended that tail cement slurries be tested at 85% of the BHST.

•

Lead slurries should be tested at the temperature at the midpoint of the lead, or at the highest point covered by the lead if strength at the top of the lead slurry is critical.

Strength tests should always be performed at the top of liners. This is important in determining when the cement has set and the liner top can be pressure tested. If the cement has set at the top of the liner, it should be set at the higher temperatures further down the well. There are very few areas where specific strength numbers have any importance. One specific place is where some regulatory body has set a requirement for strength development over a given period of time. The second area is with plug cementing where high strength gives an advantage for kick-off plugs. Depending on well conditions, any strength in excess of 2,500 is acceptable for a kick-off plug. It is generally accepted that any strength over 500 psi is adequate for continuing any well operation such as drilling out the casing shoe, casing testing, etc. Data at one time suggested a need for at least 2,000 psi for perforating casing, but subsequent work has shown higher-strength cements tend to crack, and lower-strength cements give improved results. While specific strength numbers are of little importance except for regulatory compliance, the development of strength is very important to well design. It is more important to determine when the cement gains sufficient strength to continue operations, than it is to determine the strength at a particular point in time. Because of this, the use of the UCA is the recommended method for strength determination.

3.6.5.

Test Limitations

Strength tests measure unconfined strength, which will vary considerably from values of confined strength that will be present in the well. Data has shown that lower strength slurries will have up to 8 - 10 times more strength if tested in a confined environment. High strength samples, those having unconfined strengths of 4,000 or more, will show

March 2004

Company Use Only

Section 3 - 15

Cement Testing

3

an increase of 3 - 5 times. The difference is the high strength material is too brittle to gain from the load transfer to the surrounding material.

3.6.6.

Considerations

1. Test the tail slurry at 85% of BHST. Do not use BHST (see Section 4.3.3). 2. Test the lead at the temperature of the midpoint of the lead, or at the top of the lead, if strength development at the top of the lead cement is important. 3. If strength development is a problem, consider performing the test following a preconditioning period on a consistometer at the BHCT of the well following API/ISO procedures. 4. Do not pay more money for incremental strength gain. 5. Always request a strength test be performed at the top of a liner.

3.7.

COLD TEMPERATURE TESTING

Conventional strength tests are performed at a single temperature. For cold applications, such as deepwater, the use of a single temperature can give unrealistically pessimistic results. This is because the test procedure does not account for the thermal mass of the cement, and does not allow for the heat of hydration of the slurry to aid in strength development. ISO 10426-3 procedures include a specific testing protocol for use in cold temperature environments. The procedures call for very similar testing to the strength testing, with additional consideration given to the temperature profiles of the test. API RP 10B also contains test protocols that address arctic testing. The procedures call for cycling the cement through several freeze-thaw cycles to determine slurry stability. This specialty test is only used in permafrost environments. Test details for this protocol are found in the API text.

3.7.1.

Information Needed to Perform the Test

Water depth Temperatures Casing and hole size

3.7.2.

Test Description

Testing in cold environments utilizes the same equipment as other testing, but the equipment is cooled to temperatures below room temperature. This creates a number of challenges for the equipment as condensation can cause electrical problems with some test equipment. Additionally, the equipment has not been designed to simulate a cool down ramp, so temperature control may be a problem.

March 2004

Company Use Only

Section 3 - 16

Cement Testing

3

Strength development is most effected by cold temperatures. The thickening time of the slurry will be longer, fluid loss will not change, and free water will be unaffected. The procedures outlined in the API and ISO documents recommend testing after running some type of temperature simulator to estimate temperature recovery in the wellbore. The temperature profile for the strength test can be modified to simulate the recovery of the formation, and in some cases, the heat generated from the hydration of the cement. The thermal gain from the heat of hydration of cement is not accounted for in conventional cement testing. The size of the sample in comparison to the test cell is insignificant, and it is easy to withdraw heat from the sample during the test. When testing at cold temperatures, it is recommended the UCA cell be chilled to the test temperature and then the cooling water turned off to allow the cell to warm as the cement sets. The normal testing for cold temperature tests involves setting cubes in a refrigerator or cold bath. The samples are then crushed and the strength determined. While this will give an indication of the strength at that point in time, it will not tell the user when the cement began to set. In cold temperature testing, it is often more important to know when the cement begins to set than the strength at some point in time. The preferred method for testing cement in cold temperatures is the UCA if there is a need to reduce WOC time on the rig. An example where this can be critical is where the casing string must be held in position until the cement sets. If there is no rig time tied up in waiting on cement, then conventional testing will work well. Cases where this is applicable involve long runs of risers, where it can take up to three days to be back on the well.

3.8.

FREE WATER

Also known as free fluid, the test is an indication of water separation from a slurry. This test is particularly important for higher angle wells where gas migration may be encountered. The free water test will give an indication of the slurry stability under static conditions.

3.8.1.

Information Needed to Perform the Test

Well Angle Temperature

3.8.2.

Test Description

The test consists of taking a cement slurry that has been conditioned on a consistometer to BHCT and placing it in a 250 mL graduated cylinder for two hours. The fluid separated from the cement slurry at the end of the two-hour period is measured and reported as percent free water (see Section 4.3.6). Free water tests should be performed at either a 0° or 45° angle. For deviated wells, a test angle of 45° is the standard. Slurries may show free water when tested at 45°, even if the 0° test showed no free water development. This is due to a phenomenon called

March 2004

Company Use Only

Section 3 - 17

Cement Testing

3

the "Boycott Effect," that shows solids settle faster at angle, with 45° being the most severe angle. Figure 3.4 shows the set up with the graduated cylinder deviated at 45° from vertical for the test.

Figure 3.4: Free Water

3.8.3.

Data Interpretation

Test data will be reported as a percentage. For slurries across nonproductive zones, free water should be less than 2.5% for lead slurries, and for tail slurries, less than 1%. For any slurry across a productive interval or any gas zone, the free water at angle should be zero (0). To obtain zero free water, even a neat cement slurry will require the addition of some additive, or a reduction in the amount of mix water. An API cement will have free water when mixed at the recommended water content.

3.8.4.

Test Limitations

The test does not measure solids settling directly. The results can show zero free water and the slurry can still settle. The test is performed at atmospheric pressure and a maximum temperature of 180°F (82°C).

3.8.5.

Considerations

1. Request zero free water for any slurry across a productive interval. 2. Test at well angle or 45° from vertical for high-angle wells.

March 2004

Company Use Only

Section 3 - 18

Cement Testing

3.9.

3

FLUID LOSS

The fluid loss test measures the amount of fluid (mL) that can be forced out of a cement slurry at 1,000 psi differential pressure across a 325-mesh screen at the bottomhole circulating temperature of the well.

3.9.1.

Information Needed to Perform the Test

BHCT

3.9.2.

Test Description

The test is performed in a pressurized cell that has a small opening in the top and bottom (Figure 3.5). The top opening is used to introduce nitrogen to the cell. The bottom opening has a 325-mesh screen across the ID of the cell to prevent the cement from being pushed out of the lower opening. After conditioning the slurry at BHCT for at least 20 minutes, the slurry is placed in the fluid loss cell and 1,000 psi differential pressure is applied across the 325-mesh screen.

Figure 3.5: Fluid Loss Test 1000 psi Nitrogen

Cement Slurry 325 Mesh Screen Filtrate

March 2004

Company Use Only

Section 3 - 19

Cement Testing

3

The test is begun and the filtrate from the slurry collected for 30 minutes or until the cement "blows dry." Because the surface area of the test cell is one-half (1/2) of a standard mud fluid loss test, the volume of filtrate is doubled to give the API fluid loss. If the test blew dry, then the 30-minute equivalent fluid loss is calculated by the equation:

Calculated API Fluid Loss = 2 Qt *

5.477 t

Where Qt is the volume (mL) of filtrate collected at the time t (min) of the blowout For example, if 50 mL is collected in 16 minutes and the test blows dry at that point, the API fluid loss is calculated as:

2 * 50 *

5.477 16

= 547.7 ÷ 4 = 137 mL

The cement fluid loss test is very different from the mud fluid loss test. While both tests measure the amount of filtrate from a fluid sample, the standard mud fluid loss test is done at room temperature against filter paper and 100 psi differential pressure. There is a mud test that is performed at a higher temperature and 500 psi differential, but still uses filter paper as the filter medium. The cement fluid loss test is performed at 1,000 psi differential against a 325-mesh screen and is performed at the bottomhole circulating temperature of the well. Fluid loss additives are second only to gas migration materials as the most expensive additives used in cement. It is common to see tail cement slurries with very good fluid loss control following a lead slurry with little or no fluid loss control. The practice should be avoided. Fluid loss is important for gas migration control, squeeze cementing, and narrow annular gaps.

3.9.3.

Data Interpretation

Fluid loss values will be reported in mL. Check to be sure that the test was performed at temperature. Depending on the cement job being planned, the acceptable range for fluid loss will vary. In general, the tighter the annular clearance, the lower the fluid loss should be. The test is not exact, so a range of fluid loss is given: Surface pipe

-

no control required

Intermediate

-

250 - 500 mL

Long String

-

200 - 350 mL

Liner

-

less than 200 mL

Gas Migration

-

50 mL or less

The table lists general guidelines, not fast requirements. A cement system with no control will have an API fluid loss value of approximately 1,200 - 1,400 mL.

March 2004

Company Use Only

Section 3 - 20

Cement Testing

3.9.4.

3

Test Limitations

The test does not take into account the effects of the mud filter cake, which will tend to reduce the fluid loss from a cement slurry. This is why recommendations for fluid-loss control ranges may be higher than those of service companies or other operators.

3.9.5.

Cost Versus Performance

Figure 3.6 represents the relative cost for fluid loss control. The data shows that to obtain the 200 - 400 mL fluid-loss is relatively inexpensive when compared to trying to reduce the fluid loss from 100 - 50 mL. At very low, fluid loss values, the incremental gain in fluid loss compared to the increase in cost is often not beneficial.

Figure 3.6: Cost Versus Performance 1400 1200 1000 800 600 400 200 0 1

2

3

4

5

6

7

8

9

10

11

12

Increasing Cost

3.9.6.

Considerations

1. Check to make sure the test is run at circulating temperature. 2. Fluid loss below 100 mL is quite expensive and usually not necessary. It should only be specified if technically required, as with liners, some squeeze work, or gas migration control.

3.10. SETTLING This test measures slurry stability by taking a sample of cement and allowing it to set in a standard cylinder. The sample is removed, sectioned, and the density of each section measured. The data is reported in lb/gal for each section.

3.10.1. Information Needed to Perform the Test Well Temperature

March 2004

Company Use Only

Section 3 - 21

Cement Testing

3

3.10.2. Test Description This test is also called the BP settling test, as the test was originally developed by BP. The test consists of setting up a cement in a long tube, sectioning the set cement sample and measuring the density variance from the top to the bottom. The tube is designed to be placed in an autoclave, so the test can be performed at temperature and pressure. The cement is normally conditioned in a consistometer prior to being put into the tube. This test is not a routine part of cement testing, but should be run when evaluating new high-density slurries and slurries used for high angle and extended reach work.

3.10.3. Data Interpretation The data from the test is presented as density versus sample. Variations in density, from the top to the bottom of the sample in excess of 0.3 lb/gal, are a sign of settling and slurry stability problems. The average density of all of the samples is often higher than the design density. This is due to the intrinsic error in the test where the total volume of the sample is not accounted for in the calculations. This is not a problem as the test is designed to evaluate changes in density within a single sample.

3.10.4. Test Limitations The test does not account for free water development.

3.10.5. Considerations Watch for excessive density variations from top to bottom of the sample. Temperature can have a major effect on the test. This test is primarily a screening test used for highdensity slurries and those being used for high angle and extended reach wells.

3.11. DENSITY The long-term properties of cement are controlled by the water to cement ratio. The easiest method to test for this is by measuring the density of the slurry. This test is most commonly performed in the field to ensure the cement has been mixed to the proper density. The test should also be performed in the lab if new sources of major additives are being used. This would include previously unused flyash sources, etc.

3.11.1. Information Needed to Perform the Test Desired density of slurry

3.11.2. Test Description The test is performed using a fluid balance. There are two types of balances - an atmospheric and pressurized balance. For cementing purposes, only the pressurized

March 2004

Company Use Only

Section 3 - 22

Cement Testing

3

balance should be used. The pressure in the balance reduces the amount of air entrained in the sample to a negligible amount, thus increasing the accuracy of the reading.

3.11.3. Data Interpretation The data is reported as a density measurement. It is important to use a calibrated fluid balance, and checking the calibration is readily done by measuring the density of a fresh water sample.

3.11.4. Test Limitations The scales are not effective for slurries below 11 lb/gal. Slurries with very high water content, or those containing special ultra lightweight additives may require special measuring devices to determine proper mixing. If the balance is not pressurized properly, the measurement will be off. As a comparison, the difference in an atmospheric and pressurized fluid balance is 0.4 - 0.6 lb/gal.

3.11.5. Considerations 1. Assure the balance is calibrated. 2. Use only a pressurized fluid balance, not an atmospheric balance for measuring cement density.

3.12. GAS MIGRATION/GAS TIGHTNESS There is no API or ISO standard procedure for testing a slurry for the ability to prevent gas migration or exhibit gas tightness through the cement. The industry has developed a number of tests in an attempt to evaluate a slurry for the ability to control gas. The most common models test the slurry for fluid loss, and attempt to inject gas through the matrix of the cement. Cements with very good fluid loss control tend to do very well in the models. These tests evaluate the ability of the cement to prevent gas migration through the matrix of the cement itself. There is no test to evaluate the potential for gas to migrate at either the interface of the cement and the formation of the cement and the casing. Gas migration in these areas can be the result of poor mud removal, oil-wet surfaces, etc. There is a difference between gas intrusion and gas migration. It is very difficult to prevent gas intrusion into a cement column. Materials used for gas migration control must interact with the gas to be effective. The material will thus prevent the gas from forming a flow channel within the cement, but will do little to prevent invasion into the cement immediately across from the gas zone. The only material that has shown the ability to prevent gas intrusion is gas generating additives or foamed cement. The presence of gas in the slurry tends to maintain the pressure of the cement column on the gas zone, thus preventing influx. This effect has been shown in the laboratory, but cannot be demonstrated on cement evaluation logs because the cement will have gas

March 2004

Company Use Only

Section 3 - 23

Cement Testing

3

entrained in the slurry and there is no way to differentiate between gas from a formation and that introduced intentionally to the slurry.

3.12.1. Information Needed to Perform the Test Bottomhole static temperature Well depth Depth to gas zone Gas zone pressure

3.12.2. Test Description There is no single test for gas migration/gas tightness. The test will vary from company to company but will normally include some sort of fluid loss test and potentially a gel strength determination. Most of the industry tests look for gas tightness through the matrix of the cement.

3.12.3. Data Interpretation Data presented and interpreted will depend on the test, but will generally include a review of the gas flow into the cement versus time.

3.12.4. Test Limitations Most of the tests are performed at BHST, but some are limited to atmospheric pressure and 190°F (88°C).

3.12.5. Considerations 1. Do not confuse this test with the transition time measurement. 2. Due to variability in the tests, understand how the test is performed and what the data actually means. 3. See Section 7 for recommendations on techniques to minimize gas migration.

3.13. TRANSITION TIME This is not an API test. The transition time test is commonly used to identify slurries that have increased gas migration control. This test determines the amount of time for a cement to go from 100 - 500 lbs/100 ft2 gel strength when measured at very slow shear rates. The shear rate applied to the test is less than 0.005 sec-1.

3.13.1. Information Needed to Perform Test BHCT and BHST

March 2004

Company Use Only

Section 3 - 24

Cement Testing

3

3.13.2. Test Description The transition time test is normally performed in a special consistometer that has the ability to turn the consistometer paddle at rates of approximately 0.25 revolutions/hour. This means to make one complete rotation of the cup would require four hours. This extremely low shear rate is used to measure gel strength development. Higher shear rates break the gel and are not a measure of the transition time. The test can also be performed on a special rheometer capable of very low shear rates. The standard rheometer cannot be used for this test. The test is not an API or ISO test, and the term transition time is one of the most misused and misunderstood of any cement term. Some personnel have referred to the transition time as the time for a cement to set on a standard thickening time test. This is not a transition time, and must not be confused. Only when the slurry is measured at very low shear rates, can the transition time be measured. For comparison, a thickening time test is performed at 150 revolutions per minute, with the transition time test being performed at 0.25 revolutions per hour.

3.13.3. Data Interpretation The data will be presented as the time for the slurry to go from "zero gel time" to 500 lbs/100 ft2. The zero gel time is the time for the slurry to reach 100-pound gel strength. Data indicates the shorter the transition time, the less likely gas will migrate through the cement. The transition time of a slurry is not the only parameter to measure for gas tightness, but can give an indication of the quality of the slurry. Transition times for quality slurries will normally be less than one (1) hour and preferably less than 30 minutes.

3.13.4. Test Limitations Only specialized equipment can measure gel strength development at the very low shear rates. The lab must use one of these pieces of equipment (e.g., MACS analyzer, MiniMacs, Vane Rheometer). The transition time will vary depending on the device used to make the measurement, but all of the devices have in common an extremely low shear rate. The transition time cannot be measured or determined from a thickening time curve, regular Fann 35 rheometer, or other high shear device. Additional testing devices are in development that will electronically measure the transition time and gel strength development of cement slurries. These tests apply no shear to the slurry at all and depend on changes in signal travel time through the test sample. Correlation equations between these electronic devices and mechanical methods are under development.

3.13.5. Considerations 1. Look for short (less than one hour) transition times. 2. Temperature will have a major effect on gel strength development. 3. Do not confuse the transition time test with high shear measurements from consistometers or conventional rheometers.

March 2004

Company Use Only

Section 3 - 25

Cement Testing

3

4. Very few labs have the capability to actually run a transition time. Generally, the test must be performed at a central lab facility. 5. The test should be requested at the beginning of drilling projects, changing service companies, or if new additives are being introduced. This test is used as a screening test to prove out particular slurry design philosophies rather than specific slurries.

3.14. WETTABILITY This test attempts to measure the effectiveness of a surfactant system to water wet metal surfaces. The test evaluates spacer systems mixed with non-aqueous fluids (NAF) and the ability to remove that fluid from a metal surface, therefore, this test cannot be performed with water-based drilling muds.

3.14.1. Information Needed to Perform Test BHCT and BHST Sample of drilling fluid

3.14.2. Test Description This test is performed in a modified metal blender cup that has a set of electrodes mounted in the side. The cup can be heated to 180°F (82°C). A sample of nonaqueous mud is put in the cup and stirred at constant rpm on the blender. The sample is then titrated with the spacer, and the electrical resistance between the two electrodes measured. As the resistance reduces, the electrodes are said to be more water wet.

3.14.3. Data Interpretation The results of the test are reported in "Hogans," but the interpretation of the involves evaluating the curve of the reading versus amount of spacer required. less spacer required to effect a water wet change, the more efficient the material. test can also be used to test various surfactants, combinations of surfactants, surfactant concentrations.

test The The and

3.14.4. Test Limitations The test does not evaluate fluid compatibility, nor does it give an indication of the ability of the spacer to mechanically remove the mud in the wellbore. Separate compatibility and rheology tests must be performed.

March 2004

Company Use Only

Section 3 - 26

Cement Testing

3

3.14.5. Considerations The test does not measure compatibility or the mechanical ability of the spacer to remove the mud. It is intended to optimize surfactant loading for a particular mud system and should be requested for new projects or when evaluating the use of a new NAF mud system. 1. The test is limited to 180°F (82°C) and atmospheric pressure. 2. There are no guidelines developed to determine a good spacer from a bad spacer; the test is only qualitative.

3.15. RHEOLOGY 3.15.1. Information Needed to Perform Test BHCT

3.15.2. Test Description This test utilizes a rotating sleeve viscometer to measure the apparent viscosity of fluids at various shear rates. The data is curve fit to an equation that can be used to predict friction pressures in the well during cement placement. The data can also give an indication of the "mixability" of the slurry on location. Figure 3.7 illustrates the rheometer. A rotating sleeve turns around a fixed bob that is attached to a spring. As the sleeve turns, it creates a drag on the bob, and the amount of drag is read as a deflection of the spring. As the speed of the sleeve changes, the shear placed on the fluid changes. The data set generated is then evaluated. A typical rheometer used for cement testing will have readings taken at 300, 200, 100, 6, and 3 rpm. Additional data points may be available, depending on the manufacturer of the rheometer. Changing the rotor (sleeve), bob, spring, or any combination of the three, can modify the test. If some combination other than the standard R1 B1 1X (#1 rotor, #1 bob and #1 spring) is used, then the calculations must be changed to reflect the new test set up.

3.15.3. Data Interpretation The calculation of rheological properties of a slurry can be quite complex, but there are a number of computer programs available to assist in the calculation. The raw data can be evaluated to determine potential mixing or settling problems on location. If the 300 rpm reading is in excess of 275, the mixing rate on location may be limited because of the viscosity of the slurry. If the low shear rate viscosity (3 and 6 rpm) readings are below 5, there is a high potential for settling in the slurry. Be sure to check the settling test and the free water test.

March 2004

Company Use Only

Section 3 - 27

Cement Testing

3

Figure 3.7: Viscometer

Spring

Rotating Sleeve Bob

Figure 3.8 shows a plot of data from a typical rheology test. Depending on the shape of the curve, and data interpretation, calculations can be made for estimated friction pressures, pump pressures, effects on equivalent circulating density (ECD) and any other calculation related to fluid viscosity.

Figure 3.8: Viscometer Data 300 250

Reading

200 150 100 50 0 0

100

200

300

400

500

600

700

RPM

3.15.4. Test Limitations Cement rheology testing is limited to atmospheric pressure and 180°F (82°C). The slurry cannot contain lost circulation materials, as these tend to clog the gap in the

March 2004

Company Use Only

Section 3 - 28

Cement Testing

3

rheometer. The data from foamed cements does not appear to be sufficiently accurate to use for downhole pressure predictions.

3.15.5. Considerations 1. Watch for very high readings at 300 rpm and very low readings at 3 and 6 rpm. 2. Test at room temperature and BHCT or 180°F if BHCT > 180°F (82°C).

3.16. COMPATIBILITY This test evaluates the rheological compatibility of two or more fluids. Normally, the test is run on spacer and mud combinations to determine the compatibility of the fluids. The test can also be performed on mixtures of the spacer and cement, cement and mud, and all three fluid mixtures.

3.16.1. Information Needed to Perform Test Sample of drilling mud Spacer composition Cement slurry composition BHCT

3.16.2. Test Description This test is performed similar to the rheology test for cement and uses the same instrumentation. Samples of the mud and spacer are mixed at varying ratios to evaluate the effects of intermixing of the fluids on rheology. The most common ratios are 0:100, 25:75, 50:50, 75:25, and 100:0.

Table 3.1: Representative Compatibility Data Fann Viscometer Reading @ RPM % Mud

% Spacer

600

300

200

100

6

3

100

0

87

45

30

18

4

3

75

25

92

52

33

23

6

4

50

50

100

60

42

32

7

5

25

75

107

68

49

35

9

7

0

100

118

73

58

40

12

9

March 2004

Company Use Only

Section 3 - 29

Cement Testing

3

The table above shows data from a mud and spacer that are compatible. With the spacer being the "thickest" fluid, all mixtures of spacer and mud show a lower reading than the spacer. There is no rheological incompatibility between these two fluids. When performing the test with mud, spacer, and cement, an equal mixture of concentrations of all three fluids is recommended (1/3 mud, 1/3 spacer, and 1/3 cement).

3.16.3. Data Interpretation For two fluids to be compatible, a mixture of the two fluids should not yield a mixture with a higher viscosity than either of the two individual fluids. Indications of incompatibility are fluid mixtures that show large viscosity increases, tendencies to gel, clabbering, etc. This test should be run whenever a non-aqueous mud is being used. Hydrocarbon-based muds tend to clabber with water-based spacers.

3.16.4. Test Limitations The test is limited to atmospheric pressure and 180°F (82°C). The test will not determine if a spacer will remove a mud in the well, as this is a function of compatibility, density differential, and rheological properties of the spacer and mud systems.

3.16.5. Considerations 1. Look for large increases in viscosity of the fluid mixtures. 2. Make sure the test was performed at BHCT or 180°F (82°C), whichever is lower.

3.17. ADDITIONAL COMPATIBILITY TESTS The API protocols also contain tests for compatibility that include effects on thickening time, strength development, and fluid loss. These tests are rarely run with the exception of the thickening time test when dealing with non-aqueous fluids. It is recommended that when dealing with a non-aqueous fluid at high temperature, a thickening time test of a 50:50 mixture of the mud and spacer be performed.

3.18. STRENGTH DEVELOPMENT AT TOP OF LINER 3.18.1. Information Needed to Perform Test Temperature at top of liner Thickening time test schedule

March 2004

Company Use Only

Section 3 - 30

Cement Testing

3

3.18.2. Test Description This test is identical to the compressive strength with two exceptions. The test is run at the temperature at the top of the liner, and the slurry is preconditioned at BHCT for a period of time to simulate placement in the well. By preconditioning the slurry, the slurry is exposed to BHCT for a time, allowing reactions with the retarders to occur. Without the preconditioning period, strength development testing at the top of the liner would give results that are too conservative, potentially resulting in loss of rig time due to excessive WOC time.

3.18.3. Data Interpretation Same as for strength testing.

3.18.4. Test Limitations Same as for strength testing.

3.18.5. Considerations Properly condition the slurry at BHCT before running the test.

3.19. TEST TIMING When requesting any cement test, sufficient time must be given to the lab to properly perform the required test. For example, to run a thickening time test, the lab technician must calculate placement time, determine slurry composition, weigh out the proper materials, mix the cement, then place it on the machine for testing. It requires at least one (1) hour to prepare a cement sample for testing. Additional time is required for equipment clean up and calibration. Also, following a test, the equipment must be cooled to room temperature prior to beginning the next test.

March 2004

Company Use Only

Section 3 - 31

Cement Testing

3

Table 3.2: Testing Summary Test Name

What the test tells

What the test does not tell

Variability

Needed Data

What to look for

Thickening Time

Gives an indication of amount of time for a slurry to remain pumpable at test temperature and pressure.

Test does not measure effects of fluid loss, contamination, etc.

+/- 15 min.

Temperature

Rapid set. Time between 30 and 70 Bc should be short.

Pressure Time to bottom

Dynamic test does not normally test gel build up Compressive Strength

Unconfined crush strength at a particular temperature and given time period.

Cement mechanical properties down hole.

Minimum job time

+/- 50%

Temperature Time

How the cement will drill.

Total time - time to 70 Bc must be more than job time. Lightweight silicate systems should report point of departure. 500 psi minimum Test temperature for lead should NOT be BHST. Tail should be tested at 85% of BHST.

That the annulus is sealed. Sonic Strength

Strength based on sonic velocities.

Same as compressive strength.

+/- 30%

Temperature Pressure

At least 100 psi for data to be accurate

Data is conservative by 20%. Free Water

Fluid separation from the slurry.

Ability to prevent gas migration. Settling of solids.

+/- 2%;

Hole angle

More with higher values

Always below 2.5%, zero for slurries across producing zones and in angled wells.

Fluid Loss

Amount of filtrate pressed out of a slurry.

Effects of mud filter cake

+/- 10%

BHCT

Requirements depend on type of cement job.

Settling

Density segregation

Does not measure free water.

+/- 0.1 lb/gal

Temperature

Require density variance from top to bottom of cell of 0.2 lb/gal or less.

+/- 0.1 lb/gal

Desired slurry density

Normally, not run in lab. Check for complicated slurries or specialty cements.

Test is not normally run at angle. Density

Density of finished slurry. Confirms validity of lab calculations.

March 2004

Non-pressurized test will not give proper data.

Company Use Only

Section 3 - 32

Cement Testing

Test Name

What the test tells

Gas Migration/ Gas Tightness

No API/ISO test protocol.

Transition Time

Generally listed as pass/fail. Time for a slurry to go from 2 500 lbs/100 ft gel strength.

What the test does not tell

Variability

Needed Data

What to look for

May not be able to compare various service company systems.

Depends on test

Temperature

Get explanation of the test and what factors influence the results.

Ability for a slurry to control gas or fluid migration

+/- 20 min

Well pressure

Fluid loss will be a key. Temperature

Must be measured at very low (.005) shear rate. Wettability

3

Short transition times are generally required for gas migration control. Do not confuse with thickening time test.

Gives an indication of efficiency of surfactant packages for use in spacers.

Only used with non-aqueous muds.

Rheology

Determines viscosity profile of the fluids.

Mud removal efficiency

Compatibility

Tests rheological compatibility of spacer, muds, and cements.

Does not address bulk mud removal only chemical compatibility

+/- 20%

Mud sample Temperature

Effects of changing surfactant concentration and type on results.

Does not address rheology effects. +/- 10%

Temperature

Very high rheology indicates a problem

Generally, pass/fail test

Temperature

Fluids should not gel or increase in viscosity when mixed together.

Mud sample

Check compatibility of spacer mud and cement. Cold Temperature Testing

Strength Development at TOL

Indication of setting properties of cement at cold temperatures.

Effects of thermal mass and heat of hydration are ignored

Evaluates the strength development at a colder temperature than BHST.

Same as compressive strength

+/- 50%

Temperature Time to bottom

+/- 50% on actual strength

Temperature at TOL Job schedule

Look for when the cement sets. Do not be concerned about the amount of strength in a given time. Look for when the cement gains strength at TOL temperature. May need to precondition cement at BHCT prior to running test.

March 2004

Company Use Only

Section 3 - 33

Section

Primary Cementing Cementing Service Company Laboratory Responsibilities and Testing Guidelines Scope This Section discusses the guidelines developed as the standard procedure for obtaining consistent, reproducible cement results for use on ExxonMobil wells. Unless otherwise noted, it is the intent of this document to follow the practices listed in the most recent issue of the API Recommended Practice for Testing of Oil Field Cement (API RP 10B) or the equivalent ISO 10426-2. For purposes of this document, reference to API testing procedures shall also include the ISO equivalent.

Company Use Only

Cementing Service Company Laboratory Responsibilities & Testing Guidelines

4

Table of Contents ExxonMobil Requirements ............................................................................... 3 ExxonMobil Recommended Practices ............................................................ 3 4.

Cementing Service Company Laboratory Responsibilities & Testing Guidelines ............................................................................................... 4

4.1.

Required References ............................................................................. 4

4.1.1.

API-American Petroleum Institute.................................................................. 4

4.1.2.

ISO-International Standards Organization ..................................................... 4

4.2.

Laboratory Responsibilities .................................................................. 4

4.3.

Cement Testing Guidelines ................................................................... 5

4.3.1.

General Requirements .................................................................................. 5

4.3.2.

Thickening Time Tests .................................................................................. 6

4.3.3.

Strength Testing ............................................................................................ 7

4.3.4.

Conditioning of Slurries for Fluid Loss, Free Water and Rheology Testing .... 7

4.3.5.

Fluid Loss Tests ............................................................................................ 8

4.3.6.

Free Water Tests........................................................................................... 8

4.3.7.

Rheology....................................................................................................... 8

4.3.8.

Spacer Compatibility ..................................................................................... 9

4.3.9.

Specialty Testing ........................................................................................... 9

4.3.10. Deepwater Testing ........................................................................................ 9

4.4.

Additional Information ........................................................................... 9

4.4.1.

Liner Jobs ..................................................................................................... 9

4.4.2.

Liner Top Packers ....................................................................................... 10

4.4.3.

Liner Top Compressive Strengths ............................................................... 10

March 2004

Company Use Only

Section 4 - 2

Cementing Service Company Laboratory Responsibilities & Testing Guidelines

4

ExxonMobil Requirements Section #

ExxonMobil Requirement

There are no ExxonMobil requirements in this Section.

ExxonMobil Recommended Practices ExxonMobil recommended practices for testing protocols are found in the following:

Section #

ExxonMobil Recommended Practice

4.3.2

The heat-up ramp found in the API casing and liner tables should not be used for determining the heat-up rate for thickening time tests.

4.3.2

The maximum heat-up rate for thickening time tests is one (1) hour.

4.3.2

For jobs incorporating cement wiper plugs, the thickening time test should incorporate a 10-minute shut-down period to simulate dropping the plug.

4.3.2

The thickening time should be reported as the time to reach 70 Bc.

4.3.2

For extended slurries, the thickening time may be reported as the time to 50 Bc provided the time to 70 Bc is at least 1.5 hours more than the time to reach 50 Bc.

4.3.3

Strength testing on tail cement systems should be performed at 85% of BHST.

March 2004

Company Use Only

Section 4 - 3

Cementing Service Company Laboratory Responsibilities & Testing Guidelines

4.

4.1.

4

CEMENTING SERVICE COMPANY LABORATORY RESPONSIBILITIES & TESTING GUIDELINES REQUIRED REFERENCES

This Section lists Practices and Standards generically referenced and assumed part of this document. Unless otherwise specified herein, use the latest edition.

4.1.1.

API-American Petroleum Institute

API RP 10B

4.1.2.

Recommended Practice for Testing Well Cements

ISO-International Standards Organization

ISO 10426-2

Cements and Materials for Well Cementing - Part 2: Testing of Well Cement

ISO 10426-3

Cements and Materials for Well Cementing - Part 3: Testing of Deepwater Well Cement Formulations

ISO 10426-4

Cements and Materials for Well Cementing - Part 4: Methods for Atmospheric Foamed Cement Slurry Preparation and Testing

4.2.

LABORATORY RESPONSIBILITIES

Testing of all cement and additives to be used on ExxonMobil jobs is the responsibility of the service company testing lab. Quality control testing of the cement additives may be done at the point of manufacture, but the final responsibility for the QA/QC of these materials lies with the service company. Quality control of cement testing with liquid additives includes the proper identification of the additive to be used on the job. As required, this may include sampling of the additive(s) on the rig, identifying the samples with lot and tank numbers, and the use of those identifiers on the laboratory test report. Proper design of the cement systems that best meet the specific requirements of the job shall be the primary responsibility of the lab. Communication with the service company coordinator is essential to ensure the design meets the specific well requirements at the lowest practical cost. Timely testing of pilot tests and field blend systems is required. No cement system should be pumped on any ExxonMobil well that has not been laboratory tested unless specifically agreed by ExxonMobil. Exceptions to this may be granted by the ExxonMobil Field Drilling Manager or designee.

March 2004

Company Use Only

Section 4 - 4

Cementing Service Company Laboratory Responsibilities & Testing Guidelines

4

Testing results should be reported by the lab to the service company coordinator for communication to ExxonMobil. Final lab tests of field blend results should be communicated to the appropriate ExxonMobil engineer. This should be accomplished directly through the service company coordinator.

4.3.

CEMENT TESTING GUIDELINES

The goal of these guidelines is to establish a basis for cement testing, and standardize certain specific tests. It is the intent of these guidelines to establish a basis for communicating test results and the methods used to arrive at those results. Every effort should be made to communicate the results and how the results were obtained on the laboratory report.

4.3.1.

General Requirements

All cementing tests for ExxonMobil are to be performed according to the latest API/ISO testing standards (API RP10B, ISO 10426-2), unless otherwise specified. Deviations from these standard test procedures is allowed provided the test procedure has been approved by the ExxonMobil Field Drilling Manager or designee, and is communicated on the laboratory report. The use of API/ISO standards is not intended to obviate the need for sound engineering judgment regarding when and where the standards should be applied. The temperature of the mix water should approximate that found in field conditions. For laboratory testing, the mix water may require heating or cooling to the anticipated temperature on location. Seasonal variations in temperature should be considered. If other than standard laboratory temperature, the temperature of the water should be noted on the lab report. For field blend tests, samples of drill water and/or seawater from the rig should be used for testing when possible. For general testing with fresh water, municipal tap water may be used. Depending on the quality and consistency of the fresh water and/or seawater at the location, it may be necessary to perform all tests with samples of water from the rig. All wells require a field blend test of the lead and the tail cement systems unless approved otherwise by the ExxonMobil Field Drilling Manager or designee. Proper sampling on location is required, and the samples are to be retained in case of a well problem. The location sample shall consist of the dry blend cement, mix water, and any liquid or solid additives added to the water on location. If additives are placed in the water prior to the addition of the cement, a sample of the mix water with all additives shall be taken. Every effort should be made in the laboratory testing to simulate field conditions. If the field procedure calls for the dissolution of a dry additive into water before mixing the cement, then this should be done in the lab. Liquid additives should be added to the water before the introduction of the cement slurry. Order of addition should mirror field operations. Observations should be made as to any apparent additive incompatibility, excessive foaming, viscosity increase or any flocculation and should be noted and discussed on the lab report.

March 2004

Company Use Only

Section 4 - 5

Cementing Service Company Laboratory Responsibilities & Testing Guidelines

4

The routine use of liquid antifoams in laboratory testing should be avoided. If a liquid antifoam is used in the lab test, it should be noted on the lab report. All slurries should be prepared according to the API mixing procedures. Exceptions to this will be made for slurries containing ceramic spheres, or other specialty slurries as required. Non-API standard mixing methods should be reported on the lab report.

4.3.2.

Thickening Time Tests

The heat-up rate for the thickening time test shall be determined by taking the casing volume and dividing it by the anticipated pump rate. The anticipated pump rates should be at the lower end of the field rates. The heat-up ramp found in the API casing and liner tables should not be used for this determination. The heat-up rates and pressure-up rates for squeeze cement testing may use the tables. The pressure used for the test should be determined from the anticipated mud weight during the job. The maximum heat-up rate should be 60 minutes. If the calculated time is greater than 60 minutes, use 60 minutes as the heat-up rate, unless specific well conditions dictate. If the calculated time is less than 60 minutes, use the calculated time. The temperature for performing the thickening time test may be determined using the API calculation method or the API tables. Use of a temperature simulator is encouraged and the output should be compared to API. For jobs incorporating cement wiper plugs: 1) after reaching the test temperature on the consistometer, hold those conditions for 10 minutes, 2) and then turn off the consistometer motor for 10 minutes to simulate dropping the plug. When the motor is turned back on, the slurry consistency should not exceed 50 Bc, or the slurry should be redesigned. In certain situations, the time for dropping the plug may vary considerably from the time to reach test conditions. In these instances, modifying the shut-down period to mirror field conditions is preferred and should be noted on the laboratory report. The thickening time of a cement slurry is to be reported as the time required for the slurry to reach a consistency of 70 Bc unless otherwise noted on the lab report. The time required to reach 30, 50, and 70 Bc should be noted on the lab report. For lightweight slurries with extended thickening times (greater than five (5) hours), the time to reach 50 Bc may be reported as the thickening time provided: •

The time to reach 70 Bc is at least 1.5 hours more than the time to reach 50 Bc.

•

The lab report reflects the data is reported to 50 Bc.

For slurries containing silicate extenders (sodium silicate, sodium metasilicate), the point of departure shall be noted on the thickening time report. The point of departure is the point in time when the slurry begins to thicken. For slurries that are to be batch mixed, a preconditioning time of one (1) hour (or longer if field conditions merit) should be applied in the lab. The preconditioning will consist of stirring the slurry in the consistometer for one hour (or longer) at atmospheric pressure and temperature. At the end of the preconditioning period, the normal thickening time test will begin. The preconditioning period should not be counted as part of the thickening time, but must be noted on the lab report.

March 2004

Company Use Only

Section 4 - 6

Cementing Service Company Laboratory Responsibilities & Testing Guidelines

4.3.3.

4

Strength Testing

Strength tests should be run at 85% of BHST or at the calculated top of the tail cement. The strength test temperature should be noted on the laboratory test report and should not be at the BHST. For liner jobs, the strength should be determined using the static temperature at the top of the liner. In the case of long liners and production strings, it may be necessary to precondition the cement slurry in the consistometer prior to running the strength test. This may be performed according to the API Procedure of Determining Cement Compressive Strength at the Top of Long Cement Columns. When this method is used, it should be so noted in the lab report. It may be necessary to perform tests at other temperatures depending on individual well conditions. An ExxonMobil representative will specify these tests. For lead slurries, the strength should be tested at the minimum static temperature to which the slurry will be exposed in the annulus or as directed by an ExxonMobil representative. A lead slurry should not be tested for strength at BHST. The use of atmospheric pressure testing for strength determination should be avoided where possible. Use of an ultrasonic cement analyzer (UAC) or equivalent non-destructive testing device is preferred to crush tests. If crush tests are used, testing at temperatures above 180°F (82°C) will require the use of multiple curing chambers. Testing 12- and 24-hour samples in the same chamber is not acceptable for temperatures above 180°F (82°C). To calculate the temperature (in °F) for compressive strength testing, the following calculation should be used: (BHST - 80°F) * 0.85 + 80°F

=

Test Temperature in °F

(BHST - 27°C) * 0.85 + 27°C

=

Test Temperature in °C

4.3.4.

Conditioning of Slurries for Fluid Loss, Free Water and Rheology Testing

Pressurized or atmospheric conditioning may be used for slurries being tested below 190°F (88°C). For atmospheric conditioning, the following should be followed: 1. Start with a cold machine - do not preheat to temperature. 2. Heat to the test temperature at whatever rate the atmospheric consistometer will allow. 3. Atmospheric conditioning is allowed up to 190°F (88°C). For pressurized conditioning, follow the appropriate heat-up schedule for the well.

March 2004

Company Use Only

Section 4 - 7

Cementing Service Company Laboratory Responsibilities & Testing Guidelines

4.3.5.

4

Fluid Loss Tests

The fluid loss test is to be performed at 1,000 psi against a 325-mesh screen, at the BHCT of the well. Data taken at lower temperatures should not be extrapolated to higher temperatures. The use of a stirred fluid loss cell is recommended for tests above 180°F (82°C) if the apparatus is available. This cell is considered safer to operate, and may be used for these tests. The API fluid loss should be calculated by the following formula: API Fluid Loss = ((5.477 * (mL)) / time ^0.5) x 2 Example:

4.3.6.

Test time

=

30 min.

Fluid Collected

=

47 mL

API Fluid Loss

=

(5.477 * 47 / 30^0.5)* 2 = 94 mL

Free Water Tests

Free water (free fluid) tests should be run at vertical or, for deviated wells, at 45°. The lab report should indicate the angle of the test. Free water is defined as the fluid that separated from the cementing slurry during the test. All fluid that separates from the slurry is considered free water, and is not limited to the clear colorless portion. Free water is to be reported as mL/250 mL test or as a percentage. The units must be clearly marked on the lab report. Free water test results of less than 1 mL may be reported as a trace.

4.3.7.

Rheology

The rheology of the slurry should be determined at the BHCT of the well or 180°F (80°C) whichever is less. A 12-speed rotational viscometer is the preferred method for measuring the rheology of the cement slurry. It is not necessary to take readings at rpm's less than three (3) rpm. An initial rheology should be taken on the slurry immediately after mixing to aid in determining the mixing characteristics on location. It is not necessary to condition the slurry for this test. This slurry may be used for the subsequent test at elevated temperature, provided the second test is initiated as quickly as possible. Notations should be made following the rheology tests of any settling tendencies of the slurry. Excessive settling can cause mixing and placing problems. Any slurry design that indicates settling must be redesigned. Five and 10-minute gel strengths should also be run for all plug cement designs. This may prevent problems with pulling out of the plug and/or reversing cement out of the well.

March 2004

Company Use Only

Section 4 - 8

Cementing Service Company Laboratory Responsibilities & Testing Guidelines

4

Data reported on the lab report should include the test temperature, rpm, and dial readings.

4.3.8.

Spacer Compatibility

Unless otherwise requested, testing for compatibility of spacers with muds and/or cement slurries will be limited to rheological determination of mixtures of the various fluids. These tests are to be performed at BHCT or 180°F (80°C) whichever is less. A minimum of three systems should be tested, consisting of fluid ratios of 95:5, 50:50, and 5:95 (95% fluid 1, 5% fluid 2, etc.). For all spacers used with oil-based or non-aqueous muds, a thickening time of a mixture of 50% drilling mud, 50% spacer is recommended. The test should incorporate the shut-down period as with the cement tests previously discussed. The test should be run for the minimum job time plus one-hour. Other combinations of spacer and mud may be tested, depending on the results of the rheology testing.

4.3.9.

Specialty Testing

In the event specialty tests are required, the laboratory test procedure should be clearly defined and understood by all parties involved. A clear definition of the meaning of the results of the test must be established prior to testing. Slurries containing experimental additives should be carefully tested to identify any potential abnormalities in the slurry design.

4.3.10. Deepwater Testing Testing for slurries used in deepwater applications should include the procedures outlined in ISO 10426-3.

4.4.

ADDITIONAL INFORMATION

It is the goal of these guidelines to better simulate field conditions in an effort to improve cementing results. Modification of the API/ISO recommended practices to mirror field conditions is considered an integral part of cement testing.

4.4.1.

Liner Jobs

Depending on the design situation, consideration may be given to adding an additional contingency to the job time calculation to account for circulating out excess cement volume from the top of a liner.

March 2004

Company Use Only

Section 4 - 9

Cementing Service Company Laboratory Responsibilities & Testing Guidelines

4.4.2.

4

Liner Top Packers

If an integral liner top packer is to be used on a liner job, consideration should be given to incorporating an additional shut-down period at the end of the job time to simulate setting the packer. Excessive gel build up at this time could prevent removing the drill pipe after setting the packer. If there is a potential for gas migration, a gas migration prevention slurry should be used. The use of a liner top packer can increase the potential for gas migration when the packer is set due to the removal of active hydrostatic pressure below the packer.

4.4.3.

Liner Top Compressive Strengths

The temperature for the tests can be ramped on the UCA to simulate actual temperatures at the liner top. Use of a temperature simulator to estimate the heat-up ramp is recommended.

March 2004

Company Use Only

Section 4 - 10

Section

Primary Cementing Factors Influencing Slurry Design

Scope This Section covers the factors that should be considered when designing a slurry, including discussions with the service company engineer.

Company Use Only

Factors Influencing Slurry Design

5

Table of Contents Tables................................................................................................................. 3 ExxonMobil Requirements ............................................................................... 4 5. Factors Influencing Slurry Design............................................................. 5 5.1. Required References ............................................................................... 5 5.1.1.

API-American Petroleum Institute.................................................................. 5

5.1.2.

ISO-International Standards Organization ..................................................... 5

5.2. Government Regulations......................................................................... 5 5.3. Temperature ............................................................................................. 5 5.3.1.

Temperature Determination........................................................................... 6

5.4. Well Pressures ......................................................................................... 7 5.5. Formation Properties ............................................................................... 7 5.5.1.

High Permeability Zones ............................................................................... 7

5.5.2.

Salt Zones ..................................................................................................... 8

5.5.3.

Lost Circulation ............................................................................................. 8

5.5.4.

Gas Migration................................................................................................ 8

5.6. Drilling Fluids ........................................................................................... 8 5.7. Logistics ................................................................................................... 9 5.8. Cement Supply ......................................................................................... 9 5.9. Mix Water .................................................................................................. 9 5.9.1.

Seawater ....................................................................................................... 9

5.9.2.

Fresh Water .................................................................................................. 9

5.10.

Equipment............................................................................................ 10

5.11.

Volume ................................................................................................. 10

5.12.

Strength Development ........................................................................ 10

5.13.

Fluid Loss ............................................................................................ 11

5.14.

Free Water............................................................................................ 11

March 2004

Company Use Only

Section 5 - 2

Factors Influencing Slurry Design

5

Tables Table 5.1: Correction Factors for Open Hole Logs......................................................... 6

March 2004

Company Use Only

Section 5 - 3

Factors Influencing Slurry Design

5

ExxonMobil Requirements Section Number

ExxonMobil Requirement

There are no ExxonMobil requirements in this Section.

March 2004

Company Use Only

Section 5 - 4

Factors Influencing Slurry Design

5. 5.1.

5

FACTORS INFLUENCING SLURRY DESIGN REQUIRED REFERENCES

This Section lists Practices and Standards generically referenced and assumed part of this document. Unless otherwise specified herein, use the latest edition.

5.1.1.

API-American Petroleum Institute

API Spec 10A

Specification for Cements and Materials for Well Cementing

API RP 10B

Recommended Practice for Testing Well Cements

5.1.2.

ISO-International Standards Organization

ISO 10426-1

Cements and Materials for Well Cementing - Part 1: Specification

ISO 10426-2

Cements and Materials for Well Cementing - Part 2: Testing of Well Cement

ISO 10426-3

Cements and Materials for Well Cementing - Part 3: Testing of Deepwater Well Cement Formulations

ISO 10426-4

Cements and Materials for Well Cementing - Part 4: Methods for Atmospheric Foamed Cement Slurry Preparation and Testing

To properly design and place a cement slurry for a particular application, a number of well conditions and design criteria must be known.

5.2.

GOVERNMENT REGULATIONS

Most locations have a governing body that sets minimum requirements for well cementing. Generally, these regulations are present to provide safe drilling parameters, environmental control of the well, optimize the removal of the hydrocarbons from the well and ultimately proper abandonment. The requirements for the cement systems may be simply a minimum volume, or there may be specific slurry performance criteria. The slurry designs must comply with the specific regulations governing the well.

5.3.

TEMPERATURE

One of the most important factors in slurry design is the well temperature. The static and circulating temperatures are critical for proper slurry design. For upper casing strings, the production temperatures can also be important.

March 2004

Company Use Only

Section 5 - 5

Factors Influencing Slurry Design

5

Cement exposed to temperatures above 230°F (110°C) requires the addition of silica for long-term stability. In the absence of the added silica, the chemical structure of the cement will begin to change with exposure to high temperatures over time, resulting in an increase in permeability and a reduction in the strength. The cement will not disappear, but will have reduced properties over time. This may be acceptable in certain parts of the well, but should be considered in the design. Circulating temperatures in the range of 180° - 230°F (82° - 110°C) can be particularly challenging. Within this temperature range, there is a change from low-temperature to high-temperature retarders. The design will call for either large concentrations of lowtemperature retarders, which can be detrimental to strength development, or very small concentrations of a high-temperature retarder. High-temperature retarders in this temperature range are very sensitive, and small variations in concentration can lead to extreme changes in thickening time and strength development. Temperature extremes between the bottomhole circulating temperature and the static temperature at the top of the cement column can result in lengthy set times for strength development. There are materials on the market designed to address these extremes, but are more expensive than the standard retarders. For example, if strength development at the top of a liner is critical, consideration may be given to using a material specifically designed to address these needs. The slurry design depends on an accurate bottomhole circulating temperature for development of a proper thickening time. The strength development will be governed by the static temperature of the well. The long-term stability of the set cement is governed by the producing temperature of the well.

5.3.1.

Temperature Determination

Bottomhole static temperature can be determined from offset well information, logs, Horner plots, etc. If using logs, some correction factor should be applied to the log temperature depending on how long the well has remained static. Table 5.1 gives a general guide of correction factors for open hole logs:

Table 5.1: Correction Factors for Open Hole Logs Time Since Last Circulation (hrs)

Correction Factor

0-6

1.2

7 - 12

1.18

13 - 18

1.15

19 - 24

1.12

> 24

1.0

March 2004

Company Use Only

Section 5 - 6

Factors Influencing Slurry Design

5

Bottomhole circulating temperature is determined from well depth and bottomhole static temperature. The API and ISO procedures give both calculations and tables based on the temperature gradient and well depth. Most cementing operations can use the API or ISO approximations with little difficulty. For highly deviated wells and deepwater applications, it is recommended a temperature simulator be used to estimate the circulating temperature. WellCAT is the ExxonMobil standard temperature simulator and is used by Halliburton. Both BJ Services and Schlumberger have developed in-house simulators that appear to be very accurate in temperature estimation. The three simulators give essentially the same results when using the same input data.

5.4.

WELL PRESSURES

Well pressures refer to the pore pressure and fracture pressures in the well. This will determine the required cement densities that will be used for the job. Generally, most jobs are designed with a lead cement density at least 0.5 lb/gal higher than the mud weight, and a tail cement at or near the API water requirement. For jobs with lightweight muds (less than 11.5 lb/gal), the practical lower limit on cement density would be 11.5 - 11.8 lb/gal. Lighter densities than this are possible, but require the use of specialty more expensive additives, or processes such as hollow beads or foamed cement. Job pressures must also consider the friction pressures when placing the cement. These pressures can be checked through the service company placement simulators, and indicate if there is a potential lost circulation problem during the job. Changes in the wellbore pressures during the job can be made through the proper use and selection of spacers, lead, and tail cement volumes. For example, if the mud weight is less than 11.0 lb/gal, water is recommended as a spacer. Using water will reduce the hydrostatic pressure in the annulus, which can allow higher density slurries to be used. At the same time, care must be taken that the reduction in the hydrostatic does not create an under-balanced situation and allow the well to flow.

5.5.

FORMATION PROPERTIES

The types of formations to be cemented are important to slurry design. Depending on formation properties, various additives or job design changes must be implemented. The following general categories cover the most common formation problems.

5.5.1.

High Permeability Zones

Formations are normally well sealed by the drilling fluid filter cake, and that cake will control much of the fluid loss from the cement. High permeability zones, those with permeabilities greater than 100 mD, require additional consideration with cement fluid loss control. If high permeability formations are to be cemented, the fluid loss of the cement should be controlled to under 200 mL/30 min. Additional control may be required depending on annular gap and is discussed in well architecture.

March 2004

Company Use Only

Section 5 - 7

Factors Influencing Slurry Design

5.5.2.

5

Salt Zones

These formations are prone to washout if fresh water systems are placed across the formation face. To prevent washouts and promote bonding, salt should be added to the cement. A maximum of 24% salt concentration is recommended. At this concentration, the amount of salt will allow for bonding, prevent washout of the salt, but is not so high to over retard the cement. Many other additives will work better at the lower salt content, which makes slurry design easier. If working offshore, the system can be designed with 18 - 21% salt, and then mixed with seawater to obtain the required salt concentration.

5.5.3.

Lost Circulation

Formations that cannot support the weight of a cement column may require changing the job design to incorporate a stage collar or specialty lightweight cement system. Rarely does the addition of lost circulation materials to the cement prevent lost circulation while cementing. Thixotropic slurries have been shown to aid in preventing cement fall back, but do little to prevent lost circulation from occurring while pumping. Newly developed materials, like Schlumberger's CemNetä are finding some success in stopping or reducing lost circulation. CemNetä is a fibrous material added to either the spacer or the initial portion of the cement. Due to the nature of the material, it cannot be dry blended with the cement, but must be added to the mixing tub.

5.5.4.

Gas Migration

A number of wells will encounter productive gas zones where some sort of gas migration prevention will be required. Most of the materials currently available for this application lower the fluid loss of the slurry, and will shorten the transition time. The transition time is the time required for the cement to go from a liquid to a solid, and is measured at very low shear rates. The transition time cannot be measured on a conventional consistometer used for thickening time testing (see Section 3.13 and Section 7).

5.6.

DRILLING FLUIDS

The density, viscosity, and type of drilling fluid will have a minor effect on the slurry design. The main effect is in the selection of spacer systems to remove the mud ahead of the cement. Rarely does the drilling fluid type have a direct effect on the slurry design. It is the removal of the mud from the hole, and its replacement with cement, that is key to cementing success. A discussion of mud removal, spacer design and application is covered in Section 9, Mud Removal.

March 2004

Company Use Only

Section 5 - 8

Factors Influencing Slurry Design

5.7.

5

LOGISTICS

The location of the well can effect the base cement available for use, the additive type and mix water properties. The cement available for use on the well can determine the amount and type of additives required, and can result in considerable changes to slurry design. For many remote operations, cement must be brought in due to either lack of local supply, or poor quality of local cement. This is typical for West African operations. The cement is shipped in very large quantities and cement quality may change over time if not stored properly. Additional laboratory testing of the cement may be required for these operations.

5.8.

CEMENT SUPPLY

In some locations, locally available cement does not lend itself for use in oilfield applications. These cements can require large amounts of additives to make them function in the well environments. In these instances, it may be more economical to import a more consistent cement (related closely to logistics).

5.9.

MIX WATER

5.9.1.

Seawater

Offshore sites typically use seawater for cement mixing, at least in the upper parts of the hole. This is less expensive than using fresh water, and allows reducing the amount of accelerators needed in the upper portions of the well. Using seawater on deeper casing strings is not recommended as the amount of retarder required to overcome the accelerating effects of the seawater can be excessive and result in very poor strength development. Seawater should be limited to mix cement that will not be exposed to a BHCT of more than 150°F (66°C). At temperatures above this, the acceleration effects of the seawater make retardation of the cement more difficult and expensive. The source of the seawater can have an effect on slurry design. Depending on rig location, the relative concentration of salt in the seawater can vary. Locations near the mouth of major rivers will change salinity due to seasonal runoff changes in river flow. Major ocean current changes, as with the Gulf Stream or Labrador Current, can change the salinity of the water. Small variations in seawater will not have a major effect on slurry properties, but it is best to obtain a sample of water from the rig for system design.

5.9.2.

Fresh Water

Similar to changes in seawater composition, fresh water changes can effect slurry design. Water taken from inland waterways and swamps will seasonally change. In the fall of the year, the amount of organic compounds in the water can increase

March 2004

Company Use Only

Section 5 - 9

Factors Influencing Slurry Design

5

substantially due to falling leaves. This will also increase the concentration of lignins and tannins in the water, both of which act as cement retarders. Again, obtaining a sample of the mix water for cement design is desired. For land locations, water is often taken from dedicated water wells, ponds, lakes or streams. The water may also be city water hauled to the location in a transport. The quality of the mix water should be evaluated well in advance of the cement job, with attention paid to salinity.

5.10. EQUIPMENT The equipment used can effect the slurry design. Section 14.3.2.1, Equipment, discusses if a batch mixer is being used, the slurry design must take into account the time at surface. In addition, certain additives (like gas generating agents) should never be batch mixed due to the potential for flammable gas generation at surface.

5.11. VOLUME The total volume of cement to be used on the well is integral to the determination of job time. Care must be exercised to remember to recalculate the job time if the cement volume has been adjusted based on open hole calipers. Increasing the volume of cement will require additional time for mixing, and may effect the total job time. Two areas where volume changes can result in cement job failures are: 1) large increases in cement volume due to hole washout, and 2) changing the job from a "stabin operation" to a "conventional displacement." Both of these changes will increase the required time to do the job, and can effect the minimum acceptable thickening time of the slurry. A stab-in operation, typical in large casing strings where the displacement is done down drill pipe rather than the casing string, will have a much lower displacement volume than if the job were displaced through the casing. For example, at 1000 ft, a 20-inch casing stab-in job using 5-inch drill pipe has a displacement volume of approximately 18 bbl, while displacing down the casing would require 350 bbl. Associated with cement volumes is the amount of lead and tail cement being pumped. The volume of slurry may be changed to take advantage of the bulk equipment capacity available at the location. Small changes in tail cement volumes can often eliminate the need for additional bulk equipment for lead slurries.

5.12. STRENGTH DEVELOPMENT Specific situations may require a minimum amount of strength from the cement. For most applications, 500 psi strength will provide the minimum necessary support for any well activity. When setting kick-off plugs, the strength requirement will be higher, and can be obtained by using higher density or reduced water slurries. For the majority of operations, there is no benefit in paying more for additional strength.

March 2004

Company Use Only

Section 5 - 10

Factors Influencing Slurry Design

5

For perforating, data indicates that lower strength materials will not shatter as much as high strength, brittle cements. A lower strength slurry will be more "perforation friendly" than a high strength slurry. The lower strength (less than 1,500 psi) will tend to be more elastic and has a much lower tendency to shatter. Studies have shown that very high strength slurries (in excess of 5,000 psi) can shatter distances of up to 250 ft away from the perforated interval. This can result in loss of isolation in these areas, especially if high perforation density and large perforation charges are used. Strength development for perforation control should be considered at the time of perforating. If perforation will occur within a short time of setting the casing, most cement slurries should work. If perforating is to be delayed by weeks or months, and isolation over a short interval is required, consideration should be given to using a lightweight slurry, or a system that contains latex.

5.13. FLUID LOSS Hole size, annular gap, well angle, and casing requirements will all effect cement slurry design. As the hole size decreases and the corresponding annular gap decreases, there is a greater need for fluid loss control in the cement slurry. The following can be used as a general guide to the amount of fluid loss control required for various situations. Surface pipe

-

no control required

Intermediate

-

250 - 500 mL

Long String

-

200 - 350 mL

Liner Gas Migration

-

less than 200 mL 50 mL or less

5.14. FREE WATER Higher angle wells require control of free water development. Without free water control, solids settling can lead to the formation of a water channel on the high side of the well, which can result in gas and fluid migration and loss of annular seal. Use of slurries that have zero (0) free water when tested at an angle of 45° is recommended for deviated wells. Areas where this may not be necessary are where zonal isolation is not required and cement is being used only for casing support. Lead Slurries across nonproductive intervals Tail Slurries across nonproductive intervals

-

1 - 1.5% Maximum < 1%

Slurries through productive intervals

-

Zero

Slurries in deviated wells (> 25 degrees)

-

Zero to trace

Slurries across gas zones

-

Zero

Squeeze Cementing

-

No Requirement

Plugs

-

< 1%

March 2004

Company Use Only

Section 5 - 11

Section

Primary Cementing Specialty Cement Systems

Scope This Section describes the various types of specialty cement systems. These include foamed cement, available from all service companies, to specialty systems available through individual companies.

Company Use Only

Specialty Cement Systems

6

Table of Contents Tables................................................................................................................. 4 ExxonMobil Requirements ............................................................................... 5 6.1. Required References ............................................................................... 6 6.1.1.

API-American Petroleum Institute.................................................................. 6

6.1.2.

ISO-International Standards Organization ..................................................... 6

6.2. Introduction .............................................................................................. 6 6.3. Foamed Cement ....................................................................................... 7 6.3.1.

Definition and Overview................................................................................. 7

6.3.2.

Applications................................................................................................... 7

6.3.3.

Other Advantages ......................................................................................... 8

6.3.4.

Disadvantages .............................................................................................. 8

6.3.5.

Job Design .................................................................................................... 8

6.3.6.

Design Considerations .................................................................................. 9

6.3.7.

Base Cement Slurry ...................................................................................... 9

6.3.8.

Liquid Additive Delivery ............................................................................... 10

6.3.9.

Nitrogen Injection ........................................................................................ 10

6.3.10. Equipment Hookup...................................................................................... 11 6.3.11. Example of Foamed Cement Calculations................................................... 12 6.3.12. Calculations................................................................................................. 13 6.3.12.1. Calculation #1 (Surface Conditions) ...................................................... 13 6.3.12.2. Calculation #2 (100 psi) ........................................................................ 14 6.3.12.3. Calculation #3 (1,000 psi) ..................................................................... 15 6.3.12.4. Density of Cement Example.................................................................. 16 6.3.12.5. Density of Foam Cement (2,000 psi)..................................................... 16 6.3.13. 3,500 Ft TD Well Example........................................................................... 17 6.3.14. Calculations and Service Company Computer Programs ............................ 19

6.4. CemCRETE* Cement Systems .............................................................. 20 6.4.1.

General ....................................................................................................... 20

6.4.2.

What are the "CRETE" Cements? ............................................................... 20

6.4.3.

Marketing Points ......................................................................................... 20

6.4.3.1. 6.4.3.2.

March 2004

Higher Strength Development ............................................................... 20 Porosity................................................................................................. 21

Company Use Only

Section 6 - 2

Specialty Cement Systems

6

6.4.4.

SqueezeCRETE*......................................................................................... 22

6.4.5.

Cost Comparisons....................................................................................... 22

6.4.6.

Other Related Designs ................................................................................ 23

6.4.7.

Summary..................................................................................................... 23

6.5. Acid Soluble Systems............................................................................ 23 6.6. CO2 Resistant Cements ......................................................................... 24 6.6.1.

Cement Reactions with CO2 ........................................................................ 25

6.6.1.1. 6.6.1.2. 6.6.1.3.

Cement Hydration ................................................................................. 25 Carbon Dioxide Reactions .................................................................... 25 Reaction Products................................................................................. 26

6.7. Hydrogen Sulfide (H2S) Resistance ...................................................... 26 6.8. High Temperature Cements .................................................................. 26 6.8.1.

Preventing Strength Retrogression.............................................................. 27

6.8.2.

Alternatives ................................................................................................. 27

6.9. Permafrost Cement Systems ................................................................ 27 6.10.

Resins and Plastics ............................................................................ 28

6.10.1. Applications................................................................................................. 28 6.10.2. Limitations ................................................................................................... 28 6.10.3. Job Considerations...................................................................................... 29

March 2004

Company Use Only

Section 6 - 3

Specialty Cement Systems

6

Tables Table 6.1: Example Nitrogen Volumes ........................................................................ 15 Table 6.2: SCF per BBL N2 to 5,000 Pressure ............................................................. 30 Table 6.3: SCF per BBL N2 to 10,000 Pressure........................................................... 31

March 2004

Company Use Only

Section 6 - 4

Specialty Cement Systems

6

ExxonMobil Requirements Section Number

ExxonMobil Requirement

There are no ExxonMobil requirements in this Section.

March 2004

Company Use Only

Section 6 - 5

Specialty Cement Systems

6. 6.1.

6

SPECIALTY CEMENT SYSTEMS

REQUIRED REFERENCES

This Section lists Practices and Standards that are generically referenced and assumed part of this document. Unless otherwise specified herein, use the latest edition.

6.1.1.

API-American Petroleum Institute

API Spec 10A

Specification for Cements and Materials for Well Cementing

API RP 10B

Recommended Practice for Testing Well Cements

6.1.2.

ISO-International Standards Organization

ISO 10426-2

Cements and Materials for Well Cementing - Part 2: Testing of Well Cement

ISO 10426-3

Cements and Materials for Well Cementing - Part 3: Testing of Deepwater Well Cement Formulations

ISO 10426-4

Cements and Materials for Well Cementing - Part 4: Methods for Atmospheric Foamed Cement Slurry Preparation and Testing

6.2.

INTRODUCTION

Specialty cement systems are materials specific to a particular cement service company, or are not based on conventional Portland Cement. These systems are normally not considered for use in daily operations but can have specific applications under certain well conditions. The systems discussed in this Section range from the very inexpensive system of an acid soluble slurry made with cement and calcium carbonate, to specialty resin systems costing several thousand dollars per barrel. Service companies tend to market many of their specialty systems as having application in every well. Similar to the "one-size-fits-all" approach, care must be taken that the extra cost of the system is justified by the well requirements.

March 2004

Company Use Only

Section 6 - 6

Specialty Cement Systems

6.3.

6

FOAMED CEMENT

6.3.1.

Definition and Overview

Foamed cement is a stable mixture of a cement slurry and an introduced gas, typically nitrogen. The gas is held in place using surfactants and stabilizers that prevent the bubbles from coalescing prior to the cement setting. This will yield a set cement system with individual pore spaces filled with gas. This Section gives a basic understanding of foamed cement and the process. The process of foam cementing involves injecting a predetermined amount of nitrogen into a base cement slurry to make a stable foam. Several things determine the stability of the foam and can determine the success or failure of the foam cement treatment. The basic foam cementing treatment can be divided into three basic parts. These are the mixing and pumping of the cement, the addition of liquid foaming agent to the cement slurry, and the addition of nitrogen to the slurry. For the purpose of job management, there are three operations involved in the job. The cement operator only needs to worry about mixing a given slurry at a particular density and a particular rate. The liquid additive operator only needs to worry about how fast he is putting the surfactant into the slurry. Finally, the nitrogen operator is only concerned about his nitrogen rate at any particular point in time.

6.3.2.

Applications

Foamed cement systems are generally used for one of four applications. Foamed cement was originally designed as an ultra, lightweight cement system that allowed for the elimination of stage cementing, by providing high quality, lightweight cement systems for low fracture gradient wells. Densities below 11 lb/gal were common with this application. Due to the presence of the inert gas, foamed cements have a very low thermal conductivity, and have found use in geothermal and secondary recovery wells. The density of these slurries need not be low, but the concentration of gas must be high enough to provide sufficient insulation. Gas migration and shallow water flow prevention have become major applications for this technology. Prevention of shallow water flows in offshore applications has become a major market for foamed cement. A properly designed foamed cement system is gas tight, thus preventing gas migration in almost any application. The final area of application has been its use in high-stress environments to prevent stress failure of the cement sheath. Adding gas to a cement system will have a dramatic effect on the ultimate rock properties of the set cement. Foamed cement has been used for this application in high-rate gas wells like those found in Mobile Bay, as well as gas wells in the Western US, where fracturing treatments are done down the casing string. (Additional information is found in a 1996 Oil and Gas Journal paper by Benge, McDermott, Langlinais and Griffith.)

March 2004

Company Use Only

Section 6 - 7

Specialty Cement Systems

6

The Young's Modulus is reduced effectively through the addition of gas. The amount of reduction is essentially equivalent to the concentration of gas in the system. It is the reduction in the Young's Modulus that gives the improved mechanical properties.

6.3.3.

Other Advantages

Foamed cement offers a number of technical advantages over conventional cements. By varying only the gas concentration, the density of the foamed cement can easily be changed on location. Because the base cement system does not change, the thickening time of the cement remains unchanged. Altering the gas concentration, and thus the density of the cement system, is a simple matter of changing the gas rate on location. Like any specialty cement system, foamed cement can offer many advantages, but is not considered appropriate for every application. Operational complexity can be quite challenging in some applications, and excellent quality control on location is essential.

6.3.4.

Disadvantages

Foamed cement is operationally more complex than many other systems. It requires considerable pre-job planning and on-location coordination of the cement and nitrogen operations. While these are readily overcome, the complexity in design and application often requires specially-trained cementing crews be used for foamed cementing operations. When selecting foamed cement over ultra lightweight additives (see Section 2, 2.9.6), the cost of the nitrogen equipment and additional operational complexity must offset the savings in ultra lightweight additive costs. As cement volumes increase, economics tend to favor foam over the ultra lightweight additives.

6.3.5.

Job Design

There are two accepted design methods for foamed cement jobs. One method is to introduce a constant concentration of gas for the entire job. This is the easiest method, and results in a cement system in the annulus that will have a lower density at the upper portion of the well, graduating to a higher density at the bottom. The density variation is due to the compression of the gas in the annulus. To compensate for the increased pressure in the well, and yield a constant density in the annulus, a variable gas ratio is used. More gas is added to the later stages of cement to compensate for the compression due to hydrostatics; thus, the density of the cement in the annulus is constant. The variable gas method can be further broken down into two methods. The first method is to simply break the well into 500-ft increments or stages. The amount of gas is calculated for each stage and the nitrogen rate is then changed in steps throughout the job. This will give a variable cement density within the 500-ft increment, but if done properly, will give very acceptable results.

March 2004

Company Use Only

Section 6 - 8

Specialty Cement Systems

6

The other method of employing variable gas design is to utilize computer-controlled nitrogen addition. The computer is programmed with the required amount of nitrogen for varying points in the well and then the nitrogen is ramped throughout the job. The gradual increases in nitrogen rate result in a cement system that is essentially constant throughout the well.

6.3.6.

Design Considerations

1. Unless specifically designed to do so, do not circulate out a foamed cement slurry. If the job appears to be a total failure, do not attempt to circulate out the cement. The nitrogen will expand rapidly when it gets to the surface, in the same manner when dealing with a gas kick. However, there will be cement associated with the gas, and the cement will get into the choke and kill lines, gas buster and associated well control equipment. In the event of a total job failure, close the annular and displace all of the cement. Then, pump enough mud down the annulus to reach the loss zone. 2. Foam cement is an energized fluid. DO NOT allow personnel near the cementing lines during a foam cement job. 3. Pressure-test the lines with nitrogen. Not all of the lines can be pressure tested with nitrogen, but as much of the line as practical should be tested with nitrogen. 4. Confirm there is a check valve between the nitrogen unit and the cement unit. In the event the cement unit goes down during the job, the check valve will prevent any nitrogen from backing up in the system and into the cement unit. 5. Bypass for check valve - this will allow pressure from bumping the plug to be bled back through the cement unit. Without the bypass, pressure on the treating line cannot be bled off. 6. Check valve in N2 and cement lines - this will prevent nitrogen from going to the cement unit, or cement from going to the nitrogen unit in the event either unit goes down during the job. 7. Bleed point for N2 - after pressure testing and at the end of the job, there will be pressurized nitrogen in the line. A bleed point is needed for safe release of this gas.

6.3.7.

Base Cement Slurry

The composition of the base cement slurry is very important, and must contain a foaming agent and a stabilizer. The foaming agent and the stabilizer can be mixed together in appropriate concentrations, which results in easier handling. The stabilizer can vary from simply adding gel to the system to the use of latex and other polymers. Assuming the slurry composition has been correctly developed, the next key issue is the slurry density. Variations in slurry density are not acceptable in foamed cement operations. The cement must be mixed to a tolerance of ± 0.2 lb/gal. Mixing the cement outside this range may result in an unstable foam. The final variable effecting foam quality is the cement-mixing rate. Because the nitrogen is added on a per barrel basis, the rate of the cement is critical to the final foam

March 2004

Company Use Only

Section 6 - 9

Specialty Cement Systems

6

density. With the introduction of computer-controlled nitrogen units, this is less of a concern, however, very low cement-mixing rates cannot be tolerated. This is because at very low cement-mix rates, the resulting concentration of nitrogen may be too low for the nitrogen unit to accurately deliver. Conversely, very high rates later in the job can lead to problems with the upper rate limits on the nitrogen unit. An automatic density control (ADC) mixer should allow close density control with little effort. These mixers will require the cement delivery to the cement unit is carefully monitored, and the bulk system must be in good condition for these jobs. Lacking an ADC mixing system, the next best choice is to batch mix the slurry. Attempting to continuously mix a slurry in conventional cement mixing equipment does not give the quality control required on these jobs. At the very least, the first part of the slurry should be batch mixed. Job control during the initial stages of the job is the most critical. This is because nitrogen rates are at the lowest point during the job, and small variations in any of the job parameters will have a major effect on the final slurry properties.

6.3.8.

Liquid Additive Delivery

The surfactant cannot be added to the cement before it is mixed. It is injected into the low-pressure side of the triplex pump by means of a liquid additive metering pump. The concentration of surfactant is important for foam stability. If the surfactant pump goes out, the nitrogen should be stopped and the job continued by mixing either the base slurry or an alternate, lightweight slurry. An automated control-liquid-additive pump to inject the surfactant will improve the quality control of the surfactant addition. The additive pump should be keyed to the cement-mixing rate and designed to automatically compensate for changes in the cement pump rate.

6.3.9.

Nitrogen Injection

It is important the first part of the cement contain the correct amount of nitrogen. At the top of the well, the nitrogen content is very low in the cement, and small changes in the nitrogen rate can cause large changes in the final foam density. (Some example calculations showing the sensitivity of the slurry density to nitrogen content are found later in this Section.) For the density of the final foam cement to be constant, the cement at the bottom of the well must contain more nitrogen than the cement at the top of the well. This is simply due to the compression of the nitrogen with increased hydrostatic pressure. Because of the need for additional nitrogen at the bottom of the well, the nitrogen rate will slowly increase throughout a foam cement job. If possible, the nitrogen unit should be tied via automatic controller to the cement rate. This is often referred to as an automated process controlled system. These systems automatically control the various pieces of equipment based on the cement pump rate.

March 2004

Company Use Only

Section 6 - 10

Specialty Cement Systems

6

If the automated nitrogen unit fails, the nitrogen can be injected manually following a normal schedule for nitrogen injection. If the nitrogen unit fails during the job, simply continue mixing the base slurry or switch to the alternate, lightweight slurry and continue operations. Do not attempt to circulate foam cement out of the well.

6.3.10. Equipment Hookup Equipment hookup for a foam cement job involves two key elements. First is the injection of the foaming agent into the suction or low-pressure side of the triplex pump. This is accomplished by hooking up the line from the foaming agent pump directly to the cement at the pump suction. The foaming agent rate is controlled by a direct electronic feed of the cement rate from the cement unit. As the cement rate changes, the foaming agent pump automatically adjusts to maintain the correct amount of foaming agent in the system. If the computer control goes out, the foaming agent can be added at a constant rate. There should be a backup pump on the liquid-additive-injection system, which provides redundancy for this system. The second key element is the injection of the nitrogen. The nitrogen unit is hooked into the cement line via a 'T' or 'Y' lateral connection. Some companies then go through a foam generator. Depending on the hookup, the foam generator can be as simple as a valve, or as complicated as opposing chokes across a frac cross. For most foam cement jobs, a separate foam generator is not necessary. Tests have shown that mixing in the line is sufficient to generate a stable foam. The nitrogen rate is again keyed to a feedback rate from the cement unit. The nitrogen injection is automatically controlled through the feedback loop that matches the required nitrogen rate to the cement rate. If this system goes down, the nitrogen operator will need to follow a preprinted schedule of nitrogen injection. This will key the nitrogen injection rate to the cement rate and the volume of cement pumped. The nitrogen will be increased in stages as discussed in the calculation section. A generalized hookup for the foam cement job is: Computer Control System Pressure Transducer Check Valve

Foam Generator

Cement Unit

Check Valve

Wellhead

Nitrogen Pump Skid

Liquid Additive Skid

Nitrogen Tanks

March 2004

Company Use Only

Section 6 - 11

Specialty Cement Systems

6

The computer control system has sensors tied to each unit and takes the feedback from all of the pressure transducers. It is important there be a pressure transducer at the wellhead to record the entire job including displacement. Because of the check valve in the cement line, the cement unit cannot record pressures during the entire job.

6.3.11. Example of Foamed Cement Calculations Calculating the amount of nitrogen to add to a cement slurry and the final yield of the slurry can be confusing. This Section gives several examples for calculating nitrogen content, the resulting slurry yield, and other calculations for foam cementing. The calculations are performed at several pressures to show the effects of pressure and temperature on the density, yield, and nitrogen content of the slurry. For a majority of applications, the well is broken up into sections of 200 - 500 ft. The pressure and temperature at the midpoint of each section is determined, and then the amount of nitrogen required for that point in the well is calculated. Alternative methods involve calculating the required nitrogen for each predetermined volume of cement slurry. For example, the nitrogen is calculated for each 20 bbl of cement slurry. This effectively is the same calculation since the final location in the well must be known for each 20 bbl of slurry so the temperature and pressure can be determined. After the nitrogen requirements for each section of the well have been determined, the cement job is broken up into stages, with each stage representing a portion of the well. The nitrogen is then injected at the rate determined for each stage. Since the nitrogen volume has been calculated for the average pressure and temperature of each section, the cement at the top of the stage will weigh slightly less than the design. The cement at the bottom of the stage will be slightly heavier than the design. The smaller the stage, the smaller the variation in the density across the stage. For the purposes of these calculations, the weight of the nitrogen will be ignored. The absolute results will be off by the weight of the nitrogen, and the error will increase with increased pressure. Only at high pressures (generally over 2,500 psi) does the density of the nitrogen make a measurable difference. For this reason, these hand calculations will vary from those received from a computer program by a few SCF/bbl. To properly correct for the density of nitrogen, the temperature in degrees (°) absolute and the z factor for nitrogen must be used in the calculations. These calculations are presented only as a guide to foamed cementing, and to aid in understanding some of the complexities associated with the process. These are not designed to be used for foamed cement job design. For actual job designs, use a service company computer program that determines nitrogen content that accounts for the density of the gas.

March 2004

Company Use Only

Section 6 - 12

Specialty Cement Systems

6

6.3.12. Calculations 6.3.12.1. Calculation #1 (Surface Conditions) Calculate the amount of nitrogen required to make a 10 lb/gal slurry using a 14.5 lb/gal base slurry at surface conditions. If the yield of the 14.5 base slurry is 1.44 cu ft/sk, calculate the yield of the foam slurry. The base equation is:

Weight of the base slurry 1+ x

= Weight of the desired slurry

where x is the volume of nitrogen Note: the volume of nitrogen will be expressed in the same units as are used for the density of the slurries. If lb/gal is used for the weight, the nitrogen will be in gallons. If the weight per barrel of slurry is used, then the volume of nitrogen is in barrels. An example:

14.5 lb/gal = 10 lb/gal 1+ x

14.5 = 10 (1 + x) 14.5 = 10 + 10x 14.5 - 10 = 10x 4.5 = 10x .45 = x in gallons This means that to make a 10 lb/gal slurry, you must take one gallon of a 14.5 lb/gal slurry and add .45 gallons of nitrogen. The resulting volume of slurry will be 1.45 gallons. If working with units in barrels, you will need to add 0.45 barrels of nitrogen to a barrel of cement slurry to get a 10 lb/gal slurry. There are 5.61 SCF per barrel, so the amount of nitrogen required is 5.61 * .45 = 2.52 SCF of nitrogen. To get the yield of the foam slurry, multiply the yield of the base (1.44) with the increase in volume (1.45) to get the new yield of 2.088 cu ft/sk.

March 2004

Company Use Only

Section 6 - 13

Specialty Cement Systems

6

6.3.12.2. Calculation #2 (100 psi) Calculate the amount of nitrogen in SCF/bbl required to make a 10 lb/gal slurry using a 14.5-base slurry at 100 psi. The temperature at 100 psi is 100°F (38°C). Again, using the same equation, this time we will base the calculations on the amount of nitrogen that should be added to a barrel of base slurry.

1 bbl of 14.5 lb/gal cement weights 609 pounds 1 bbl of 10.0 lb/gal foam cement weighs 420 pounds 609 = 420 1+ x 609 - 420 (1 + x) 609 = 420 + 420x 609 - 420 = 420x 189 = 420x 189 =x 420 .45 = x in barrels That means for a barrel of slurry, it will take 0.45 bbl of nitrogen. As can be seen, since we are ignoring the density of the nitrogen, the required concentration (percentage) of nitrogen will not change. All that remains is to determine the amount of SCF of nitrogen are in 0.45 bbl of nitrogen at 100 psi and 100°F (38°C). Looking in a nitrogen table, it shows that at these conditions there are 35 SCF/bbl. (Nitrogen tables are found at the end of this Section.) The amount of nitrogen required for this part of the job will be:

35 * 0.45 = 15.75 SCF Therefore, if you take a barrel of 14.5 cement slurry and inject 15.75 SCF of nitrogen into it, it will weigh 10 ppg at 100 psi and 100°F (38°C). Notice too the yield of the slurry does not change. The base slurry has a yield of 1.44 cu ft/sk and the addition of the nitrogen has increased the yield by a factor of 1.45. In the previous two examples, the density of the slurry did not change, but because of the pressure, the amount of nitrogen required changed considerably. To make a 10 lb/gal slurry at surface, the nitrogen requirement was 2.52 SCF, but at 100 psi, it required 15.75 SCF.

March 2004

Company Use Only

Section 6 - 14

Specialty Cement Systems

6

6.3.12.3. Calculation #3 (1,000 psi) Calculate the amount of nitrogen required to make a 10 lb/gal slurry using a 14.5 base slurry at 1,000 psi and 100°F (38°C). Using the same equations as the above two examples, the amount of nitrogen required will be 0.45 bbl. From the nitrogen tables, at 1,000 psi and 100°F (38°C), nitrogen requires 353 SCF per barrel. Therefore the required amount of nitrogen per barrel of cement will be:

353 * 0.45 = 159 SCF / bbl of slurry Notice that with a tenfold increase of pressure, the nitrogen requirement increases by approximately the same amount. The other factor that will effect the amount of nitrogen is temperature. As can be seen from the nitrogen tables, as the temperature goes up, the amount of nitrogen in a barrel goes down simply due to the expansion of the nitrogen. In the above example, the amount of nitrogen at 1,000 psi and 100°F (38°C) was 159 SCF/bbl of slurry. The same calculation for 1,000 psi at 160°F (71°C) will yield:

316 * 0.45 = 142 SCF / bbl of slurry If the above calculations are made for several pressures and temperatures, the nitrogen requirements are:

Table 6.1: Example Nitrogen Volumes SCF Nitrogen / bbl Cement Slurry Pressure

100°°

140°°

180°°

200°°

0

2.52

-

-

-

100

15.75

14.85

13.95

13.5

1.000

159

148

137

133

2.000

311

288

267

258

3.000

449

415

386

373

4.000

567

527

491

475

A remaining question in foam cementing is "what happens if a foam cement that was designed for one depth actually winds up in a different part of the well"?

March 2004

Company Use Only

Section 6 - 15

Specialty Cement Systems

6

6.3.12.4. Density of Cement Example What is the density of a cement slurry that contains 159 SCF/bbl of nitrogen at 100 psi? The base slurry is 14.5 lb/gal. In this example, the slurry that was originally designed for 1,000 psi has been circulated in the well to where the pressure is only 100 psi. From the nitrogen tables, at 100 psi and 100°F (38°C), it takes 35 SCF of nitrogen to make a barrel. The amount of nitrogen is:

159 SCF/35 SCF/bbl = 4.52 barrels The resulting slurry density is : Original slurry = 14.5/gal * 42 = 609 pounds Total volume = 1 bbl (from the slurry) + 4.52 bbl (from the expanded nitrogen) Density = 609 lb/5.52 bbl = 609 lb/231.84 gal Density = 2.83 lb/gal If the same slurry is circulated to the surface, the total volume will occupy : 159 = 28.34 barrels 5.61 28.34 + 1 = Total volume of 29.34 barrels 609 gallons Density = 1232 Density = 0.49 lb/gal This calculation shows the reason foam cement should not be circulated out of the hole. One bbl of slurry that was designed to weigh 10.0 lb/gal at 1,000 ft will occupy 29 bbl of space at the surface and have a "density" of 0.49 lb/gal.

6.3.12.5. Density of Foam Cement (2,000 psi) Calculate the density of a foam cement that has 159 SCF/bbl added to a 14.5 lb/gal base at 2,000 psi and 100°F (38°C). This is the same calculation used to determine the density of the foam cement as it rounds the shoe of the casing. From the nitrogen tables, at 2,000 psi and 100°F (38°C), a barrel of nitrogen has 692 SCF. Therefore, the volume of nitrogen at this point is:

159 = 0.23 bbl 692 The total slurry volume is 1 (from the cement) + 0.23 (from the nitrogen) = 1.23 bbl

609 lbs 609 lbs = 1.23 bbl 51.66 gal Density = 11.79 lb / gal

March 2004

Company Use Only

Section 6 - 16

Specialty Cement Systems

6

Therefore, the cement slurry will weigh approximately 11.8 lb/gal at the shoe, and when it is in place it will weigh 10.0 lb/gal.

6.3.13. 3,500 Ft TD Well Example A well is 3,500 ft TD. The casing is 9-5/8 inches to be cemented in a 14-inch open hole. No excess is to be run. The job calls for using a 10 lb/gal foam cement from 1,500 3,000 ft, followed by 500 ft of tail slurry. The base slurry is a 14.5 lb/gal slurry with a yield of 1.44 cu ft/sk and will be foamed to 10.0 lb/gal. The mud weight is 9.5 lb/gal; the temperature gradient is 1.1°F/100 ft. The spacer used for the job will be a 9.5 lb/gal spacer. The surface temperature is 80°F (27°C). Calculate the required nitrogen injection rates, the amount of nitrogen, and the amount of cement required for the foam portion of the cement job. The first step is to divide the foam section into stages. The total amount of foam cement is 1,500 ft. If the well is broken into 500 ft stages, there will be three stages: Stage

Top

Bottom

Average

1

1500

2000

1750

2

2000

2500

2250

3

2500

3000

2750

Hydrostatic pressure and temperature at midpoint: Stage

Cement Rate (bpm)

Nitrogen Rate

1

871

99

2

1131

105

3

1391

110

From the nitrogen tables, the SCF of nitrogen per barrel for each stage is: Stage

March 2004

SCF Nitrogen Per Barrel

1

319

(300 psi and 100°F (38°C))

1

388

(400 psi and 100°F (38°C))

1

483

(1,400 psi, average between 100° and 120°F (38° and 49°C))

Company Use Only

Section 6 - 17

Specialty Cement Systems

6

From earlier calculations, we know that 0.45 bbl of nitrogen must be added to each barrel of cement to produce a 10 lb/gal slurry: Stage

SCF Nitrogen Per Barrel of Cement

1

144

2

175

3

217

From the above information, a table of nitrogen rates can be generated: Stage

1

2

3

Cement Rate (bpm)

Nitrogen Rate

1

144

2

288

3

432

4

576

5

720

1

175

2

350

3

525

4

700

5

875

1

217

2

434

3

651

4

868

5

1085

The annular volume for a 9-5/8 inch casing in a 14-inch open hole is 0.1004 bbl/ft, thus for each 500 ft interval we need 50 bbl of foam slurry. Since each barrel of cement pumped will occupy 1.45 bbl of space after the nitrogen is added, the volume of cement required for each stage will be:

50 = 34.6 bbl 1.45

March 2004

Company Use Only

Section 6 - 18

Specialty Cement Systems

6

Volume of nitrogen per stage is calculated by taking the volume of cement times the SCF per barrel of nitrogen for each stage: e

Stage

Total Nitrogen Per Stage

1

4,982

2

6,055

3

7,508

Total

18,545

The yield of the cement is 1.44 cu ft/sk, so the amount of cement per stage will be 135 sacks of cement. The total amount of cement will be 3 * 135 = 405 sacks for the foamed cement portion only. (The cement for the tail slurry has not been included.) Therefore, for the foam cement portion of the job, it will require: 405 Sacks of cement 18,545 SCF of nitrogen

6.3.14. Calculations and Service Company Computer Programs In the above examples, the weight of the nitrogen has been ignored. When the weight of the nitrogen is included in the calculations, the amount of gas will increase to compensate for that weight. This means when the hand calculations are compared to those from service company computer programs, the hand calculations should yield a lower amount of nitrogen for any given stage. The relative error will increase with increasing pressure. Some of the service company programs will also calculate the friction pressure while the foam is being placed. The friction pressure will act the same as back pressure on the well, and if included in the calculations, will result in more nitrogen being needed for any given point in the well. While the physics are correct that the friction pressure does indeed tend to compress the foam, the problem with using this pressure in the calculations is that now the foam density in the well is also rate dependent. This is essentially the same as using ECD to control the well while drilling. While this can certainly be done, if the pumps are shut down, or the rate is not what was predicted, there will be a problem with backside control. It is recommended only the final static conditions be considered when determining the nitrogen content of foamed cements.

March 2004

Company Use Only

Section 6 - 19

Specialty Cement Systems

6.4.

6

CEMCRETE* CEMENT SYSTEMS

6.4.1.

General

The CemCRETE* cement systems are heavily marketed specialty systems from Schlumberger. These systems are marketed as having superior compressive strength, improved mechanical properties, and lower rheologies. While many of the claims may be valid, these systems can be considerably more expensive than the alternatives, and must be justified on a cost per cubic foot basis. It is very rare that paying more money for additional compressive strength is justified, and the high added cost of these systems requires very careful evaluation of the well needs. As with any cement additive, the use of the system should be justified through well requirements, not marketing by the service company. With the CemCRETE* systems, the engineer must realize there are more cement additives than cement in the "CRETE*" systems. *Service mark of Schlumberger

6.4.2.

What are the "CRETE" Cements?

The "CRETE*" slurries are marketed cement blends available from Schlumberger. The base of the blends is normal Portland Cement used on all wells. Schlumberger adds two essentially inert materials to "optimize the particle size distribution" of the system. The system must be dry blended and blown back and forth at least five (5) times to assure blending. This will give a basic "CRETE*" blend. If no additional materials are blended, the system is called CemCRETE*. Adding hollow ceramic spheres, marketed by Schlumberger as LiteFill*, will reduce the density of the cement, and make LiteCRETE*. Adding weighting agents to the base system makes DensCRETE*. Designing the system for deepwater will result in a DeepCRETE* design. Leaving out the cement, and just using the micro-fine particles, makes SqueezeCRETE*. Much like adding a minimum concentration of GasBLOK* to any cement will make a GasBLOK* slurry, adding the special particle-sized materials to a cement will make a CRETE* slurry. There is quite a bit of technology in the development of the CRETE* line of slurries, and the systems can fill niche applications in normal operations. These slurries should not be considered as daily use systems due to their much higher cost.

6.4.3.

Marketing Points

6.4.3.1.

Higher Strength Development

Most of the CRETE* cements are marketed as having higher strength development or as having the properties of a slurry that is much denser than the one being used. While strength development is important, the absolute value of the strength is unimportant.

March 2004

Company Use Only

Section 6 - 20

Specialty Cement Systems

6

Tests have shown the compressive strength measurement to be one of the least reproducible tests that is done on cement. Even with neat cement, and very controlled conditions, strength values obtained typically vary by as much as 50%. LiteCRETE* is marketed heavily as giving superior strength at very lightweights. The system will live up to that claim, and it is possible to get a 12 lb/gal system that has 3,000 psi compressive strength. Comparable conventionally extended systems, those containing bentonite, pozzolans, etc., will have strengths in the 500 - 750 psi range at that density. The key is to determine why there would be any need for a very highstrength lightweight cement. There is rarely any need to pay more for strength development. One case where strength is important is kick-off plugs, but in primary cementing, the interest is in when the cement sets, and when it gains some minimum strength, like 500 psi. There is no need to have a lightweight filler cement that has high strength. One argument to the strength question would be the ability to perforate and perform a fracturing treatment through the lightweight cement. Work has clearly shown that the cement does not require high strengths to keep the fracture from extending through the cement sheath. The compressive strength of the cement need only be greater than the tensile strength of the rock, which is typically less than 100 psi. (Tensile strength of cement can be estimated conservatively as 10% of the compressive strength.) There is a point where strength development can have an economic impact and that is not how much strength, but when the slurry begins to develop strength. In high cost environments, if the rig is waiting on the set of the cement, then slurries that gain strength faster can give an advantage. There has been very little comparison of LiteCRETE*, and a cement slurry of the same density that does not contain the CRETE* additive package, yet still contains the lightweight hollow spheres. This would be the equivalent of a Schlumberger system with just the LiteFill* as the lightweight additive. If very lightweight cement is needed, consider using only the hollow spheres system as an alternate. The strength development will be less, but well within most well requirements. Compare cost per cubic foot of the two systems. Foamed cement may also be considered as an alternative for very lightweight slurries. Foam has many technical advantages, but like any high-tech system, carries its own set of operational challenges.

6.4.3.2.

Porosity

Schlumberger has coined a term "porosity" to define the amount of "open" space in a cement slurry. This is NOT the same as the porosity commonly defined to describe rocks, or set cement. The porosity calculation made is only applicable to the slurry when in a liquid state. This is only a calculation and no physical measurements are made to determine slurry porosity. The theory is by putting the smaller particles in the cement, the porosity of the slurry is less, and fewer additives may be needed. Further, it will push water out of the pore spaces, making the rheology less.

March 2004

Company Use Only

Section 6 - 21

Specialty Cement Systems

6

The rheologies of the LiteCRETE* slurries may or may not be less than comparable hollow sphere slurries. The viscosity of these slurries must be sufficiently high to prevent particle segregation and the floating out of the hollow spheres. Because of this requirement, the slurry will probably have a very similar rheology. DensCRETE* does appear to benefit from lower rheologies at the higher densities. Care must be taken to select the base cement carefully as this will have a major effect on the final slurry rheology. Work in South Texas has shown the DensCRETE* slurries used in the area to be easily mixed with good rheological properties, while work in the Gulf of Mexico yielded slurries that were quite difficult to mix. The expertise of the laboratory personnel in the slurry design has a direct effect on the efficiency of this system.

6.4.4.

SqueezeCRETE*

Using only the very fine particles and leaving out the Portland Cement will yield SqueezeCRETE*, which is being marketed as a material that will allow slurry placement into extremely small openings. Because of the very small particle size, standard fluid loss cannot be performed, as the material will pass through the API fluid loss screen. SqueezeCRETE* fluid loss tests are run against filter paper and cannot be compared to conventional cement fluid loss tests. Cement fluid loss against paper will always be considerably lower than API tests. For example, a cement with 1,200 mL API fluid loss will have approximately 25 mL of fluid loss when tested against filter paper. Another characteristic identified in the use of SqueezeCRETE* has been poor strength development. The material does not gain strength quickly and has created some additional rig problems. Efforts have been made to tail in a SqueezeCRETE* job with more conventional cement to gain a squeeze pressure and to obtain some type of strength development.

6.4.5.

Cost Comparisons

Care must be taken to evaluate the cost per cubic foot of the system being considered, and to make appropriate comparisons with current systems. The CRETE* systems are sold as being less expensive than comparable systems. This is particularly true when GasBLOK*, Schlumberger's anti-gas migration additive, is part of the design. Schlumberger bases the concentration of GasBLOK* on a chart that is related to temperature and the porosity calculation, and is normally sold in the 2.5 - 3.5 gallons per sack range. With the CRETE* systems, the relative concentration of GasBLOK* is reduced, and because of the high cost of the GasBLOK*, the added cost of the CRETE* is negated. ExxonMobil does not recommend the high concentrations of GasBLOK* typically recommended by Schlumberger. GasBLOK* concentrations should not exceed 11.25 gals per sack except in extreme cases. Using the lower concentration as a baseline for cost comparison, the CRETE* cost advantage may quickly disappear.

March 2004

Company Use Only

Section 6 - 22

Specialty Cement Systems

6.4.6.

6

Other Related Designs

Additional slurries are being marketed that utilize the "optimized particle size distribution" concept with additional additives to further change the properties. These include DuraSTONE* and FlexSTONE*. These systems supposedly have more durability, lower Young's Modulus or other properties that reportedly help the system seal the wellbore for the life of the well. There are no identified cement properties directly related to long-term sealing ability of the cement, and current claims are made based on mathematical simulators only.

6.4.7.

Summary

The CRETE* slurries can have application in ExxonMobil's operations. These slurries are more expensive, and require much higher levels of quality control while blending. As with any cement additive, the use of the system should be justified through well requirements, not marketing by the service company. If there is justifiable need, the systems fill a niche and have application. The engineer must be aware that on a per pound basis, the CRETE slurries have more additives than cement in the system. Unless specifically required for well conditions, do not pay more money simply for strength development. High compressive strengths are rarely required, especially with lightweight slurries.

6.5.

ACID SOLUBLE SYSTEMS

Many times, there is a need for a cement to be acid soluble. While cement itself is readily soluble in acid, there is a surface reaction between Portland Cement and hydrochloric acid (HCl) that forms a gel structure and does not allow the live acid to continue to react with the cement. Since the live acid can no longer come in contact with the un-reacted cement, the reaction stops. This is why the cement in wells does not dissolve out during acid treatments. To make a cement acid soluble requires either changing the base cement system to a non-Portland cement, or increasing the reaction sites on the cement by improving the live acid penetration. Cements that change the base chemistry to a non-Portland cement include systems that have a very high magnesium content (like Magne Plus* available through BJ Services). These systems work well, but cost more than conventional cement. * Mark of BJ Services

A good alternative to acid soluble cement is to mix 100-200 % calcium carbonate in with conventional cement. This will reduce the density of the slurry somewhat, but the addition of the calcium carbonate will make the total system acid soluble. The mixture consists of one sack of Portland Cement and one to two sacks of calcium carbonate. Caution must be taken to properly choose the size grade of the calcium carbonate. Using only the coarse material may not give sufficient acid solubility, and using too fine a material can lead to mixing problems. To address this issue, the service company lab

March 2004

Company Use Only

Section 6 - 23

Specialty Cement Systems

6

should use mixtures of fine, medium and coarse calcium carbonate to optimize the rheology of the slurry. The effect of adding these large amounts of calcium carbonate will be to reduce the compressive strength of the cement. Essentially, the calcium carbonate is non-reactive, and acts as a diluent. Because the material is added on a 1:1 ratio, strengths can be expected to be reduced by at least 50%. Higher concentrations of calcium carbonate will further reduce the strength, but as previously noted, that is rarely a problem. The relative solubility of these systems in HCl will be on the order of 90 - 94%, depending on the purity of the calcium carbonate and other additives. The reaction rate will be less than with pure calcium carbonate, so soak times may need to be extended. Performing pre-testing in the lab is recommended for the specific application.

6.6.

CO2 RESISTANT CEMENTS

CO2 will react with Portland Cement and convert the cement into a calcium carbonate material. The strength of the system will reduce, but will still retain sufficient strength and low permeability to provide isolation. The problem in most CO2 applications is the well eventually is treated with an acid, and this will dissolve the cement from behind the pipe. This is common in CO2 flood areas and leads to severe problems with loss of CO2 into unwanted zones. To prevent carbonate conversion of the cement, the solution is to use a system that does not contain Portland Cement. Another method that has been applied is to attempt to lower the permeability of the cement to as low a value as possible, thereby delaying the eventual conversion of the Portland Cement. Depending on the well life and economics of the field, the later solution will be less expensive, but will not provide a long-term (>10 year) solution. Because of the chemical reactions, Portland Cement in a CO2 environment will eventually convert and become acid soluble, regardless of the permeability. ThermaLock™ cement is available from Halliburton as a CO2 resistant cement. The cement is made up of high alumina cement that does not contain any Portland Cement. The material can be difficult to use, and care must be taken when blending to not have any Portland Cement contaminate the system. Portland Cement contamination will accelerate the ThermaLockä to the point it will "flash set." The high alumina cement is essentially the same material used to make the bricks that line the fireplace in most homes. Conventional Portland Cement cannot withstand the high temperatures and harsh chemical environment of a fireplace, and the high alumina cement has been found resistant to those conditions. The ThermaLockä slurries are normally mixed at densities between 14 and 15 lb/gal. Higher densities are available, but will require addition of weighting agents. In areas where ThermaLockä is not available, an alternative would be the use of a very low permeability cement. Schlumberger's CRETE* line of slurries would fit in this category. The CRETE* systems are Portland Cement based, but have very low-cement content and very low permeability. The Portland Cement content in these systems is typically 30% by volume. The system will react with the CO2, but at a much lower rate

March 2004

Company Use Only

Section 6 - 24

Specialty Cement Systems

6

due to the low permeability, and low concentration of Portland Cement. The lowcement content will reduce the effects of the reaction, but it will ultimately react to convert the cement in the system to carbonate. To further enhance gas resistance, latex can be added to the CRETE* system. This can help reduce attack by the CO2 by further reducing system porosity and permeability. Regardless of the cement system used, it is important the Production Company realize if a Portland Cement has been used in a CO2 application, the cement behind the pipe will ultimately become acid soluble. If the well is repeatedly treated with acid, there is a potential for loss of annular seal due to the dissolution of the Portland Cement.

6.6.1.

Cement Reactions with CO2

The basic cement reactions of cement with CO2 are outlined below. (No attempt has been made to chemically balance the equations.) The abbreviations used in the formulas are: C3S

-

Tricalcium Silicate - A basic component of cement

C2S

-

Dicalcium Silicate - A basic component of cement

CSH

-

Calcium Silica Hydrate - A reaction product forming part of a set cement matrix

H2O

-

Water

CO2

-

Carbon Dioxide

Ca(OH)2

-

Calcium Carbonate

Ca(HCO3)2

-

Calcium Bicarbonate

CO3-2

-

Carbonate ion

H+

-

Hydrogen Ion

6.6.1.1.

Cement Hydration

C3S + H2O → CSH + Ca(OH)2

β - C2S + H2O → CSH + Ca(OH)2

6.6.1.2.

Carbon Dioxide Reactions

CO2 + H2O → H2CO3 → H+ + HCO3HCO3- → CO3-2 + H+

March 2004

Company Use Only

Section 6 - 25

Specialty Cement Systems

6.6.1.3.

6

Reaction Products

Ca(OH)2 + H+ + CO3-2 → CaCO3 + H2O CO2 + H2O + CaCO3 → Ca(HCO3)2 + H2O Ca(HCO3)2 + Ca(OH)2 → CaCO3 + H2O After a time, all of the calcium hydroxide in the cement system will be converted to calcium carbonate in the presence of carbon dioxide. Note this also requires the presence of water in the system. In a completely dry environment, no reaction will take place directly with the cement. All cement contains some amount of unbound water, and the presence of this water will allow some minor conversion. It is the presence of the CO2 over the long term that will ultimately convert the cement to a soluble system.

6.7.

HYDROGEN SULFIDE (H2S) RESISTANCE

Coupled with CO2 resistance, wells often contain H2S or will have H2S as part of a gas injection process. Studies have shown H2S does not react with Portland Cement; therefore, it is not necessary to pump any specialty type of cement system. However, if the gas injection stream contains CO2, then protection from the CO2 is required. One exception is systems containing salt. High-salt systems tend to be more susceptible to H2S attack, and should be avoided if H2S is expected.

6.8.

HIGH TEMPERATURE CEMENTS

Portland Cement with no additives will maintain stability up to 230°F (110°C). Above this temperature, the cement structure will begin to change with time, and the crystals in the cement will begin to degrade and/or react to form new species. This results in higher permeability and lower strength. The process is called strength retrogression. Strength retrogression does not necessarily cause many operational problems due simply to the loss of compressive strength. Over time, the cement strength may regress from 3,000 psi to as low as 500 psi. Even this low strength is sufficient to maintain casing support. The problem begins to arise due to the increase in the permeability of the cement. Permeability can increase from 0.001 mD (in a standard cement) up to 0.5 mD (in a fully strength-regressed slurry). This can lead to problems with zonal isolation, fluid movement and other well problems. Cement systems can experience this temperature at any point in time, not just when being placed in the well. High production rate wells can have wellhead temperatures exceeding 300°F (149°C), and because of the high heat at the wellhead, all of the cement must be stabilized not just the cement in the lower parts of the well.

March 2004

Company Use Only

Section 6 - 26

Specialty Cement Systems

6.8.1.

6

Preventing Strength Retrogression

Silica flour should be added to cements that will be exposed to temperatures exceeding 230°F (110°C). This temperature may be due to BHST of the well, later steam injection, or high producing temperatures. Adding 30-40% by weight of silica to a Portland Cement will prevent strength retrogression. Normally, 35% silica is added to the cement, and usually in the form of silica flour. Fine silica sand may also be used, but because of the larger surface area, will not be as effective, and will have a slower reaction rate. The addition of the silica will stabilize Portland Cement systems up to approximately 600ºF (316ºC). Above this point, standard Portland Cement can no longer be stabilized, and the system will fail. These very high temperatures are normally only seen in very high-pressure steam injection wells, or with continuing fire floods. Note the temperature must be above 600ºF (316ºC) for some time period (in excess of seven days) to do significant damage to a standard stabilized cement.

6.8.2.

Alternatives

For wells requiring very high temperature cements, using non-Portland cements is the simplest solution. These cements are high alumina cements, commonly used to manufacture the bricks used in fireplaces. These cements are also applicable to CO2 resistance (see Section 6.6). Care must be exercised when using these specialty cements in the field. Contamination of these cements with Portland Cement will result in extremely short pumping times, and can result in a job failure. Care must be taken by the service company to assure all of their tanks and storage systems are completely cleaned of Portland Cement before introducing these materials to the system.

6.9.

PERMAFROST CEMENT SYSTEMS

When cementing sections of casing traversing permafrost formations, special consideration must be given to the cold temperatures, controlling the heat of hydration of the slurry to prevent formation thaw, and temperature cycling of the cement during production. Permafrost cements address the challenges by incorporating large concentrations of gypsum. Permafrost cement slurries will contain from 40 - 60% gypsum by weight of cement. The high concentration of gypsum serves several purposes: Early Strength Development - Below 45°F (7°C), cement does not hydrate. The gypsum will set below this temperature and is responsible for the early strength of the slurry. Low Heat of Hydration - Unlike cement setting, gypsum does not have a large exothermic reaction upon setting. This prevents melting of the permafrost around the casing.

March 2004

Company Use Only

Section 6 - 27

Specialty Cement Systems

6

Freeze/Thaw Stability - During the production life of the well, the cement will be exposed to freezing temperatures alternately with the warm wellbore temperatures. The cement must be capable of surviving several freeze-thaw cycles. Standard Portland Cement is subject to failure from internal ice crystalline growth. This is eliminated with the use of the high gypsum concentration. Some deepwater designs also utilize high gypsum cement systems, because of the low sea floor temperatures. This allows for more rapid strength development, but can lead to problems of retardation of the cement. In Permafrost conditions, the slurry mix temperature is usually low because of surface temperature conditions. In deepwater applications, surface conditions can be quite warm, requiring over-retardation of the gypsum to allow placement. Modifying the concentration of gypsum in these systems has been used to address this problem.

6.10. RESINS AND PLASTICS The most expensive, specialty use "cement" slurries are the resins and plastics. These systems are used in wells to combat acid corrosion and extreme chemical environments. While these systems are marketed as synthetic cement, or plastic cement, there is no cement in the system. They are made entirely of organic resins or plastics. Any solids in the systems are from fillers such as silica flour or sand.

6.10.1. Applications The plastic and resin systems have application in wells used for the disposal of live acid, or caustic. These systems have found primary use in disposal wells used by chemical plants and some refineries due to their resistance to many acids and some organic compounds. Some testing has indicated long-term cracking or embrittlement of these systems, which could lead to loss of seal. The systems are solids free, with a base density of approximately 9.5 lb/gal. The density can be increased by incorporating silica flour, sand, or barite. The solids free systems have been used to attempt to squeeze casing collar leaks and temporarily seal wellhead valves.

6.10.2. Limitations The plastics and resin systems have limits to their use in oilfield operations: •

Placement Temperature Limits - The systems cannot be placed at high temperatures. The reaction of the resins and plastics is accelerated by temperature and will set quickly at higher temperatures. This limits the application to wells with bottomhole circulating temperatures under 150°F (66°C).

•

Application Temperature - Even if the systems can be placed at low temperatures, the set materials will begin to soften at temperatures exceeding 250°F (120°C). This softening can lead to extrusion of the resin into the

March 2004

Company Use Only

Section 6 - 28

Specialty Cement Systems

6

perforation or other opening. If the production is flowing past the resin, the material can be stripped off the walls.

6.10.3. Job Considerations •

Environmental - These systems are organic based, and will require disposal of excess material and special clean up of the pumping equipment. Often the cleaning and disposal charge for using these systems exceeds the job costs.

•

Health and Safety - The catalysts and base resins are often hazardous to personnel, requiring special personal protective equipment. This must be considered as part of the job plan, and all personnel involved in the operation must be aware of the potential health risks.

•

Cost - These systems can cost in excess of $3,000 per barrel. The volume used for the job must be preordered, and is not refundable. Job volume control is essential. Any excess material must not only be paid for in advance, but will require proper disposal if not used in the well.

March 2004

Company Use Only

Section 6 - 29

Specialty Cement Systems

6

Pressure

Table 6.2: SCF per BBL N2 to 5,000 Pressure 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 3700 3800 3900 4000 4100 4200 4300 4400 4500 4600 4700 4800 4900 5000

March 2004

40 39 79 119 158 198 240 280 320 360 400 440 480 519 558 597 636 674 712 749 787 823 860 895 930 965 999 1033 1066 1098 1130 1161 1192 1222 1251 1279 1307 1334 1361 1386 1411 1457 1482 1506 1530 1554 1577 1600 1622 1645 1667

60 38 76 114 152 190 230 268 307 345 383 421 459 498 534 571 608 644 681 717 752 787 822 856 890 923 956 989 1021 1052 1083 1113 1143 1172 1200 1228 1255 1282 1308 1334 1359 1395 1419 1442 1466 1489 1512 1534 1556 1578 1600

80 36 73 110 147 183 221 258 294 331 367 404 440 476 511 547 582 617 652 686 720 754 787 820 853 885 916 948 978 1009 1038 1068 1096 1125 1153 1180 1207 1233 1258 1284 1308 1337 1361 1384 1407 1429 1452 1474 1495 1517 1538

100 35 70 106 141 177 212 248 283 318 353 388 422 457 491 525 559 592 625 658 691 723 755 787 818 849 879 909 939 968 997 1025 1053 1081 1108 1134 1160 1186 1211 1236 1260 1284 1307 1330 1352 1374 1396 1417 1439 1460 1481

120 34 68 102 136 171 204 238 272 306 339 373 406 439 472 504 537 569 601 632 663 694 725 755 785 815 845 873 902 930 958 986 1013 1039 1065 1091 1117 1142 1166 1190 1214 1236 1258 1280 1302 1324 1345 1366 1387 1408 1428

Temperature 140 160 33 32 66 64 99 96 132 128 165 160 197 190 230 222 262 253 295 284 327 315 359 346 391 377 423 407 454 438 485 468 516 498 547 527 578 557 608 586 638 615 668 643 697 672 727 700 756 728 784 755 812 782 840 809 868 836 895 862 922 888 948 914 975 939 1000 964 1026 989 1051 1013 1075 1037 1100 1060 1124 1084 1147 1106 1170 1129 1191 1149 1213 1171 1234 1192 1256 1213 1277 1234 1298 1254 1319 1274 1339 1294 1359 1314 1379 1334

Company Use Only

180 31 62 93 128 155 184 214 245 275 305 334 364 393 423 452 480 509 537 565 593 621 648 675 702 728 755 781 806 832 857 882 906 930 954 978 1001 1024 1046 1068 1090 1111 1132 1153 1173 1193 1213 1233 1253 1272 1292

200 30 60 90 120 150 178 208 237 266 295 323 352 380 408 436 464 492 519 546 573 600 626 652 678 704 729 754 779 803 828 852 875 899 922 945 967 989 1011 1033 1054 1075 1096 1116 1136 1156 1176 1195 1214 1233 1252

220 29 58 87 116 146 173 201 229 257 285 313 341 368 395 422 449 476 502 528 554 580 606 631 656 681 705 729 753 777 801 824 847 869 892 914 936 957 979 1000 1020 1042 1062 1082 1101 1121 1140 1159 1178 1197 1215

240 28 56 85 113 141 168 195 222 250 277 304 330 357 383 409 435 461 487 512 537 562 587 611 635 659 683 707 730 753 776 798 820 842 864 886 907 928 949 969 989 1011 1031 1050 1069 1088 1107 1126 1144 1163 1181

260 27 55 82 110 137 163 189 216 242 269 295 321 346 372 397 422 447 472 497 521 545 569 593 616 640 663 686 708 731 753 775 796 818 839 860 880 901 921 941 961 982 1001 1020 1039 1058 1076 1095 1113 1131 1149

280 26 53 80 107 134 158 184 210 236 261 287 312 337 364 386 411 435 459 483 506 530 553 576 599 622 644 666 688 710 732 753 774 795 816 836 856 876 896 915 935 955 974 993 1011 1029 1048 1066 1083 1101 1119

300 26 52 78 104 130 154 179 204 229 254 279 303 328 352 376 400 423 447 470 493 516 538 561 583 605 627 649 670 691 713 733 754 774 795 815 834 854 873 892 911 930 949 967 985 1003 1021 1038 1056 1073 1090

Section 6 - 30

Specialty Cement Systems

6

Pressure

Table 6.3: SCF per BBL N2 to 10,000 Pressure 5100 5200 5300 5400 5500 5600 5700 5800 5900 6000 6100 6200 6300 6400 6500 6600 6700 6800 6900 7000 7100 7200 7300 7400 7500 7600 7700 7800 7900 8000 8100 8200 8300 8400 8500 8600 8700 8800 8900 9000 9100 9200 9300 9400 9500 9600 9700 9800 9900 10000

March 2004

40 1688 1710 1731 1752 1772 1792 1812 1832 1851 1871 1890 1908 1927 1945 1963 1981 1999 2016 2033 2050 2067 2083 2100 2116 2132 2147 2163 2178 2194 2209 2228 2246 2259 2272 2285 2298 2311 2323 2336 2348 2360 2372 2384 2396 2407 2419 2430 2441 2452 2463

60 1621 1642 1663 1683 1703 1723 1743 1762 1782 1800 1819 1838 1856 1874 1892 1909 1927 1944 1961 1978 1995 2011 2027 2043 2059 2075 2090 2106 2121 2136 2156 2170 2183 2196 2209 2222 2235 2248 2260 2272 2284 2296 2308 2320 2332 2343 2355 2366 2377 2388

80 1559 1579 1600 1620 1640 1659 1679 1698 1717 1736 1754 1772 1790 1808 1826 1843 1861 1878 1894 1911 1928 1944 1960 1976 1992 2007 2023 2038 2053 2068 2086 2100 2113 2126 2139 2152 2165 2177 2190 2202 2214 2226 2238 2250 2262 2273 2284 2296 2307 2318

100 1501 1522 1542 1561 1581 1600 1619 1638 1657 1675 1694 1712 1730 1747 1765 1782 1799 1816 1833 1849 1865 1882 1898 1913 1929 1944 1960 1975 1990 2005 2021 2035 2048 2061 2074 2087 2099 2112 2124 2137 2149 2161 2173 2185 2196 2208 2219 2230 2242 2253

120 1448 1468 1488 1507 1527 1546 1564 1583 1601 1620 1638 1655 1673 1690 1708 1725 1742 1758 1775 1791 1807 1823 1839 1855 1870 1886 1901 1916 1931 1946 1960 1974 1987 2000 2013 2026 2039 2051 2064 2076 2088 2100 2112 2124 2135 2147 2159 2170 2181 2192

Temperature 140 160 1399 1353 1419 1373 1438 1392 1457 1410 1476 1429 1495 1447 1513 1466 1532 1484 1550 1501 1568 1519 1585 1537 1603 1554 1620 1571 1638 1588 1655 1605 1671 1621 1688 1638 1705 1654 1721 1670 1737 1686 1753 1702 1769 1718 1785 1733 1800 1749 1816 1764 1831 1779 1846 1794 1861 1809 1876 1824 1890 1838 1904 1851 1917 1864 1930 1877 1943 1890 1956 1903 1969 1916 1982 1928 1994 1941 2007 1953 2019 1965 2031 1978 2043 1990 2055 2001 2067 2013 2078 2025 2090 2036 2101 2048 2113 2059 2124 2070 2135 2081

Company Use Only

180 1311 1330 1348 1367 1385 1403 1421 1439 1456 1474 1491 1508 1525 1542 1558 1575 1591 1607 1623 1639 1654 1670 1685 1701 1716 1731 1745 1760 1775 1789 1801 1815 1828 1840 1853 1866 1878 1891 1903 1915 1927 1939 1951 1963 1974 1986 1997 2009 2020 2031

200 1271 1289 1308 1326 1344 1362 1379 1397 1414 1431 1448 1464 1482 1498 1515 1531 1547 1563 1578 1594 1609 1625 1640 1655 1670 1685 1699 1714 1728 1743 1755 1768 1781 1794 1806 1819 1831 1844 1856 1868 1880 1892 1904 1915 1927 1938 1950 1960 1972 1983

220 1234 1252 1270 1288 1305 1323 1340 1357 1374 1391 1408 1425 1441 1457 1473 1489 1505 1521 1536 1552 1567 1582 1597 1612 1627 1641 1656 1670 1685 1699 1711 1724 1737 1749 1762 1775 1787 1799 1811 1823 1837 1847 1859 1871 1882 1894 1905 1916 1927 1938

240 1199 1217 1235 1252 1269 1287 1304 1321 1337 1354 1370 1387 1403 1419 1435 1450 1466 1481 1497 1512 1527 1542 1557 1571 1586 1600 1615 1629 1643 1657 1670 1682 1695 1708 1720 1733 1745 1757 1769 1781 1793 1805 1817 1828 1840 1851 1862 1873 1885 1896

260 1166 1184 1201 1218 1236 1252 1269 1286 1302 1319 1335 1351 1367 1382 1398 1413 1429 1444 1459 1474 1489 1504 1518 1533 1547 1561 1576 1590 1603 1617 1630 1643 1656 1668 1681 1693 1705 1718 1730 1741 1753 1765 1776 1788 1799 1811 1822 1833 1844 1855

280 1136 1153 1170 1187 1204 1220 1237 1253 1269 1285 1301 1317 1333 1348 1363 1379 1394 1409 1424 1438 1453 1468 1482 1496 1510 1524 1538 1552 1566 1580 1594 1606 1619 1631 1643 1656 1668 1680 1692 1704 1715 1727 1738 1750 1760 1772 1783 1795 1805 1816

300 1107 1124 1141 1157 1174 1190 1206 1222 1238 1254 1269 1285 1300 1316 1331 1346 1361 1375 1390 1404 1419 1433 1447 1461 1475 1489 1503 1516 1530 1543 1559 1571 1583 1596 1608 1620 1632 1644 1656 1668 1679 1691 1702 1713 1725 1736 1747 1758 1769 1779

Section 6 - 31

Section

Primary Cementing Gas Migration

Scope This Section briefly covers some of the theories on the causes of gas migration and proposed slurry and job designs to address gas migration. This is not an exhaustive discussion of the causes of gas migration, nor the myriad of mitigation techniques. Rather this Section covers the most common forms of gas migration and the most common prevention and mitigation methods.

Company Use Only

Gas Migration

7

Table of Contents ExxonMobil Requirements ............................................................................... 3 ExxonMobil Recommended Practices ............................................................ 3 7.1.

Required References ............................................................................. 4

7.1.1.

7.2.

API-American Petroleum Institute.................................................................. 4

Types of Gas Migration.......................................................................... 4

7.2.1.

Immediately After Placement of the Cement.................................................. 4

7.2.2.

Influx After the Cement Has Been in Place for Several Hours ....................... 4

7.2.3.

Presence of Gas Days or Weeks After the Cement is in Place ...................... 5

7.2.4.

Gas Seen Following Fracture Treatments, Production or Drilling Deeper ...... 5

7.3.

Under-balance of the Well ..................................................................... 5

7.4.

Gas Influx After Several Hours.............................................................. 6

7.4.1.

Theory........................................................................................................... 6

7.4.2.

ExxonMobil Recommended Practices ........................................................... 9

7.4.2.1. 7.4.2.2.

Latex....................................................................................................... 9 Energized Fluids ..................................................................................... 9

7.5.

Gas Present After Days or Weeks......................................................... 9

7.6.

Gas Present After Fracturing Treatment, Production or Drilling Deeper ................................................................................................... 10

7.7.

Summary ............................................................................................... 10

March 2004

Company Use Only

Section 7 - 2

Gas Migration

7

ExxonMobil Requirements Section #

ExxonMobil Requirement

There are no ExxonMobil requirements in this Section.

ExxonMobil Recommended Practices Section # 7.4.2

ExxonMobil Recommended Practice In general, gas resistant slurries are recommended for: 1. Gas zones with pore pressure greater than 13 ppg. 2. Any gas zone in the surface hole, regardless of pore pressure. 3. Any gas zone below a liner top packer. LTPs remove the head early in the set process, resulting in a reduction in final effective stress.

7.4.2.1

March 2004

The recommended latex concentration is 1 - 1.5 gallons per sack. Additional material has not been shown to be necessary for gas migration prevention.

Company Use Only

Section 7 - 3

Gas Migration

7. 7.1.

7

GAS MIGRATION

REQUIRED REFERENCES

This Section lists Practices and Standards that are generically referenced and assumed part of this document. Unless otherwise specified herein, use the latest edition.

7.1.1.

API-American Petroleum Institute

API RP 65

7.2.

Cementing Shallow Water Flow Zones in Deep Water Wells

TYPES OF GAS MIGRATION

There are four general types of gas migration distinguished by when the problem is seen at surface. Summarized here, each type will be examined in detail with slurry and job design suggestions for the prevention of each type.

7.2.1.

Immediately After Placement of the Cement

This type of gas migration is characterized by gas to surface immediately after placing cement in the well. The cause of the gas to surface is usually the result of an underbalance situation in the well, or the well has been swabbed in while moving pipe. The under-balance situation can be caused by running too much lightweight preflush ahead of the cement, mixing the slurry too light for well conditions, or taking a gas influx while cementing.

7.2.2.

Influx After the Cement Has Been in Place for Several Hours

This is one of the most common occurrences of annular gas flow, and is of great concern, because it often occurs when the diverter is being rigged down, or the surface stack has been lifted to drop slips. The flow during this period most likely occurs either at the cement/casing interface or cement/borehole interface, and is due to the loss of effective stress in the cement as it sets. This phenomena is the one most commonly addressed by a number of specialty products. Flow during this period may also be brought on by excessive free water development in the cement slurry, particularly in deviated wells where a mobile channel may form on the topside of the hole.

March 2004

Company Use Only

Section 7 - 4

Gas Migration

7.2.3.

7

Presence of Gas Days or Weeks After the Cement is in Place

This can be the result of dehydration of the mud filter cake, leading to a flow path between the cement and the formation. This can also be brought on by the formation of a microannulus between the pipe and cement, most often the result of changing the fluid density inside the casing.

7.2.4.

Gas Seen Following Fracture Treatments, Production or Drilling Deeper

This is generally the result of stress cracking of the cement due to large wellbore stresses. The cement no longer maintains a seal in the annulus because of cracking of the cement sheath.

7.3.

UNDER-BALANCE OF THE WELL

An under-balance situation in the well can be the result of either swabbing in the well during pipe reciprocation, or by pumping excessive amounts of low-density preflush ahead of the cement. Performing surge and swab calculations prior to the job can minimize swabbing in the well. If the margins are very close, pipe reciprocation should be avoided, though the situation where this is a problem is rare. Using a cement job simulator will help predict if the hydrostatics in the well does not allow using water or other low-density wash ahead of the cement. These calculations should always be made prior to cementing. In situations where gas is seen at the surface immediately following the cement job, the annulus must be immediately shut in and the pressures monitored. At this point, there are three options: 1. Maintain pressure on the well until the cement sets: If no fluid is bled off the annulus, no additional gas can enter the wellbore. This may help prevent further channeling of the gas. 2. Circulate out the cement and associated gas: This can only be done with sufficient pumping time on the slurry; will result in cement slurry in the choke manifold and BOP equipment on the rig. This is usually the least desirable approach. 3. Pressure up on the annulus and displace sufficient mud to sweep the annulus to the previous casing shoe. This will ensure a flow path from the surface to at least the last casing shoe, allowing later placement of high-density mud or additional cement squeeze jobs.

March 2004

Company Use Only

Section 7 - 5

Gas Migration

7.4.

7

GAS INFLUX AFTER SEVERAL HOURS

This situation is one of the most common forms of gas migration, and is the situation most addressed by specialty gas migration additives.

7.4.1.

Theory

Annular gas flow is most commonly caused by a combination of cement gellation, volume reduction, and lack of total system elasticity. In the end, these result in low stress between the cement and casing, and/or the cement and borehole. Because of the low stress, the gas pressure is able to push the two surfaces apart and a microannulus is created. When a column of cement begins to set, the chemical bonding between the solids starts to create gel strength. Simultaneously, the volume of the cement begins to shrink due to fluid loss to the formation and the uptake of water in the chemical reaction. As shrinkage occurs, gellation in the column prevents the cement column from moving downward to maintain hydrostatic pressure. The loss of hydrostatic pressure was noted in the 1970's. Commonly cited papers are: SPE 5701, "An Investigation of Annular Gas Flow Following Cementing Operations," published in 1976 by J. A. Garcia and C. A. Clark; and SPE 8266, "Annular Gas Flow After Cementing: A Look At Practical Solutions," by Levine, Thomas, Besner and Toole in 1979. These early works noted the pressure loss problem, but did not identify shrinkage as a contributing factor for the loss of internal column pressure. It was assumed that as the cement hardened, the solids began to support their own weight. Because the liquid phase no longer carried the weight of the solids, the pressure would revert to that of the mix water gradient. This resulted in the operational practices recommended in SPE 8266, which included the use of a 9-ppg-gradient line to predict the occurrence of annular gas flow. Field data presented in the August 1983, JPT, "Field Measurements of Annular Pressure and Temperature During Primary Cementing," written by Cooke, Kluck, and Medrano of Exxon showed this assumption to be incorrect. The pressure in the fluid phase does fall, but not to a water gradient. Cement lacks the vertical permeability to be able to transmit pressure over long distances. Because the interstitial water is not connected vertically, the internal pressure can theoretically fall to zero (0) psi as the column sets and the water is drawn out of the interstitial spaces by the hydration process. In reality, field data shows the pressure falls until it equals that of the adjacent rock, whether it is normally pressured, abnormally pressured, or drawn down. The pressure can fall no further because the water phase in the cement is in communication with the fluids in the rock. There may actually be no measurable flow, only fluid-on-fluid pressure at the interface. In one interval where a sensor was placed across from a shale, the pressure fell well below formation gradient. This can also occur in a liner overlap where the cement is between steel strings.

March 2004

Company Use Only

Section 7 - 6

Gas Migration

7

As the process was better understood in the late 1990's, it became apparent the pressure level in the pore spaces of the cement is relatively unimportant. The flow rates observed during annular gas flow are not due to gas flowing through the matrix of cement. Even lightweight cements do not have adequate permeability to allow significant matrix flow. This early theory moved the industry to focus on products that attempted to maintain the internal pressure of the cement. However, even during lab testing, flow was consistently seen only between the cement and contact surfaces. Researchers attributed this to their inability to fully simulate field conditions, but in fact the same phenomena occurs in boreholes. Flow occurs due to inadequate contact force between the solid grains of cement and the casing or borehole wall. The contact force between the solid grains is referred to as "effective stress," and the term is used in the same manner as in rock mechanics. As the cement sets, it becomes a two-phase material consisting of solid grains and fluid. If the net sum of the force is such that the grains are in contact with the casing, there can be no gap and no flow. The pressure of the fluid between the grains does not effect the contact force because it acts equally on all sides of the grain. The contact force between the grains is determined by the elastic behaviors of the solid components of the system; which are the casing, cement grains, and formation. The first rigorous modeling of a fully elastic system was developed in 2000. This finite element work was published in SPE/IADC 59137, "New Model of Pressure Reduction to Annulus During Primary Cementing," by Desheng Zhou, and Wojtanowicz at LSU. This yielded the first successful hind casting of the field pressures published 17 years earlier by Exxon in 1983. The development of models to predict the loss of internal head due to gellation and volume reduction were critical first steps in the development of annular gas flow theory because these factors determine the starting stress in the elastic system. However, they did not accurately predict field measurements until the elastic effects were added. As the cement sets and shrinks, the casing and borehole expand due to the loss of pressure acting on their surface (casing OD increases, hole ID declines). The casing, cement, and borehole also expand thermally as the well heats back to thermal gradient. The Modulus of Elasticity and Thermal Expansion Coefficient of each material determines its contribution to maintaining the stress as the cement contracts. After the cement sets and the system comes to thermal equilibrium, the stress between the cement and casing or cement and borehole will determine whether there is a seal. The sequence of events that determines if annular gas flow will occur are: 1. As the cement sets, water volume is lost due to fluid loss and the hydration reaction. The loss of volume causes a drop in internal column pressure. 2. Simultaneously, the setting process creates gel strength in the column so that it does not move downward efficiently to recompress the remaining fluid (hydrostatic head is not transmitted). 3. The internal pressure of the fluid phase falls until it equals the adjacent formation pressure. This does not result in measurable influx because there is no void in the annulus space to allow influx. The solids are not moving, the interstitial spaces are simply pressuring up.

March 2004

Company Use Only

Section 7 - 7

Gas Migration

7

4. As the effective stress falls and the system heats up, the casing, cement, and borehole respond elastically. The pressure of the fluid phase within the cement is not a factor in determining the grain contact force (effective stress) at the surfaces because it acts equally on all sides of the grains. 5. After the cement sets, annular gas flow can occur if the contact stress between the grains and surfaces is less than zero (0) psi, which is to say, if a gap has been opened. Although they were developed along other lines of thought, many of the gas-resistant products on the market fit into this concept. The dominant products, which are latex and foamed cements, address many of the key issues. •

Low fluid loss results in less shrinkage, which reduces the loss of effective stress. This is the basis for recommending FL < 50 cc's for all gas-resistant slurries, regardless of the mechanism for achieving the fluid loss control.

•

Although gas cannot travel long distances in the matrix of the cement, low fluid loss also helps to ensure the vertical permeability is sufficiently low that the gas cannot travel short distances through the matrix to nearby zones.

•

Latex and foam both increase the modulus of elasticity of the set cement, allowing expansion when the effective stress drops due to shrinkage or movement in the casing OD.

•

Gas-resistant systems have a "right-hand set." The rapid set minimizes the time during which fluid loss can occur, which reduces shrinkage.

The effective stress model of annular gas flow also explains many operational behaviors that are observed. For example, annular gas flow often develops following cementing after heavy mud is replaced with light completion fluid in the casing. The reduction in internal pressure allows the casing OD to decline, which reduces the effective stress. This is addressed by using a more elastic cement (foam or higher concentrations of latex). Cement evaluation logs are often run under pressure in order to be able to "see the cement." Applying internal pressure expands the casing OD, which increases the effective stress that attenuates the signal and improves the sonic coupling. Tools that estimate bonding are measuring effective stress more than an actual adhesion of the cement to the casing. If adhesion were being measured, the signal would not improve by raising the internal pressure. There are no tools available to predict the onset of annular gas flow based on the loss of effective stress. The service industry has computer simulations that provide some of the key data, but they do not currently handle the complex elastic movements of all of the components of the system.

March 2004

Company Use Only

Section 7 - 8

Gas Migration

7.4.2.

7

ExxonMobil Recommended Practices

The ExxonMobil recommended practices, such as FL < 50 cc's, are based on years of successful experience in high-pressure gas and there are few situations in which these guidelines are not adequate. In general, gas-resistant slurries are recommended for: 1. Gas zones with pore pressure greater than 13 ppg. 2. Any gas zone in the surface hole, regardless of pore pressure. 3. Any gas zone below a liner top packer. LTPs remove the head early in the set process, resulting in a reduction in final effective stress.

7.4.2.1.

Latex

The preferred product for normal and higher density slurries is latex at 1.0 - 1.5 gps. A concentration of 1.0 - 1.5 gal/sk will normally yield a FL < 50 cc's, regardless of BHT. Schlumberger will recommend latex concentrations of 2.5 - 3.5 gal/sk based on the "porosity" of the slurry. This porosity number is a calculation of the amount of solids and liquids in the liquid slurry, and is not related to porosity of a set cement. Latex has been used in ExxonMobil operations for over 18 years and field results do not support these higher levels of latex. If latex is not available, other systems designed to achieve a fluid loss less than 50 cc's will normally be effective. This can be accomplished by using several different materials, the more common being polyvinyl alcohol (PVA) based additives. While these materials have been effective, latex is preferred in more severe situations because it provides elasticity in addition to fluid loss control.

7.4.2.2.

Energized Fluids

Other methods of gas migration control include the use of gas generating agents and foamed cements. Both incorporate gas at varying concentrations into the cement. They have inherently low fluid loss, low matrix permeability, and high elasticity to maintain effective stress. The use of a low concentration of latex is the economic solution in most wells. Foam is more effective than latex in very challenging situations where extreme changes in effective stress are anticipated due to changes in thermal or stress loads. The elasticity of foam allows it to maintain effective stress over a larger range of dimensional changes. It can also be compressed further without developing radial stress cracks, another avenue for annular gas flow (see Section 7.5).

7.5.

GAS PRESENT AFTER DAYS OR WEEKS

Gas migration following several days or weeks can be due to a number of reasons, from dehydration of the mud filter cake to the formation of a microannulus. Changes in wellbore stresses, as discussed above, play an important role in this type of gas migration. The elasticity of the cement is a key parameter in resolving this situation. Often, this type of gas problem presents itself as pressure on the annulus that cannot be bled off, or will bleed down to zero and return in a few days. Generally, attempts to

March 2004

Company Use Only

Section 7 - 9

Gas Migration

7

pump into the annulus are ineffective as no fluid can be placed in the annulus. There is very little that can be done with conventional cementing materials and equipment to resolve this problem once it has occurred. Prevention of a large microannulus is best accomplished during primary cementing. Remediation techniques for this type of gas flow have ranged from lubrication of heavy brines into the microannulus to perforating the casing at the influx zone and attempting squeeze operations. The most radical approach has been to enter the well, mill the casing at the influx zone and under-ream the remaining hole and attempt to set plugs to shut off the flow. This is most often required when the well is to be abandoned.

7.6.

GAS PRESENT AFTER FRACTURING TREATMENT, PRODUCTION OR DRILLING DEEPER

This problem is the result of the sealing ability of the cement, brought on by stress failure of the cement sheath. The stress can come from the pressurization of the casing through a fracture treatment, or an increase in the mud weight for drilling deeper. Temperature changes have a major effect on the stress environment of the well. Increasing the temperature will place radial loads on the cement sheath as the casing attempts to expand, and can lead to tensile failure of the cement. This will lead to the loss of isolation, but casing support will still remain. Prevention of the failure of the cement to maintain isolation has centered on development of more flexible cement systems. These have included latex slurries, foamed cements, Schlumberger's FlexStone, and the incorporation of flexible fibers into the system. One of the least expensive techniques to increase the flexibility of cement is to simply reduce the cement density. Diluting the cement, in this case with water, reduces the rigidity of the set cement, and will improve its resistance to cracking.

7.7.

SUMMARY

It is important to understand the full life-cycle requirements for the well for proper cement design. The best way to prevent long-term problems is to properly address gas migration in the initial design. Gas migration prevention should be considered with: •

Gas zones with pore pressure greater than 13 ppg.

•

Any gas zone in the surface hole, regardless of pore pressure.

•

Any gas zone below a liner top packer.

These conditions are arbitrary, and experience in a particular area, or knowledge of future operations can dictate the use of gas migration prevention slurries on any particular well.

March 2004

Company Use Only

Section 7 - 10

Gas Migration

7

It is equally critical that the cement be properly placed. It does not matter how good the slurry design, if the slurry is not placed properly in the annulus. Gas migration prevention does not center around a cement additive, or group of additives, but on the entire system of slurry design and placement.

March 2004

Company Use Only

Section 7 - 11

Section

Primary Cementing Lost Circulation

Scope This Section covers the use of lost circulation materials in primary cementing, how the materials work, and the limits of the systems. It is specific to primary cementing operations, and is not intended to supercede or replace the lost returns response plan.

Company Use Only

Lost Circulation

8

Table of Contents ExxonMobil Requirements ............................................................................... 3 8. Lost Circulation........................................................................................... 4 8.1. Required References ............................................................................... 4 8.1.1.

API-American Petroleum Institute.................................................................. 4

8.1.2.

ISO-International Standards Organization ..................................................... 4

8.2. General...................................................................................................... 4 8.3. Additives and Systems ............................................................................ 5 8.4. Flakes ........................................................................................................ 5 8.4.1.

Cellophane Flakes......................................................................................... 5

8.5. Granular Materials.................................................................................... 6 8.5.1.

Ground Coal.................................................................................................. 6

8.5.2.

Gilsonite ........................................................................................................ 6

8.6. Fibers ........................................................................................................ 6 8.6.1.

CemNet* ....................................................................................................... 6

8.7. Cement Systems ...................................................................................... 6 8.7.1.

March 2004

Thixotropic Cement ....................................................................................... 6

Company Use Only

Section 8 - 2

Lost Circulation

8

ExxonMobil Requirements Section Number

ExxonMobil Requirement

There are no ExxonMobil requirements in this Section.

March 2004

Company Use Only

Section 8 - 3

Lost Circulation

8. 8.1.

8

LOST CIRCULATION

REQUIRED REFERENCES

This Section lists Practices and Standards that are generically referenced and assumed part of this document. Unless otherwise specified herein, use the latest edition.

8.1.1.

API-American Petroleum Institute

8.1.2.

ISO-International Standards Organization

8.2.

GENERAL

Controlling lost circulation with cement is often a futile effort. Depending on the cause of the losses, the response to the losses is several-fold. The lost returns response plan is intended as the basis for lost circulation response. This plan should be followed for lost circulation response, with cement playing a minor role in that response. The current edition of the Lost Circulation Response Plan can be found on GlobalShare (located in the library folder of the Drilling Technical Share) and the EMDC Drilling Technical Intranet website. Major lost returns occurs when the wellbore pressure exceeds wellbore integrity and a fracture is created. The integrity is equal to the rock stress holding the two faces of the fracture closed (minimum stress). Integrity is built by pressing the fracture wider to increase the closing stress, then packing the fracture with solids to sustain the width. If the width achieved is adequate so the increased stress exceeds ECD, losses stop. If not, the ECD will press the fracture wider and losses continue. For more information, refer to other ExxonMobil documentation on Fracture Closure Stress. Cement is not effective in stopping losses unless the required increase in integrity is small. Cement particles are essentially the same size as barite so it flows into the fracture as freely as mud. In contrast, LCM pills become very resistant to flow down the fracture because of their high fluid loss rate. As the pill dehydrates, the solids remaining in the fracture become unpumpable and the fracture tip cannot grow. Fluid loss is the key to this process. The fluid loss of most cements is low enough that it does not dehydrate significantly as it flows down the permeable face of the fracture. Cement

March 2004

Company Use Only

Section 8 - 4

Lost Circulation

8

is more likely to propagate the fracture rather than arrest it. The small amount of width that is achieved may result in only a 100-200 psi increase in closing stress. In field operations, returns often increase when the circulating cement arrives at the loss zone. However, this only occurs when the ECD is only slightly higher than the integrity and the 100-200 psi of stress that can be built with cement is adequate to support the ECD. The loss zone must also be permeable so the cement can dehydrate. If a significant increase in integrity is required, or if the loss zone has low permeability, the losses should be treated with more effective fracture closure stress (FCS) procedures prior to running casing. Since the effectiveness of cement cannot be predicted, pretreatment with LCM is preferred if cement returns are critical. The effectiveness of the cement may also be enhanced slightly by adding LCM to the slurry. Lost circulation materials in cement are typically larger than those used in drilling fluids because particle size is not constrained by nozzles or other restrictions. Cellophane flake is the most common material, though ground coal and Gilsonite are also used. Because cement slurries are already crowded with solids, it is not possible to add a significant concentration of LCM and yet remain pumpable. Cellophane is usually mixed at only 2-3 ppb (0.25 lb/sk), which does not greatly improved its effectiveness in stopping losses. Higher concentrations of granular materials may be used in lower-weight cements (70 ppb), however, the slurry will still not be as effective as an LCM pill. This is due to the low fluid loss created by the pore throat plugging efficiency of fine cement particles. If lost circulation materials are used in the cement, there is an increased chance the material can settle out, or otherwise concentrate as the cement is being pumped down the casing. This can result in a large concentration of LCM hitting the float collar at one time. This has led to plugging of the float collar valves, and plugging the valve. This results in a premature end to the cement job.

8.3.

ADDITIVES AND SYSTEMS

Discussed briefly in Section 2.13, Additives, most LCMs for cement are large flakes or large granular materials. It should be noted that because of the dimensions of most laboratory test equipment, cement blends are not tested with lost circulation additives present.

8.4.

FLAKES

8.4.1.

Cellophane Flakes

Cellophane flakes are approximately 0.25-inch square. The normal concentration for this material is 0.25 lb/sk. Higher concentrations do not blend well, and can cause problems with cement transfer through the bulk system. They do not require additional water for mixing.

March 2004

Company Use Only

Section 8 - 5

Lost Circulation

8.5.

8

GRANULAR MATERIALS

8.5.1.

Ground Coal

Ground coal was used extensively through the 1980's, marketed by Dowell as Kolite. The particle size of the material is ≤ 0.125-inch. The material is still in use, though only in limited areas. Typical concentrations for the ground coal are 10 - 12.5 lb/sk.

8.5.2.

Gilsonite

More common than ground coal, Gilsonite is the other common granular lost circulation material. It is used in similar concentrations of 10 - 12 lbs/sk. One limiting factor to Gilsonite is the material will begin to soften at temperatures above 180°F (162°C).

8.6.

FIBERS

8.6.1.

CemNet*

Marketed by Schlumberger, CemNet* is a fiber that is added at a concentration of 1 - 2 pounds per barrel. (Note the concentration is in pounds per barrel and not pounds per sack.) The material cannot be dry-blended, as it will not allow bulk transfer of the cement. The material can also be added to the spacer ahead of the cement. CemNet* is added to the mixing tub by hand, therefore the actual concentration will vary with addition rate and pump rate. Care must be taken to prevent adding too much material, as this will cause mixing problems. Of the currently available lost circulation materials for cement, it appears fibers are more effective at preventing lost circulation. ExxonMobil experience is quite limited for CemNet* fibers. The operations that have utilized the material have had success, though the high cost has limited the use.

8.7.

CEMENT SYSTEMS

8.7.1.

Thixotropic Cement

The most common cement system used to combat lost circulation is a thixotropic slurry. Thixotropic slurries will build gel strength very quickly as the shear on the slurry is reduced. The theory behind the use of a thixotropic system is that as the cement enters a fracture or loss zone, the leading edge velocity will reduce, allowing for gel strength development. This in turn self limits the amount of cement that can be lost to the zones.

March 2004

Company Use Only

Section 8 - 6

Lost Circulation

8

Thixotropic cement systems are most commonly made by adding 8 - 10% gypsum to a cement. The cement chosen should have a C3A content of at least 3 - 6%, with the higher C3A content giving a better slurry. In the absence of C3A, gypsum will not react to form a thixotropic slurry. Because of this, use of a Class C cement for these systems are not recommended. The use of thixotropic cements is limited to shallower wells because of the difficulty in maintaining the thixotropic behavior at higher temperatures. At elevated temperatures, retarders are required, and most retarders act as dispersants, thus destroying much of the thixotropic behavior of the cement. There are specialty retarders available for thixotropic cements, but the resulting slurry remains marginally effective. The primary application for thixotropic cements is with low temperature, shallow wells. Wells that experience cement fall back, where cement may come to surface, but falls back down the annulus, benefit greatly from thixotropic cements. The major areas for application of these cements have been Western Canada and the Western US.

March 2004

Company Use Only

Section 8 - 7

Section

Primary Cementing Mud Removal

Scope This Section covers the main considerations for optimizing mud removal. Included is discussion on spacer selection, compatibility evaluations, and chemical compatibility. Mechanical aspects of mud removal covered include centralization, pipe movement, spacer volumes, and fluid velocities.

Company Use Only

Mud Removal

9

Table of Contents Tables................................................................................................................. 3 ExxonMobil Requirements ............................................................................... 4 ExxonMobil Recommended Practices ............................................................ 4 9. Mud Removal............................................................................................... 5 9.1. Required References ............................................................................... 5 9.1.1.

API-American Petroleum Institute.................................................................. 5

9.1.2.

ISO-International Standards Organization ..................................................... 5

9.2. Introduction .............................................................................................. 5 9.3. Fluid Considerations ............................................................................... 6 9.3.1.

Mud Conditioning .......................................................................................... 7

9.3.2.

Separating the Mud and Cement................................................................... 7

9.3.2.1. Definitions ............................................................................................... 8 9.3.3. Spacer/Pre-Flush Selection Criteria............................................................... 8 9.3.4.

Spacer Usage Guide ..................................................................................... 8

9.4. Mechanical Considerations..................................................................... 9 9.4.1.

Pipe Movement ............................................................................................. 9

9.4.2.

Centralization .............................................................................................. 10

9.4.3.

Pump Rates ................................................................................................ 10

9.4.4.

Pressure Considerations ............................................................................. 11

9.4.5.

Wellbore Considerations ............................................................................. 11

9.4.5.1. 9.4.5.2.

March 2004

Borehole Stability .................................................................................. 11 Annular Gap.......................................................................................... 11

Company Use Only

Section 9 - 2

Mud Removal

9

Tables Table 9.1: Mud Removal Considerations ....................................................................... 6

March 2004

Company Use Only

Section 9 - 3

Mud Removal

9

ExxonMobil Requirements Section #

ExxonMobil Requirement

There are no ExxonMobil requirements in this Section.

ExxonMobil Recommended Practices Section #

ExxonMobil Recommended Practice

9.3.3

Spacer selection criteria aids in design of a spacer based on three criteria: type, density and viscosity.

9.3.4

Spacer usage guide contains recommendations on volumes, rates, etc., for spacers and washes.

March 2004

Company Use Only

Section 9 - 4

Mud Removal

9. 9.1.

9

MUD REMOVAL

REQUIRED REFERENCES

This Section lists Practices and Standards that are generically referenced and assumed part of this document. Unless otherwise specified herein, use the latest edition.

9.1.1.

API-American Petroleum Institute

API RP 10B

9.1.2.

ISO-International Standards Organization

ISO 10426-2

9.2.

Recommended Practice for Testing Well Cements

Cements and Materials for Well Cementing - Part 2: Testing of Well Cement

INTRODUCTION

The process of mud removal is central to a successful cementing operation. Without replacement of the drilling fluid with cement, zonal isolation cannot occur. Mud contamination of cement results in delayed set or no set, lower-strength development, dilution of the cement, potential for fluid and gas migration, and loss of isolation in the well. Mud removal is not limited to primary cementing. The need for mud removal also applies to squeeze and plug cementing. The same practices that give a good primary cement job will enhance the success rates of plugs and squeeze work. Table 9.1 lists some of the considerations for mud removal. Each of these parameters must be considered in every cement job design to some degree. All of the recommendations and considerations may not be possible in every well; thus, the design should optimize those that are possible.

March 2004

Company Use Only

Section 9 - 5

Mud Removal

9

Table 9.1: Mud Removal Considerations Parameter

Consideration

Type of drilling fluid

Hydrocarbon, water, brine

Drilling fluid properties

Viscosity, solids content, presence of cuttings, density

Hole size

Washed out areas, velocities

Pipe size

Annular gap, velocities, internal fluid displacement

Well architecture

Angle, previous casing strings

Casing movement

Rotation, reciprocation, no pipe movement

Centralization

Amount of centralization, where applied

Spacer and wash volume

Contact time, dilution volumes

Spacer chemistry

Compatibility with drilling fluid and cement

Density differentials

Density of mud, spacer and cement

Pump rates

Flow profiles, annular velocities, ECD

Temperature

Fluid rheology, compatibility

General characterization of mud removal involves two areas: fluid systems and properties, and mechanical actions to be taken. Fluid systems and properties deal with mud properties and conditioning, spacer selection and usage, volumes and chemistry. Mechanical actions include pipe movement, centralization, casing hardware and flow rates. While not a controllable factor during the cement job, the annular gap in the well will effect the annular velocities, flow regimes and centralization.

9.3.

FLUID CONSIDERATIONS

Primary fluid considerations center around the physical removal of the drilling mud, chemical compatibility of the selected spacer with the mud and the cement, and the maintenance of pressure control in the well.

March 2004

Company Use Only

Section 9 - 6

Mud Removal

9.3.1.

9

Mud Conditioning

Circulating the mud after the casing is on bottom serves a number of purposes prior to the cement job: •

By circulating at least one casing volume, it is confirmed at least that volume of fluid can be pumped through the float equipment. This is an indication there are no foreign objects in the casing string.

•

Circulation lowers the well temperature from the bottomhole static to the circulating temperature. In wells that have not been circulated for some time, this can be particularly important.

•

Removal of remaining cuttings - Hopefully, the wellbore is clean prior to running casing. There will be some formation knocked off while running the casing, and if the wellbore is not completely stable, there can be a build up of solids at the bottom of the well from hole sloughing.

•

Lowering the rheology of the mud by circulating will make the mud more fluid, mobile and aid in its subsequent removal. Circulation will break up mud gels that develop when the mud is quiescent.

•

The final well circulation should be at a rate as fast as practical without losing returns. This will put the maximum amount of energy into the system and maximize mud movement.

•

The well should be circulated until the mud properties in and out are the same. Lacking the ability to do this, a minimum of one casing volume or annular volume, whichever is more, should be pumped.

9.3.2.

Separating the Mud and Cement

Some sort of spacer or pre-flush should be run ahead of the cement. The spacer functions to separate the mud and the cement, clean the wellbore and pipe, and prepare the well for the cement. Most drilling fluids and cement are not compatible. The calcium in the cement tends to flocculate the bentonite in the mud, making it a gelled mass. The gelled mixture is either bypassed by fresh cement, leaving a noncemented section in the well, or the mixture is sufficiently large that it begins to move, increasing friction pressure in the annulus, and resulting in lost circulation. In either case, the cement job will not perform as designed. The newer non-aqueous fluids (NAF) have a much higher tolerance to water-wet solids than the more traditional oil-based muds. Historically, it was the water-wet solids in the cement that resulted in the incompatibility between oil mud and cement. With the advent of newer surfactants, emulsifiers, and oil-wetting agents, the rheological incompatibility between oil or non-aqueous systems has been largely eliminated. While the fluids may mix well together, causing no problems in displacement, incorporating NAF systems into cement can result in little or no strength development of the cement. This has resulted in failures of cement plugs and lack of zonal isolation on many wells. When dealing with NAF systems, extreme care must be exercised to remove the mud.

March 2004

Company Use Only

Section 9 - 7

Mud Removal

9.3.2.1.

9

Definitions

Two general categories of fluids used to separate mud and cement are a pre-flush or wash, and spacers. Pre-flushes are typically thin, unweighted fluids that are pumped in turbulent flow. A pre-flush can be simply water, seawater, or base oil. Additionally, a pre-flush may contain surfactants and fluid loss additives. Spacers are more viscous as they are capable of being weighted to a desired density. Depending on the well requirements, the spacer may be designed to be displaced in either turbulent, laminar or plug flow. Spacers designed for turbulent flow have a complex chemistry to allow for suspension of the weighting agent, while still allowing for turbulent flow. These materials should be evaluated at both surface-mixing temperatures and the circulating temperature of the well (or 190°F (88°C)), whichever is less).

9.3.3.

Spacer/Pre-Flush Selection Criteria

•

When possible, use water or seawater.

•

Type - The spacer should be water-based, but if it is being used to remove a non-aqueous fluid, it should contain surfactants and possibly mutual solvents to leave the pipe water wet.

•

Density - Maintenance of well control is essential, and must take precedence over any other considerations. If well conditions allow, and the mud weight is less than 12.0 ppg, water or seawater is the recommended spacer. Convention calls for the spacer to be 0.5 ppg higher than the mud weight when possible, but until the differential density between the mud and spacer exceeds 1 ppg, the incremental effect of the higher density is minor. If necessary, the spacer density can be identical to the mud density.

•

Compatibility - The spacer should be compatible with both the mud and the cement slurry. Testing should be done to determine the rheological interaction of the spacer with the mud and the cement (see Section 3.17).

•

Viscosity and Yield Point - Depending on the computer model employed, a viscosity hierarchy is employed to determine optimum mud-removal efficiency. The theory being the spacer must have a higher yield point than the mud, and the cement must be higher than the spacer to effect mud removal. The service company models ignore the value of water as a spacer; often the viscosity of water entered into the program is increased from one (1) to as high as five (5). This falsely indicates poor mud removal with water.

9.3.4.

Spacer Usage Guide

•

Volume - Run at least 500 annular feet of spacer, more if well conditions merit. The 500-ft volume can be either all water or a combination of water and viscosified spacer.

•

Many service companies are recommending at least 10 minutes contact time or 1,000 annular feet. Field data has not shown large gains in mud removal when

March 2004

Company Use Only

Section 9 - 8

Mud Removal

9

following these recommendations. While larger volumes of spacer may be applicable in high-risk situations, the general recommendation is for 500 annular feet of spacer. •

Flow Regime - Regardless if the spacer is designed for turbulent, laminar or plug flow, do not sacrifice compatibility with the mud and cement in favor of a particular flow regime. Volume and compatibility have been shown to be more critical factors than flow regime.

•

Turbulent flow is emphasized in the cementing literature, as the flat viscosity profile and internal eddies are purported to improve mud displacement. Work by Haut and Crook indicated that regardless of the flow regime, mud displacement was improved with increasing rate.

•

Do not add materials to enhance turbulent flow to the cement slurry to improve mud removal. As noted, cement and mud are generally not compatible, and as such, will viscosify on contact. This eliminates any advantage from the dispersant. Chemical additives used solely to introduce turbulent flow are unnecessary and are not recommended.

•

The Schlumberger displacement model recommends a 10% increase in density between the mud and spacer, followed by another 10% increase between the spacer and cement. This practice leads to the use of very high fluid densities, increases the risk of lost circulation, and is not recommended.

•

Non-aqueous muds require the use of multiple spacers, depending on the base fluid used. Multiple spacer systems can include base oil followed by spacers containing solvents followed by water-based systems.

•

It may be necessary to use an intermediate spacer to change the wettability of the wellbore to allow the surfactants to function. These systems are available from wellbore cleaning companies that specialize in fluid displacements on completions. These materials are blends of solvents and gelling agents and by themselves will not leave the wellbore water-wet, but will function to clean the wellbore in advance of a water-based spacer containing a surfactant. (Much like using a hand cleaner will remove oil and grease if used prior to washing.)

•

Recommendations have been made by some service companies to run spacer "trains." These are systems that use a thin spacer, followed by thick, followed by thin, etc. The train can also start with the thick spacer. There has been no information published to justify alternating viscosities of the spacer systems. No advantage has been shown when pumping additional stages.

9.4.

MECHANICAL CONSIDERATIONS

9.4.1.

Pipe Movement

If at all possible, incorporate pipe rotation into the cement job design. Considerable data has shown pipe rotation greatly improves cementing results, regardless of other factors involved. Use of scratchers, cable wipers, or other devices to enhance the mechanical movement of the mud can improve the results.

March 2004

Company Use Only

Section 9 - 9

Mud Removal

9

The pipe should be rotated at 10 - 20 rpm where possible. The torque on the pipe must be monitored and kept below the make-up torque of the casing connections. The anticipated displacement pressure must also be considered when designing for pipe rotation. On wells where the displacement pressure will be very high, as occurs when displacing a heavy mud with a lightweight brine, the pressure on the rotating head may be too high to allow for pipe rotation. In situations where the displacement pressure exceeds 5,000 psi, pipe rotation may not be advisable and alternates should be considered. If rotation is not possible, consideration should be given to reciprocation. While not as effective, any pipe movement will aid in mud removal. The effects of reciprocation can be enhanced by the proper selection of centralizers, which is covered in Section 14.4.1, Cementing Equipment. When reciprocation is employed, the surge and swab pressures should be calculated to prevent breaking the well down, or swabbing in a formation. These are the same calculations that were made for running the casing. Also, note the changes in hook load during the cement job. As cement fills the casing, the hook load will increase, then begin decreasing as the cement enters the annulus. Calculations with the casing full of cement, and at the end of the job, with cement in the annulus, should be made.

9.4.2.

Centralization

Discussed in more detail in Section 14, Cementing Equipment (Centralizers), moving the pipe toward the center of the hole will improve cementing success. Good centralization becomes more important in the absence of pipe movement. At least 80% standoff is recommended where isolation is required in the well. Selection of centralizer type (bow spring or rigid/solid) should be made based on well requirements, side loads, and casing running parameters. For vertical wells, bow spring centralizers are recommended.

9.4.3.

Pump Rates

Putting energy into the wellbore will enhance fluid movement. With all else being equal, higher rates will improve results. Maximizing the displacement rate of the cement should be used whenever possible. The maximum displacement rate can be determined using cement service company simulators. The displacement rate chosen should not cause lost circulation in the well, but should maximize mud displacement. Note - it is ONLY the displacement rate that should be controlled. The mixing rate may be limited by the ability to mix cement to the proper density. On many jobs, the cement is still being mixed when the spacer or cement rounds the shoe and enters the annulus. The mixing rate will determine early mud removal at the bottom of the well, and these rates should not be increased if density control will be sacrificed. Careful simulation of the job with placement programs should take into account realistic mixing and pumping rates.

March 2004

Company Use Only

Section 9 - 10

Mud Removal

9.4.4.

9

Pressure Considerations

The limiting factor to pump rate will be the pressure induced by the friction in the wellbore, and the potential for initiating lost circulation. Loss of circulation can lead to bridging in the annulus in some wells, and will result in a lowered top of cement. At any given depth, the pressure exerted on the wellbore will be a combination of the hydrostatic pressure exerted by the fluids in the well and the associated frictional resistance of that fluid column. Cementing simulators take into account the friction pressures in the well. These simulators should be run to evaluate the pressures at various points in the wellbore. Simulators should take into account the full pressure profiles, and not simply those at TD. This is particularly important for wells with weak zones.

9.4.5.

Wellbore Considerations

9.4.5.1.

Borehole Stability

The wellbore should be stable with no gas or fluid intrusion. This implies the well is being cemented with full pressure control. If not possible, the well should be shut-in as soon as possible after cement placement. The well should be left shut-in until the cement has had sufficient time to set. The practice of bleeding off some pressure to "check for flow" must be avoided, as this merely allows more intrusion into the well, and can lead to channel formation and loss of isolation.

9.4.5.2.

Annular Gap

Annular gap (clearance) should be maximized, if possible, to increase the amount of flow area and cement coverage. For casing strings less than 7 inches, a minimum annular gap of 3/4-inch (pipe size 1.5-inch less than hole size) can normally be cemented with little trouble. Smaller annular gaps have been shown less successful. This is due to the higher friction pressures seen in these annuli, and the resulting limits on displacement rates. In addition, with small annuli, eccentering of the casing has a more pronounced effect than larger annular gaps. The use of small casing in very large annuli can give mixed results. Centralization, though at times not as effective in tighter annuli, is less of a concern with smaller casings in large holes. Minor eccentering of the casing has less effect on differential annular velocities between the wide and narrow sides of the annulus than with smaller gaps. Displacement simulations can readily demonstrate the effects of eccentering on differential flow around casing. As the annular gap reduces, there is less room for eccentering, and minor changes have a large affect on the differential velocities from the wide to the narrow side of the annulus. For example, in an 8-1/2-inch open hole, running a 7-inch casing with 20% eccentering will result in a channel on the narrow side of the annulus. Running the same simulation but with a 4-1/2-inch casing shows good mud removal throughout the entire interval.

March 2004

Company Use Only

Section 9 - 11

Mud Removal

9

Annular velocities can be limited in very large annular gaps. Care must be exercised during cleanup trips to remove all of the drill cuttings from the wellbore, as there will be little or no annular velocity with the casing in the well to effect any cuttings removal. In these situations, consideration should be given to use viscous spacers to displace the mud in plug flow, or what is also deemed effective laminar flow. The spacer should be more viscous than the mud, and the cement more viscous than the spacer. This will improve the cleaning efficiency of each fluid as it enters the annulus. When using small pipe in large hole sizes, pipe movement can be essential. If pipe rotation can be used, there is a high potential for a high-quality cement job.

March 2004

Company Use Only

Section 9 - 12

Section

Primary Cementing Cement Calculations

Scope This Section contains a description of various cement calculations related to slurry and job design. Calculations are presented that relate to cement slurry properties, primary cement job design, squeeze cement job design, and cement plug design. Foamed cement calculations are found in Section 6, Specialty Cement Systems.

Company Use Only

Cement Calculations

10

Table of Contents Tables................................................................................................................. 4 ExxonMobil Requirements ............................................................................... 5 10.

Cement Calculations................................................................................ 6

10.1.

Required References ............................................................................ 6

10.1.1. API-American Petroleum Institute.................................................................. 6 10.1.2. ISO-International Standards Organization ..................................................... 6

10.2.

Terms ..................................................................................................... 6

10.3.

Cement Slurry Calculations ................................................................. 7

10.3.1. API/ISO Mix Water ........................................................................................ 7 10.3.2. Cement Specific Gravity ................................................................................ 7 10.3.3. Absolute and Bulk Volume ............................................................................ 8 10.3.4. Reporting Additive Concentrations ................................................................ 8 10.3.5. Calculation of Slurry Density, Water Content and Yield ................................. 9 10.3.6. Slurry Calculations ........................................................................................ 9 10.3.6.1. Example 1............................................................................................. 10 10.3.6.2. Example 2............................................................................................. 11 10.3.6.3. Example 3 - Silica Calculation............................................................... 12 10.3.6.4. Example 4 - Seawater Calculation ........................................................ 13 10.3.7. Special Cement Blends ............................................................................... 14 10.3.7.1. 10.3.7.2. 10.3.7.3. 10.3.7.4.

10.4.

Example 5 - Pozzolan Calculation......................................................... 14 Salt - NaCl ............................................................................................ 15 Example 6 - Salt Calculation ................................................................. 16 Liquid Additives..................................................................................... 16

Cementing Job Calculations .............................................................. 17

10.4.1. Annular Volume........................................................................................... 18 10.4.2. Cement Volume .......................................................................................... 19 10.4.3. Water Volume ............................................................................................. 19 10.4.4. Pressure Calculations ................................................................................. 20 10.4.5. Displacement Volume ................................................................................. 20 10.4.6. Job Time ..................................................................................................... 20 10.4.7. Maximum Allowable Rates for 2-Inch Line................................................... 20 10.4.8. Job Time Safety Factors.............................................................................. 21

March 2004

Company Use Only

Section 10 - 2

Cement Calculations

10.5.

10

Operational Calculations .................................................................... 22

10.5.1. Pressure to Lift Casing ................................................................................ 22 10.5.2. Directional Force ......................................................................................... 23 10.5.3. Calculation While Pumping.......................................................................... 23 10.5.4. Balanced Plug Calculations......................................................................... 24

March 2004

Company Use Only

Section 10 - 3

Cement Calculations

10

Tables Table 10.1: Mix Water ................................................................................................... 7 Table 10.2: Absolute Volumes of Salt Concentrations (By Weight of Water) ............... 15

March 2004

Company Use Only

Section 10 - 4

Cement Calculations

10

ExxonMobil Requirements Section Number 10.4.7

ExxonMobil Requirement The maximum rate through a 2-inch treating line is 8 bpm. Rates above this require multiple lines to the wellhead.

Note: Rates above 8 bpm exceed the erosion velocity for a 2-inch treating line. Extended pumping above this limit can lead to line erosion and failure of the treating line. Exceptions to this requirement require approval by the Operations Manager.

March 2004

Company Use Only

Section 10 - 5

Cement Calculations

10.

10

CEMENT CALCULATIONS

10.1. REQUIRED REFERENCES This Section lists Practices and Standards that are generically referenced and assumed part of this document. Unless otherwise specified herein, use the latest edition.

10.1.1. API-American Petroleum Institute API Spec 10A

Specification for Cements and Materials for Well Cementing

10.1.2. ISO-International Standards Organization ISO 10426-1

Cements and Materials For Well Cementing - Part 1: Specification

10.2. TERMS Sack - A sack of cement weighs 94 pounds and has an absolute volume of 3.59 gallons. Yield - The yield is expressed in cubic feet per sack of cement. This volume includes all of the additives and mixing fluid. Water Requirement or Water Ratio - This is the amount of water required to prepare one sack of cement slurry to the design density. It is measured in gallons per sack. Density - Calculated as the final weight in pounds per gallon of the slurry when mixed with all additives and mixing fluids. Percent Additive - This is the amount of dry additive added to the cement, expressed as a percentage based on the weight of the cement (BWOC). For example, 1% additive would equate to 0.94 pounds of additive added to a sack of cement:

0.01 * 94 = 0.94 lbs Gallons per Sack - Liquid additives are expressed as gallons of additive added per sack of cement. Total Fluids - This is the total volume of water plus liquid additives used to mix the cement. By Weight of Water - Salt (NaCl) is normally expressed as a percentage based on the weight of the mix water (BWOW) rather than as a percentage by weight of cement. Cubic Foot - Standard volume used for reporting cement yields - equal to 7.48 gallons.

March 2004

Company Use Only

Section 10 - 6

Cement Calculations

10

Bulk Volume - The total volume occupied by a solid including the surrounding air. In the case of cement, one sack of cement (94 pounds) has a bulk volume of 1 cubic foot or 7.48 gallons. Bulk volumes are used to determine the amount of storage required at surface for a particular cement job. Absolute Volume - The volume occupied by a solid with no air or void spaces present. The absolute volume for cement is equal to 3.59 gallons per 94-pound sack. The absolute volume is used in the calculation of slurry volume.

10.3. CEMENT SLURRY CALCULATIONS 10.3.1. API/ISO Mix Water The API Specification 10A and ISO 10426-1 specify a particular amount of mix water for the various classes of cement. These API water contents as well as the corresponding weights are based on cement with a specific gravity of 3.15 and are a function of the surface area for the various cement classes.

Table 10.1: Mix Water Slurry Density Class

Mix Water (% BWOC)

(lb/gal)

(g/cm3)

Yield (ft3/sk)

A

46

15.6

1.87

1.18

C

56

14.8

1.77

1.32

G

44

15.8

1.89

1.15

H

38

16.45

1.97

1.05

When additives are used in the system, the water concentration may change. For cement calculations, the important considerations are the slurry density, the yield, and the amount of water required per sack of cement. All of these values are related to the amount of water in the system, and will reflect in the water to cement ratio. As this ratio changes, the permeability, strength, and other properties of the cement will change.

10.3.2. Cement Specific Gravity The specific gravity of Portland Cement will vary from approximately 3.10 - 3.25, and is a function of the raw materials used to manufacture the cement. For cement calculations to be exact, the specific gravity of the cement and all additives should be considered in the calculations. While many service companies calculate the specific gravity of the various additives in their designs, a 3.15 specific gravity of Portland Cement is normally assumed.

March 2004

Company Use Only

Section 10 - 7

Cement Calculations

10

10.3.3. Absolute and Bulk Volume The absolute volume of a material is the volume occupied by only the substance. There is no air surrounding the material. This volume is used for cement calculations for slurry design, and is normally stated in gallons per pound. The bulk volume is the volume of the material including all of the surrounding air. In cement calculations, the bulk volume is used to determine the amount of bulk storage required on location to hold a particular volume of cement. For example, the absolute volume of a sack of cement is 3.59 gallons, while the bulk volume is equal to 7.48 gallons. As various additives are added to the cement, the bulk volume will increase. Adding 35% silica to a system will increase the bulk volume of a sack of this blend by approximately 2.25 gallons, while increasing the absolute volume by approximately 1.5 gallons. The absolute volumes of many cement additives are found in the respective service company cement books, and are readily available. Additives that dissolve in water do not add much volume in their absolute form as they are used at very low concentrations. Additives like dispersants, retarders, and fluid loss agents are normally used at such low concentrations (< 1%) that their contribution is negligible, and may be left out of the calculations with very little error. Salt, however, is used at high concentrations, and is always considered in the calculations, regardless of concentration.

10.3.4. Reporting Additive Concentrations Additive concentrations are denoted in one of four ways, depending on the concentration of the additive, the additive form, and the base slurry design. Most dry additives are added as a percentage by weight of cement (BWOC). This method is also used as a calculation for the amount of water in the system. NaCl is calculated as a percentage based on the weight of water in the slurry (BWOW). This is because the contribution of the salt to the density and volume of the slurry is dependent on the volume increase of the dissolved salt. Weighting agents (e.g., barite and hematite) are often added in pounds per sack. Liquid additives are calculated as gallons per sack, or for low concentration additives, as gallons per one hundred sacks. It is critical the report of the slurry composition be very clear as to the designated units for the liquid additive. For pozzolan-containing slurries, the base cement composition is calculated as a ratio of the cement to pozzolan. A mixture designated as 50:50 pozzolan, Class A, will contain 1/2 sack of pozzolan and 1/2 sack of cement. The resulting weight of the blend is considered an equivalent sack, and all materials are calculated from this equivalent sack weight.

March 2004

Company Use Only

Section 10 - 8

Cement Calculations

10

10.3.5. Calculation of Slurry Density, Water Content and Yield There are two basic methods of slurry design. The first method uses the API water requirement, then changes to the slurry density is based on the additives used and the water requirements for each of the additives. Normally, the density of the slurry is set and the slurry properties modified with additives to meet the requirements of the well. Once the additives are selected, and their concentrations determined, the final slurry yield and water requirement are determined. This method of slurry calculation is the most common, and will be utilized throughout this Section.

10.3.6. Slurry Calculations All cement slurry calculations are based on the ratio of the weights of the cement, additives, and water to the volumes of each of these materials. The formula can be summarized as:

Density =

åWc + Wa + Ww åVc + Va + Vw

Where: Wc

=

Weight of cement

Wa

=

Weight of all additives

Ww

=

Weight of water

Vc

=

Volume of cement

Va

=

Volume of additives

Vw

=

Volume of water

Note: Volumes are absolute volumes, not bulk volumes. Note: Often the absolute volume may not be known, but the specific gravity is known or can be measured. To convert from specific gravity to absolute volume, the following formula can be used: Absolute Volume =

1 Specific Gravity * 8.33

The actual units of the calculation for density are not important as long as they are consistent throughout the formula. Weight can be in pounds, grams, or kilograms. Volume can be in gallons, liters, cubic meters, etc., but must be an absolute volume value. The final answer of density will be in a weight/volume ratio.

March 2004

Company Use Only

Section 10 - 9

Cement Calculations

10

The yield of the slurry is calculated by the formula:

Yield =

åVc + Va + Vw 7.48

For this equation, the yield is expressed in cubic feet/sack, and the volumes must be expressed in gallons. The 7.48 constant is a conversion factor of gallons to cubic feet. There are no conversion constants required for metric calculations if the units are consistent. For the purposes of most of the examples, fresh water is used in the calculations, and an assumed weight of water is 8.33 lb/gal.

10.3.6.1. Example 1 Weight (lbs)

Absolute Volume (gal/lb)

Volume (gal)

94

0.0382

3.59

Water

43.82

0.120

5.26

Total

137.82

Component Cement

Density =

137.82 = 15.6 lb / gal 8.85

8.85

Yield =

8.85 = 1.18 cu ft/sk 7.48

In Example 1, the components are known, including the water. In most of the calculations, the density is known along with the required additives, but the amount of water and the yield must be determined.

March 2004

Company Use Only

Section 10 - 10

Cement Calculations

10

10.3.6.2. Example 2 For the following example, determine the water requirement and yield for a 15.8 lb/gal slurry containing 0.2% retarder. Step 1 - As noted in the discussion, the contribution of the retarder will be very small, and will normally be ignored. For the purpose of this calculation, the only two components will be cement and water. (Note for the weight of water, a value of 8.33 lb/gal is used.)

Component

Weight (lbs)

Absolute Volume (gal/lb)

Volume (gal)

Cement

94

0.0382

3.59

Water

8.33 * X

0.120

X

Total

94 + 8.33X

Density = 15.8 =

3.59 + X

94 + 8.33X 3.59 + X

Solving for x :

15.8 * (3.59 + X) = 94 + 8.33X 56.722 + 15.8X = 94 + 8.33X 7.47X = 37.278 X = 4.99 gallons Therefore, to mix the slurry at 15.8 lb/gal, a total of 4.99 gallons of water must be used. The yield is calculated by:

Yield =

March 2004

3.59 + 4.99 = 1.15 cu ft/sk 7.48

Company Use Only

Section 10 - 11

Cement Calculations

10

10.3.6.3. Example 3 - Silica Calculation Using this same calculation method, any number of dry additives can be figured into the slurry, and the resulting water and yield requirement calculated. Most additives are added in very small concentrations will have a minor effect on the cement density or yield, and can be largely ignored in the calculations with little effect. Materials added in large amounts will have an effect and must be used in the calculations. Silica sand is an example of a material that is added in large amounts. Using the previous example, the same slurry will be calculated with the addition of 35% silica sand by weight of cement (BWOC). Note in the calculation, after the addition of the silica, one sack of blend now weighs 126.9 pounds. The weight of a sack of cement does not change.

Weight (lbs)

Absolute Volume (gal/lb)

Volume (gal)

94

0.0382

3.59

32.9

0.0456

1.5

Water

8.33 * X

0.120

X

Total

126.9 + 8.33X

Component Cement 35 % Silica

Density = 15.8 =

5.09 + X

126.9 + 8.33X 5.09 + X

Solving for x :

15.8 * (5.09 + X) = 126.9 + 8.33X 80.4 + 15.8X = 126.9 + 8.33X 7.47X = 46.5 X = 6.22 gallons Therefore, to mix the slurry containing 35% silica at 15.8 lb/gal, 6.22 gallons of water must be used. The yield becomes: Yield =

March 2004

5.09 + 6.22 = 1.51 cu ft/sk 7.48

Company Use Only

Section 10 - 12

Cement Calculations

10

10.3.6.4. Example 4 - Seawater Calculation To this point, only fresh water has been used. Using the information in Example 3, if the system were mixed with seawater, the resulting cement properties become:

Component

Weight (lbs)

Absolute Volume (gal/lb)

Volume (gal)

Cement

94

0.0382

3.59

Water

8.5 * X

0.1176

X

Total

94 + 8.5X

Density = 15.8 =

3.59 + X

94 + 8.5X 3.59 + X

Solving for x :

15.8 * (3.59 + X) = 94 + 8.5X 56.722 + 15.8X = 94 + 8.5X 7.3X = 37.278 X = 5.11 gallons Therefore, to mix the slurry at 15.8 lb/gal with seawater, 5.11 gallons of water must be used as opposed to 4.99 if the system were mixed with fresh water. The yield for the fresh water system was 1.15 and with the seawater system is:

Yield =

March 2004

3.59 + 5.11 = 1.16 cu ft/sk 7.48

Company Use Only

Section 10 - 13

Cement Calculations

10

10.3.7. Special Cement Blends Blends containing pozzolans require a different calculation basis. While the formulas are identical, the blend of pozzolan and cement is calculated on an equivalent sack basis rather than only on the weight of the cement. For example, a 50:50 Poz:Class H cement system contains 1/2 sack of pozzolan and 1/2 sack of cement. Typically, pozzolans come in one cubic foot sacks, so the volume of the equivalent sack will remain constant. Pozzolans are lighter than cement, and the resulting sack will weigh less than 94 pounds. The following example calculates a 50:50 Poz:Class H slurry with 2% bentonite and 54% water. The pozzolan being used is supplied in a 74-pound sack and has a specific gravity of 2.48.

10.3.7.1. Example 5 - Pozzolan Calculation Weight (lbs)

Absolute Volume (gal/lb)

Volume (gal)

Cement

47

0.0382

1.795

Pozzolan

37

0.0483

1.795

Bentonite

1.68

0.0454

0.076

Water

45.36

0.12

5.45

Total

131.04 lbs

Component

Density =

March 2004

131.04 pounds = 14.4 lb/gal 9.12 gallons

9.12 gallons Yield =

9.12 = 1.22 cu ft/sk 7.48

Company Use Only

Section 10 - 14

Cement Calculations

10

10.3.7.2. Salt - NaCl Sodium chloride, NaCl, requires other calculations because it is measured based on the weight of water. This is because the absolute volume of the salt varies with concentration and the solubility in water. Table 10.2 lists the absolute volume of various concentrations of salt when added by weight of water.

Table 10.2: Absolute Volumes of Salt Concentrations (By Weight of Water) Absolute Volume

March 2004

Concentration (% BWOW)

(gal/lb)

(M3/T)

2

0.0371

0.310

4

0.0378

0.316

6

0.0384

0.321

8

0.0390

0.326

10

0.0394

0.329

12

0.0399

0.333

14

0.0403

0.336

16

0.0407

0.340

18

0.0412

0.344

20

0.0416

0.347

22

0.0420

0.351

24

0.0424

0.354

26

0.0428

0.357

28

0.0430

0.359

30

0.0433

0.361

34

0.0439

0.366

37.2 (saturated)

0.0442

0.369

Company Use Only

Section 10 - 15

Cement Calculations

10

10.3.7.3. Example 6 - Salt Calculation This example will demonstrate how to calculate the amount of salt and water required for a cement system consisting of cement + 18% NaCl (BWOW) mixed at a density of 16.0 lb/gal. (From Table 10.2, the absolute volume of 18% salt is 0.0412 gal/lb.) Component

Weight (lbs)

Volume (gal)

Cement

94

3.59

18% Salt

0.18 * (8.33X)

0.0412*(0.18(8.33X))

8.33X

X

Water

Total Weight = 94 + .018 * 8.33X + 8.33X 94 + 1.5X + 8.33X 94 + 9.83X Total Volume = 3.59 + 0.0412 * 0.18 * 8.33X + X 3.59 + 0.062X + X 3.59 + 1.062X Given a density of 16.0 lb/gal, the solution for X is:

16.0 lb/gal =

94 + 9.83X 3.59 + 1.062X

Solving for X 16.0 * (3.59 + 1.062X) = 94 + 9.83X 57.44 + 16.99X = 94 + 9.83X 16.99X - 9.83X = 94 − 57.44 7.16X = 36.56 X = 5.11 gallons 5.11 is the amount of water in gallons The amount of salt needed for the slurry will be:

5.11* 8.33 * 0.18 = 7.66 lb/sk

10.3.7.4. Liquid Additives A number of slurry designs call for the addition of liquid additives. These materials are generally added as gallons per sack or gallons per one hundred sacks. Many liquid additives have a specific gravity close to water, and for most calculations, assuming the material has the same weight as water will not effect the calculations. Most service company laboratories use the actual specific gravity of each liquid additive for their

March 2004

Company Use Only

Section 10 - 16

Cement Calculations

10

calculations. This may become significant only when calculating lifting weights for offshore marine transport tanks.

10.4. CEMENTING JOB CALCULATIONS Cement jobs require a common, basic set of calculations. These include: •

The amount of cement required for the job

•

The amount of mix water

•

Differential pressures to land the top plug

•

Differential pressures at the top of a liner

•

Lift pressures for large casing sizes

•

Displacement volumes

•

Job times

Other calculations may also include the amount of bulk space required, the amount of liquid additives needed, etc. This Section covers many of these basic calculations with examples given for each. As a basis for the calculations, a single set of well conditions and a single cement slurry will be used. The basis numbers are: Depth Drilling Mud

10,000 ft 13.5 lb/gal

Casing

9 5/8" 53.5 ppf

Float Collar

9920 ft

Open Hole Previous Casing

12 1/4" 13 3/8" 54.5 ppf

Previous Casing Depth

4,000 ft

Desired top of cement

5,000 ft

Cement Excess

25%

Cement System: Density

15.8 lb/gal

Yield

1.15 cu ft/sk

Water Requirement

4.99 gal/sk

March 2004

Company Use Only

Section 10 - 17

Cement Calculations

10

10.4.1. Annular Volume Annular volumes are calculated to determine how much cement will be required to obtain a desired fill in the annulus. Usually, the volume is calculated using the bit size and adding a predetermined amount of excess to account for hole washout. This volume is then used to calculate the amount of time required to mix and place the cement. This calculation will then be used to determine the necessary thickening time of the slurry. After reaching casing point, a caliper may be run to determine the annular volume. Volumes calculated from one, two, or three arm calipers are inherently unreliable. Using a four-arm caliper is preferred. Fluid calipers may also be used on some wells. The calculated hole size can vary depending on the amount of circulation and the amount of fluid moving in the wellbore. If fluid calipers are being used, more than one caliper should be used with the results compared. Calipers should be run until the hole volume does not significantly change, which can result in long circulation times prior to cementing. Fluid calipers can consist of dyes, loss circulation materials, carbide or any other material that can be picked up on surface. The choice of fluid caliper will depend on the mud system in use. Excess volumes are added to most annular volume calculations. When cementing a casing x casing annulus, no excess is required. When cementing in an open hole, the amount of excess to add will depend on the type of job and the operational risks of having too much or too little cement. Surface Casings - These casing strings usually require cement to surface to allow for stabilization of the surface equipment, support of subsequent casings, and to potentially cover freshwater sands. The consequence of not having cement returns can range from performing a top job, to needing to log the pipe and then perforate the casing and circulate above the top of the cement. In either case, the additional cost of excess cement is small compared to the additional operational costs to correct the problem. Most surface-casing jobs will utilize at least 100% excess. Depending on area conditions, as much as 300% could be required. Offset information is important in deciding the amount of excess for these casing strings. Below surface casing, the amount of excess cement is dependent on the particular well requirements. The main selection point is to minimize the risk of either too much or too little cement in the annulus. Liner Jobs - Liners can pose an additional operational risk with regard to cement excess. For production liners, it is important to get cement through the overlap and above the top of the liner. Too much cement on top of the liner can result in problems reversing or circulating out the excess cement. In these cases, choice of excess volumes will be dependent on the amount of time required to clean out the excess cement. For most liner operations, 10% over caliper appears to be an appropriate amount of cement excess.

March 2004

Company Use Only

Section 10 - 18

Cement Calculations

10

As a reminder, the generic calculation for annular volume in bbl/ft is:

Annular Volume =

OD 2 − ID 2 1029.4

Where : OD = Outside Diameter (inches) : ID = Inside Diameter (inches)

10.4.2. Cement Volume Based on the annular volume determined either through calculation or from a caliper log, the amount of cement required for the job is determined. The excess percentage is determined and the total volume corrected to that amount. Using the example basis:

12.25 2 − 9.625 2 = 0.05578 bbl/ft 1029.4 Annular Volume = 0.05578 bbl/ft ∗ 5000 ft = 280 bbl Desired Excess = 25% Cement Volume = 280 bbl ∗ 1.25 = 350 bbl Cement Volume = 350bbl ∗ 5.61cuft/bbl = 1964 cubic feet Annular Volume =

Sacks of Cement = 1964 cu ft ÷ 1.15 cu ft/sk = 1708 sacks Seventeen hundred and eight (1,708) sacks will be required to place 5,000 ft of cement into the annulus. The volume of the casing shoe track must also be added to this volume. This is because cement will need to fill the volume inside the casing from the float collar to the end of the casing. (In this case, the last 80 ft of casing.)

8.535 2 Csg Volume = ∗ 80 ft = 5.66 bbl 1029.4 5.66 bbl = 31.8 cu ft = 28 sacks Total cement required for job = 1736 sacks

10.4.3. Water Volume For each sack of cement in the example, a total of 4.99 gallons of water must be used to mix the cement to the proper density. The total amount of mix water required for this example will be:

Water Volume = 1736 ∗ 4.99 = 8663 gallons Water Volume = 8633 gallons ÷ 42 gal/bbl = 206 bbl

March 2004

Company Use Only

Section 10 - 19

Cement Calculations

10

The minimum water volume required on location will need to have some safety factor to allow for pump suctions, wash up, etc. For most applications, at least 50 bbl of excess water volume should be ready for the cement job.

10.4.4. Pressure Calculations Assuming the casing is displaced with mud, and the only fluids in the annulus are either mud or cement, the differential pressure on the casing shoe at the end of the job will be:

Annular Pressure = (5000 ∗ .052 ∗ 13.5) + (5000 ∗ .052 ∗ 15.8) = 7618 psi Internal Pressure = (9920 ∗ .052 ∗ 13.5) + (80 ∗ .052 ∗ 15.8) = 7030 psi Differential Pressure at Shoe = 7618 - 7020 = 588 psi

10.4.5. Displacement Volume The displacement volume for the job is based on displacing the column of cement to the bottom of the casing string.

Displacement Volume =

8.535 2 ∗ 9920 ft = 702 bbl 1029.4

10.4.6. Job Time Job time is the amount of time required to mix and pump all of the cement, plus the time to displace the cement into the well. Estimation of job time requires assuming a particular mixing rate as well as a displacement rate. As a rule of thumb, the mixing rate for most cement slurries can be estimated at 5 6 bpm. High-density slurries may require lower rates, but the time difference will normally be quite small. For example, to mix 100 bbl of cement at 4 bpm takes 25 minutes, and 17 minutes at 6 bpm. Displacement rates will depend on the casing size, friction pressures in the well and pump capabilities. Maximum displacement rates are approximately 6 - 8 bpm, and for most jobs, a minimum rate would be 3 bpm. Displacement rate can have a major effect on calculated job time because of the large volume required. The selection of displacement rate will normally govern the job time.

10.4.7. Maximum Allowable Rates for 2-Inch Line For a single 2-inch treating line, the maximum rate is approximately 8 bpm. This rate is stated in all of the service company's safety manuals. Above this rate, the fluid will erode the metal in the treating line. If high mixing or displacement rates are anticipated, multiple lines should be used on location.

March 2004

Company Use Only

Section 10 - 20

Cement Calculations

10

10.4.8. Job Time Safety Factors After determining the job time, a safety factor is added to account for uncertainties on location. Depending on the length of the job, the safety factor can vary from as short at 30 minutes to several hours. Engineering judgment must come into play with the selection of an appropriate safety factor. Some service companies have assigned an arbitrary safety factor or minimum additional time whichever is greater. For example, the company may require the minimum acceptable thickening time for cement will be the job time times 1.4, or job time plus two hours, whichever is longer. Using these criteria, a job that will take 4 hours to place, would have a minimum thickening time requirement of 6 hours. (This is because 1.4 times the 4-hour job time would be 5:36, which is less than 6 hours.) Calculating longer times can result in exceedingly long requirements for thickening times. Large and/or long casing strings may require job times of 8 to 10 hours. Using this same 1.4 criterion, the minimum acceptable thickening time would be on the order of 11-1/2 to 14 hours. Trying to set arbitrary standards for minimum safety factors can result in unrealistic thickening times. The following table can be used as a guideline for determining safety factor. This table does not take into account specific field limitations or well conditions, and should be used ONLY as a guide. Calculated Job Time

Minimum Safety Factor

Less than 2 hours

1 hour

2 - 4 hours

1 - 1.5 hours

4 - 8 hours

1.5 - 2 hours

8 - 12 hours

2 - 3 hours

> 12 hours

3 - 4 hours

Using the example, the job time for this cement job would be: Cement volume

356 bbl

Mixing rate Time to mix cement

5 bpm 71 min

Displacement volume

702 bbl

Displacement rate

6 bpm

Time to displace Total job time

117 min 188 min (approximately 3 hours)

Safety factor

1 - 1.5 hour

Requested thickening time

4 - 4.5 hours

The requested thickening time for the cement design incorporates the job time, plus the safety factor. A wider range for thickening time is given to allow the cement service

March 2004

Company Use Only

Section 10 - 21

Cement Calculations

10

company more latitude in slurry design. Because of the variations in cement, requesting a narrow window for thickening time may not be realistic or wise.

10.5. OPERATIONAL CALCULATIONS Two additional calculations that will be required for specific jobs include pressures to lift large casing sizes and plug placement. Some job designs can result in the buoyed weight of the casing being such that the casing can be pumped out of the hole. Ensuring this does not occur is critical. Operations where this can occur include: •

Lightweight pipe

•

Short pipe lengths

•

Large diameter pipe

•

High density cement slurries

•

Lightweight displacement fluids

These conditions are often encountered when cementing surface or conductor casings.

10.5.1. Pressure to Lift Casing The pressure required to lift the casing out of the well will be a function of the following: Pipe weight Cross sectional area of the pipe calculated from the outside diameter Cross sectional area of the interior of the pipe Weight of fluid in the annulus Weight of fluid inside the pipe The calculation for determining lift pressure is:

∆F = ( Ph ∗ A) − (Wc + Wd ) where : ∆F =

Directional force

Ph =

Hydrostatic pressure in the annulus (psi)

A

Cross sectional area of casing OD (in2)

=

Wc =

Casing weight (lbs)

Wd =

Weight of fluids inside casing (lbs)

March 2004

Company Use Only

Section 10 - 22

Cement Calculations

10

10.5.2. Directional Force The directional force, if negative, will indicate the casing will not move out of the well during the operation. A positive force value indicates the casing can be pumped out of the hole, and additional steps must be taken. These can include chaining down the casing, changing the density of the displacing fluid, or reducing the annular fluid density.

10.5.3. Calculation While Pumping When pumping, the pump force must be included in this equation. The pump pressure will act only on the ID of the casing. While pumping, the force calculation will be:

∆F = [( Ph ∗ A) + ( Pp ∗ a )] − (Wc + Wd ) where : Pp = Pump Pressure (psi)

a = ID cross section area (in 2 ) Example: Depth:

800 ft

Casing Size:

13 3/8 61 lb/ft (ID = 12.525 in)

Cement Density:

14.8 lb/gal

Mud Density:

8.33 lb/gal

The casing is to be cemented to surface.

Pp = 800 ft * 0.052 * 14.8 lb/gal = 616 psi A = (13.375 2 * π/4) = 140.5 in 2 Wc = 800 ft * 61 lb/ft = 48,800 lbs Wd = 800 ft * .052 * 8.33 lb/gal * 12.515 2 * π/4 = 42, 627 lbs ∆F = (616 psi * 140.5 in 2 ) - (48,800 lbs + 42,627 lbs) ∆F = 86,548 lbs - 91,427 lbs = - 4,879 lbs This means that in a static state, the casing weight will be pulling down with a force of approximately -4,900 lbs. During the job, pump pressure will be required to place the cement. calculation using the pump pressure will be:

The force

Pp = (14.8 * .052 * 800) - (8.33 * .052 * 800) = 616 - 346 = 270 psi (The calculation of Pp is the calculation of differential pressure at the shoe when the plug bumps as discussed earlier.)

March 2004

Company Use Only

Section 10 - 23

Cement Calculations

10

The 270-psi force will be acting on the inside of the casing:

Pumping Force = 270 * 12.515 2 * π/4 = 33,214 lbs ∆F while pumping = - 4,879 + 33,214 = + 28,317 lbs This shows the pump pressure will be sufficient to lift the casing out of the well with a force of over 28,000 lbs. This example used a single weight fluid in the annulus and casing. Field calculations should take into account the weights and pressures of all fluids in the system. An alternate way to calculate this is to take the surface area of the casing, and divide it into the downward force. This will be the force required (in psi) to lift the casing. Any pressure above that value will result in the casing being pumped out of the hole. For the above example, the downward force was approximately 4,900 psi. The cross sectional area of the casing was 140.5 square inches.

4900 = 35 psi 104.5 Therefore, any pump pressure above 35 psi will cause the casing to be pumped out of the well.

10.5.4. Balanced Plug Calculations See Section 12, Plug Cementing, for example plug calculations.

March 2004

Company Use Only

Section 10 - 24

Section

Primary Cementing Liner Cementing

Scope This Section covers the types and purposes of liners, common liner cementing problems, design considerations and liner cementing techniques. Part of this Section contains a separate report on liner top packers. As liner top packers are commonly used in many liner applications, it is included here as the use of a liner top packer affects the design of the cement system.

Company Use Only

Liner Cementing

11

Table of Contents Figures ............................................................................................................... 3 ExxonMobil Requirements ............................................................................... 4 11.

Liner Cementing....................................................................................... 5

11.1.

Required References .................................................................................... 5

11.1.1. API-American Petroleum Institute .............................................................. 5 11.1.2. ISO-International Standards Organization .................................................. 5 11.2. Types of Liners.............................................................................................. 5 11.2.1. Drilling Liners ............................................................................................. 5 11.2.2. Production Liner ......................................................................................... 6 11.2.3. Scab Liner.................................................................................................. 6 11.2.4. Tieback ...................................................................................................... 6 11.3. Liner Equipment ............................................................................................ 6 11.3.1. Liner Hangers ............................................................................................ 6 11.3.2. Liner Setting Tool ....................................................................................... 6 11.3.3. Liner Wiper Plugs....................................................................................... 7 11.4. Design Considerations .................................................................................. 7 11.4.1. Annular Gap............................................................................................... 7 11.4.2. Cement Contamination............................................................................... 7 11.4.3. Pipe Movement .......................................................................................... 8 11.4.4. Temperature Differences............................................................................ 8 11.4.5. Temperature Determination ....................................................................... 8 11.4.6. Slurry Testing............................................................................................. 9 11.4.7. Centralization ............................................................................................. 9 11.4.8. Liner Overlap ........................................................................................... 10 11.5. Cement Slurry Design ................................................................................. 10 11.6.

Liner Cementing Techniques....................................................................... 11

11.6.1. 11.6.2. 11.6.3. 11.6.4. 11.6.5. 11.6.6.

March 2004

Conventional Liner Cementing ................................................................. 11 Planned Squeeze..................................................................................... 12 Tack and Squeeze ................................................................................... 12 Conventional Planned Squeeze ............................................................... 12 Full Coverage Cementing......................................................................... 13 Liner Top Packers .................................................................................... 13

Company Use Only

Section 11 - 2

Liner Cementing

11

Figures Figure 11.1: Multiple Temperature Gradients ................................................................ 9

March 2004

Company Use Only

Section 11 - 3

Liner Cementing

11

ExxonMobil Requirements Section Number

ExxonMobil Requirement

There are no ExxonMobil requirements in this Section.

March 2004

Company Use Only

Section 11 - 4

Liner Cementing

11.

11

LINER CEMENTING

11.1. REQUIRED REFERENCES This Section lists Practices and Standards that are generically referenced and assumed part of this document. Unless otherwise specified herein, use the latest edition.

11.1.1. API-American Petroleum Institute API RP 10B

Recommended Practice for Testing Well Cements

11.1.2. ISO-International Standards Organization ISO 10426-2

Cements and Materials for Well Cementing - Part 2: Testing of Well Cement

11.2. TYPES OF LINERS A liner is a string of casing that does not directly connect the bottom of the well with the surface. Liners typically extend from the bottom of the well to 300 - 500 ft inside the last casing string. At this point, a liner hanger is installed and the weight of the casing is hung from the hanger. A liner tieback is a casing string that extends from the top of a previous liner back to the surface. It seals in the top of the previous liner through seals set into a tieback receptacle (or polished bore receptacle (PBR)). Liners are set for a number of reasons. One major benefit to a liner can be the reduced costs of setting a liner rather than running a full string of casing back to surface. This is particularly the case with drilling liners. A liner can be cheaper than a full string of casing unless there is a need to squeeze the liner top, etc. Another key advantage of a liner is the ability to case-off the open hole while maintaining wellhead space. Many wellheads can only accommodate a limited number of casing strings.

11.2.1. Drilling Liners Drilling liners are used to allow for deeper drilling by isolating nonproductive intervals, and to control problem formations. A drilling liner generally does not cover productive hydrocarbon zones, and formation isolation behind the casing is often not critical. The cementing objectives of a drilling liner are to obtain a good shoe test and top of liner seal.

March 2004

Company Use Only

Section 11 - 5

Liner Cementing

11

11.2.2. Production Liner As indicated by the name, a production liner is set across producing intervals in the well. It is usually one of the last casing strings set in the well, and successful cementing of this liner can be critical to the success of the well. A production liner is typically run to limit the weight of casing being run in the well. This can be due to rig limitations, excessive drag that would be experienced by a full casing string, or inability to manipulate a full casing string when at depth.

11.2.3. Scab Liner A scab liner is a short section of casing set across a problem area in the well that has previously been cased and cemented. A scab liner is designed to regain casing integrity over a relatively short section of pipe.

11.2.4. Tieback A liner tieback is run to connect the top of a production liner back to surface. A tieback is run to protect previous casing strings that may not be adequate for production loads, to provide added protection for pressure or corrosion.

11.3. LINER EQUIPMENT 11.3.1. Liner Hangers A liner hanger is used to hang-off the liner in the previous casing string. It consists of a set of slips or mechanical holding devices that grip the outer casing and support the liner. Liner hangers can also have integral liner top packers that are energized at the end of the cement job. There are two types of liner hangers, mechanical and hydraulic. Mechanical hangers depend on physical movement of the running string to set the liner hanger. A hydraulic hanger depends on pump pressure to actuate the liner hanger. For many extended reach and high angle wells, a hydraulic liner hanger is preferred. This is because of the uncertainties in being able to set the proper amount of weight down on the liner to energize the slips. A tieback receptacle or polished bore receptacle (PBR) is usually installed on top of the liner to facilitate tieback of the liner when required.

11.3.2. Liner Setting Tool The liner setting tool provides the connection between the liner and the running string (typically drill pipe). The liner setting tool or running tool is provided by the liner hanger company, and is removed from the well following the cement job. It is usually released from the liner by mechanical movement of the drill string.

March 2004

Company Use Only

Section 11 - 6

Liner Cementing

11

The setting tool must provide a seal between the tool and the liner. This is usually accomplished by using a pack-off bushing, swab cups, or some other type of packing element.

11.3.3. Liner Wiper Plugs As the liner is run on drill pipe, unlike conventional casing strings, the plugs cannot be pumped down from surface. Carried in the liner-running tool are special wiper plugs that are hollow to allow circulation of the liner. A drill pipe dart is released from surface and will latch into the liner wiper plug, releasing it from the running tool. This provides a plug to wipe the interior of the liner. Many liner hangers and liner jobs will use only the top plug. There are double-plug liner wiper systems available, and if possible, it is recommended a two-plug system be used. However, there is an additional risk to using a double-plug system due to the mechanical complexity.

11.4. DESIGN CONSIDERATIONS 11.4.1. Annular Gap Correlations have been made for cementing success as it relates to annular gap. Success rates tend to increase with increasing annular gap, with the highest success being seen at gaps of 1 - 1.5 inches. This correlates to a hole size of 2 - 3 inches larger than the casing OD. In liner situations, the clearance between the pipe and hole are rarely as large as desired. Commonly, there is less than one-inch annular clearance. Because of this, centralization, pressure control, and mud removal are all more challenging. When given a choice, from a cementing standpoint, additional annular gap is preferred. This can be obtained by underreaming the hole, use of smaller casing, or use of bicentered bits to drill the interval. Each of these choices carry additional cost, and in the case of smaller casing, may not allow the well to be drilled to TD, or can limit production options. Rarely is there an option to change the annular gap for liner cementing. Faced with reduced annular gaps, the adherence to other good cementing practices becomes more important in liner cementing.

11.4.2. Cement Contamination On jobs where there is no bottom plug, there is additional potential for intermixing the cement and mud inside the casing. This leads to excessive contamination of the cement that will ultimately be at the top of the liner in the overlap. Running sufficient spacer and additional excess cement can help reduce this problem. There is also concern the top plug will pick up a mud film left on the casing and contaminate the liner shoe, though it is unlikely this is a major source of cementing problems. While a potential problem, running sufficient shoe track can prevent this from

March 2004

Company Use Only

Section 11 - 7

Liner Cementing

11

becoming a problem on the well. It should be noted that running sufficient spacer ahead of the cement would also help remove mud from inside the casing and further reduce any film problem that may exist. The cost of additional spacer and cement should be weighed against the added cost for drilling out excess shoe tracks.

11.4.3. Pipe Movement If possible, rotation of the liner during cementing should be attempted. Rotating liner hangers are readily available and quite reliable. As the liner hanger is set prior to cementing, reciprocation of the liner is not possible during cementing. The use of a liner top packer should not restrict rotation of the liner during cementing. Proper selection of liner hanger equipment will allow rotation. A more detailed discussion of this topic is found in the LTP report found on the Drilling Technical GlobalShare and the Drilling Technical Intranet website. The use of a rotating liner hanger is preferred over a "delayed release technique" where setting the liner hanger is delayed until after the cement job. While this technique allows for pipe movement during the job, the added operational risks are usually not justified.

11.4.4. Temperature Differences In liner cementing, as with all primary cementing, the cement must be retarded for the bottomhole circulating temperature (BHCT) of the well. Unlike many primary jobs, of additional importance in liner cementing is strength development at the top of the liner. Depending on the length of the liner, the temperature at the top of the liner can be considerably lower than the BHCT of the well. This can result in very long WOC times for the top of the liner (TOL).

11.4.5. Temperature Determination It is common to assume a single temperature gradient in a well. This can cause severe problems in liner cementing, as many of the liners are set through pressure transitions. As formations trap pressure, the temperature profile will also change. This can result in multiple gradients through the wellbore.

March 2004

Company Use Only

Section 11 - 8

Liner Cementing

11

Depth

Figure 11.1: Multiple Temperature Gradients

Temperature

Figure 11.1 is an example of multiple gradients in a well. While the temperature at the bottom of the well is identical in both situations, assuming a constant gradient throughout the well would result in over-estimation of the temperatures in the intermediate portions of the well. As noted above, this can result in over-estimation of the temperature at the top of a liner. As with other cement designs, accurate temperature prediction is critical. Use of temperature data from the well, use of temperature simulators, or other means of estimating the wellbore temperature will improve cementing results.

11.4.6. Slurry Testing Static formation temperatures at the top of the liner are commonly used to test for strength development. Because a well does not return to static conditions for at least 24 hours after circulating, the test temperature should be adjusted to account for the cool down. As noted in the cement testing section, using 85% of the static temperature is recommended. Conditioning the slurry at BHCT prior to performing strength testing at the TOL will allow the retarders to react, and will give a better indication of strength development. API RP 10B contains specialized protocols for testing cement for use on long liners. The cement slurry should always be tested for strength development at the top and bottom of the liner.

11.4.7. Centralization Small annular gap calls for good centralization as any offset can prevent placing cement around the pipe. Centralizers will also aid in preventing differential sticking of the liner and aid in getting the liner to bottom.

March 2004

Company Use Only

Section 11 - 9

Liner Cementing

11

Centralizers are often left off liners because of fear of excessive drag forces. While the weight of the casing is supported on a smaller area, the total force remains the same. What is not considered is the presence of permeable formations, and the reduced contact area will help prevent sticking of the liner. Centralization of the casing may not be possible due to the very small annular gap. In some cases, use of rigid centralizers is preferred. These centralizers cannot provide 100% standoff, but will assure some degree of standoff in the well. Care must be exercised in running solid centralizers as these can further reduce the annular clearance and lead to higher displacement pressures, and lost circulation in some cases. Rotating the liner will definitely improve cementing results. To aid in liner rotation, Weatherford has developed a rotating centralizer that can reduce the torque required for rotation by as much as 65%. Use of these devices is highly recommended if it will allow for liner rotation.

11.4.8. Liner Overlap The area in the well between the top of the liner and the previous casing shoe is called the overlap. In this area, the annulus is a pipe x pipe configuration, and cement in this area is responsible for giving a seal at the top of the liner. As the cement that will be placed in the overlap has traveled further in the well than any other, it has the highest potential for contamination. Because of this, sufficient overlap should be run to get a seal. A minimum of 100 ft of overlap and preferably 300 - 500 ft of overlap should be allowed. Additional factors may dictate the required length of the overlap. These include: •

Collapse loading of the outer casing

•

Burst loading of the outer casing

•

Consideration of trapped annulus fluids in the overlap

11.5. CEMENT SLURRY DESIGN The tight annular clearances in liners require the use of fluid loss control. Fluid loss values of 100 - 150 mL are recommended. If gas migration is a potential problem, the fluid loss should be dropped to less than 50 mL, preferably with a latex additive. Lost circulation materials should not be used in liner cement designs. Dispersants may be required in the slurry design to reduce the frictional pressures from the cement. Care must be exercised to prevent overuse of dispersants for the sole purpose of friction reduction. This can lead to excessive free water and settling of the solids in the slurry.

March 2004

Company Use Only

Section 11 - 10

Liner Cementing

11

The thickening time of the slurry must be sufficient to allow for pulling out of the running string at the end of the job. This is not usually a problem as the temperature at the top of the liner is normally less than the BHCT. If a liner top packer is being set after cement placement, an additional test should be performed to evaluate the gel strength development at the top of the liner. This test is performed on a consistometer by taking the slurry to BHCT, holding it at that temperature for 10 minutes, then cooling the cement to the circulating temperature at the top of the liner. The cool off rate would correspond to the anticipated placement time for the cement. When the cement reaches the temperature at the top of the liner, the motor of the consistometer is turned off for 10 minutes. After 10 minutes, restart the motor and check for excessive gellation.

11.6. LINER CEMENTING TECHNIQUES Primary cement jobs attempt to place cement into the annulus in a single stage, or as a single continuous operation. Often liner cementing does not allow for this conventional approach and requires preplanning for squeezing cement in the overlap at the top of the liner. From the viewpoint of cementing, there are four main cementing techniques for liners. It is assumed that for each of the cement job types discussed the liner hanger has been set prior to cementing. As noted in the section on pipe movement, some operations in the past have performed the cement job prior to setting the liner hanger to facilitate pipe movement. This process is not recommended unless there is a specific technical need for the added risk.

11.6.1. Conventional Liner Cementing The liner hanger is set, and then the drill pipe is pulled up a short distance to be certain the running string is free and the hanger has set. The cement is conventionally pumped using either one or two plugs, depending on the liner hanger design. The volume of cement planned for the job should cover the open hole, the overlap, and some distance above the top of the liner. Three hundred feet (300 ft) of cement should be placed above the top of the liner. This allows any contaminated cement to be circulated above the top of the liner, increasing chances for a good seal in the overlap. (The 300-ft volume should be calculated as the volume without the drill pipe in place.) After the cement is in place, the running string is released from the liner, and 10 stands are pulled out of the hole. The well can be circulated at this point to be sure the casing is clear prior to pulling out of the hole. The pressures should be monitored closely to be sure the shoe of the previous casing is not broken down during this process. The circulation path can be through either reverse or conventional circulation. Reverse circulation takes less time, but does have limitations. Normally, the annular is closed while reverse circulating, thus limiting, or eliminating the opportunity to rotate the drill pipe during circulation. In addition, while lining up to reverse, the cement is in a static state longer than if conventional circulation is used.

March 2004

Company Use Only

Section 11 - 11

Liner Cementing

11

Alternately, the well can be conventionally circulated following the liner job, which offers several advantages. Conventional circulation will result in lower pressures being exerted on the well, which can prevent squeezing the liner top, or if the plug did not bump, reduces potential for placing additional mud out of the bottom of the liner. The time to line-up to continue pumping is very short, and the drill pipe can be moved during circulation. Conventional circulation will take longer, which can be a concern with respect to slurry pump times. For long jobs, it is recommended the cement be tested at BHCT for the anticipated job time, the temperature reduced to the BHCT at the top of the liner, and the test continued for the anticipated circulation time. Normally, there should be sufficient time for conventional circulation of the cement due to the temperature differences from the bottom of the well to the TOL. Sufficient pump time may be a concern with very long cement placement times. Alternately, the running string can be simply pulled out of the well without circulation. If there is spacer and cement above the top of the liner (as desired in the design), when the drill pipe is pulled out of the top of the liner, the well will tend to U-tube up the drill pipe. The rig crew should be prepared to handle the mudflow at this point.

11.6.2. Planned Squeeze There are three types of planned squeeze jobs with liner cementing. The types are Tack and Squeeze, Conventional Planned Squeeze, and Full Coverage Cementing.

11.6.3. Tack and Squeeze For drilling liners that do not require cement over the entire length of the liner, performing a job with a planned squeeze can save time and money. The process is the same as in conventional cementing, except the volume of cement is limited to cover only the lower portion of the liner. After placement of this cement, the drill pipe is pulled up above the top of the liner, the annular closed, and a squeeze job performed on the liner lap. This process tacks the bottom of the casing, which should give isolation at the shoe, and isolates the overlap in a second job.

11.6.4. Conventional Planned Squeeze The difference in this technique and a tack and squeeze is the volume of cement pumped initially is larger, and generally consists of a full liner annular volume of cement. The job attempts to cover the entire open hole, as in conventional liner cementing, but incorporates a planned squeeze job on the liner lap at the end of the primary cement job. This involves performing the job conventionally and then following the liner job, a volume of mud is injected to clear the overlap. There must be sufficient mud injected to account for the excess cement on top of the liner. At this point, additional cement is mixed and a squeeze job performed at the top of the liner.

March 2004

Company Use Only

Section 11 - 12

Liner Cementing

11

11.6.5. Full Coverage Cementing If there is a single loss zone in the well, a technique can be applied that can give full cement coverage in the liner. With this method, a squeeze packer is run on the drill pipe above the liner hanger, which can be set after pulling out of the liner top. The first stage consists of pumping a conventional liner job. The difference is when the spacer reaches the shoe of the liner, the annular is closed. (Depending on liner volumes, the annular may be closed prior to this point.) This will bullhead cement into the lost circulation point of the annulus. The reason for closing the annular is to force cement into the zone and prevent cement from moving above the loss zone. Because there is full control of the well, and no worry about lost returns, the job can be displaced at high rates. This will improve mud removal and cement placement. After disengaging the setting tool, pump 30 bbls of mud down the annulus to ensure it is clear of any cement that may have gotten above the loss zone. Then flush the cement down the fracture so it is less likely to change the stress in the original loss zone. The drill pipe is then pulled up, the packer set, and another full volume of cement is squeezed in the annulus. Again, because there is full well control, the cement can be squeezed at a high rate. An additional benefit from this technique is in the selection of spacers. Because the well is always under control, there is no worry about lightweight spacers. This technique allows for running large amounts of water ahead of both stages of cementing. This further enhances mud removal and cement placement.

11.6.6. Liner Top Packers Liner top packers (LTP) seal the annulus between the liner hanger and previous casing string. This isolates the annulus so that high pressure can be applied to the liner top to reverse all of the excess cement out from above the liner. This eliminates the rig time required to drill out cement. High-pressure LTPs also eliminate the potential cost of liner top squeezes. They may also be used in place of production packers in some monobore designs. Cementing designs for LTPs differ from open liner tops in two aspects. One is the likelihood of microannuli developing is greater due to the early loss of hydrostatic head and effective stress. The other is the set time at the liner top must be adequate to accommodate the reversing operations. The potential for microannuli to develop is addressed by the use of gas resistant slurries for all strings where an LTP will be set. Annular gas flow is most commonly caused by the loss of effective sealing stress between the cement and casing or borehole due to shrinkage of the cement. The cement starts to lose volume as soon as it is in place due to filtrate loss and the uptake of water in the setting process. In the early stages, the mud and cement columns shift downward to replace these losses and hydrostatic pressure is maintained. After the cement sets sufficiently, its gel strength prevents this movement, the shrinkage is not offset, and effective stress starts to decline. The introduction of an LTP prevents the column movement and pressure support that would normally occur in the early set period. In the end, this results in greater loss of effective stress in the final set material, and increased likelihood of annular gas flow.

March 2004

Company Use Only

Section 11 - 13

Liner Cementing

11

The recommended gas slurry additive for most LTP applications is latex. Latex reduces the water loss, has a low shrinkage coefficient, and increases the elasticity of the cured cement. To date, field problems have not been seen where latex is used in standard quantities (0.75 - 1.5 gps and FL < 50 mL). The additional pumping time required to set the LTP and reverse out should be included in the design. This is less than one hour in most cases. The LTP should be set in under 30 minutes, and because the cement is being reversed up the drill pipe the volume required to bring it to surface is not great. Over-retardation should also be avoided because it will increase the likelihood of the development of micro annuli beneath the packer.

March 2004

Company Use Only

Section 11 - 14

Section

Primary Cementing Plug Cementing

Scope This Section contains design and placement of cement plugs. Included in this Section are calculations to properly balance a plug in the well.

Company Use Only

Plug Cementing

12

Table of Contents ExxonMobil Requirements ............................................................................... 4 12. 12.1.

Plug Cementing........................................................................................ 5 Required References ............................................................................ 5

12.1.1. API-American Petroleum Institute.................................................................. 5 12.1.2. ISO-International Standards Organization ..................................................... 5

12.2.

Types of Plugs....................................................................................... 5

12.2.1. Abandonment................................................................................................ 5 12.2.2. Kick-Off or Whipstock .................................................................................... 5 12.2.3. Formation Isolation........................................................................................ 6 12.2.4. Lost Circulation ............................................................................................. 6

12.3.

Slurry Design......................................................................................... 6

12.4.

Cement Slurry Composition For Specific Types of Plugs ................. 7

12.4.1. Abandonment................................................................................................ 7 12.4.2. Whipstock or Kick-Off Plug ............................................................................ 7 12.4.2.1. Use of Sand and Silica Flour in Whipstock Plugs .................................... 7 12.4.3. Formation Isolation........................................................................................ 8 12.4.4. Lost Circulation ............................................................................................. 8

12.5.

Plug Placement Techniques................................................................. 8

12.5.1. Balanced Plug ............................................................................................... 8 12.5.2. Two-Plug Method .......................................................................................... 8 12.5.3. Dump Bailer .................................................................................................. 9

12.6.

Job Design............................................................................................. 9

12.6.1. What is Below the Plug ................................................................................. 9 12.6.2. Temperature................................................................................................ 10 12.6.3. Use of a Stinger .......................................................................................... 10 12.6.4. Run a Diverter ............................................................................................. 11 12.6.5. Cement Volume .......................................................................................... 11 12.6.5.1. Plug Length........................................................................................... 11 12.6.6. Mixing.......................................................................................................... 11 12.6.7. Spacers....................................................................................................... 11 12.6.8. Pipe Movement ........................................................................................... 12

March 2004

Company Use Only

Section 12 - 2

Plug Cementing

12

12.6.9. Use of Scratchers........................................................................................ 12 12.6.10. Displacement ........................................................................................... 12 12.6.11. Waiting on Cement (WOC) Time.............................................................. 12

12.7.

Balanced Plug Calculations ............................................................... 12

12.7.1. Example Balanced Plug Calculation ............................................................ 14

March 2004

Company Use Only

Section 12 - 3

Plug Cementing

12

ExxonMobil Requirements Section Number

ExxonMobil Requirement

There are no ExxonMobil requirements in this Section.

March 2004

Company Use Only

Section 12 - 4

Plug Cementing

12.

12

PLUG CEMENTING

12.1. REQUIRED REFERENCES This Section lists Practices and Standards that are generically referenced and assumed part of this document. Unless otherwise specified herein, use the latest edition.

12.1.1. API-American Petroleum Institute

12.1.2. ISO-International Standards Organization

12.2. TYPES OF PLUGS Plugs are used in wells for a variety of reasons. Plug cementing is primarily concerned with strength development. Assuming the plug is placed properly, the definition of success in plug cementing hinges on strength development. The most common reasons for setting plugs are abandonment, kick-off or whipstock, or formation isolation, or lost circulation.

12.2.1. Abandonment Every well will eventually be plugged and abandoned. There are a number of regulations that address the proper abandonment of wells, and are generally written to ensure proper isolation of hydrocarbon zones, protection of fresh water areas, and pressure isolation of the wellbore. It is imperative that local regulations be checked for the proper plugging requirements.

12.2.2. Kick-Off or Whipstock Whether to drill around lost materials in the hole, or for some geologic reason, a sidetrack plug is used to give a hard base to the well from which to change the drilling direction. This is accomplished using directional drilling equipment, but usually requires the use of a high-strength cement plug. A kick-off plug is one of the few cement designs that call for high strength when possible, and may be one of the few times where paying more for strength makes economic sense.

March 2004

Company Use Only

Section 12 - 5

Plug Cementing

12

12.2.3. Formation Isolation Used primarily to isolate different portions of the wellbore, a cased hole plug is employed to cover perforations, or isolate unwanted zones. This is commonly performed during workover operations, but is also utilized during drilling operations, particularly following well testing.

12.2.4. Lost Circulation In areas of severe lost circulation, cement plugs have sometimes been used with success to isolate the loss zone. This can include setting a plug, then drilling through the plug in an attempt to use the cement sheath as an artificial formation. This requires incorporation of specialty additives to prevent sloughing of the drilled cement. Depending on the type of lost circulation, the purpose of the cement plug varies. If the loss is due to vugular formations, the cement is used to fill the voids. For fracture propagation, cement is used to build fracture closure stress, and should always be designed for hesitation squeezing to maximize the width achieved. For more information on use of cement in lost circulation situations, refer to the FCS Workshop Manual and lost circulation response plans found on the Drilling Technical GlobalShare or Drilling Technical website.

12.3. SLURRY DESIGN Depending on the purpose of the plug, the slurry design will vary slightly. Most plug designs can be accomplished using cement, water, and retarder. Few, if any, other additives are required. In the event high density and strength are required, then the judicious use of a cement dispersant may be necessary. All materials that do not contribute to the development of strength should be deleted from the slurry design. Unless a plug is required to be stable for very long time periods, the use of sand or silica flour is not recommended. Usually, these materials only act to dilute the cement, and can result in a more friable system that will not drill well. For deviated wells, free water control is essential. Fluid loss control is generally not required for plug cementing.

March 2004

Company Use Only

Section 12 - 6

Plug Cementing

12

12.4. CEMENT SLURRY COMPOSITION FOR SPECIFIC TYPES OF PLUGS

12.4.1. Abandonment BHST < 230°F (110°C) Slurry:

Cement + retarder if required

Thickening Time: Placement time + 30 - 45 min assuming drill pipe can be extracted in less than 30 min. Fluid Loss:

None Required

Free Water:

Zero at BHCT and well angle

Strength:

Minimum 500 psi

BHST > 230°F (110°C) Slurry:

Cement + 35% silica flour + retarder

Other properties as above

12.4.2. Whipstock or Kick-Off Plug Slurry:

Cement + Dispersant if required for density

Density:

Higher is better without requiring weighting agents.

Thickening Time: As in Abandonment (12.4.1) Fluid Loss:

None Required

Free Water:

Zero at BHCT and well angle

Strength:

Minimum of 500 psi, if using a mechanical whipstock. Otherwise, 3,000 psi is acceptable for most operations.

12.4.2.1. Use of Sand and Silica Flour in Whipstock Plugs Sand and silica flour are added to prevent strength retrogression at temperatures above 230°F (110°C). Below this temperature, the materials act as fillers and do not contribute to strength development. Silica sand reacts very slowly at elevated temperatures, and at temperatures approaching 300°F (150°C) may take 2 - 3 months to react. As the strength of a whipstock plug after this time is irrelevant, the use of sand is not recommended.

March 2004

Company Use Only

Section 12 - 7

Plug Cementing

12

Silica flour will begin to effect strength development at lower temperatures and within short periods of time. Therefore, silica flour should be used at temperatures above 230°F (110°C) unless a densified slurry is being used. Densified or reduced water slurries do not exhibit strength retrogression for long periods of time at temperatures up to 300°F (150°C).

12.4.3. Formation Isolation Slurry, Thickening Time, Free Water, strength - as in Abandonment (12.4.1) Fluid Loss - If slurry is to be squeezed and needs to fill a void or penetrate into a channel - 150 - 250 mL Gas Migration Prevention - Not required if squeezing as filter cake will prevent gas flow. If not, then reduce fluid loss to <100 or incorporate gas migration preventative like latex or gas generating agent.

12.4.4. Lost Circulation Slurry:

Cement + Extender + potentially LCM

Thickening Time, Free Water:

As above

Fluid Loss:

No Control - fluid loss may help resolve the loss problem

Density:

Mud weight + 0.5 - 1 lb/gal. Minimize cement density to aid in drill out. There is no need for high density or strength in a lost circulation plug.

12.5. PLUG PLACEMENT TECHNIQUES There are three basic methods to place a cement plug. These are balanced plug, twoplug method, and dump bailer.

12.5.1. Balanced Plug The most common method of placing a plug is with drill pipe or tubing. The pipe is run into the hole to the desired depth and then a specific volume of cement is placed in the well. The plug is balanced by pumping appropriate volumes of spacer ahead and behind the plug to achieve the same height inside and outside the pipe.

12.5.2. Two-Plug Method Use of mechanical plugs makes placing the cement plug easier. Similar to primary cementing, plugs are run ahead and behind the cement. When the top plug lands, there is a pressure increase indicating the cement is in place. Continued pumping will shear out the top plug allowing the pipe to be pulled out of the well.

March 2004

Company Use Only

Section 12 - 8

Plug Cementing

12

12.5.3. Dump Bailer Used primarily in completions and workover operations, a dump bailer is a wire line conveyed tool that will place a specific volume of cement at a particular depth in the well.

12.6. JOB DESIGN For both the balanced plug and two-plug methods, job design is identical. As dump bailers are rarely used in drilling applications, reference is given to SPE Paper 24574, "A Laboratory Study of Cement and Resin Plugs Place with Thru-Tubing Dump Bailers," White, Calvert, Barker and Bour, 1992. This paper covers placement and design elements for dump bailer work. One of the most common reasons for plug failure is mud contamination. This can be due to the plug moving down the hole and mixing with the mud, failure to displace the mud during placement, or leaving the formation or pipe oil wet, preventing bonding of the cement. The job design should seek to limit or eliminate mud contamination.

12.6.1. What is Below the Plug One of the major failure modes of plug cementing is contamination of the plug. This can be a result of improper displacement or the plug moving downhole after placement. Gravitational forces tend to allow the plug and mud to swap out, leaving the plug lower in the well than anticipated and contaminated with mud. Studies have shown the results of fluid movement after plug placement can result in a plug that ropes or spirals down the hole. When drilled, the plug will tend to drill hard, then soft, depending on the amount of contamination. Because of the density difference, heavy cement plugs may swap places with the lighter mud beneath and move down the hole. The tendency for this to occur depends on hole size, hole angle, and viscosity at the interface. Theoretically, a heavy column can be placed on top of a light one and, if the interface were perfectly flat, the two would not swap. In reality, the materials are mixed and there is always a small imbalance in the interface. The swapping process will not begin if the gel strength in the interface is greater than the initial swapping forces. The tendency for the interface to be stable depends on: 1) viscosity at the interface, 2) hole size, and 3) inclination. The viscosity at the interface is largely due to contamination. For example, cement plugs are often balanced in saltwater to squeeze perforations. When the cement is drilled out, the base is usually found within a few feet of where it was placed. The cement and water do not swap because the salt in the seawater tends to flocculate the cement. Water base muds built with bentonite also do not tend to swap because the calcium in the cement severely flocculates the bentonite in the mud, creating a very rigid interface. It is rare to take special precautions to prevent swapping when using a bentonite-based WBM.

March 2004

Company Use Only

Section 12 - 9

Plug Cementing

12

Swapping is of great concern in an non-aqueous fluid (NAF) because there may be very little reaction between the cement and base fluid. Hole size is also a factor because the surface tension in the contaminated region must be greater in order to maintain a stable interface across the larger surface. Hole angle essentially has the effect of creating greater surface area at the interface, as well, which reduces the stability of the interface. The recommended practices with NAF muds is to place the cement on bottom whenever possible. If not, some barrier should be placed in the hole just below the pill. This barrier can be a high viscosity mud, a mechanical barrier such as BJ's Parabow, or a chemical reactant that will gel with the cement on contact. A barrier is usually not required in WBM unless the hole size is large, the fluid has little bentonite content, or the hole angle is high. In general, drill teams that work vertical inland wells do not spot pills. Drill teams that work offshore in high-angle programs with low-bentonite or NAF muds find that it is necessary.

12.6.2. Temperature The temperature where the plug will be placed will be different than that used to design a primary cement job. The amount and rate of fluid circulation prior to placing the plug will effect the temperature, generally reducing it. If possible, run a temperature simulation to determine the proper temperature for the plug placement.

12.6.3. Use of a Stinger A cement stinger, typically consisting of tubing, is commonly run on the end of the drill pipe to place a plug. Stingers are advisable where the final height of cement with drill pipe is excessive, which can occur in smaller hole sizes. Stingers are recommended for most plug jobs. Getting the mud properly displaced in the well can be a concern. The use of drill pipe alone will improve the mud displacement process because of the increased annular velocities when using drill pipe rather than tubing. Plugs set in wells drilled with NAF fluids are particularly prone to contamination due to poor mud displacement, and may benefit from the use of drill pipe to place the plug. In cases where a plug must be placed for well control purposes, omitting the stinger may be advisable. Incentives for eliminating the stinger are: 1. Rig time required to change handling tools 2. Rig time waiting on the stinger to arrive (which is common) 3. Increased annular velocity and displacement efficiency 4. Improved ability for the balanced cement to fall inside the DP due to its increased ID

March 2004

Company Use Only

Section 12 - 10

Plug Cementing

12

12.6.4. Run a Diverter A flow diverter on the end of the pipe is designed to divert the flow of the cement to the sides of the well rather than straight down. This improves the mud removal across the 90-ft stroke interval when moving the pipe during plug placement. The diverter can also reduce the jetting action below the end of the pipe and reduce the amount of cement and mud contamination.

12.6.5. Cement Volume The volume of cement should be sufficient to give the required length of plug, plus 200 f, if possible. The additional cement will allow some contamination of the cement at the top of the plug. Often, the plug is being set in a portion of the well where the hole ID is unknown due to earlier work on the well. Fishing operations occur at a single depth, often resulting in considerable washout of the hole. The added hole volume must be taken into account when setting the plug.

12.6.5.1. Plug Length Many regulatory agencies set the minimum length for a cement plug. Always check with the regulations to determine any plug set for abandonment or hydrocarbon isolation meets the appropriate requirements. Beyond regulations, most plugs should be designed for a minimum of 500 ft, preferably 750 ft. This allows sufficient cement for contamination at the top and bottom of the plug, plus sufficient additional cement to dress off the top of the plug. For operational risk, designing plugs in excess of 1,000 ft is not recommended as the time to pull out of the plug can be excessive, increasing the risk of leaving pipe in the well. If longer plugs are required, multiple smaller plugs should be set rather than attempting a single plug of excessive length.

12.6.6. Mixing Batch mixing is preferred, and is a simple operation if one of the larger 25-bbl recirculating units is used. Otherwise, mix as slow as required to assure density control. Do not batch mix slurries that contain an accelerator. For systems that do not contain a retarder, the thickening time begins when the cement mixes with the water at surface.

12.6.7. Spacers Use an appropriate spacer for the drilling fluid. Plug failures in non-aqueous fluids are common and a result of failure to remove the mud, or a failure to leave the formation or pipe water wet. Mud contamination is a major cause of plug failures and is especially a problem in wells drilled with NAF.

March 2004

Company Use Only

Section 12 - 11

Plug Cementing

12

12.6.8. Pipe Movement As with primary cementing, pipe movement, specifically rotation will aid in getting a successful plug. Pipe rotation helps assure cement placement around the pipe, and more importantly in plug cementing, aids in removing the drilling mud. Pipe reciprocation is not recommended while placing a plug. Use of a liner-type-cementing head with a swivel is recommended. This will facilitate rotation of the string as well as assisting with dropping of plugs or darts. Pipe rotation should also be employed while circulating bottoms up after placement of the plug.

12.6.9. Use of Scratchers Scratchers and other mechanical devices to aid in getting the drilling mud moving are recommended. Scratchers made of wire rope can be very effective in getting fluid moving in the annulus.

12.6.10. Displacement When displacing a cement plug, it is common practice to under-displace the plug by a few barrels to allow the cement to fall out of the pipe as it is being pulled out of the plug. This practice helps prevent mudflow up the drill pipe in the event the cement was overdisplaced and essentially puts a small slug in the pipe. This practice is not effective in high-angle or horizontal wells. The angle of the well does not allow the under-displacement to act as a slug. If the pipe is pulled out of the plug in a high-angle situation, the cement will not fall out of the pipe, and the plug will become more contaminated. To address this problem, it is recommended the pipe be pumped out of the plug. As each stand of pipe is pulled up, the equivalent pipe volume of mud should be pumped.

12.6.11. Waiting on Cement (WOC) Time Plan for sufficient WOC time. A minimum time of 12 hours should be used, longer for shallower wells, due to reduced trip times. If the cement does not drill as expected after 12 hours, waiting an additional six hours may be beneficial. Waiting longer than 18 hours, indicates a problem with the cement design. Depending on rig rates, waiting longer than 18 hours for a cement plug to set is not advised.

12.7. BALANCED PLUG CALCULATIONS Cement plugs are normally placed or "balanced" in the wellbore. Balancing a plug is simply calculating the volumes to equalize the pressures inside and outside the work string. As the work string will be pulled out of the plug after placement, the length of the plug with the work string in place is also calculated. (The calculations presented assume the density of the spacer ahead and behind the cement is equal. If this is not the case, the calculations should be modified to account for those differences.)

March 2004

Company Use Only

Section 12 - 12

Plug Cementing

12

Volume of Cement (in bbl):

Vcmt = L ∗ Vh

where : L = Required length of cement plug (ft) Vh = Volume of hole (bbl/ft) Length of plug (in ft) with drill string in place:

Lcmt =

Vcmt Vann + Vws

where : Vann = Volume of the annulus (bbl/ft) Vws = Volume of the work string (bbl/ft) To properly balance the plug, the volume of spacer (in bbl) behind the plug should be calculated to balance the volume pumped ahead of the plug.

Vsp 2 =

Vsp1 Vann

*Vws

where : Vsp1 = Volume of spacer pumped ahead of the plug (bbl) Vsp 2 = Volume of space pumped behind the plug (bbl) The displacement volume (in bbl) for the plug is calculated as: Vdis = Vws ∗ [ D − ( Lcmt + Lsp 2 )]

where : D = Depth to the bottom of the plug (ft) Lcmt = Length of the cement plug (ft) Lsp 2 = Length of the spacer behind the plug (ft) Note: in the calculations for cement plugs, the units may be changed to any required units provided there is consistency in the units throughout the calculation. For example, if the volumes are calculated in cubic feet, the annular capacities should be converted to cuft/ft.

March 2004

Company Use Only

Section 12 - 13

Plug Cementing

12

12.7.1. Example Balanced Plug Calculation Place a 500-ft plug in an 8-1/2-inch open hole from 10,000 ft to 9,500 ft. The work string consists of 5-1/2 inches, 19.5 ppf drill pipe, with a tubing stinger at the bottom. The stinger is 750 ft of 2-7/8 inches, 6.85 ppf tubing. 20 bbl of spacer will be run ahead of the plug. Volume of the annulus is 0.0622 bbl/ft, and the volume of the tubing is 0.00579 bbl/ft.

Volume of Cement = 500 * Volume of Cement = 35 bbl

8.5 2 1029.4

Length of Plug with the work string in place:

Lcmt =

35 = 515 ft 0.0622 + .00579

Volume of spacer behind:

Vsp2 =

20 * 0.00579 = 1.86 bbl 0.0622

This calculation assumes the top of the spacer in the annulus is below the transition between drill pipe and tubing. This is not the case in this example because of the volumes. Further, the volume of spacer to balance the plug behind will be slightly less than that calculated. This is because the top of the spacer will be located inside the drill pipe rather than the tubing. The length of the spacer in the annulus is actually: Length of cement:

= 515 ft.

Length of tubing string:

= 750 ft

Volume of tubing x OH:

= 0.0622 * (750 - 515) = 14.6 bbl

Remaining Spacer:

= 20 - 14.6 = 5.4 bbl

Length of spacer in drill pipe x open hole:

= 5.4 / .0408 = 132 ft

Top of spacer in annulus:

= 10,000 - 750 - 132 = 9118 ft.

March 2004

Company Use Only

Section 12 - 14

Plug Cementing

12

Spacer to balance behind: The spacer to balance behind the plug must fill the remaining tubing string, plus drill pipe to 9,118 ft.

Remaining volume of tubing = 0.00579 * (750 - 515) = 1.4 bbl Length in drill pipe = 10,000 - 750 - 9,118 = 132 ft Volume in 132 ft of drill pipe = 132 * .01776 = 2.3 bbl Total space behind = 2.3 + 1.4 = 3.7 bbl As shown, the change in the work string size must be taken into account for volume calculations. This will also effect the displacement volumes. If the size change is ignored, the calculations are: Displacement Volume:

Vdis = .01776 ∗ [10,000 − (515 + 321)] = 163 bbl If the volume change is taken into account, the displacement volume is

Vdis = .01776 ∗ [9,118] = 162 bbl 9118 was previously calculated as the top of the spacer The volume difference for displacement is only one bbl in this case. Actual displacement on location should be less than the calculated volume to allow the cement to fall out of the work string. In this example, the actual displacement on the rig should be between 155 - 160 bbl.

March 2004

Company Use Only

Section 12 - 15

Section

Primary Cementing Operational Requirements and Specifications for Cementing Services Scope This Section contains the minimum operational requirements for equipment, materials, personnel, and service coordination for providing cementing services at ExxonMobil locations. This Section contains the expectations for the type of equipment on location, how that equipment should function, and how it is to be used to properly perform a cement job. This Section may be used and modified as required to serve as a template for tender requirements for new projects, as a checklist for existing installations, or as a tool for operations improvements.

Company Use Only

Operational Requirements/ Specifications for Cementing Services

13

Table of Contents ExxonMobil Requirements ............................................................................... 3 13.

Operational Requirements / Specifications for Cementing Services 4

13.1. Required References ............................................................................. 4 13.1.1. API-American Petroleum Institute.................................................................. 4 13.1.2. ISO-International Standards Organization ..................................................... 4

13.2. Exceptions .............................................................................................. 4 13.3. Specifications For Cement Unit and Related Equipment.................... 5 13.3.1. Additional Requirements For Liquid Additives ............................................... 6

13.4. Specifications For Foamed Cement Services & Related Equipment. 6 13.5. Cementing Services Equipment, Service & General Requirements .. 7 13.5.1. Additional Requirements For Offshore and Remote Installations................. 11

13.6. Personnel Requirements For Cementing Services ........................... 12 13.6.1. Additional Offshore and Remote Location Requirements ............................ 12

13.7. Service Coordinator Responsibilities................................................. 13

March 2004

Company Use Only

Section 13 - 2

Operational Requirements/ Specifications for Cementing Services

13

ExxonMobil Requirements Section Number

ExxonMobil Requirement

This Section contains the technical specifications for equipment, materials, testing, and personnel for providing cementing services on ExxonMobil wells. Each requirement is outlined within the Section as it pertains to each of these areas. Exceptions to these requirements are outlined in 13.2 and may be granted by the Field Drilling Manager except where safety issues are involved. Exceptions to 13.3 #8 on pressure relief devices and 13.3 #17, maximum rates through 2-inch treating lines can only be granted by an Operations Manager.

March 2004

Company Use Only

Section 13 - 3

Operational Requirements/ Specifications for Cementing Services

13.

13

OPERATIONAL REQUIREMENTS / SPECIFICATIONS FOR CEMENTING SERVICES

13.1. REQUIRED REFERENCES This Section lists Practices and Standards that are generically referenced and assumed part of this document. Unless otherwise specified herein, use the latest edition.

13.1.1. API-American Petroleum Institute API Spec 10 A

Specification for Cements and Materials for Well Cementing

API RP 10 B

Recommended Practice for Testing Well Cements

API Spec 10 D

Specification for Bow-Spring Casing Centralizers

API RP 10 F

Recommended Practice for Performance Testing of Cementing Float Equipment

13.1.2. ISO-International Standards Organization ISO 10426-1

Cements and Materials for Well Cementing - Part 1: Specification

ISO 10426-2

Cements and Materials for Well Cementing - Part 2: Testing of Well Cement

ISO 10426-4

Cements and Materials for Well Cementing - Part: 4 Methods for Atmospheric Foamed Cement Slurry Preparation and Testing

ISO 10427-1

Casing Centralisers - Part 1: Specifications for Bow-Spring Casing Centralisers

ISO 10427-3

Recommended Practice for Performance Testing of Cementing Float Equipment

13.2. EXCEPTIONS Exceptions to these technical requirements are allowed, but shall be documented in writing by the service company and approved the Field Drilling Manager or designated representative. Documentation shall include proposed change, reason for exception, and impact on operations. Exceptions to the use of pressure relief devices on cementing equipment and maximum allowable rates through treating lines require approval of the Operations Manager. All other exceptions can be made by the Field Drilling Manager

October 2004

Company Use Only

Section 13 - 4

Operational Requirements/ Specifications for Cementing Services

13

13.3. SPECIFICATIONS FOR CEMENT UNIT AND RELATED EQUIPMENT

1. The cement unit contracted to perform the cementing work shall be capable of carrying out all aspects of the proposed work. This includes the cementation of the proposed casing strings, blowout preventer pressure tests, casing pressure tests, formation integrity tests, and required well testing operations. 2. The cementing unit is to be a dual diesel or electric-powered design driving dualtriplex pumps rated to a minimum 10,000 psi working pressure, and having a recirculating type mixing system. 3. The Recirculating Mixing System (RCM) is to provide density control and slurry consistency over a wide range of slurry weights and is required to mix cement within 0.2 ppg (plus or minus) of the designed slurry weight. The RCM volume is to be sufficient to allow continuous or batch mixing and provide for homogeneous slurry. 4. The recirculating mixing system shall have the capability of computer-controlled mixing for the control of cement density and rate. 5. The displacement tank capacity shall be a minimum of 20 bbls divided into two (2) 10 bbl compartments. 6. The cement unit shall be capable of functioning to full capacity at all times. Regular maintenance and correction of equipment faults shall be performed. The Contractor shall operate and maintain the cementing unit, equipment, consumables, and provide sufficient spare parts. 7. The cement unit shall be outfitted with a downstream densitometer, or equivalent device for accurately measuring and recording the density of fluids as they are pumped into the well. 8. The cement unit shall be fitted with an automatic pressure relief device or overpressure shut-down capable of being set to the maximum pressure allowed for the job. Exceptions to this requirement must be approved by the Operations Manager. 9. The cement unit shall be fitted with electronic data and recording equipment to analyze and record pertinent job parameters for post-job analysis. 10. Real time remote display of electronic data shall be available at the location if requested. This may be accomplished through a hard-wired remote display located away from the main work area of the unit. 11. Electronic data shall be captured and recorded at a minimum rate of once every four (4) seconds. The preferred recording rate is once each second for all parameters. 12. The minimum acceptable data to be recorded shall be time, downstream density, and liquid additive rate, if applicable, cement pump rates, displacement rates where displacement is done by the cement unit, and pressure throughout the entire job. 13. Pressure shall be recorded throughout the entire job. If the rig pump is performing the displacement, this will require the line to the cement unit be left open, or an additional pressure transducer installed in the treating line to allow pressure recording for the entire displacement period.

March 2004

Company Use Only

Section 13 - 5

Operational Requirements/ Specifications for Cementing Services

13

14. The recorded job data shall be capable of being downloaded into ASCII format for evaluation in Microsoft Excel, or other similar program. 15. The cement unit shall be fitted with calibrated pressure gauges, pen-type recorder, and pop-off valves. 16. The cement unit (in its final installed position on the rig) shall be capable of consistently mixing a neat Class G or H cement slurry at 15.8 or 16.4 lb/gal respectively to ± 0.2 lb/gal at a minimum rate of 4 bbl/min. 17. Maximum rates through a 2-inch treating line shall be limited to 8.0 bpm. Use of higher rates requires additional lines or larger treating lines. Exceptions to this requirement must be approved by the Operations Manager. 18. Contractor shall be capable of providing cementing batch mix equipment capable of mixing and/or holding a minimum of 100 bbl of cement slurry.

13.3.1. Additional Requirements For Liquid Additives 1. Contractor shall provide a liquid additive proportioning system capable of providing the metered addition of liquid cement additives to the cement unit. 2. For automatic liquid additive systems, Contractor shall provide a method for monitoring flow of additives through appropriate metering. Monitoring liquid additive pump strokes is not considered appropriate metering. 3. Contractor shall provide tanks for liquid cement additives. Tanks shall be capable of being circulated via either an external or self-contained circulation pump or other mixing device. 4. Liquid additive tanks shall have unique numbering to allow tracking of liquid additives on location.

13.4. SPECIFICATIONS FOR FOAMED CEMENT SERVICES & RELATED EQUIPMENT

1. The nitrogen unit and associated equipment shall have the capacity to accurately deliver nitrogen at rates up to 2,500 scf/min. 2. Nitrogen volume capabilities shall support projected foamed cementing operations and shall include additional volumes for anticipated storage, equipment cool down, etc. 3. Contractor shall be able to meter injection of liquid foaming agents and stabilizers into the suction side of the downhole triplex pump. Contractor shall provide a method for monitoring flow of additives through appropriate metering. Monitoring liquid additive pump strokes is not considered appropriate metering. 4. Separate tanks for liquid foaming agents and liquid foam stabilizers are required. For systems where foamer and stabilizer are supplied as a single material, this requirement will not be applicable.

March 2004

Company Use Only

Section 13 - 6

Operational Requirements/ Specifications for Cementing Services

13

5. The nitrogen unit and associated equipment shall be capable of accurately delivering and metering nitrogen at a minimum rate of 200 scf/min. This will require the use of a mass-type, gas flow meter or other equivalent approved device or process. The ExxonMobil preferred nitrogen-metering method is to use a mass flow gas meter. 6. Contractor shall test all lines downstream of the nitrogen unit with nitrogen prior to any foamed cement job. 7. It is preferred all nitrogen and related equipment for use on any foamed cement job be process-computer controlled to allow automatic adjustment of nitrogen and foamer injection rates. 8. All nitrogen and related equipment shall be fitted with recording equipment capable of recording relevant parameters for all foamed cement jobs. Minimum data recording shall include, but not be limited to: time, cement pump rate and density, nitrogen rate and pressure, foamer injection rate, and wellhead pressure. Note: this will require the addition of a pressure transducer downstream of the foam generator. 9. Contractor shall demonstrate capabilities to perform detailed computer simulation and design of foamed cementing operations, and be able to relate simulation output to operational considerations of the job. This shall include, but not be limited to, sizing of nitrogen unit to match simulated rates required for the job. 10. Contractor shall provide onsite supervisor experienced in foamed cementing operations during foamed cement jobs. Qualifications of onsite supervisor will be reviewed and must be acceptable to ExxonMobil. 11. Laboratory personnel shall be familiar with foamed cement preparation and testing. Test procedures shall be reviewed prior to initial application. The review shall include laboratory equipment, stability test methods and all standard slurry tests. 12. If required for the project, Contractor shall confirm foamed cementing capabilities prior to initial usage of foamed cement on rig. Confirmation may be through prior approval of equipment and process or actual yard test of equipment. This shall occur at least 30 days prior to the initial application of foamed cement.

13.5. CEMENTING SERVICES EQUIPMENT, SERVICE & GENERAL REQUIREMENTS

1. Contractor shall provide Material Safety Data Sheets (MSDS) for all products to be used on the well or job. 2. Contractor shall maintain a cement-testing lab in the service area capable of running required tests with samples of water, cement, and chemicals sent in from the rig.

March 2004

Company Use Only

Section 13 - 7

Operational Requirements/ Specifications for Cementing Services

13

3. Minimum acceptable laboratory cement-testing equipment shall consist of: •

Two (2) high temperature high pressure (HTHP) consistometers or one dual cell consistometer

•

HTHP cement fluid loss cell. Use of a stirred fluid loss cell is recommended for safety purposes, but is not required.

•

Twelve-speed rotating viscometer (12-speed Fann 35, Chan 35 or other equivalent)

•

Apparatus for free fluid testing (at well angle and/or 45° from vertical)

•

Equipment for strength determination under temperature and pressure Strength tests may be via crush tests or nondestructive testing (UCA or equivalent)

•

API settling test apparatus

•

Constant speed mixer for slurry preparation

4. Where required, lab shall have a closed (capped) blender bowl for use on constant speed mixer to allow for the atmospheric pressure testing of foamed cement slurries as defined in ISO 10426-4:2004. 5. For projects having well temperatures below 70°F (21°C), the lab shall have a circulating chiller and the capability to perform thickening time and strength testing at temperatures below ambient. 6. All laboratory-cementing tests performed shall be run according to the latest API/ISO standards unless otherwise specified. Deviations from these standards will be allowed provided the test procedure has been approved by an ExxonMobil representative in advance of the testing. 7. In the event no API/ISO or other appropriate standard exists for a particular testing series, the test protocol will be outlined and approved prior to testing. 8. Use of previous laboratory data in lieu of actual testing must be approved by the designated ExxonMobil representative on the project. The laboratory report must clearly indicate the data has come from earlier testing. 9. Pilot tests normally utilize laboratory samples of cement and additives. These tests shall utilize a current representative sample of cement and additives to be used on the job. 10. The most meaningful tests to be performed will be those on the field sample. The field blend is considered the cement and additives pumped on the job. Samples of cement and additives taken from location shall be used for this test. 11. All wells to be cemented shall require a field blend test of both the lead and the tail cement systems. Deviations from this requirement may be made only after approval from the designated ExxonMobil representative on the project. 12. For all field blend tests, the actual water to be used at the rig shall be used for testing.

March 2004

Company Use Only

Section 13 - 8

Operational Requirements/ Specifications for Cementing Services

13

13. In the event logistics do not allow for the sampling and testing of samples from the rig site, samples from the bulk plant may be used provided the tests are appropriately identified as using bulk plant samples. 14. For land operations, the bulk plant sample is considered the same as the field blend. Every effort must be made to test these samples with water from the location. 15. The thickening time of the cement field blend shall have a thickening time of no less than 30 minutes less, nor 60 minutes longer, than that shown on the laboratory pilot test report. 16. All additives to be added to the cement on location (liquid additives, sack materials to be dissolved in the mix water, etc.) shall be sampled and the sample identified by lot number and other identifying mark. 17. If any additive is added to the mix water prior to mixing with cement (e.g., water and additives are mixed prior to the job), samples shall be taken of the mix water and additive(s), lot number(s), and concentration(s) identified. 18. Compatibility tests of any spacers with the drilling mud shall be performed. In the event non-aqueous based drilling fluids are used on the well, additional testing of the spacer and mud shall be required. This testing shall include, but not be limited to, a thickening time test of a mixture of 50% mud and 50% spacer. 19. Compatibility tests of spacers and the cement slurry shall be performed. 20. The final lab results for the cement slurries to be used shall be sent to the rig and communicated to the designated ExxonMobil representative. 21. The complete mixing procedure including order of addition of materials shall be sent to the rig and communicated to all appropriate personnel. 22. Laboratory shall have capacity for 24-hour operations if required for testing. 23. Contractor shall have additional cement testing facilities available in the event of laboratory overload. Samples of relevant cement and additives shall be maintained at the back-up laboratory facility. 24. Contractor shall have a stock point with enough capacity and storage to cover the operation. 25. Contractor shall provide sample boxes with containers and labels for cement, water, and additives. Contractor Site Representative shall be responsible for sending samples to the area laboratory for testing prior to each job, and catching samples when bulk cement is delivered to the rig. 26. All samples taken from the rig are to be labeled with the sample name, source, lot number if available, person taking sample, and date. 27. All drums, cans, and bags supplied shall be of sufficient quality to withstand breakage during shipment to and from the rig. All equipment shall be pre-slung or in containers before being shipped. 28. Contractor Site Representative shall ensure that all materials and equipment necessary for the performance of the cement job are present at rig and are in good working order. This responsibility shall include all equipment essential to the cement job. Essential equipment includes, but is not limited to, the air system on

March 2004

Company Use Only

Section 13 - 9

Operational Requirements/ Specifications for Cementing Services

13

the rig, the rig cement bulk system, and other associated third-party equipment as required. 29. The final cement formulation shall be known by all affected personnel and confirmation of all lab tests shall be made prior to all cement jobs. The Contractor Site Representative shall confirm the formulation and know the proper additives and the required volumes of cement and all additives are present at the rig. 30. A pressurized fluid density balance shall be used for density measurements on all cement jobs, and shall be calibrated. The balance shall be calibrated and ready for use before each cement job by the Contractor Site Representative. 31. A complete mixing and Quality Assurance (QA) procedure for each spacer to be mixed shall be given to the mud engineer prior to the cement job by the Contractor Site Representative. 32. Electronic data shall be recorded on the cement job. The minimum items to be recorded are the downstream density, rate, and pressure. The Contractor Site Representative shall send this data to the appropriate office for processing where required. Martin Decker charts shall be properly documented and given to the ExxonMobil representative at the rig. 33. The Contractor Site Representative shall be responsible for calibrating the pressure gauges and chart recorder on the cement unit. Proper calibration shall be confirmed prior to each cement job. 34. Contractor shall perform computerized cement job design and evaluation. Prediction of job parameters such as friction pressures, U-tube effects, equivalent circulating density calculations, flow regime determination, and wellhead pressures are minimum requirements. Actual recorded data from location shall be used for post-job evaluation. 35. Samples shall be taken using a one-inch sample valve placed in the flow stream of the cement line. 36. All samples shall be retained for 30 days or until released by ExxonMobil. 37. Each Contractor Site Representative shall be experienced and capable of running and operating all equipment provided by Contractor. 38. Any unused items returned by ExxonMobil in good condition will be credited to ExxonMobil's account. 39. All bow-spring centralizers shall meet the specifications as outlined in the most recent API Specification 10D/ISO 10427-1. 40. Float equipment shall have been tested as set out in API RP 10 F/ISO 10427-3 for the required class of service noted. 41. Contractor shall provide evidence the cement meets the requirements of the API specifications used on the project.

March 2004

Company Use Only

Section 13 - 10

Operational Requirements/ Specifications for Cementing Services

13

13.5.1. Additional Requirements For Offshore and Remote Installations 1. A running list of the materials at the rig shall be kept current at all times by the Contractor Site Representative. Volumes and names of all additives at the rig shall be updated after each cement job, and after each material shipment to the rig. The Contractor Site Representative shall assist ExxonMobil personnel in reporting the amounts of materials used on the job and reconciling the final inventory. 2. Contractor shall maintain proper marking of all pallets and containers. All pallets and materials shall be labeled and shall be checked after each shipment to the rig by the Contractor Site Representative. 3. All shipments of chemicals (buckets and sacks) shall be palletized and shrinkwrapped. All other equipment shall be palletized and/or pre-slung. 4. All cement heads shall have been pressure tested to the rated working pressure for 10 minutes before shipment to the rig. Each head shall be supplied with at least two replacement 0-rings in the event the ring is damaged when stabbing the head. Further, certification that the head has been tested is required and shall be attached to the head. The certification document shall accompany the head to the rig location. Certification can be a signed original chart of the pressure test. The chart shall include when the head was tested, who performed the test, and where the test took place. 5. Contractor shall develop a plan, acceptable to ExxonMobil, for optimizing the bulk system and the transfer program for cement. The plan shall be completed no later than 30 days prior to the first cementing operation at the rig. 6. Samples of cement shall be taken during the transfer of cement from the dock facility to the boat(s) and from the boat(s) to the rig. Contractor Site Representative shall collect the sample during the transfer from the boat to the rig. Contractor shall be responsible for sample collection at the dock facilities. 7. Contractor Site Representative shall ensure the bulk delivery system for cement at the rig is functioning properly and sufficient cement delivery rate is maintainable for all cement jobs. 8. Contractor Site Representative shall ensure the bulk delivery system at the rig is functioning properly and meets the requirements for the project. 9. The rig air shall be checked by the Contractor Site Representative for excessive water at least twice a week and prior to any cement job. 10. Contractor confirms and ensures, prior to loading any vessel with bulk material under Contractor’s control, the vessel tanks are clean and uncontaminated, which will include visual inspection of the tanks. As a result of these visual inspections, the vessel operator has the responsibility of opening, cleaning, sealing, and pressure testing the vessel's tanks. 11. Contractor shall supply equipment in sufficient quantities to support the operation inclusive of all appropriate back-up equipment to meet requirements.

March 2004

Company Use Only

Section 13 - 11

Operational Requirements/ Specifications for Cementing Services

13

13.6. PERSONNEL REQUIREMENTS FOR CEMENTING SERVICES

1. Contractor Site Representative shall be capable of performing all pertinent duties. 2. Contractor Site Representative shall be fully trained and currently qualified for his/her job in accordance with safety-related regulatory and industry standards. Personnel present at the rig should be trained in H2S hazards and have a valid certificate (less than one year old) for all locations having H2S potential. 3. Contractor Site Representative shall have all manuals, gauges, and equipment required to adequately perform the Work to ExxonMobil’s satisfaction. In the event Contractor Site Representative is unable to perform the duties adequately, or fails to provide the proper equipment, Contractor shall replace Contractor Site Representative, or remedy the situation to ExxonMobil’s satisfaction at the sole expense of Contractor. 4. All Contractor laboratory personnel shall be fully trained in laboratory operations and testing. Personnel shall be familiar with API/ISO testing requirements, standards, and recommended practices as published in the latest editions of the API/ISO Recommended Practices for testing cement. 5. Contractor engineering support personnel shall be experienced in cement design and capable of performing computerized job design and evaluation using Contractor computer programs. 6. Contractor shall provide cementing service management for the term of the agreement. Project service management shall include the full management of cementing services provided to ExxonMobil.

13.6.1. Additional Offshore and Remote Location Requirements 1. Contractor personnel based more than six (6) hours flight time from the rig location shall have a schedule organized to allow a minimum eight (8) hours rest prior to starting work. 2. Contractor personnel based more than a six-hour time change from the point of origin to the rig location shall have a schedule of work organized to allow a minimum of 12-hours rest prior to starting work. 3. Contractor Site Representative shall certify the ability to mix and pump cement per the requirements by pumping a maximum of 200 sacks of cement in a certification test to be witnessed by appointed ExxonMobil personnel. 4. For cementing equipment utilizing automatic density control, Contractor Site Representative shall perform the certification test with and without the aid of the automatic computer-control system. 5. ExxonMobil will provide sufficient cement (200 sacks each, maximum of 800 sacks total) for the certification of a maximum of four Contractor Site Representatives. 6. ExxonMobil will maintain documentation of the certification test at the rig.

March 2004

Company Use Only

Section 13 - 12

Operational Requirements/ Specifications for Cementing Services

13

7. Contractor shall have a certified Contractor Site Representative at the rig (or immediately available where appropriate) at all times. 8. Contractor shall provide personnel required to deliver bulk cement to ExxonMobil’s supply vessel to meet requirements as specified. Contractor shall have the capability to deliver bulk cement as required by ExxonMobil. 9. Where required, Contractor shall provide two certified Site Representatives per rig, working a rotational schedule. This would normally apply to locations where personnel are housed at the rig, e.g., offshore locations.

13.7. SERVICE COORDINATOR RESPONSIBILITIES 1. The service coordinator is the primary contact between ExxonMobil and the service company. This individual holds the responsibility for all activities and will serve as the single point contact between the service company and ExxonMobil. The representative must be familiar with all ExxonMobil requirements, and must remain up to date on the progress of the particular well(s) being serviced by the service company. 2. The service coordinator shall be responsible for coordination of all required services including, but not limited to: engineering, equipment, materials, testing, transportation, cementing services, quality assurance/quality control, Safety Health & Environmental (SH&E), personnel and reporting requirements. 3. The service coordinator shall keep abreast of ExxonMobil operations and maintain a smooth communications interface with ExxonMobil, other contractors and service company personnel to ensure timely progress and proper application of the services. 4. The service coordinator shall actively pursue all opportunities for continuous improvement in the overall performance of the services provided. 5. The service coordinator shall propose the Key Performance Indicators (KPIs), methods of measurement and performance review procedures to be used, including pre- and post-job reviews. 6. Agreed recommendations for process improvements shall be implemented prior to the next similar operation. 7. The service coordinator shall demonstrate the fitness-for-purpose of all materials through appropriate certification and/or testing. 8. The proposal and acceptance of a quality plan shall not relieve the service company of any of obligations and ensure the materials being used at the rig site meet the design requirements. 9. The service company shall provide to ExxonMobil for approval an implementation plan to ensure the quality of any materials. This shall include, but not be limited to: all storage, shipping, delivery systems, and any other materials handling systems (whether provided by the service company or otherwise). 10. The service coordinator shall assist with the design of all cement slurries with the laboratory and operations.

March 2004

Company Use Only

Section 13 - 13

Operational Requirements/ Specifications for Cementing Services

13

11. The service coordinator shall remain current with project progress and anticipate testing required for the well. 12. The service coordinator shall direct the design and testing of all cement slurries based on the requirements of the well. This may require development of unique testing for special applications. 13. The service coordinator shall ensure prompt end of job and end of well reporting. 14. The service coordinator shall ensure field personnel are informed of cement design and pumping requirements. 15. All design results shall be reported to the appropriate drilling engineer by the service coordinator. 16. The service coordinator shall assist with the resolution of any job problems and coordinate service company participation. 17. The service coordinator shall assist with the introduction of new materials, services, and technologies to the ExxonMobil drilling organization. 18. In the event of a job problem, the service coordinator shall be responsible for the issuance of a failure analysis report.

March 2004

Company Use Only

Section 13 - 14

Section

Primary Cementing Cementing Equipment

Scope This Section broadly defines surface and downhole cementing equipment. It includes descriptions of bulk handling equipment, mixing systems, float equipment and centralizers.

Company Use Only

Cementing Equipment

14

Table of Contents Figures ............................................................................................................... 4 Tables................................................................................................................. 5 ExxonMobil Requirements ............................................................................... 6 14.

Cementing Equipment ............................................................................. 7

14.1.

Required References ............................................................................ 7

14.1.1. API-American Petroleum Institute.................................................................. 7 14.1.2. ISO-International Standards Organization ..................................................... 7

14.2.

General................................................................................................... 7

14.3.

Surface Equipment ............................................................................... 8

14.3.1. Cement Bulk Blending, Transportation and Storage ...................................... 8 14.3.1.1. Blending.................................................................................................. 8 14.3.1.2. Bulk Cement Transfer - Cement Losses ............................................... 11 14.3.1.3. Bulk Cement Storage............................................................................ 11 14.3.1.4. Bagged Cement .................................................................................... 12 14.3.2. Cement Slurry Mixing .................................................................................. 13 14.3.2.1. Batch-Mixing Equipment ....................................................................... 13 14.3.2.2. Continuous-Mixing Equipment .............................................................. 14 14.3.3. Pump Systems ............................................................................................ 18 14.3.4. Density Measurement ................................................................................. 19 14.3.5. Data Recording ........................................................................................... 19 14.3.6. Inventory Control ......................................................................................... 20 14.3.7. Sampling ..................................................................................................... 20 14.3.8. Other Surface Cement Equipment............................................................... 20 14.3.8.1. Cement Plug Containers or Cement Heads .......................................... 20 14.3.8.2. Wiper Plugs .......................................................................................... 21

14.4.

Subsurface Equipment ....................................................................... 22

14.4.1. Casing Centralizers and Stop Collars .......................................................... 22 14.4.1.1. 14.4.1.2. 14.4.1.3. 14.4.1.4. 14.4.1.5. 14.4.1.6.

March 2004

Centralizer Performance Standards ...................................................... 22 Where to Use a Centralizer ................................................................... 22 Where Not to Use a Centralizer ............................................................ 23 Centralizer Type - Bow-Spring, Rigid or Solid ....................................... 23 Standoff ................................................................................................ 23 Flow Diversion ...................................................................................... 25

Company Use Only

Section 14 - 2

Cementing Equipment

14

14.4.1.7. Which Centralizer to Use ...................................................................... 25 14.4.1.8. Centralizers and Pipe Movement .......................................................... 26 14.4.1.9. Stop Collars .......................................................................................... 27 14.4.1.10. General Comments............................................................................ 27 14.4.2. Casing Float Equipment .............................................................................. 28 14.4.2.1. Float Equipment Performance Standards ............................................. 28 14.4.2.2. API/ISO Test Categories for Float Equipment ....................................... 28 14.4.3. Types of Float Equipment............................................................................ 30 14.4.3.1. Stab-In Equipment ................................................................................ 31 14.4.4. Stage Equipment......................................................................................... 32 14.4.4.1. Types of Stage Equipment.................................................................... 34 14.4.5. Design of Cement Slurries for Stage Jobs................................................... 34 14.4.6. Failure Modes ............................................................................................. 35 14.4.7. Example Equipment .................................................................................... 35

March 2004

Company Use Only

Section 14 - 3

Cementing Equipment

14

Figures Figure 14.1: Cement Bulk Plant..................................................................................... 9 Figure 14.2: Bulk Cement Transport............................................................................ 10 Figure 14.3: Typical Batch Mix Tank............................................................................ 14 Figure 14.4: Jet Mixer.................................................................................................. 15 Figure 14.5: Recirculating Mixer .................................................................................. 17 Figure 14.6: Typical Pump Efficiency Curve ................................................................ 18 Figure 14.7: Double-Plug Cement Head...................................................................... 21 Figure 14.8: Float Valve .............................................................................................. 30 Figure 14.9: Float Shoe & Float Collar......................................................................... 31 Figure 14.10: Stab-In Float Collar................................................................................ 32 Figure 14.11: Typical Stage Job .................................................................................. 33 Figure 14.12: Mechanical Stage Collar........................................................................ 36

March 2004

Company Use Only

Section 14 - 4

Cementing Equipment

14

Tables Table 14.1: Bulk Factors for Common Cement Systems ............................................. 12 Table 14.2: Standoff as a Function of Hole Size .......................................................... 24 Table 14.3: Categories of Flow Durability .................................................................... 28 Table 14.4: Categories of Flow Durability for Casing Fill-Up Equipment ...................... 29 Table 14.5: Categories of Static High-Temperature/High-Pressure Tests.................... 29

March 2004

Company Use Only

Section 14 - 5

Cementing Equipment

14

ExxonMobil Requirements Section #

ExxonMobil Requirement

There are no ExxonMobil requirements in this Section.

March 2004

Company Use Only

Section 14 - 6

Cementing Equipment

14.

14

CEMENTING EQUIPMENT

14.1. REQUIRED REFERENCES This Section lists Practices and Standards that are generically referenced and assumed part of this document. Unless otherwise specified herein, use the latest edition.

14.1.1. API-American Petroleum Institute API Spec 10D

Specification for Bow-Spring Casing Centralizers

API RP 10D

Recommended Practice for Centralizer Placement and Stop Collar Testing

API RP 10F

Recommended Practice for Performance Testing of Cementing Float Equipment

14.1.2. ISO-International Standards Organization ISO 10417-1

Casing Centralisers - Part 1: Specifications for Bow-Spring Casing Centralisers

ISO 10427-2

Casing Centralisers - Part 2: Recommended Practice for Centraliser Placement and Stop Collar Testing

ISO 10427-3

Petroleum and Natural Gas Industries - Performance Testing of Cementing Float Equipment

14.2. GENERAL Cementing equipment can be broadly defined as surface equipment (those items devoted to mixing and pumping in the well), and subsurface equipment (those items that attach to the casing and will remain in the well following the cement job). The recommended surface equipment for performing a cement job consists of: •

Appropriately-sized bulk equipment with sufficient dry air for the entire operation

•

Computer-aided mixing system (Automatic Density Control (ADC) or equivalent)

•

Dual pump cement unit

•

Double-plug cement head

•

Pressurized mud balance

•

Downstream recording densitometer

•

Pressure recording through the entire job to include displacement

March 2004

Company Use Only

Section 14 - 7

Cementing Equipment

14

14.3. SURFACE EQUIPMENT Surface cement equipment consists of the equipment to blend the dry cement, mix and pump the cement slurry into the well, launch plugs, and ultimately displace the cement. It can also include the launching of various opening and closing plugs for stage cementing, but these will be considered with the particular downhole tools. Cement surface equipment must be considered as a system. It is not possible to mix a quality cement slurry without good delivery of dry cement, mix water, and ultimately density control. Mixing rates for the cement should be those rates that can achieve and maintain the desired slurry density. Only two variables can be controlled on location. While mixing, the density and rate can be manipulated; and after the plug is dropped, the only controllable variable is the displacement rate. After the cement enters the casing, it is too late to make any changes to the slurry, and unless circulated out, that slurry will remain in the well permanently.

14.3.1. Cement Bulk Blending, Transportation and Storage 14.3.1.1. Blending Located at the service company facility will be a bulk blending plant. This will consist of storage silos and a batch blending tank or weigh batch blender. The weigh batch blender will be on scales, and is used for dry blending additives into the cement. Normally, these blending tanks are 350 - 450 cu ft, but are not completely filled to allow for blending. One method of blending involves adding 1/2 of the cement, introducing the additives, and then the remainder of the cement is added. A better and preferred method is to take 1/3 of the cement, 1/2 of the additives, 1/3 of the cement, 1/2 of the additives, then the remainder of the cement. This method has been shown to give improved and more consistent cement blends. Regardless of the blending method, the cement should be transferred a number of times between an intermediate tank and the weigh batch blender (or the intermediate tank and the bulk transport). This process of "boxing" or transferring the cement is critical to quality cement mixing. The cement should be moved at least three (3) times before going to location to ensure proper cement blending. Some systems (Schlumberger's CRETE* blends for example) can require at least five (5) transfers to ensure proper blending. Figure 14.1 is a picture of a bulk plant. A bulk plant is used both to blend cement and to confirm the volume of cement loaded. For locations where liquid additives are used, while no bulk blending is occurring, the cement will still be run through the bulk plant to confirm the number of sacks of cement being sent to the location. The only change is multiple moves of the neat cement are not required.

March 2004

Company Use Only

Section 14 - 8

Cementing Equipment

14

Figure 14.1: Cement Bulk Plant

Transportation (Bulk Equipment) - Dry cement is conveyed pneumatically with compressed air to the mixing equipment. All bulk equipment will have some type of air handling system, a method to fluff or aerate the bulk cement, and pressure relief valves to prevent over pressurization of the tanks. Most of these systems operate at a pressure of 40 - 80 psi. While the actual tanks will vary, the basic design is the same for all cement transfer. The cement is blown into a tank and transported to the location. The cement is then blown by air through a 4-inch hose to the mixing unit. At the mixing unit, there will be a surge can to eliminate most of the air in the system and reduce the pressure for mixing. In land operations, directly into the mixing head on the cement unit. Many of the mixing problems with cement jobs can be directly traced to problems with the bulk system. Inadequate cement delivery can usually be traced to lack of sufficient supply air, or too much pressure drop in the bulk lines. It may be necessary on permanent installations to install additional air guns into the line to facilitate better cement delivery. Air - Volume and quality of the air used is critical to quality bulk cement delivery. The air must be dry. The air tanks should be drained of any water prior to any cement job, and should be checked at least once a week by the cement operator on all offshore locations. If there is a cement delivery problem, the quality and quantity of the air should be checked. This will require using an air flow meter, not simply looking at the compressor and writing down the compressor rating. Air compressors can change efficiencies with time; thus confirming the air delivery must be done. Additionally, if possible the bulk

March 2004

Company Use Only

Section 14 - 9

Cementing Equipment

14

lines should be inspected for cement build-up, which will reduce the flow area of the line. On land operations, where the service company delivers the bulk system for each job, it is assumed the air system and bulk system are properly designed and maintained by the service company. Figure 14.2 is a typical bulk cement transport used on land operations. The two bulk cans (or pods) in the front portion of the trailer are loaded with the cement and driven to the location. The air compressor sits at the front of the truck directly behind the cab. There may also be a tank at the back of the truck used as a surge can and dust collector. This particular unit is a 400-cuft system and is a single unit. Bulk transports are also available in 660-cuft units and are hauled by a separate tractor. Because of load limits, field bin storage units are also used. These units have a 1,400cuft capacity; but if loaded, are too heavy to transport to the location. They are normally spotted at the rig site, then filled from the smaller transport units. This allows for less equipment on location during the actual cement job. Individual cement silos can also be spotted on location, each holding approximately 1,100 cuft. Offshore locations have permanently mounted tanks that range in size from 1,000 1,750 cuft. Depending on the rig, these tanks may be located next to the cement unit or completely across the rig and several decks away. The closer the bulk system is to the cement unit, the better the cement delivery, and the better control of cement mixing.

Figure 14.2: Bulk Cement Transport

March 2004

Company Use Only

Section 14 - 10

Cementing Equipment

14

The same type of bulk equipment is used at all locations. The tanks are removed from the trailer, put on a skid, and used for barge operations. The tanks can be mounted on a boat and used as an offshore transport. Offshore rigs use permanently mounted upright silos that function the same way as those shown in the figure.

14.3.1.2. Bulk Cement Transfer - Cement Losses On land locations, the amount of cement delivered to the location is approximately what was ordered for the job. Additional cement is loaded because of problems with offloading the last 50 sacks from a bulk system. The last remaining sacks of cement in a bulk system cannot be unloaded without large amounts of air coming with the cement. This causes slugs of cement to be delivered to the cement unit, making density control very difficult. Enough excess cement is brought to location to account for the delivery limitations. For offshore locations, there are multiple transfers of cement. The cement will be transported from the bulk plant to a transfer boat, then again blown into the rig tanks. Since the transfer does not require consistent delivery rates of cement, the tanks on the boat can be blown down to near empty. The problem with offshore bulk material transfer is the amount of dust created in the process, which results in losses in total volume transferred. Often the tanks on the boat are not well maintained, and the transfer process not closely monitored. Many operations have experienced as much as a 15 - 20% loss in bulk material transfer. This is excessive, and for most operations, the material loss should not exceed 10%. High-loss rates can be traced to failure to empty boat tanks or overfilling rig tanks which leads to raw product being forced out the vent lines.

14.3.1.3. Bulk Cement Storage The volume quoted on a cement bulk tank will be the total volume available in the tank; NOT the volume of cement that can be placed in the tank. Because cement is moved by air, it requires some space to be able to aerate or fluff. Further, when filling the tank, it is not possible to completely remove all of the air from the system. Because of this, the volume of cement in a bulk tank is limited by the bulk volume factor of the cement. For neat cement, the bulk loading factor is approximately 0.873. This means that in a bulk tank with a capacity of 1,000 cuft, approximately 873 sacks of cement can be placed in the tank. Cement additives will change this bulk loading factor. For example, cement with 35% silica sand has a bulk loading factor of approximately 0.678. Over time, the cement will settle in the tank and additional cement can be put on top of the initial load. This works well for one extra "top off" of the tank, but excessive cement in the tank prevents proper unloading. Table 14.1 lists several common cement systems, the corresponding approximate bulk factor, and the number of sacks that can be placed in typical bulk tanks. These figures vary from one service company to another, but will be within 5%.

March 2004

Company Use Only

Section 14 - 11

Cementing Equipment

14

Table 14.1: Bulk Factors for Common Cement Systems # of Sacks to Fill Various Tank Sizes Cement System

Bulk Factor

200

420

620

1050

1250

Neat Cement

0.873

175

367

541

917

1091

Cement + 35% Sand

0.678

136

285

420

712

848

Cement + 2% Gel

0.844

169

354

523

886

1055

Cement + 4% Gel

0.817

163

343

507

858

1021

Commercial Lightweight

0.670

134

281

415

704

838

50:50 Poz: Cement + 2% gel

0.712

142

299

441

747

890

Understanding bulk cement storage limitations aids in designing cement volumes for a particular job. If the calculated cement job requires 2-1/2 bulk tanks of lead cement and 1/2 tank of tail, it may be better to redesign the amount of lead and tail cement allowing for two tanks of lead and one tank of tail cement. Of course, this would depend on well requirements and hydrostatics, but often the bulk system can be optimized simply by changing the relative amounts of cement to be used. Optimizing the use of the bulk system will improve the results of the cement job. The operation will be simplified and the quality of the cement mixing improved. For offshore operations, large jobs may require spotting additional cement bulk tanks on the rig. When this is required, it is normally best to fill these tanks with lead cement, and mix from these tanks first. This is due to the lower technical requirement of a lead cement system, and if there is a mixing problem, normally the lead cement has a longer thickening time, which could allow more time for problem resolution.

14.3.1.4. Bagged Cement Cement may also be shipped and handled in sacks or "big bags." Sacked cement is common in many remote areas that lack pneumatic truck transport. The sacks are cut on location into bulk silos, and then the cement handling procedure mimics normal operations. These operations require sufficient time to cut all the required sacks, and require the sacked cement be properly stored. An alternative to sacked cement is the use of big bags. These bags usually contain one metric ton of cement (1,000 kg) and are common in many areas where cement is shipped great distances. The big bags are easily transported and stored. Again, storage should be in a protected environment to prevent moisture contamination. The operations using big bags will normally have a large cutting area where the bag is lifted with a forklift and set on a hopper that cuts the bag and the cement falls into a tank. The tank is then closed and the cement moved pneumatically to a holding tank. Big bag operations are much faster than dealing with sacked cement, but do require the use of a forklift while loading the cement.

March 2004

Company Use Only

Section 14 - 12

Cementing Equipment

14

14.3.2. Cement Slurry Mixing There are several methods to mix the dry cement with the mix water. The methods fall into two broad categories of batch mixing or continuous mixing. Batch mixing involves mixing a large volume of cement prior to pumping it in the well. The density and other properties of the slurry can be measured and confirmed prior to placement in the well. Continuous mixing involves mixing cement "on the fly" and pumping it directly into the well. This requires very good control of cement density while mixing.

14.3.2.1. Batch-Mixing Equipment As the name suggests, batch-mixing equipment consists of a large tank and a mixing device to mix a volume of cement. Most batch-mixing equipment consists of two tanks, each having a 50-bbl capacity. The mix water is placed in the tank and dry cement blown into the tank and mixed until the desired density is reached. The slurry is continuously stirred with paddles, and is recirculated with a centrifugal pump. When the cement is ready to be pumped in the well, the centrifugal pump will feed the triplex pump on the cement unit. A batch mixer cannot pump a slurry into the well, as there are no positive displacement pumps on the unit. Some cement units have very large (± 25 bbl) recirculating tubs that allow for batch mixing small volumes of cement. This is convenient for setting plugs and squeeze operations. Batch-mixing equipment is recommended for some critical cementing operations. These include production liners, high-density slurries, and other high-risk operations. If batch-mixing equipment is to be used for the cement job, the cement tests should be modified to include the mixing time for the slurry. Normally, this is estimated at one hour and simply involves stirring the cement for the mixing time prior to starting the thickening time test (see Section, 3, Cement Testing). Often a single-batch mixer will not be large enough to hold all of the required cement. In these cases, one tank on the batch mixer can be filled with slurry, and as it is emptied, additional slurry is mixed in the remaining tank. In this process, the batch mixer is being used as an averaging tank. The large residence volume of slurry will even out the swings in slurry density seen in continuous operations. The disadvantage to this type of operation is if one tank has the wrong density, there is a large volume of cement that must be dealt with before the correct density can be achieved. A generic batch-mixing tank is shown in Figure 14.3. A typical unit has two 50-bbl mixing tanks, an operator station in the middle, and the power system on the end. This tank allows for mixing the dry cement with the mix water, recirculating the blend until the cement is at the proper density, then discharging to the downhole pump unit. The centrifugal pump on the unit is responsible for both mixing and transferring the cement slurry to the downhole pump.

March 2004

Company Use Only

Section 14 - 13

Cementing Equipment

14

Figure 14.3: Typical Batch Mix Tank

Dry Cement

Prehydrator

Turbine Agitator

Baffles

Batch-Mixing Tank Water Inlet

To Displacement Pumps Centrifugal Pump

Recirculating Cement Suction

14.3.2.2. Continuous-Mixing Equipment The majority of cement for oilfield applications is continuously mixed. The volume of cement needed for most cement jobs is simply too large to batch mix, and the additional time and equipment required to batch mix large cement jobs makes batch mixing impractical. Continuous-mixing equipment falls into three groups. The first is jet mixing, which is the oldest method for mixing cement. The second group is recirculating mixing and has evolved to the third group, computer-aided mixing. The only place where jet mixing is still routinely used is Germany. Other locations use either recirculating mixers or the newer compute-aided mixing.

14.3.2.2.1

Jet Mixer

Erle P. Halliburton invented the original jet mixer in 1920, and the design is still in use after 80 years. The mixing rate is controlled by the volume of water forced through the jet, and by the amount of cement fed into the hopper. This is a one-pass system,

March 2004

Company Use Only

Section 14 - 14

Cementing Equipment

14

meaning there is no recirculation of the mixed cement, and control of the density can be very difficult. When these systems are used, it is best to feed the cement into an averaging or holding tank, and if possible recirculate a portion of the slurry back through the jet mixer. Figure 14.4 is a schematic of a typical jet mixer.

Figure 14.4: Jet Mixer Mixing Water Surge Tank or Atmospheric Tank

(from the mixing manifold)

Slurry (to pump(s))

Additional Water

Butterfly Valve Sock

Suction Pipe

Dry Cement Gooseneck

Hopper

Grating Water Jets Slurry

Bowl

Slurry Tub

Mixing Water

14.3.2.2.2

Recirculating Jet Mixer

The original, jet mixer design was a single-pass system where the finished product was ejected out of the mixer and pumped into the well. This gave only one opportunity for the cement to be mixed to the proper density. Advances in mixing led to a recirculating jet mixer, where a portion of the mixed slurry could be added back into the mixing line and additional cement added. This allowed for increasing the density of slurries that had not been properly mixed. The system mixed the cement the same as in Figure 14.4, but an additional recirculating line was added from the resident tank back to the mixing line.

14.3.2.2.3

Recirculating Mixer

The majority of the cement mixed in the oilfield today uses some sort of recirculating mixer. The next generation of mixers increased the amount of shear and mixing energy at the cement head, and eliminated the use of the jet mixer. The newer cement heads take cement directly from the surge can under pressure and feed the cement into the mixing chamber. The water enters the head at high pressure and shear, and the

March 2004

Company Use Only

Section 14 - 15

Cementing Equipment

14

cement mixing occurs. A small mixing chamber or premix side, typically 3 bbl, is used to confirm the density and allow for air escape. The cement then falls over a weir into a larger recirculating tub where it is homogenized to pump downhole. The size of the larger tank will vary from 5 - 25 bbl. Advantages of the recirculating mixer include better density control, and the ability to mix cement at low rates. With a recirculating mixer, rates under 1 bpm are possible. With a jet type mixer, very low mixing rates can lead to plugging the gun barrel, backup of slurry into the dry cement, and plugging the mixing system. Figure 14.5 is a schematic of a typical recirculating mixer. A key component of the system is the use of a densitometer in the recirculating line. This allows the operator to continuously monitor the density of the slurry in the tub, and make appropriate changes prior to pumping downhole.

14.3.2.2.4

Automatic Density Control (ADC)

A major advance in cement mixing has been the introduction of computer-aided mixing. During manual mixing, the operator must keep track of the density, rate, mix water, and tub level. These multiple tasks can be very difficult to perform properly all of the time, and can lead to large variations in cement density control. Adding the complexity of inconsistent cement delivery, the job can become extremely challenging. The ADC systems control cement mixing by measuring the density of the slurry in the recirculating tub. If the density is too light, the gate valve on the cement line is opened to allow for more cement. Conversely, too heavy of a slurry would see the valve being closed on the cement line. Most of the ADC systems are keyed to the mix water rate. This rate is maintained at a constant value, and the density adjusted by changing the cement-input rate. This does not relieve the cement operator from monitoring the system. If the bulk system does not deliver cement to the unit, the ADC will not shut down pumping, and even with no cement in the system, will pump mix water directly downhole. The operator must monitor the system closely. The best cement density and rate control available is with an ADC system that is married to an excellent bulk cement system. The total package must work together for optimum mixing. For all ExxonMobil operations, the preferred mixing system is automatic density controlled or computer-aided mixing.

March 2004

Company Use Only

Section 14 - 16

Cementing Equipment

14

Figure 14.5: Recirculating Mixer Bulk Cement

Cement Metering Valve Mixing Water Water Metering Valve Slurry

Centrifugal Pumps

Recirculation Line

Mixing Tub Slurry (to pump(s))

14.3.2.2.5

De-aeration Partition

Solids Fraction Monitor

Schlumberger has introduced a density and rate control mixing system called a solids fraction monitor. The system consists of two flow meters and a tub level indicator. The primary use of the system is for mixing cement systems below 10.0 lb/gal. The system works by determining the input rate of water into the mixing tub. An additional meter measures the slurry flow rate coming out of the system. The final variable is the tub level, which determines the volume of slurry in the system. By comparing the flow rate of the water into the tub with the slurry rate out of the unit, the amount of cement added can be determined. The system depends on an accurate blend of cement, consistent densities of mix water and accurate tub levels to work properly. The slurry fraction monitor is said to control the percentage of mix water to within +/-3%. This level of control works well for lightweight slurries, but is not sufficiently accurate to control the density of a slurry exceeding approximately 14.5 lb/gal.

March 2004

Company Use Only

Section 14 - 17

Cementing Equipment

14

The use of a solids fraction monitor to control cement density is recommended only for slurries containing specialty lightweight additives, mixed below 11.0 lb/gal.

14.3.3. Pump Systems After the cement is mixed, it must be pumped downhole. This is the job of the positive displacement pumps on the unit. There are single and dual pump cement units, with one pump serving as a backup for the other on dual pump systems. For ExxonMobil operations, the preferred pump unit is a dual-pump system. At some locations, particularly small land operations, some service companies offer a singlepump cement unit. These units may be acceptable for squeeze and plug operations, but should not be routinely used for primary cementing operations. Most cement pumps are equipped with a pump rated to 10,000 psi. The pressure rating and pump output capacity depend on the fluid end (plunger size) and horsepower of the pump. Most dual-pump units have two fluid ends, one with 4-inch plungers and one with 4.5-inch plungers. An approximation of the rate at pressure capabilities of a pump can be made if the horsepower of the engine driving the pump is known.

Horsepower =

rate( gpm) ∗ Pressure( psi ) 1714 ∗ Efficiency

For average cement pump skids, each pump is assumed to be driven by a 200horsepower engine with 95% efficiency. A typical pressure, rate graph is shown in Figure 14.6.

Figure 14.6: Typical Pump Efficiency Curve

March 2004

Company Use Only

Section 14 - 18

Cementing Equipment

14

14.3.4. Density Measurement The principal objective of cement mixing is to mix the slurry at the designed density. This assures a consistent slurry with the properties that were designed for the well. Without good density control, the quality of a cement job is severely compromised. Measuring density on location should always be performed under pressure. Because cement is conveyed pneumatically, there will be entrained air in the system. The air must be compressed to properly measure the density of the cement slurry. Differences in atmospheric and pressurized density measurements average about 0.5 lb/gal, but can be as high as 1 lb/gal in some systems. The cement units will have a densitometer located in the recirculating line, and hopefully one located in the discharge line to the well. The densitometer on the recirculating line is used to measure the mixing density of the cement as it is mixed, while the downstream unit is measuring the density of the slurry as it is being pumped in the well. Both units are under pressure, with the recirculating densitometer being under approximately 100 - 150 psi and the downstream unit at the circulating pressure of the well. The ExxonMobil standard is to calibrate the densitometer on location with a pressurized mud balance that has been itself calibrated with water. Samples of the cement from the mixing tub should be taken during the initial weight-up of the cement to confirm slurry density and calibrate the densitometer. Periodic checks of the cement density should be done throughout the job. An atmospheric mud balance should not be used to measure cement density.

14.3.5. Data Recording Modern cement units are equipped with recording equipment to record the density, rate, and pressures during the cement job. The ExxonMobil standard requirement for data recording on cementing operations is the density, rate, and pressure. This data is critical to enable evaluation of the cement job in the event of a failure, or for future improvements to the operation. The data should be collected on a 1-4 second interval, with preference given to a 1 second recording. A common problem with data recording on cement jobs is when the rig pumps are used for displacement. The cement unit operator will record the mixing and pumping of the cement. However, as soon as the displacement is turned over to the rig pumps, the valve leading to the cement unit is closed, and no further data is collected. This is done to allow cleaning of the unit. The cement operator should be instructed to leave the valve open to the unit to allow for recording of pressures for the entire job. Switching the valves on the unit will still allow for unit cleanup after the cement mixing, while still recording the displacement pressures. On some locations, it may be necessary to add an additional pressure transducer to record the entire job. Recording the pressures for the entire cement job is an essential part of any job report. Additional data to be captured on location includes the density of all mixed fluids and the downhole pump rate. Often the rates for liquid additives will also be recorded, but at a minimum, the rate and density should be recorded.

March 2004

Company Use Only

Section 14 - 19

Cementing Equipment

14

While not directly related to equipment, inventory control and sampling are an important part of every cementing operation.

14.3.6. Inventory Control Following the cement job, a full accounting of all materials should be made. This is particularly important in offshore operations or operations where liquid additives have been used. The volume of all additives and mix water should be compared to the planned volumes.

14.3.7. Sampling Samples of all cement blends, mix water, and additives should be collected and retained until the cement job is considered a success. Samples of mix water should include the mix water with any additives included. Individual samples of liquid additives should be collected and retained. The service provider should provide appropriate sample containers for all cement, additives, and mix fluids.

14.3.8. Other Surface Cement Equipment 14.3.8.1. Cement Plug Containers or Cement Heads Most cement jobs will call for the use of a bottom and top cement plug. The bottom plug is designed to separate the drilling fluid from the spacer or cement, The top cement plug separates the cement from the displacement fluid and serves as a volume indicator for displacement. Operationally, when using a double-plug cement head, the plugs are launched by opening a valve directly above the plug to force fluid above the plug and pump it into the well. A common mistake is to fail to close the valve below the plug, which can allow for fluid bypass below the plug. This will result in the plug leaving late. After assuring the plug has dropped, all valves can be opened, but not during the dropping operation (see also Section 16.2.4.4). Figure 14.7 illustrates the double-plug cement head. There are three common methods used to determine if the top plug has left the cement head. Some cement heads have a "flag sub" that will trip a lever and give a visual sign the plug has moved past that point in the head. These devices are the least accurate because the flag can be tripped without the plug leaving the head. High velocity fluid bypassing the plug can trip the flag. Commonly, a wire is attached to the top plug and the wire run through the top of the cement head. When the plug leaves the head, the wire is pulled with the plug, thus confirming the plug has left. This works very well, but the wire must be long enough to see regardless of the location of the head relative to the drill floor. If the wire detaches from the plug, the assumption can be made that the plug is still in the head.

March 2004

Company Use Only

Section 14 - 20

Cementing Equipment

14

Figure 14.7: Double-Plug Cement Head Lifting Ring Hex Plug and Cap

Valve

Ball Assembly with Lock Bolts

Bull Plug

Flow Line to Cement Units

Connection to Casing

A final method of determining if the top plug has left the head is through the use of a radioactive tag placed in the top plug. The radioactive tag can be easily tracked with a sensor and if the plug hangs up in the cement head, it is easily identified by the sensor. This is the most reliable method of assuring a cement plug has left the head, though it does require handling radioactive tags. (Note these tags have a very low level of radioactivity and do not pose a health problem if handled properly.)

14.3.8.2. Wiper Plugs Wiper plugs are used to separate the cement and mud both in front of the cement and behind. On liner jobs, the plugs are loaded into the running tool on the liner, and a drill pipe wiper dart is used to clean the drill pipe. The dart then latches into the casing plug and the liner is then cleaned of cement. It is critical to determine that the dimensions of the plugs, darts and related equipment are compatible and will work with all of the equipment in the well. There are several failures due to simply not checking that all of the parts (plugs, heads and darts) will fit together properly.

March 2004

Company Use Only

Section 14 - 21

Cementing Equipment

14

Most cement jobs strive to "bump the plug," which means displacing the top cement plug to the float collar. The success or failure of a cement job is not measured by the presence or absence of a plug bump, but it is always reported. Failure to bump the top plug can result in the need to drill out excessive cement from the casing.

14.4. SUBSURFACE EQUIPMENT For the purposes of this Section, any piece of equipment that is either attached to the outside of the casing, or is integral in the casing string (screwed in between two or more joints of casing) is considered subsurface equipment. This includes centralizers, stop collars, scratchers and wall cleaners, float equipment, and stage collars. The cement plugs are integral to the float equipment and are included in the discussion of float equipment. This Section does not cover downhole equipment used during remedial operations, which will be covered in a future manual on remedial cementing.

14.4.1. Casing Centralizers and Stop Collars 14.4.1.1. Centralizer Performance Standards When using a bow-spring centralizer, the ExxonMobil standard is to utilize a centralizer that meets the requirements of API Spec 10D, Bow-Spring Casing Centralizers, or the equivalent ISO 10427-1-2001. The specification is only for bow-spring centralizers. There are no API or ISO requirements for rigid or solid centralizers. This does not preclude the use of solid or rigid centralizers, but the user must be aware there are no industry standards for these types. The specification for bow-spring centralizers dictates the minimum requirements for a centralizer under a specific set of load conditions. There is also a recommended practice for centralizer placement and stop collar testing, API RP10D (ISO 10427-2). This recommended practice contains calculations for centralizer placement and test procedures for evaluating the holding force of stop collars. Centralizer placement is not part of the API specification for centralizer performance, but simply one recommended method of calculating standoff, casing sag, and ultimately centralizer placement.

14.4.1.2. Where to Use a Centralizer 1. Centralize where isolation is required: It is important to establish why the pipe is being centralized. The focus areas should be those requiring zonal isolation. Centralizers will help obtain that isolation. For long sections of unproductive interval, with no requirement for isolation, the need for centralization is reduced from a cementing standpoint. However, this does not eliminate the need for centralization from a casing running standpoint. 2. Centralize at the shoe: This will improve the chances of a successful shoe test and isolation at the shoe.

March 2004

Company Use Only

Section 14 - 22

Cementing Equipment

14

3. Centralize pipe in pipe: Centralization is generally required at the liner hanger or other equipment. For tie back strings, centralization is generally not critical. Calculations of drag depend on surface area in contact with the rock. Calculations show running centralizers in a horizontal well may require a higher running force in part due to the restoring force on some centralizers. Solid centralizers do not have a restoring force and will calculate a lower running force. Running centralizers in a well with productive intervals open will reduce the contact area subject to differential sticking, thus making running the casing easier. The user must be very careful to evaluate the drag calculations being used and the impact of permeable formations.

14.4.1.3. Where Not to Use a Centralizer 1. Be very careful putting centralizers at the top of a casing string, especially rigid centralizers near a wellhead. If the casing needs to be moved slightly to accommodate a hanger or wellhead, and a centralizer is keeping it in one place, the process can become very difficult. 2. Very tight clearances pose unique problems. There may simply not be enough room for centralization. This may be due to the centralizer itself or the tolerances of the stop collar.

14.4.1.4. Centralizer Type - Bow-Spring, Rigid or Solid 1. A bow spring is a centralizer with flexible bows that can move in and out. There are several types available. The tandem-rise type tends to give high restoring forces with lower running force. 2. Rigid and solid centralizers have a fixed OD and do not have flexible bows. The difference is all solid centralizers are rigid, but not all rigid centralizers are solid. The solid centralizer will be a solid piece of material, made of aluminum, steel, highimpact plastic or other material. A rigid centralizer will be a solid metal band attached to end rings. The interior of the centralizer will be open. Weatherford Gemoco manufactures a rigid centralizer with collapsible bows called a Spiral Glider. The advantage of these centralizers is if the pipe gets into a sufficient bind, a load of approximately 17,000 pounds will collapse the bow. This is a complete collapse and the centralizer will no longer be able to provide standoff, but will not bind the pipe.

14.4.1.5. Standoff There is no such thing as an API recommended standoff. It is common to quote that API recommends 67% standoff ratio. The API makes no recommendation as to the amount of standoff required. The source of the 67% number is for performing a centralizer specification test. At a 67% standoff, the centralizer has to show a particular amount of force. 1. For most applications, 80% standoff (when isolation is needed) will give good cementing results. Above 80%, the incremental gain can become very expensive. Lower standoff may be acceptable if there is sufficient distance above and below the area requiring isolation. If isolation is required within a 100 - 200 ft interval, higher

March 2004

Company Use Only

Section 14 - 23

Cementing Equipment

14

standoff will be required. If isolation is only required within a 500-ft or greater interval, lower standoff will probably be sufficient. 2. In the calculation of standoff, there can be different values if the standoff is calculated at the centralizer or at the sag of the casing. It is recommend the sag of the casing be taken into account in the equation. 3. The standoff calculations assume a particular hole size, and wash out will effect the results. Better centralization is obtained from a bow spring in a washout zone than with a solid or rigid type simply because of the presence of the bow. 4. Casing standoff with rigid centralizers is evaluated at the centralizer. Calculation at the sag of the casing between the centralizers is more difficult, as it requires the calculation of the lateral movement of the casing. Table 14.2 evaluates standoff of a rigid centralizer at the centralizer body for a particular pipe and hole configuration. Note the standoff at the sag of the casing will be worse than that calculated at the centralizer. The standoff is calculated by the equation:

Annular Clearance = Standoff Ratio = Casing:

IDHole − ODcasing 2

Actual Standoff Annular Clearance

7"

Centralizer OD:

8.25" (from Manufacturing Catalog)

Open Hole:

8.5"

For this situation, the annular clearance for perfectly centered casing is 0.75 inch. The centralizer is 0.25 inches smaller than the open hole, and will therefore be offset by 0.25 inch of the difference, or .125 inch on each side. This makes the standoff for this centralizer:

Standoff Ratio =

0.75 − 0.125 = 0.83 0.75

Table 14.2: Standoff as a Function of Hole Size

March 2004

Hole ID

Annular Clearance (in)

% Standoff

8.5

0.75

83

8.75

0.875

71

9

1

63

9.5

1.25

50

10

1.5

42

10.5

1.75

36

Company Use Only

Section 14 - 24

Cementing Equipment

14

As is seen in this table, as the hole size increases, the standoff at the centralizer becomes worse very quickly. It is apparent solid, rigid centralizers should not be used in holes that are washed out or have any hole enlargement.

14.4.1.6. Flow Diversion 1. Many centralizers incorporate some sort of flow diversion either through angling the blades in some particular direction, or incorporating some other type of flow diversion. Considerable full-scale testing has been done to determine the effectiveness of these devices; the data indicates the flow diverts for approximately 1 - 2 times the length of the centralizer. Therefore, with a 3-foot long centralizer, expect a maximum of 6 feet of flow diversion. To get more diversion would require large pressure drops across the centralizer that would lead to lost circulation or the inability to circulate the well. 2. Many demonstrations of flow diversion or swirl enhancement tools use water or other very low viscosity fluids to demonstrate flow diversion. Viscous fluids like cement do not react like these low viscosity fluids and will not continue the swirling action, as noted in the full scale tests. 3. If a flow diversion centralizer can be obtained at no additional cost, then the potential gain from the flow diversion may be appropriate. 4. Flow diversion centralizers can have application where only short intervals require isolation. This can be true in overlap areas of liners and between production intervals that are closely spaced. 5. Coupled with pipe reciprocation, flow diversion centralizers can also aid in mud removal. This is due to the "full wellbore" coverage of the vanes on the centralizer effectively wiping the entire wellbore face. 6. If there is any wash out, or excessive decentralization of the casing, flow diversion will be severely compromised. The cement will simply take the path of least resistance, typically on the wide side of the annulus, away from the flow diversion area.

14.4.1.7. Which Centralizer to Use 1. Depending on the well, and the location within the well, there may be applications for both bow-spring and rigid centralizers. Bow-spring centralizers work well in almost any application where the side loading force can be overcome by the force of the centralizer bow. Areas where this is usually not the case is in the build or drop section of the well. In these areas, the side load is so high, a bow-spring centralizer cannot be used. The main marketing area for solid centralizers has been in horizontal wells. Every salesman has pointed out that he has been on location where the bow-spring centralizer has already been put on the pipe and it is completely flattened. If this is actually the case, the centralizer cannot meet the API specifications, because the bow must hold up the medium weight of a joint of the casing for which it was designed. Using a bow-spring centralizer in any well, even horizontal is not a problem. It is the side load calculation that is important.

March 2004

Company Use Only

Section 14 - 25

Cementing Equipment

14

2. It is not possible to ever get 100% standoff with any rigid or solid centralizer. The centralizer must be smaller than the hole it is going into, and therefore cannot give complete centralization. In most drilling situations, the smallest portion the centralizer must pass is the previous casing string, and once in the open hole, the hole OD increases due to wash out, and should be considered when calculating stand off. The rigid or solid centralizers will not give as good a standoff as a bowspring in these situations. This assumes the side loads are within the limits of the bow-spring centralizer. 3. Suppliers of solid centralizers often use a marketing fear factor to sell their product. It is commonly questioned or stated that they have seen a number of centralizers fall or come apart in the well, causing severe casing running problems, failed casing running, damage to wellheads, etc. Given enough force, anything can be broken and bow-spring centralizers can fail. This is very rare and literally thousands of wells have been successfully cemented with bow-spring centralizers. 4. Suppliers of bow-spring centralizers point to stiffening of the casing by the rigid centralizer and sticking the pipe because the centralizer plows into the formation. They point to cases where the casing hung up on the centralizer due to a wellbore restriction. There are undoubtedly cases where this has occurred, but like bowspring centralizers, the vast majority of the wells cemented with rigid or solid centralizers have worked as expected. 5. With respect to solid centralizers, there is conflicting marketing information on the use of aluminum, steel, zinc, plastic, etc. There are differences in drag depending on the friction factor employed. Included with the friction factor is data on wear of the various materials. Aluminum appears to suffer the most wear, with steel showing the least, though the data sets are too small to make any conclusions. 6. Small steel centralizers less than 18 inches in length can offer the least desirable situation. The area of the fin is half or less than half of the larger centralizers, which increases the point load. 7. Another marketing technique of the solid centralizers is the need to overcome the starting and running force of the bow spring. It is definitely true if too many bowspring centralizers are run on the casing, the casing must be pushed into the well. The running force numbers should be available for all of these centralizers and the calculations from the service company will help in determining these numbers.

14.4.1.8. Centralizers and Pipe Movement Pipe movement can greatly enhance cementing success, particularly in tight annular clearances. For liner applications, pipe rotation is preferred over reciprocation as it allows setting the liner hanger prior to beginning the cement job. Depending on the type of pipe movement planned, centralizer selection can become important. For casing strings in deviated wells that are to be rotated, a rigid or solid centralizer is preferred. In highly deviated wells, torque can be excessive. This can be reduced by using roller type centralizers. These centralizers have been shown to reduce the effective torque by as much as 67%. In straight or low angle wells where the pipe is to be reciprocated, bow-spring centralizers are preferred.

March 2004

Company Use Only

Section 14 - 26

Cementing Equipment

14

If rotation is not employed in the drilling plan, consideration should be given to centralizers that provide 360° coverage around the casing. These centralizers will have some type of flow diversion. By using full wellbore coverage, the reciprocation action will still result in moving mud over the entire annulus. Without this coverage, reciprocation alone may not get mud moving on the narrow side of the annulus.

14.4.1.9. Stop Collars A majority of failures of centralizers can be traced directly to a failure of the stop collar. Failure of the collar to hold the centralizer in place can result in bunching up of the centralizer, or allowing the centralizer to be pushed into the hole rather than pulled into the hole. There are a number of stop collars or holding devices on the market, and are available either as separate items or integral to the centralizer. The most common types and limitations: •

Friction type devices - Held in place with a nail or other similar device; these may be available in either slip on (solid ring) or hinge type. These devices will cause the least amount of damage to the casing, but offer the lowest holding force (generally less than 10,000 lbs).

•

Set screw type - Held in place with set screws tightened against the casing; generally, only sold as slip on type. This type will result in some minor casing damage due to contact with the casing. Require the screws be properly tightened, which is often a problem on location. Quite often, one screw is tightened completely before engaging the opposite screw. This places the stop collar off center and will reduce the holding force. Holding force for these type devices will be 15,000 - 25,000, depending on the number of screws and casing grade.

•

Dogs or other slip type devices - Only available as a slip on device. These devices offer the highest resistance to movement. They employ a slip type holding device, and have a holding force up to 50,000 lbs. The OD of the stop collar will be higher to accommodate the slip area, so they may not have application in slim hole wells.

•

It is recommended that consideration be given to the drag forces that will be applied to the centralizer. These calculations are readily available from the centralizer company.

14.4.1.10. General Comments 1. Do not run a solid or rigid centralizer in the open hole of a vertical hole. 2. Do not place a solid or rigid centralizer in close proximity to the wellhead area. 3. There is no such thing as API standoff. 4. Bow springs work very well if the side loads imposed by the casing are within the operating envelope of the centralizer. 5. Do not buy a particular centralizer based on fear of failure of another type. Select the centralizer based on required performance in the well.

March 2004

Company Use Only

Section 14 - 27

Cementing Equipment

14

6. Flow diversion is fine but do not pay extra for it. 7. If rotation cannot be employed in the casing movement, consideration should be given to running centralizers that have 360º coverage of the wellbore. 8. There is application for each type of centralizer, often within the same well. depends on the side loads, stiffness of the assembly, point loads, etc.

It

9. Do not purchase a particular centralizer based on "marketing hype." Each centralizer has its merits and limitations and the selection should be made using engineering judgment, not marketing. 10. For long, extended-reach casing strings that are to be rotated, roller-type centralizers provide the best reduction in torque over conventional centralizers.

14.4.2. Casing Float Equipment 14.4.2.1. Float Equipment Performance Standards The ExxonMobil standard is to utilize casing float equipment that has been manufactured and tested per the API Recommended Practice, API RP10F, or the equivalent ISO 18165-2001. Both of these standards refer to a recommended practice. There is no API specification for casing float equipment. The recommended practice divides float equipment into service categories depending on the severity of the application. The equipment used in a well need only meet those requirements that are expected for the particular application.

14.4.2.2. API/ISO Test Categories for Float Equipment The standard API/ISO nomenclature for float equipment identifies equipment based on flow durability and temperature application. Flow is performed in the forward direction, and the sealing ability of the float valve checked by back-flowing the fluid. This determines the ability of the float valve to withstand erosion and remain capable of sealing the well at the end of the cement job. These categories are tested without the use of any cementing plugs. The tables outlining the test categories from the API follow:

Table 14.3: Categories of Flow Durability

March 2004

Category

Flow Durationa (Hours)

Max. Sealing Pressureb (psi/kPa)

I

8

1500 (10,300)

II

12

3000 (20,700)

III

24

5000 (34,500)

Company Use Only

Section 14 - 28

Cementing Equipment

a

14

3

Circulation rate is 10 bbl/min (1.6m /min) for float equipment larger than 3-1/2 inch 3 (88.9 mm) and 6 bbl/min (1.0 m /min) for 3-1/2 inch (88.9 mm) and smaller float equipment b

The maximum test pressure should be the lesser of the values shown or 80% of the manufacturer's rated burst or collapse pressure for the float equipment casing, whichever is applicable.

Table 14.4: Categories of Flow Durability for Casing Fill-Up Equipment Category

a

Max. Pressurec (PSI/kPa)

Flow Duration (Hours) Reversea

Forwardb

I

2

8

1500 (10,300)

II

4

12

3000 (20,700)

III

6

24

5000 (34,500)

3

Circulation rate for all categories is 3 bbl/min (0.5m /min)

b

3

Circulation rate is 10 bbl/min (1.6m /min) for float equipment larger than 3-1/2 inch 3 (88.9 mm) and 6 bbl/min (1.0 m /min) for 3-1/2 inch (88.9 mm) and smaller float equipment c

The maximum test pressure should be the lesser of the values shown or 80% of the manufacturer's rated burst or collapse pressure for the float equipment casing, whichever is applicable.

Table 14.5: Categories of Static High-Temperature/HighPressure Tests

a

Category

Temperaturea ºF (ºC)

Max. Sealing Pressureb (psi/kPa)

A

200 (93)

1500 (10,300)

B

300 (149)

3000 (20,700)

C

400 (204)

5000 (34,500)

Duration at temperature is eight (8) hours for all categories.

b

The maximum test pressure should be the lesser of the values shown or 80% of the manufacturer's rated burst or collapse pressure for the float equipment casing, whichever is applicable.

Float equipment will be designated as III-C or I-B, depending on how it has been tested. Generally, larger casing sizes are not tested to III-C requirements, as they will not be used under these extreme conditions.

March 2004

Company Use Only

Section 14 - 29

Cementing Equipment

14

If very long circulation times are anticipated, it is recommended a higher grade of float equipment be used. In many cases, the change may be accomplished by simply changing the type of valve used in the equipment. Care must be taken in critical applications to be assured the float equipment, and not just the valve, have been tested to the reported category.

14.4.3. Types of Float Equipment The two main categories of float equipment are float collars and float shoes. Both pieces of equipment have some type of check valve. The float collar has threads on each end and is placed between two joints of pipe. The float shoe is placed on the end of the casing string, and is the first thing in the hole. Figure 14.8 is a typical springloaded valve. The fluid flow is from the top down, and as the fluid moves through the valve, the spring is depressed, allowing fluid flow. When the fluid flow stops, the spring returns the valve to the closed position, preventing back flow.

Figure 14.8: Float Valve

Courtesy of Weatherford Gemoco

Other types of float valves include flapper or ball type. These valves depend on the fluid flowing back up into the casing, to keep the valve closed. These types of valves are not recommended for high-angle or horizontal wells because the valve may not close properly. Figure 14.9 shows a typical float shoe on the left. The valve has been pre-cemented into the casing, and the end threaded to allow screwing it onto the casing string. The shoe has a rounded nose to ease running into the well. Figure 14.9 also shows a typical float collar. Much like the float shoe, the same valve is pre-cemented in place, but in this case, the equipment has been threaded on each end to allow for placement within the casing string. The distance from the float shoe to the float collar is typically two to four joints of pipe (80 - 160 ft). This area is called the shoe track. At least one joint of casing should

March 2004

Company Use Only

Section 14 - 30

Cementing Equipment

14

separate the float collar and float shoe. The reduced ID of the valve in the float collar will accelerate the fluids flowing through it. Depending on the design, the jetting action immediately below the valve can wash out the valve on the float shoe if the two pieces of equipment are screwed directly into each other. There are double float cement shoes that have two valve systems in one shoe if required. Both a float collar and float shoe are typically run for several reasons. The use of a float collar reduces the risk of over-displacement and a wet shoe. If only a float shoe was used, any mud pushed ahead of the top plug would contaminate the area around the shoe. By using both a float shoe and float collar, there is also redundancy in the float valves, greatly reducing the chance of failure. If the floats do not hold, it is necessary to hold pressure on the casing until the cement sets to prevent the cement from U-tubing back up the casing. When this pressure is released, a microannulus can form, potentially eliminating isolation in the well.

Figure 14.9: Float Shoe & Float Collar

Float Shoe

Float Collar Courtesy of Weatherford Gemoco

14.4.3.1. Stab-In Equipment On large casing jobs 20 inches and greater, the displacement volume can be excessive, requiring considerable changes to the cement system to compensate for the long displacement time. For these jobs, the float equipment can be modified to allow the drill

March 2004

Company Use Only

Section 14 - 31

Cementing Equipment

14

pipe to be stabbed into the top of the collar. This allows displacement down the drill pipe, greatly reducing the displacement volumes and the likelihood of cement contamination. Figure 14.10 illustrates a stab-in type float collar. The drill pipe is threaded into the top of the collar prior to the cement job. At the end of the job, the drill pipe is removed, and the casing circulated inside.

Figure 14.10: Stab-In Float Collar

Courtesy of Weatherford Gemoco

When performing a stab-in job, care must be exercised to calculate the collapse loads on the pipe. As cement is brought up the annulus, the casing x drill pipe annulus is not exposed to pressure and will experience a collapse load. It may be necessary to fill the casing with weighted mud to prevent excessive collapse loads during a stab-in cement job. As a precaution, after stabbing into the collar, the drill pipe x casing annulus should be filled and monitored to detect any leaks in the stinger seals.

14.4.4. Stage Equipment Stage cementing equipment allows a wellbore to be broken up into multiple sections to allow each section to be cemented individually. This equipment is most often used in wells where it is not possible to perform a single cement job due to lost circulation and low fracture gradients. Stage cementing was used extensively before the development of quality foamed cements or specialty ultra, lightweight cement additives. It is a low cost, often lower risk alternative to specialty cementing.

March 2004

Company Use Only

Section 14 - 32

Cementing Equipment

14

Figure 14.11 is an illustration of a stage cement job. The first stage is pumped conventionally followed by a wiper plug. After the first stage plug bumps, the stage collar is opened by either pressure, as in the case of hydraulic equipment, or via a "bomb" dropped from surface. The bomb seats in the stage collar and pressure is applied to open the tool.

Figure 14.11: Typical Stage Job

Centralizer

Opening

Closing Plug

Bomb Stage Collar

Cementing Basket

First-Stage Float

Plug

Collar

Shoe

First Stage

Dropping Opening Bomb

Second Stage

Tool Closed

With the tool open, the well can now be circulated from the stage collar up, effectively isolating the bottom portion of the well. The second stage is then performed, and the closing plug pumped behind the cement job. When this plug lands, pressure is applied to close the stage collar. After the cement sets, the stage collar is drilled out and operations continued. If necessary, more than one stage collar can be run in a single well. Generally, the bottom tool will be a hydraulic opening tool, with the upper collar being mechanical. Running more than one hydraulic tool in a single casing string is not recommended.

March 2004

Company Use Only

Section 14 - 33

Cementing Equipment

14

14.4.4.1. Types of Stage Equipment There are two classes of stage collars, hydraulic and mechanical. The difference in the two is in the opening mechanism for the tool. Both collars require bumping a plug to be closed.

14.4.4.1.1

Hydraulic Opening Tools

Hydraulic stage collars operate by the application of differential pressure across the tool to open. The advantage of these tools is that there is no time required waiting for a bomb to be dropped from surface, then fall to the tool. These tools are normally used deeper in the well where waiting on the bomb drop could be excessive, or in highly deviated wells where the bomb would not fall to the tool. Care must be exercised when running these tools. The main failure mode of a hydraulic stage collar is premature opening due to pressure surges while running in the hole or during circulation.

14.4.4.1.2

Mechanical Opening Tools

Mechanical stage collars require dropping an opening "bomb" that seats in a landing profile. Pressure is then applied to the bomb and the tool opens. Alternately, drill pipe can be run in the casing and the tool shifted to the open position. These tools are commonly used as the upper stage tool in wells where more than one stage collar is used, or in low deviation wells.

14.4.5. Design of Cement Slurries for Stage Jobs When designing the cement slurries for use in stage jobs, the primary concern will be the development of strength at the stage collar. This will be particularly important in the design of the first stage cement system. The design needs to take into consideration the time required for the cement at the stage collar to set. This will allow performing the second stage cement job without concern of lost returns below the collar. The lead cement for the first stage should be tested by preconditioning the cement at the bottomhole circulating temperature, then allowing the cement to set at the temperature found at the stage collar, similar to a liner top. The time required for the cement to gain 100 psi strength should be determined. After this time has elapsed, the second stage job can be performed. Additionally, if a mechanical stage collar is being run, the gel strength of the lead slurry for the first stage should be checked to ensure excess cement can be circulated out of the well after the tool is opened. While not required, often there is a small amount of tail cement placed at the stage collar on the second stage to place high-strength cement at the collar.

March 2004

Company Use Only

Section 14 - 34

Cementing Equipment

14

14.4.6. Failure Modes Stage equipment is subject to three mechanical failures: premature opening, failure to open, and failure to close. Hydraulic tools are more prone to premature opening than mechanical tools. Care must be taken with these tools when running into the well and circulating prior to cementing. As differential pressure opens the tool, if at any time during the running in and circulating process, differential pressure exceeds that required to open the tool, the tool will open and circulation to the bottom of the well will be lost. If the stage collar is set in a dogleg, or is otherwise subject to lateral loads, it may be difficult to open the tool. If this occurs, pulling some tension on the casing string may relieve enough of the load to allow the tool to function properly. Failure of the tool to close properly is generally caused by lack of sufficient closing pressure. The tool will close due to differential pressure, thus the differences in hydrostatics from the annulus to the inside of the casing must be added to the required closing pressure to properly close the tool. Additionally, gel strength of the mud can effect the transmission of the pressure. This can be readily overcome by simply pressuring the tool to at least 500 psi over the recommended closing pressure. If the tool does not close, most of the stage collars can be closed with the drill string. On drill out, weight set down on the closing plug will cause the tool to shift to the closed position. This requires sufficient weight be placed on the plug to close the tool. This can be readily done by simply running in the hole to the stage collar and setting down weight on the tool prior to beginning the drill out. Another failure mode for stage cementing is the inability to circulate the well after opening the stage collar. This is generally caused by excess cement being placed on top of the stage collar, and the cement either setting up or generating sufficiently high gel strengths to prevent circulation.

14.4.7. Example Equipment Figure 14.12 illustrates the function of a typical mechanical stage collar. The left picture demonstrates the tool as it is being run in the hole in the closed position. Note the ports in the side of the tool are closed (at the bottom of the blue inner sleeve). After pumping the first stage, an opening bomb is dropped which seats in the tool allowing pressure to be applied, which shifts a sleeve (shown in blue) and opens the ports in the tool. At this point, there is now a flow path through the open ports. The opening bomb also acts as a barrier and no fluid can be pumped past the bomb to the bottom of the well. Following the opening of the tool, the well is circulated for the second stage. At the end of the second stage, the cement is followed by the closing plug, which lands in the top of the tool. The closing plug acts the same as a top plug on a conventional cement job, with the exception that the nose fits into a profile on the stage collar. When the plug lands, pressure is applied to again shift the sleeve, closing the ports on the tool. The system is now closed. Note to close the tool, the plug must bump. If this does not occur, the tool must be closed by running drill pipe down and pushing the plug and sleeve to the closed position.

March 2004

Company Use Only

Section 14 - 35

Cementing Equipment

14

To continue well operations, the plugs and internal workings of the stage tool are drilled out. The closing sleeve remains and provides the long-term seal to the casing.

Figure 14.12: Mechanical Stage Collar

Port Closed

Port Open

Port Closed

Courtesy Weatherford Gemoco

March 2004

Company Use Only

Section 14 - 36

Section

Primary Cementing Design Checklist

Scope This Section lists items for consideration in cement design. Not all items will be applicable to all jobs or all wells.

Company Use Only

Design Checklist

15

Table of Contents Tables................................................................................................................. 3 ExxonMobil Requirements ............................................................................... 4 15. 15.1.

Design Checklist ...................................................................................... 5 Required References ............................................................................ 5

15.1.1. API-American Petroleum Institute.................................................................. 5 15.1.2. ISO-International Standards Organization ..................................................... 5

15.2.

Planning ................................................................................................. 5

15.2.1. Regulatory Compliance ................................................................................. 5 15.2.2. Field History .................................................................................................. 6 15.2.3. Drilling History ............................................................................................... 6 15.2.4. Formation Properties..................................................................................... 7 15.2.5. Well Architecture ........................................................................................... 7 15.2.5.1. Well Location .......................................................................................... 7 15.2.5.2. Well Profile.............................................................................................. 8 15.2.5.3. Casing to be Cemented .......................................................................... 8 15.2.5.4. Previous Casings .................................................................................... 9 15.2.5.5. Other Considerations .............................................................................. 9 15.2.6. Future Operations ....................................................................................... 10

15.3.

Cementing Design............................................................................... 10

15.3.1. Purpose of the Job ...................................................................................... 10 15.3.2. Cement Excess ........................................................................................... 10

15.4.

Material Design.................................................................................... 10

15.4.1. Spacers....................................................................................................... 10 15.4.2. Cement Design ........................................................................................... 11

15.5.

Cement Evaluation .............................................................................. 11

15.6.

Recommended Cement Tests ............................................................ 12

March 2004

Company Use Only

Section 15 - 2

Design Checklist

15

Tables Table 15.1: Recommended Cement Tests .................................................................. 12

March 2004

Company Use Only

Section 15 - 3

Design Checklist

15

ExxonMobil Requirements Section #

ExxonMobil Requirement

There are no ExxonMobil requirements in this Section.

March 2004

Company Use Only

Section 15 - 4

Design Checklist

15.

15

DESIGN CHECKLIST

15.1. REQUIRED REFERENCES This Section lists Practices and Standards that are generically referenced and assumed part of this document. Unless otherwise specified herein, the latest edition and any addendum of the appropriate standard should be used.

15.1.1. API-American Petroleum Institute

15.1.2. ISO-International Standards Organization

15.2. PLANNING The document is broken into sections dedicated to various parts of the design. While not exhaustive, each section should have some application to most wells and cement jobs. As noted in Section 5, in a slurry design, there are a number of generalized areas, such as regulatory compliance, that apply to all wells.

15.2.1. Regulatory Compliance Virtually every location has some regulatory agency governing the drilling and abandonment of a well. Depending on the location, the regulations can vary considerably. For example, wells drilled on state-owned land in Colorado fall under the regulations of the State Oil and Gas Board. Those wells drilled on Bureau of Land Management land fall under federal jurisdiction, and follow a different set of rules. In this area, wells drilled within one mile of each other may have completely different regulations. Some key areas for regulatory compliance are: •

Top of cement must cover required zones

•

Cement strength development must meet requirements

•

Check for minimum required WOC times

•

Check placement of any cement plugs against regulations

March 2004

Company Use Only

Section 15 - 5

Design Checklist

15

15.2.2. Field History Identifying recurring problems from offset information can improve cementing results. Problem identification should not be limited to drilling issues, but include production and even abandonment problems. •

Gas Migration - Presence in offset wells or history of annular pressure indicates need for prevention. Also, need to evaluate cost of prevention against offset cost of managing the existing wells.

•

Lost Circulation - Cases of severe lost circulation will require additional work on design for density and possibly additional additives in the cement.

•

Reservoir Depletion - Risk of lost circulation is higher due to reservoir depletion, even if it was not in earlier wells. Fluid loss control across these zones will be important.

•

Flowing Zones - Water flows are especially difficult to address. problem offshore.

•

Poor Shoe Tests - Indicate a potential need to change operational procedures when cementing.

•

History of Squeeze Work - Indicates goals of cement jobs not being met.

•

Production Problems - Excess water production indicates isolation does not meet requirements.

•

Annular Pressure Problems at Wellhead - Indication of gas or fluid migration need to establish when in the life of the well this occurred.

•

Formation Collapse Issues - Not a cementing issue, but can effect top of cement designs.

Mainly a

15.2.3. Drilling History Drilling history identifies variables and problems that occurred prior to running casing. This is more real-time information. •

Mud Weight - Can effect spacer selection, and densities of spacers and cement

•

Mud Type - Effects spacer selection

•

Mud Rheology - Can effect displacement rates and ECD control

•

Hole condition - If the hole is not stable, it will be extremely difficult to get an effective cement job. Need to evaluate expected results of job in light of hole problems.

•

Lost Circulation - Cure if possible before cementing. May need to plan for additional mud on location for displacement.

•

Coal Seams - A source of lost circulation and potential gas.

•

Water Flow - Critical to design. Especially critical in deepwater applications.

March 2004

Company Use Only

Section 15 - 6

Design Checklist

15

•

Presence of Excessive Gas - May require gas migration prevention additives.

•

Wash Out Zones - Effects cement volumes and job time.

•

Problems with Ballooning - Hole stability issues.

•

Salt Zones - May require adding salt to system. Will effect efficiency of other additives.

•

Sensitive Shales - May need to reduce fluid loss or salinity of cement system. In some cases, adding 2% KCl to cement system will resolve the problem.

15.2.4. Formation Properties Identify the pertinent properties of the formation to be cemented: •

Bottomhole Pressure - Effects fluid densities in well.

•

Fracture Gradient - Important to fluid densities and rate calculations.

•

BHST - Important for strength development and determination of BHCT.

•

BHCT - Used for all testing - determine via API or simulators.

•

Permeability - Helps identify gas migration potential, need for fluid loss, etc.

•

Hydrocarbon Zone Locations - Effects TOC and can be a regulatory issue. Can effect cement volume and thus job time.

•

Formations Requiring Isolation - Either from each other or from surface.

15.2.5. Well Architecture Well architecture is defined broadly to include basic information about the structure of the well. Items such as number, size, and location of casing strings are included.

15.2.5.1. Well Location •

•

Land •

Water Source - Purity, volume available and temperature.

•

Location Size - Can effect type of equipment on location - may limit availability of batch equipment.

Offshore •

Water Depth - Effects mud line temperature. For deep water can identify need for cold temperature testing.

•

Water Source - Fresh or seawater - have sample sent to testing lab.

•

Drill Pipe Size - Effects hook up and displacement.

•

Rig Size - Can effect ability to spot additional equipment - bulk availability can effect volume of lead and tail cement.

March 2004

Company Use Only

Section 15 - 7

Design Checklist

15

15.2.5.2. Well Profile The well profile effects free water requirements, centralization, and ability to move pipe. For deviated wells, the well profile will also assist in determining if free water testing should be done at 45° or vertical. The profile will also effect the centralizer selection and placement calculations. •

Kick off point

•

Build rate

•

Dogleg severity

•

Final angle of casing

•

Average well angle

15.2.5.3. Casing to be Cemented Key in the design of the cement job is what type of pipe is being cemented in the well. This will effect cement volumes, displacement volumes, ability to move pipe, etc. •

Size

•

Weight

•

Grade

•

Thread - This can effect centralizer selection and placement. Some threads will not allow placement of the centralizer across the casing collar. Flush joint pipe requires use of stop collars.

•

Float collar or landing collar depth

•

Length of shoe track

•

Type of string •

Full string

•

Liner - Additional testing is required for liners - i.e., strength at TOL

March 2004

•

Temperature at top of liner

•

Drill pipe size

•

Use of liner top packer - This can effect the slurry design if gas zones are present in the area below the packer. See also the liner top packer report on GlobalShare and the Technical intranet website.

Company Use Only

Section 15 - 8

Design Checklist

15

15.2.5.4. Previous Casings The presence of additional casing strings in the well can effect annular volumes. In addition, consideration should be given to the chances of trapped pressure in the upper annulus. This can have an effect on the selected top of cement. •

Depth

•

Size

•

Weight

•

BHST

•

Leak off results - Should be used in job simulations to be sure lost circulation is not induced at this point. Particularly important in liner cementing because of restrictions around the liner hanger.

15.2.5.5. Other Considerations Cement design will also depend on future activities planned for the well. These may include later recompletions planned for the well to change zones, conversion from production to injection, etc. •

Trapped Annular Pressure - Will the design result in a trapped annulus that can cause problems during production?

•

Plans for Injection - May require that cement not be circulated above previous casing shoe.

•

Type of injection material •

Gas - Type, temperatures and pressures are important

•

Steam - Temperature and pressure

•

Water - Type and rate

•

Perforating - How long until the well will be perforated? Longer times may require use of special cement systems or lower density cements to be more perforation "friendly" slurry designs.

•

Distance to Nearest Recompletion Zone - How critical is isolation between adjacent zones and how far apart are they? The closer this separation, the more consideration should be given to mechanical properties of the cement. Will probably require use of lightweight, lower strength cements IF well conditions allow.

•

Fracturing - Down casing or work string and pressures involved. Can result in stress failure of the cement sheath if the pressures are high. The design will need to incorporate lower-strength cements or specialty cements like foam to withstand the stress environment.

March 2004

Company Use Only

Section 15 - 9

Design Checklist

15

15.2.6. Future Operations •

Drill Deeper - Temperature and pressure increases may effect the isolation in the well through additional stress on the upper casing.

•

Temporary Abandonment - Will effect time to perforate (see above).

•

Well Life - Can effect the need to evaluate subsidence, stress failure, etc. Usually, not a consideration for a single well, but may be considered for large projects in the same field. Note - well life calculations are only valid for a given set of well conditions and formations.

15.3. CEMENTING DESIGN The cementing requirements will depend on the previous information to aid in designing the required additives for the cement.

15.3.1. Purpose of the Job •

Isolation Requirements - Is there only a need for a shoe test or is there a need for extensive zonal isolation in the interval?

•

Support Requirements - Casing support for prevention of buckling may dictate top of cement and strength properties.

15.3.2. Cement Excess •

Primary Jobs - Evaluate risk of low top of cement against cost of additional cement.

•

Liner Jobs - Excess cement on top of liner must be either circulated out or drilled out later. Make sure the pump time is sufficient to be able to circulate out.

•

Stage Cementing - Risk of excess cement above stage collar versus the risk of TOC in the first stage being too low.

•

Subsea - Evaluate risk of cement in the wellhead and riser area.

15.4. MATERIAL DESIGN Material design is defined as the design of the spacers and cement system itself.

15.4.1. Spacers •

Density - If mud weight is above 11 lb/gal, use a weighted spacer. Otherwise, use water if well hydrostatics allow.

•

Volume - Sufficient for 500 annular feet.

March 2004

Company Use Only

Section 15 - 10

Design Checklist

15

•

Compatibility - Must be rheologically compatible with the mud and cement. Be sure to check if using an NAF mud.

•

Use of Pre-flush - For NAF fluids, use a base oil. In many situations, a combination of water and spacer can be used if hydrostatics allow.

15.4.2. Cement Design •

•

•

Lead Cement •

Density

•

Volume

•

Thickening time

•

Strength development

•

Other properties - Fluid loss, free water, settling, gas migration prevention, etc.

Tail Cement •

Density

•

Volume

•

Thickening time

•

Strength development

•

Other properties - Fluid loss, free water, settling, gas migration prevention, etc.

Cement Volumes - Will effect thickening time requirements - must figure in total volume to be pumped including excess. If hole size changes from original design, recheck thickening time requirements.

15.5. CEMENT EVALUATION How the cement job will be evaluated, should in part, depend on the expectation from the job. If all that is required of the cement is a shoe test, then a simple leak off test is required for the cement evaluation. If the requirements for the cement include isolation of very closely spaced zones, then the cement evaluation methods must be sufficiently sophisticated to demonstrate that isolation. Standard sonic cement evaluation logs are not appropriate in these situations, and the evaluation should include the use of ultrasonic logs. See Section 18, Cement Sheath Evaluation, for additional information on logs.

March 2004

Company Use Only

Section 15 - 11

Design Checklist

15

15.6. RECOMMENDED CEMENT TESTS Table 15.1 contains a summary of recommended cement tests that should be requested for various cement jobs. If the requirements for a particular job change, the testing requirements would reflect those changes. For example, if fluid loss is required for a particular job, then a fluid loss test should be requested. Alternately, if no fluid loss is needed in the design (as is the case with most conductor-casing strings), then no fluid loss test is required.

X

X

Intermediate

R

R

R

R

X

Long String

R

R

R

R

X

Liner

R

R

R

R

X

R

NAF Mud

X

R

X

R

X

X

R - Required Test

March 2004

X

R

Deepwater Deviated Well

R R

Mud > 10 ppg Gas Migration

TOL Strength

R

Cold Temperature

R

Compatibility

Surface

Wettability

X

Transition Time

X

Gas Migration

R

Settling

Free Water

R

Rheology

Strength

Conductor

Fluid Loss

Casing String or Job Parameter

Thickening Time

Table 15.1: Recommended Cement Tests

X - Recommended Test

Company Use Only

Section 15 - 12

Section

Primary Cementing On Location Guidelines

Scope This Section outlines the items that should be checked prior to performing a cement job. The assumption is that the design requirements for the cement system will meet the requirements of the job and no additional design work is required to develop a cement slurry or spacer system.

Company Use Only

On Location Guidelines

16

Table of Contents ExxonMobil Requirements ................................................................................ 2 16. 16.1.

On Location Guidelines ............................................................................ 3 Required References ............................................................................. 3

16.1.1. API-American Petroleum Institute................................................................... 3 16.1.2. ISO-International Standards Organization ...................................................... 3

16.2.

On Location Guidelines ......................................................................... 3

16.2.1. Cementing Materials....................................................................................... 3 16.2.1.1. Mix Water................................................................................................. 3 16.2.1.2. Cement .................................................................................................... 4 16.2.1.3. Additives .................................................................................................. 4 16.2.1.4. Spacers.................................................................................................... 5 16.2.2. Cement Accessories....................................................................................... 5 16.2.2.1. Float Equipment....................................................................................... 5 16.2.2.2. Centralizers.............................................................................................. 5 16.2.3. Cement Plugs and Heads............................................................................... 5 16.2.3.1. Liners ....................................................................................................... 5 16.2.4. Operations...................................................................................................... 5 16.2.4.1. Mechanics................................................................................................ 6 16.2.4.2. Job Parameters........................................................................................ 6 16.2.4.3. Job Plan................................................................................................... 6 16.2.4.4. Personnel................................................................................................. 6 16.2.4.5. Contingency Plans ................................................................................... 7 16.2.5. Calculations.................................................................................................... 7 16.2.6. Sampling ........................................................................................................ 7 16.2.7. Records.......................................................................................................... 8

March 2004

Company Use Only

Section 16 - 1

On Location Guidelines

16

ExxonMobil Requirements Section Number

ExxonMobil Requirement

There are no ExxonMobil requirements in this Section.

March 2004

Company Use Only

Section 16 - 2

On Location Guidelines

16.

16

ON LOCATION GUIDELINES

16.1. REQUIRED REFERENCES This Section lists Practices and Standards that are generically referenced and assumed part of this document. Unless otherwise specified herein, use the latest edition.

16.1.1. API-American Petroleum Institute

16.1.2. ISO-International Standards Organization

16.2. ON LOCATION GUIDELINES These guidelines outline the items that should be checked prior to starting cementing operations. Also included are items for sampling, and required paperwork to be collected on location.

16.2.1. Cementing Materials The goal is to be certain there are sufficient materials on location to perform the cement job, and those materials are "fit for purpose."

16.2.1.1. Mix Water •

Volume - There must be sufficient volume to mix the cement, pump any wash ahead or behind the cement, plus at least an additional 20 bbls for equipment clean up.

•

Source - Confirm the mix water is from the same source as the cement lab tests. Do not substitute seawater for fresh or drill water as this will accelerate the set of the cement.

•

Delivery Rate - Water feed rate to the cement unit must be sufficient to meet demand. If water is being fed into a tank while mixing cement, confirm the feedin rate is sufficient to meet the requirements of the job.

•

Temperature - Be cautious of mix water that has been sitting in a tank for several days, particularly in summer months. High water temperatures will accelerate the cement setting.

•

Salinity - The service company should confirm that no change has occurred from time of initial testing. Important for land locations that use trucked-in water.

March 2004

Company Use Only

Section 16 - 3

On Location Guidelines

16

16.2.1.2. Cement •

•

Lead •

Composition - Does the composition of the blend match what is on the lab test report?

•

Volume - Sufficient for job.

•

Location - Are the tanks containing the lead properly identified and the order for use known?

•

Mix Water Type - Confirm if needed - offshore operations often use seawater on the lead and drill water for the tail cement.

•

Mixing Density - Confirm with lab reports.

•

Mixing Rate - Determine anticipated rate - compare to job time calculations.

•

Thickening Time - Confirm there is sufficient pump time for the job.

Tail •

Composition - Does the composition of the blend match what is on the lab test report?

•

Volume - Sufficient for job.

•

Location - Are the tanks containing the tail properly identified and the order for use known?

•

Mix Water Type - Confirm if needed - offshore operations often use seawater on the lead and drill water for the tail cement.

•

Mixing Density - Confirm with lab reports.

•

Mixing Rate - Determine anticipated rate - compare to job time calculations.

•

Thickening Time - Confirm there is sufficient pump time for the job.

16.2.1.3. Additives •

•

Liquid •

Identified and proper lot numbers - Should match lab report.

•

Order of addition - May be important if water is batch mixed - otherwise liquid add goes directly into mix water and is not a concern.

•

Volume - Sufficient for job.

•

Confirm liquid additive pump can meet job requirements.

Solid - Normally, will be either spacer mix, bentonite or calcium chloride. •

Identified and lot number checked.

•

Volume sufficient for job

March 2004

Company Use Only

Section 16 - 4

On Location Guidelines •

16

Mixing procedure

16.2.1.4. Spacers •

Mixing procedure given to responsible person - Offshore, this will normally be the mud engineer.

•

Density

•

Volume sufficient for job including any required for loss in tanks

•

How pumped - By rig or service company

16.2.2. Cement Accessories These materials are run with the casing string.

16.2.2.1. Float Equipment •

Installed on proper joints

•

Correct shoe track distance

16.2.2.2. Centralizers •

Proper installation location

16.2.3. Cement Plugs and Heads •

Top and bottom plugs

•

Witness loading into head and confirm head is the proper size for the job

•

Confirm the size of the plug matches that of the head. The plugs should not require excessive force to be placed in the cement head.

•

Confirm compatibility with float equipment - some non-rotating plugs will not properly land out on competitor equipment. In addition, if non-rotating plugs are run on standard equipment, the advantage of non-rotation is lost.

16.2.3.1. Liners •

Darts and balls correct and in proper order

•

Witness loading head

16.2.4. Operations There are several operational checkpoints before and during the cement job. These can be included in the pre-job operational meeting to assure the job is properly executed.

March 2004

Company Use Only

Section 16 - 5

On Location Guidelines

16

16.2.4.1. Mechanics •

Pipe movement

•

Rotation - rpm and max torque, when to start and stop

•

Reciprocation - distance and rate, when to start and stop - note that hook load will increase when cement is in pipe.

•

Test pressures for lines to cement head

•

Pressure limit of cement head

16.2.4.2. Job Parameters •

Circulation prior to job - volume and rates

•

Job Sequence

•

When to drop plugs

•

Fluid sequence

•

Fluid volumes

•

Reconfirm displacement volumes and maximum displacement volume

•

Reconfirm maximum pressures - note maximum allowable pressure may be lowest when cement is in pipe and can increase as cement is displaced into annulus.

16.2.4.3. Job Plan •

Mixing rates for lead and tail

•

Displacement rates

•

Displacement volumes - calculated and maximum

•

Who will be performing displacement - rig or service company

•

Assure the pressure, rate and density can be recorded throughout the entire job. This is especially important if the rig is displacing the job as it may require an additional pressure sensor or leaving a line open to the cement unit.

16.2.4.4. Personnel •

Identify person dropping plug - Assure when plugs are dropped with a two-plug head that the top valve is opened, then the bottom valve closed to drop the plug. After the plug dropped, it is acceptable to open both valves, but not before the plug leaves the head.

•

Identify person monitoring returns

March 2004

Company Use Only

Section 16 - 6

On Location Guidelines

16

•

Identify person in charge of job - Who will make decisions if job problems occur?

•

Identify person responsible for switching cement tanks.

•

Identify persons responsible for weighing cement and taking samples during job.

16.2.4.5. Contingency Plans •

Minimum cement volume needed to be mixed - If less than the minimum amount of cement has been mixed, can it be circulated out of the well?

•

Pressure limits - As above, confirm pressures.

•

Lost circulation - Is there sufficient mud to displace if lost circulation occurs?

16.2.5. Calculations There are several calculations that should be confirmed. •

Double check the yield of the cement used for the volume calculations matches that on the lab reports and other documents.

•

Cement volumes - Compare to volume on location.

•

Water volume - Sufficient for cement mixing, spacers and clean up.

•

Displacement - Confirm with at least two other people.

•

Job time - Confirm and check that slurries have sufficient pump time.

•

Pressures •

Check differential pressure at the shoe at end of job.

•

Check that casing will not be pumped out of the hole - particularly important on large casing strings.

•

Differential pressure at top of liner at end of job - Will determine if well will Utube when stung out of liner top.

16.2.6. Sampling Samples should be taken in the event of a well problem. The samples can be discarded once it is determined the job was a success. •

Dry cement - Collect at least 1 gal or 20 lbs

•

Mix water with no additives - 1 gallon

•

Liquid additives - 1 quart

•

Mix water with all additives - 1 gallon (only if adds are put into the water)

Throughout the job, several samples of cement are normally taken from the mixing tub. These may be useful in estimating when the cement is set if the slurry was not retarded. Cement systems designed for high well temperatures will not normally set at surface

March 2004

Company Use Only

Section 16 - 7

On Location Guidelines

16

conditions in a reasonable time period. If surface-mixed cement samples are taken, they should be kept in a container with a lid and some water placed on top of the cement prior to storage. Dehydration of the cement can lead to incorrect assumptions that the cement has set.

16.2.7. Records Good records of the activities during the cement job are invaluable in the event of a cementing problem. Most of the pertinent records from the job should be available from the service company. The service company should record the density, rate and pressures throughout the job.

March 2004

Company Use Only

Section 16 - 8

Section

Primary Cementing Good Cementing Practices

Scope This Section covers operational practices that can enhance primary cementing results. Several practices outlined in this Section are covered in more detail in other portions of this manual.

Company Use Only

Good Cementing Practices

17

Table of Contents ExxonMobil Requirements ................................................................................ 2 17. 17.1.

Good Cementing Practices ...................................................................... 3 Required References ............................................................................. 3

17.1.1. API-American Petroleum Institute................................................................... 3 17.1.2. ISO-International Standards Organization ...................................................... 3

17.2.

Pipe Movement ....................................................................................... 3

17.3.

Centralize the Pipe ................................................................................. 3

17.4.

Condition the Mud.................................................................................. 4

17.5.

Use a Float Shoe and Float Collar ........................................................ 4

17.5.1. Use an Adequate Shoe Joint .......................................................................... 4

17.6.

Use a Bottom and Top Plug .................................................................. 4

17.7.

Use a Double-Plug Cement Head.......................................................... 5

17.8.

Check Equipment Dimensions.............................................................. 5

17.9.

Run a Spacer or Wash ........................................................................... 6

17.10. Mix the Cement to the Proper Weight................................................... 6 17.11. Use Enough Cement .............................................................................. 6 17.12. Select the Appropriate Displacement Technique ................................ 6 17.13. Record all Job Parameters for the Entire Job ..................................... 7

March 2004

Company Use Only

Section 17 - 1

Good Cementing Practices

17

ExxonMobil Requirements Section #

Topic

ExxonMobil Standard

17.12

Job Parameters

It is an ExxonMobil requirement the cement service company record the pressure during the entire cement job.

Note: Exceptions to this requirement may be made by the Field Drilling Manager or designee.

March 2004

Company Use Only

Section 17 - 2

17

Good Cementing Practices

17.

GOOD CEMENTING PRACTICES

17.1. REQUIRED REFERENCES This Section lists Practices and Standards that are generically referenced and assumed part of this document. Unless otherwise specified herein, use the latest edition.

17.1.1. API-American Petroleum Institute

17.1.2. ISO-International Standards Organization

17.2. PIPE MOVEMENT If possible, incorporate casing movement; particularly pipe rotation into the cement job design. Work by Garcia (see references on liners) demonstrated the improvements in mud removal when the design incorporated pipe rotation. Rotate the pipe at 10 - 20 rpm if torque allows. Always keep the torque when rotating pipe below the make-up torque of the connections (see Section 9.4.1). In this study, enhancement in cement placement using pipe rotation outweighed any other practice. The improvement was independent of fluid rheology, flow regime, or centralization. Incorporating pipe reciprocation with pipe rotation can improve results, but the incremental gain is small compared to rotation alone. If only pipe reciprocation is used, it must be coupled with proper centralizer selection to attempt to improve mud removal. Calculations should be made for pipe stretch while reciprocating with the pipe full of cement to avoid ramming the float shoe into the bottom of the hole potentially damaging or plugging the float. Pipe movement should be maintained while conditioning the mud and during cementing. Changes in hook load and torque due to cement should be taken into account in the calculations, and planned for in the operation.

17.3. CENTRALIZE THE PIPE Getting the casing off of the formation wall will allow cement to be placed between the pipe and formation. Proper centralization enhances the ability to get the pipe to bottom as well as cementing results.

March 2004

Company Use Only

Section 17 - 3

Good Cementing Practices

17

Proper centralization includes not only the placement of the centralizers, but also proper selection of the centralizer and stop collar. Many of the failures of quality centralizers are due to failure of the holding device or stop collar rather than the centralizer. Centralizer selection and standoff is covered in Section 14, Cementing Equipment.

17.4. CONDITION THE MUD Mud conditioning enhances fluid flow, cools the wellbore, and lowers the gels in the mud. The drilling mud should be conditioned at least one bottoms-up or one casing volume, whichever is greater. Thinning the mud while conditioning will aid in mud removal. Moving a thinner fluid is easier than a thick one. While conditioning the mud, maintain pipe movement. The mud should be conditioned at the maximum rate possible, which should be at least to the maximum U-tube rate determined from the displacement simulation of the well. The Utube rate may be much higher than the pump rate, depending on the density differences of the mud and cement.

17.5. USE A FLOAT SHOE AND FLOAT COLLAR Use of both a float shoe and float collar is highly recommended. If both floats fail, pressure must be held on the casing while the cement sets. This will cause a microannulus when the pressure is released. This can lead to gas migration and annular pressure that cannot be repaired.

17.5.1. Use an Adequate Shoe Joint Use at least one casing joint between the float shoe and the float collar. Placing the float collar directly on top of the float shoe risks swashing out the valve on the float shoe because of the high velocity fluid coming out the bottom of the float collar valve. Use of very long shoe tracks (four (4) or more joints) has been used in some operations that have experienced problems associated with wet shoes. When longer shoe tracks have been used, hard cement is drilled toward the bottom of the shoe track. While rare, longer shoe joints may be effective in certain operations.

17.6. USE A BOTTOM AND TOP PLUG Isolating the cement from the mud while in the casing will reduce contamination of the leading edge of the cement by the spacer. This will place quality cement at the shoe when the bottom plug lands. Concern of a thin mud film left inside the casing that could be wiped off if only a top plug is used, is often cited as a necessary reason for running two plugs. This could potentially leave mud-contaminated cement in the shoe, leading to a failure.

March 2004

Company Use Only

Section 17 - 4

Good Cementing Practices

17

Calculations of mud film typically assume either 1/32 or 1/64-inch film for the length of the casing. Using a top plug only could lead to a wet shoe if sufficient mud film is removed from the interior of the pipe. Field observations do not normally support a film on the inside of the pipe if sufficient cement has been pumped ahead of the top plug. There are also considerations of density differentials from the cement to the mud. For most applications, use of two plugs is recommended, but may not be required depending on casing size, cement volumes, etc. Beyond simple mud film is the displacement efficiency of cement inside casing, particularly large diameter casings of 13-3/8 inches and larger. Most cement slurries are higher density than the drilling mud, and will tend to rope or finger through the mud inside the casing. This is more likely a source of contamination at the shoe than a thin mud film left on the casing. Using a bottom plug can eliminate this problem in large casings.

17.7. USE A DOUBLE-PLUG CEMENT HEAD A double-plug cement head allows loading the bottom and top plugs and launching the plugs without the need to remove the cement head. This allows faster plug dropping, and prevents large amounts of air from being put into the well. A double-plug cement head allows for a safer, more efficient operation. When dropping the top plug from a double-plug cement head, the top valve should be opened and the bottom valve closed. This assures that mud is flowing only above the plug. If both valves are left open, the plug can be bypassed with mud. After the plug has left the head, both valves can be opened, but not before the plug launch. This applies to both cement jobs with conventional plugs and liner jobs that utilize similar double plug heads.

17.8. CHECK EQUIPMENT DIMENSIONS Confirm the size and dimensional compatibility of all wiper plugs, darts, balls and other equipment. Several failures have occurred by overlooking this and simply assuming the correct equipment has been ordered and arrived on location. Pay particular attention to sizes of cement plugs and cement heads or plug launching heads. While a cement plug should fit snugly into the head, and many come with a special tool to "tap" or hammer the plug into the head, excessive force should not be required to load a plug into the head. Beating the plug into the cement head will damage the fins, making the plug useless. Make sure the effected parties understand the order in which multiple plugs are to be dropped on multi-stage jobs. Check dimensions of all darts and balls used on liner jobs (see also 14.3.8.1).

March 2004

Company Use Only

Section 17 - 5

Good Cementing Practices

17

17.9. RUN A SPACER OR WASH Drilling muds and cements are generally not compatible. Running a compatible wash or spacer ahead of the cement will aid in pushing the mud out of the hole and replacing it with a quality cement slurry. At least 500 annular feet of spacer or wash should be run. Section 9 on mud removal further discusses spacer selection.

17.10. MIX THE CEMENT TO THE PROPER WEIGHT All of the design work and laboratory testing is of little value if the cement slurries are not mixed to the design density. Too low a weight will result in excessive free water, increased fluid loss, lower strength, potential solids settling, and poor cement quality. Too high a density can lead to lost circulation, reduced pump times, and difficulty in displacing the cement. The cement operator should not sacrifice density control for rate. While the newer computer-aided mixing systems may be able to control both density and rate, the cement-mixing rate should be secondary to density control. While seemingly obvious, mixing cement to the wrong density or with poor density control is one of the most common cementing problems on location. Proper density control is essential.

17.11. USE ENOUGH CEMENT Base the cement volume required on a caliper if possible. Offset information can also be useful in determining the minimum amounts of cement required for a particular job. The amount of excess cement to use should be risk-based. If the consequences of insufficient cement are dire, such as requiring perforating the casing and circulating additional cement, then running additional excess cement makes economic sense. If the top of the cement being too high would cause other well problems, limiting the amount of excess cement is prudent.

17.12. SELECT THE APPROPRIATE DISPLACEMENT TECHNIQUE

Putting energy into the wellbore by maximizing pumping and displacement rates will enhance mud removal. This appears to be independent of flow regime. Most wells benefit from maximizing the displacement rate. There are situations where fluid velocity is ineffective in displacing the mud. In some areas, displacing the cement at slower rates may enhance the results. In these areas, special consideration must be paid to the viscosity of the various fluids and the density

March 2004

Company Use Only

Section 17 - 6

Good Cementing Practices

17

differentials between the mud, spacer, and cement. These displacement techniques were first described in a paper by Parker, et al (SPE 1234); and more recently have been rediscovered by Schlumberger and incorporated into their displacement modeling.

17.13. RECORD ALL JOB PARAMETERS FOR THE ENTIRE JOB

Recording the density, rates and pressures during the entire job will enhance job evaluation and any problem resolution. The data can be essential in the event of a job problem. It is critical the pressure be recorded for the entire job, including the displacement, regardless of which pump system is displacing the cement job. On many jobs, the rig pumps are used to displace the cement. If the cement unit is isolated from the well, the pressures during displacement cannot be recorded. It is an ExxonMobil requirement the cement service company record the pressure during the entire cement job.

March 2004

Company Use Only

Section 17 - 7

Section

Primary Cementing Cement Sheath Evaluation

Scope This Section covers cement evaluation through use of sonic and ultrasonic logs.

Company Use Only

Cement Sheath Evaluation

18

Table of Contents Figures ................................................................................................................ 3 Tables.................................................................................................................. 4 Log Examples..................................................................................................... 5 ExxonMobil Requirements ................................................................................ 6 18.

Cement Sheath Evaluation ....................................................................... 7

18.1.

Required References ............................................................................. 7

18.1.1. API-American Petroleum Institute................................................................... 7 18.1.2. ISO-International Standards Organization ...................................................... 7

18.2.

Introduction ............................................................................................ 7

18.3.

Cement Bond Logging Principles......................................................... 8

18.4.

Waveforms ............................................................................................ 10

18.4.1. Common Log Signal Examples..................................................................... 11 18.4.2. Interpretation - Track 3 (Microseismogram) .................................................. 13 18.4.3. Interpretation - Track 2 ................................................................................. 15 18.4.3.1. Transit Time ........................................................................................... 17

18.5.

Log Examples ....................................................................................... 19

18.6.

Types of Evaluation Tools ................................................................... 24

18.6.1. Fluid-Compensated Bond Tools ................................................................... 24 18.6.2. Ultrasonic Evaluation Tools .......................................................................... 26 18.6.3. Schlumberger's USIT* Tool .......................................................................... 30 18.6.4. Halliburton's Cement Evaluation and Casing Inspection (CAST-V) Tool ....... 32

18.7.

Interpretation of Ultrasonic Logs........................................................ 34

18.8.

Quality Control - Sonic Logs ............................................................... 41

18.9.

Extenuating Circumstances in Cement Evaluations......................... 41

18.9.1. Microannulus ................................................................................................ 42 18.9.2. Tool Eccentering .......................................................................................... 43 18.9.2.1. Conventional and Compensated Bond Logs .......................................... 43 18.9.3. Eccentering of Ultrasonic Tools .................................................................... 44

18.10. Testing Recommendations ................................................................. 46

March 2004

Company Use Only

Section 18 - 1

Cement Sheath Evaluation

18

18.10.1. Cement Testing......................................................................................... 46 18.10.1.1. Operational Thickening Time .............................................................. 46 18.10.1.2. Static Time.......................................................................................... 46 18.10.2. Log Scaling and Parameters ..................................................................... 47 18.10.2.1. Bond Logs .......................................................................................... 47 18.10.2.2. Segmented Bond Tool ........................................................................ 47

18.11. Tool Selection....................................................................................... 47 References........................................................................................................ 49

March 2004

Company Use Only

Section 18 - 2

Cement Sheath Evaluation

18

Figures Figure 18.1: Tool Configuration ...................................................................................... 9 Figure 18.2: Waveform Nomenclature ............................................................................ 9 Figure 18.3: Waveforms ............................................................................................... 11 Figure 18.4: Free and Fully Cemented Pipe ................................................................. 12 Figure 18.5: Intermittent Cement Coupling to Casing and Formation............................ 12 Figure 18.6: Microseismogram ..................................................................................... 14 Figure 18.7: Amplitude vs. Cement Thickness.............................................................. 16 Figure 18.8: Eccentering Effects................................................................................... 17 Figure 18.9: Transit Time.............................................................................................. 18 Figure 18.10: Critical Transit Time................................................................................ 19 Figure 18.11: Basic Configuration of Tool..................................................................... 24 Figure 18.12: SBT Configuration .................................................................................. 25 Figure 18.13: SBT Presentation.................................................................................... 26 Figure 18.14: Signal Path (Part 1) ................................................................................ 28 Figure 18.15: Signal Path (Part 2) ................................................................................ 28 Figure 18.16: Acoustic Impedance of Mud.................................................................... 29 Figure 18.17: Acoustic Impedance of Cement .............................................................. 30 Figure 18.18: CAST-V Segmentation............................................................................ 33 Figure 18.19: Liquid in the Annulus .............................................................................. 36 Figure 18.20: Cement in the Annulus............................................................................ 37 Figure 18.21: Cement in the Annulus #2....................................................................... 38 Figure 18.22: Lightweight Cement ................................................................................ 39 Figure 18.23: Gas Cut Cement in the Annulus.............................................................. 40 Figure 18.24: Eccentering............................................................................................. 43

March 2004

Company Use Only

Section 18 - 3

Cement Sheath Evaluation

18

Tables Table 18.1: Typical Sonic Velocity Values .................................................................... 10 Table 18.2: Acoustic Impedance................................................................................... 29

March 2004

Company Use Only

Section 18 - 4

Cement Sheath Evaluation

18

Log Examples Log Example 18.1: Free Pipe ....................................................................................... 20 Log Example 18.2: Log Run with Zero Pressure........................................................... 21 Log Example 18.3: Run with Pressure.......................................................................... 22 Log Example 18.4: Free Pipe ....................................................................................... 23

March 2004

Company Use Only

Section 18 - 5

Cement Sheath Evaluation

18

ExxonMobil Requirements Section #

Topic

ExxonMobil Requirement

This Section does not contain any ExxonMobil requirements.

March 2004

Company Use Only

Section 18 - 6

Cement Sheath Evaluation

18.

18

CEMENT SHEATH EVALUATION

18.1. REQUIRED REFERENCES This Section lists Practices and Standards that are generically referenced and assumed part of this document. Unless otherwise specified herein, use the latest edition.

18.1.1. API-American Petroleum Institute

18.1.2. ISO-International Standards Organization

18.2. INTRODUCTION The objective of a cement sheath analysis is simply to confirm the cement has been successfully placed around the casing so it will provide support for the casing and assure all zones of interest are hydraulically isolated. Casing support requires the presence of any solid material in the annulus, but not necessarily 100% circumferential coverage of the casing. Sand, borehole collapse, barite, hematite, or any similar solid material will provide casing support providing it fully occupies the annulus. Hydraulic isolation, however, requires 100% annular fill of an ultra-low to non-permeable material. Some of the factors that create a good cement job include: •

Adequate circulation and cleaning of the hole prior to cementing

•

Centralization of the casing

•

Casing movement during circulation and cementing

•

Use of a cement slurry that exhibits no free water separation or solids segregation

•

Placement of the cement in the entire annulus without losing circulation

The high-quality cement mixed at the surface does not always yield what is perceived as correspondingly high-quality cement in the annulus. This apparent loss of cement quality can be a result several factors: 1. Contamination of the cement with mud and/or gas decreases density and strength, which creates a corresponding decrease in the acoustic properties of the cement. These events decrease the ability of the cement sheath (by decreasing the shear strength) to control the "ringing" of the casing during cement evaluation logging which relates to increases in bond log amplitude (or decreases in bond log attenuation rates).

March 2004

Company Use Only

Section 18 - 7

Cement Sheath Evaluation

18

2. The perception of "no cement" or poor cement in the annulus can be caused by: •

Over-estimation of a well's bottomhole temperature

•

Over retardation of the cement slurries

•

Under-estimation of the length of time required for the wellbore to heat up to bottomhole temperature after cement placement

•

Neglect of the cooler temperatures and weaker cements (filler cements) up hole with paralleling slowness to set and develop strength

It is important to understand once cement is placed in the annulus and set, it cannot be removed and replaced with a more desirable cement regardless of its "compressive strength." If the annulus were filled with sand, barite, formation solids, etc., it would not be possible to remove any of these materials or replace them with cement. What remains is to recognize the cement sheath for what it is, and be able to differentiate between a solid and a liquid using a cement evaluation device. Throughout the industry, as well as this Section, the term bond is used to indicate some sort of coupling between the cement and the formation or pipe. Bond is not strictly the correct term as tools can indicate a "bond" when in fact no chemical bond between the materials exists. The logs are identifying sonic coupling, or the ability of sound waves to traverse the interface between the two materials. A sonic log can show "bonding" to a formation when in fact the casing is simply laying against the formation, thus making a path for the sound. It is cement sheath evaluation and identification of formation isolation that should be the ultimate goal. Progress continues in the development of more effective cement sheath evaluation techniques. Correct application of these newer techniques, incorporated with a clear concept of cement strength development mechanisms, can lead to fully recognizable cement sheath quality and quantity. Correct application of the available cement evaluation tools and techniques requires a clear understanding of the measurement principles involved and the developmental stages of the cement sheath's crystalline structure.

18.3. CEMENT BOND LOGGING PRINCIPLES The sonic cement bond logging tool emits an omni-directional acoustic energy pulse. The sonic pulse travels through the borehole fluid as an expanding circular wave. When the wave strikes the casing ID, it is refracted according to Snell's law:

V1 V2 = sin ξ 1 sin ξ 2 where Zeta (ξ) is the angle of incidence and refraction and V is the velocity of sound in the respective materials. Calculations show the wave front striking the casing at a given angle will refract directly downward, parallel with the casing ID. This angle is typically referred to as the "critical angle" and is approximately 17°. Passage of the wave pulse down the inside (and outside) of the casing acts as a pressure pulse, causing the steel in

March 2004

Company Use Only

Section 18 - 8

Cement Sheath Evaluation

18

the thickness of the wall to cycle through compression and tension. The pulse loses strength as it travels down the casing because the pressure pulses in the casing wall create sonic waves in the casing fluid. The acoustic energy pulse travels down the casing fluid, down the casing wall, as well as down the tool. The signal is refracted through the casing and cement, then is refracted back through the casing and fluid to a signal receiver mounted in the tool a fixed distance away from the transmitter (Figure 18.1). The strength (amplitude) of the received signal is proportional to the percentage of the casing circumference touched by the cement, the wall thickness of the casing, as well as the density, thickness, and shear strength of the cement. The paths that the signal travels from the transmitter to the receiver, depending on the quality of the acoustic coupling of the cement to the casing and the formation, are also illustrated in Figure 18.1. Since the casing wave generally arrives at the receiver first, we can measure its energy level (amplitude) and the transit time of the signal. Figure 18.2 illustrates the common waveform nomenclature. The first positive peak (E1) is the wave measured for the casing signal. The amplitude and the transit time of the signal are generally recorded on the 3 ft receiver.

Figure 18.1: Tool Configuration

Figure 18.2: Waveform Nomenclature mV

Travel Time

E1

E3

E5

Amplitude

E2

March 2004

E4

Company Use Only

Section 18 - 9

Cement Sheath Evaluation

18

Table 18.1 illustrates the velocity of sound in the casing is generally higher than in any other borehole material. Therefore, the first part of the composite wave (Figure 18.2) is composed only of the sonic wave that passed downward through the casing. In certain carbonates, the velocity of sound can be greater than the velocity in steel. This situation constitutes a "fast formation" to be discussed later.

Table 18.1: Typical Sonic Velocity Values ∆T (µ µ sec/ft)

Vel. (ft/sec)

Miles/Hour

50

20,000

13,636

43 to 70

23,256 to 14,286

15,856 to 9,740

Quartz

52.9

18,900

12,886

Water

208

4,800

3,273

Air (1 atm)

919

1,088

742

Casing

57

17,544

11,962

Material Anhydrite Dolomite/Calcite

18.4. WAVEFORMS The composite waveform detected at the receiver is illustrated in Figure 18.2. In this composite waveform, the first positive peak is referred to as E1, with subsequent positive peaks denoted as E3, E5, E7, etc. The first negative peak is referred to as E2, with subsequent negative peaks denoted as E4, E6, E8, etc. The receivers detect the sum of all the waveforms generated by reflection of the sonic signal from the casing, the formation, the cement sheath, and the casing fluid. Generally, the signals reflected from the cement and the formation are indistinguishable. The signal detected at the receiver is transported to the surface to an oscilloscope for generation of a waveform. Figure 18.3 illustrates the typical waveforms that can be generated from each of the travel paths, i.e., from the mud, the casing, the cement, and the formation. Assuming set cement is acoustically coupled to the casing and the formation, the signal received and the waveform generated is a composite of all travel paths. The magnitude (amplitude) of the waveform is greatest in free casing. If the casing is not acoustically coupled to the cement, the only signal detected by the receiver will be the ringing of the casing caused by the pressure surge of the sonic signal travelling down the wall thickness of the casing. This can be caused by: 1. Mud in the annulus 2. Unset cement in the annulus 3. A microannulus between the set cement and the casing 4. Weak cement fully coupled to thick wall casing Cement with at least 250 psi compressive strength and complete acoustic coupling is required for transmittal of the signal through all of the conductors. The transit time of the signal from the transmitter to the receiver is relevant to the casing size, the casing fluid

March 2004

Company Use Only

Section 18 - 10

Cement Sheath Evaluation

18

density, and the distance to the receiver. Generally, the casing signal is taken from the 3-ft receiver and the formation reflection is taken from the 5-ft receiver, dependent on the type of tool used.

Figure 18.3: Waveforms Mud

Casing

Cement

Formation

Composite

18.4.1. Common Log Signal Examples Four situations can exist in the relationship between cement, casing, and the formation. These situations can be represented by separate and identifiable waveforms as illustrated in Figures 18.4-A and 18.4-B. Figure 18.4-A illustrates the easiest condition to identify downhole, uncemented casing. With this situation downhole, the only waveform that can normally exist on the log is the casing waveform. The E1 curve of the free casing waveform should arrive on the microseismogram display of the log between 300 - 400 microseconds (ms) when the signal is taken off the 5-ft receiver. Figure 18.4-B illustrates fully cemented casing. This condition is characterized by the complete dampening of the casing signal seen in Figure 18.4-B. Figure 18.3 illustrates a typical waveform expected when the cement is completely coupled with the casing but not with the formation. In this case, neither the casing signal nor the formation signal will be in evidence. The factors that create this situation downhole include: (1) thick wall cake, (2) mud-filled hole enlargements, (3) soft rock (marine shales to unconsolidated sands), or (4) gas cut or foamed cement. This type of response is also typical in cases involving casing-in-casing (e.g., liner overlaps). Generally, if mud fluid loss data, an open hole caliper log, and a lithology log are available, the cause of the loss of the formation signal can be determined.

March 2004

Company Use Only

Section 18 - 11

Cement Sheath Evaluation

18

Figure 18.4: Free and Fully Cemented Pipe 4-A

4-B

Fully Cemented Pipe

Free Pipe 0

500

1000

500

0

1000

Figure 18.5-A illustrates intermittent cement coupling to the casing and to the formation. In this situation, the composite waveform will indicate both formation and casing responses. This configuration may be attributable to one of two causes, i.e., cement channeling or a microannulus at the cement-casing interface. The only method for differentiating between the two is to run a pressured and a non-pressured pass with the logging tool. With the casing under pressure, the casing signal will disappear in the case of a microannulus. The casing signal will remain if a channel exists and is in contact with the casing. To date, no logging tool will provide identification of an outside channel, i.e., a channel between the formation and the cement sheath.

Figure 18.5: Intermittent Cement Coupling to Casing and Formation 5-A

5-B

Fully Cemented Pipe - No Bond to Formation 0

March 2004

500

1000

Channel / Microannulus 0

Company Use Only

500

1000

Section 18 - 12

Cement Sheath Evaluation

18

The size of the cement-casing microannulus may be calculated using:

∆r = (

∆P * r 2 t w* E

)

where r = Casing Radius, in P

= Pressure, psi

tw = Casing Wall Thickness, in E

= Young's Modulus of Elasticity of Steel

Channeling during cementing can be the result of: •

Poor casing centralization

•

Failure to move the casing while circulating and cementing

•

Dynamic solids settling from the mud or cement to the low side of the annulus (low side of the casing)

•

Free water separation from the cement slurry after placement (high side of the casing)

The amount of pressure required to expand the casing to the cement sheath varies with the cause of the microannulus. Whatever internal pressure existed in the casing at the time the cement hydrated, must be duplicated, plus approximately 500 psi to compensate for casing expansion caused by the heat of hydration during cement set. Another activity that contributes to the formation of a microannulus, or the creation of stress cracks in the cement sheath, is pressure testing the casing after the cement has set. If possible, pressure testing the casing immediately after bumping the top wiper plug, while the cement is still liquid, can eliminate many stress failure problems of the cement sheath. This requires the plug land and the landing collar or float collar and cement head and related equipment must withstand the required test pressure.

18.4.2. Interpretation - Track 3 (Microseismogram) Presentation of the composite waveform on the log may be in the form of the "total energy wave" (Signature plot, x-y plot, etc.). Generally, on a scale of 200 to 1,200 microseconds (µs), or in a linear representation of the positive peaks (E1, E3, E4, etc.) commonly referred to as a variable density presentation. The method of converting from the waveform to the linear presentation is illustrated in Figure 18.6. The major advantage of the linear presentation over the waveform presentation is the number of data points per linear foot.

March 2004

Company Use Only

Section 18 - 13

Cement Sheath Evaluation

18

Figure 18.6: Microseismogram Raw Waveform

Half Wave Rectified and Shaded

Stacked Shading

The size of the waveform precludes the use of more than one data point per foot. Whereas, the linear presentation permits printing of hundreds of data points per linear foot, thus yielding a more solid definition of the casing cement coupling. Methodology for creation of the linear presentation involves deleting the negative peaks and recording the width of the positive peaks from the top rather than the height of the peaks. This creates a two-dimensional log in which variations of shading indicate peak height (highest peaks are dark and wider, with decreasing intensity shading to lighter and narrower bands at low-peak heights, to white at the negative or zero peak height). Thus, dark bands on the linear presentation represent the positive peaks and the white bands occupy the position of the negative peaks. Once a basic understanding of the linear or waveform presentation is achieved, one should be readily equipped to delineate cement or non-cemented sections of the annulus, assuming the cement sheath is non-contaminated and has reached a sufficient strength to provide dampening of the casing vibration as well as carry the refracted sonic signal to the formation. For interpretive purposes, the basic responses of the waveform to the diverse downhole cement sheath conditions have been illustrated in Figures 18.4 and 18.5. When analyzed in conjunction with knowledge of borehole enlargements and borehole lithology, a fair judgement of cement sheath quality can be made, as long as the cement is not contaminated with gas. The infusion of gas from any source into the cement column, whether designed into the cement system or as a result of influxes from

March 2004

Company Use Only

Section 18 - 14

Cement Sheath Evaluation

18

a formation, negates the effectiveness of the linear or waveform presentation in Track 3 for cement sheath evaluation.

18.4.3. Interpretation - Track 2 Following processing of the signal through the oscilloscope for the waveform display, the amplitude of the signal is measured. The results of this measurement are recorded on Track 2 of the log presentation in the forms of an Amplitude curve scaled 0 - 100 millivolts (mv) and an Amplified Amplitude curve scaled 0 - 20 mv. The amplified amplitude is exactly what is inferred, i.e., the noise level is amplified by a factor of five (5) so the low amplitude values can be more accurately read. The amplitude measurement is generally made from the E1 peak magnitude via a "gating system." Measurements are made during the time the gate is open (gate width) and used to construct the amplitude curves. Two types of gates may be in use: 1. "Fixed Gate": Gate width and opening time are fixed. It is generally set to open at the expected casing signal arrival time. The bias setting determines the maximum amplitude that will be recorded as free pipe. 2. "Floating Gate”: Remains open and scans across the waveform for the E1 arrival time. Signal amplitude at the receiver is a function of the transmitted amplitude, casing wall thickness, cement strength and density, and lithology. Generally, the values of amplitude will range from approximately 55 - 80 mv (depending on the casing size) in uncemented casing to approximately 0.2 mv in thin wall, small casing (4.5 inch, 11.6 lb/ft) acoustically coupled to high-strength cement. The amplitude should never read "0." If it does, the tool is not working. Each service company publishes a "tool specific" interpretation chart. Do not use this chart for interpreting other service company logs. Assuming a constant cement strength and density, the effects of varying casing sizes and wall thickness can be determined from these charts. Likewise, assuming a constant casing size and wall thickness yields information on the varying cement compressive strengths on amplitude. All of these values are based on a minimum cement sheath thickness of 0.75 inches and assumes the cement compressive strength and density is constant around the circumference of the casing and throughout the height of the cement column. A thin, cement sheath (Figure 18.7), low cement compressive strength, and/or low cement density with thick wall casing will yield considerably greater amplitude (lower attenuation rate). Typically, percent (bonding index) is a ratio of the amplitude reading in a given section of the hole to the lowest amplitude reading in the hole. For example:

BI =

(Afp - ALS) ( Afp - A100% )

where Bonding Index (BI) is the ratio of the difference between free pipe amplitude (Afp) and the received amplitude in any logged section of hole (ALS) to the difference between the free pipe amplitude and the lowest received amplitude (A100%), or what is considered to be 100% bonding.

March 2004

Company Use Only

Section 18 - 15

Cement Sheath Evaluation

18

Figure 18.7: Amplitude vs. Cement Thickness

The major problem with this concept is changes in cement density and strength from a tail slurry to a lead (filler slurry), change in the cement strength due to decreasing static temperature up the hole, and/or decreases in cement strength and density created by gas influx into the cement column will effect ALS and A100%. Another factor that will affect the bonding index is borehole lithology. Softer, less dense rock will yield lower amplitude, which may be interpreted as better bonding. Hard limestone and dolomites will yield higher amplitudes, which may be interpreted as poor bonding. Eccentering of the tool within the casing will also create lower amplitude readings (better bonding); therefore, one must be certain the tool is centered during the run (Figure 18.8). It is important to realize the expected value for 100%-bonded pipe is part of the bond index calculation. If the well has been cemented with lightweight slurry, and the tool has not been reset to represent the lower expected value, the bond index calculation will be wrong. Changes in casing size and weight will effect the free pipe calculation, and must also be adjusted, particularly in wells with mixed casing strings. Often changes in bond index can simply be a result of a change in casing.

March 2004

Company Use Only

Section 18 - 16

Cement Sheath Evaluation

18

Figure 18.8: Eccentering Effects

1.0 0.8 0.6 0.4 0.2

1

3/4

1/2 1/4 0 -1/4 -1/2 -3/4 Inches Off Center

-1

18.4.3.1. Transit Time The transit time curve may be used as a means of quality control for centering the logging tool (Figure 18.9). The transit time curve is normally printed in track one. The recommended scale range for the transit time curve is 100 microseconds to increase the readability of changes in transit time. One must be able to determine the lithology of the section in question since a hard limestone or dolomite (hard formation) will also cause the signal to exhibit a shorter transit time. For quality control purposes, it is normally recommended the decrease in transit time caused by tool eccentering not exceed four (4) microseconds. If tool eccentering is a consistent problem during a particular logging run, it is recommended the tool be pulled out of the hole so the centralizers can be replaced, or additional centralizers added to the tool.

March 2004

Company Use Only

Section 18 - 17

Cement Sheath Evaluation

18

Figure 18.9: Transit Time 9-A

9-B Transit Time with Cycle Skip

Transit Time Curve

11900

4300 11950

4350

When the transit time suddenly increases as illustrated in Figure 18.9-B, it is due to "cycle skipping." This phenomenon occurs when E1 has become too small to detect in the "gate" and a subsequent peak such as E3 or E5 (or sometimes even later arrivals) is detected for amplitude and transit time purposes. When the transit time cycle skips, the curve is no longer valid for indicating tool eccentering. In cases of liner laps, or other situations involving casing/casing cement filled annuli, if uncontaminated cement occupies the space, it is not uncommon to experience a "cycle skip" as the transit time increases from the inner casing to the outer casing travel time. As the amplitude of the E1 decreases in well-bonded casing, the transit time begins to increase due to signal stretch. This appears as a somewhat erratic value of transit time over the critical transit time just prior to cycle skipping. The "Critical Transit" time, Figure 18.10, is the transit time measured at the 3-ft receiver in uncemented casing. Figure 18.10 illustrates the cause of stretching of the transit time curve. This type of erratic behavior should not be mistaken for tool eccentering. Both cycle skipping and signal stretch can be an indication of excellent cement well bonded to the casing. Due to the value of the transit time curve, it is recommended it be displayed on all bond logs on a magnified scale.

March 2004

Company Use Only

Section 18 - 18

Cement Sheath Evaluation

18

Figure 18.10: Critical Transit Time

E1

Poor Bond

Good Bond

Detection Level

Time

Transit Time Stretch

Additional quality control parameters (beyond the transit time curve) for cement evaluation include the repeatability of the tool and the presentation of the log. Make certain the tool repeats itself by checking the repeat section of the log. Make certain the log is printed "on depth" by comparing the lithology represented by the gamma ray to the lithology represented by the sonic formation signal on the rnicroseismogram.

18.5. LOG EXAMPLES Log Example 18.1 represents a section of log run in free pipe, i.e., casing with a liquidfilled annulus. The variable density display consists solely of straight, parallel bands that are "casing signals." These casing signals correlate to the waveform illustrated in Figure 18.3. The casing collars exhibit a chevron diffraction pattern. With fluid in the annulus and the tool fully centered, the casing signal bands are "ruler" straight. As long as the tool is centered in the casing and casing signals are in evidence, the casing signal bands will always be straight. Their straightness is one means of differentiating between casing signals and formation signals. Rarely is a formation sufficiently consistent to exhibit "ruler" straight lines on the variable density display.

March 2004

Company Use Only

Section 18 - 19

Cement Sheath Evaluation

18

Log Example 18.1: Free Pipe

Log Examples 18.2 and 18.3 illustrate the response to a microannulus when the log is run with and without pressure. In this case, 2,000 psi casing pressure was used to expand the casing into contact with the cement sheath. Compare the two logs for the disappearance of the casing signal and the significant change in the amplitude curves. This is typical of a microannulus, i.e., the casing signals will disappear with sufficient casing pressure. In the case of a channel, the casing signals will not disappear with pressure.

March 2004

Company Use Only

Section 18 - 20

Cement Sheath Evaluation

18

Log Example 18.2: Log Run with Zero Pressure

In this example, there are formation arrivals, but the casing signal is a straight line and there are chevron patterns in the microseismogram. This can indicate either a channel or microannulus depending on a second pass under pressure. After pressurizing up to 2,000 psi, Log Example 18.3 shows excellent coupling over the same interval. Note the transit time curve exhibits cycle skip, again indicating excellent coupling.

March 2004

Company Use Only

Section 18 - 21

Cement Sheath Evaluation

18

Log Example 18.3: Run with Pressure

Log Example 18.2 can also illustrate an annular channel between the casing and the cement sheath. Strong casing signals (with collar chevrons) and strong formation signals are typical on the log. The appearance of the microseismogram will not normally change whether casing pressure is applied or not when a channel is present. It is emphasized an annular channel must be in contact with the casing for detection by any cement sheath logging device. Channels existing between the cement sheath and the borehole wall are not detectable with current bond logging tools. "Noise" logs and/or temperature logs are generally required for identification of exterior channels (channels between the cement sheath and the borehole wall), which assumes that inter-zonal fluid or gas flow is occurring during the measurement. If no flow is occurring, these measuring devices are not effective.

March 2004

Company Use Only

Section 18 - 22

Cement Sheath Evaluation

18

Log Example 18.4: Free Pipe

Log Example 18.4 is from a horizontal well that was not centralized. The log is showing essentially free pipe, yet there are some formation arrivals on the microseismogram. This is an indication of either, a microannulus or, the pipe lying on the low side of the hole and no cement around the pipe. This log was run with no pressure, and there was no subsequent pressure pass to confirm whether there was a microannulus or a severe cement channel.

March 2004

Company Use Only

Section 18 - 23

Cement Sheath Evaluation

18

18.6. TYPES OF EVALUATION TOOLS 18.6.1. Fluid-Compensated Bond Tools New developments in bond log technology have led to the bore fluid-compensated logging devices for cement sheath evaluation. Figure 18.11 illustrates the basic configuration of tool. The primary advantages of the tool include: 1. Direct measurement of the signal attenuation rate (decay rate), db/ft, that is independent of the effects of changing borehole fluid densities and transmitted signal strength. 2. Measurement of attenuation rate over a 1-ft interval versus averaging of attenuation rate over a 3-ft interval. 3. Elimination of calibration problems. The major difference in interpretation of the compensated log presentation lies only in Track 2, i.e., the substitution of an attenuation curve for an amplitude curve. Analysis of the VDL or microseismogram remains the same. The bond log interpretation chart may be used alternately for amplitude or attenuation rate, assuming the casing thickness and the cement strength are known.

Figure 18.11: Basic Configuration of Tool

Upper Transmitter

T 5’ R

0.8’

First receiver for upper transmitter, rd 3 receiver for lower transmitter

3.4’ R 2.4’

Middle receiver for both transmitters

2.4’ R 3.4’

Third receiver for upper transmitter, st 1 receiver for lower transmitter

T

Lower Transmitter

One of the later innovations using the fluid-compensated logging technology is the Segmented Bond Tool (SBT). Basically, the tool (Figure 18.12) consists of six pads placed in direct contact with the casing wall that measure the 1-ft average signal

March 2004

Company Use Only

Section 18 - 24

Cement Sheath Evaluation

18

attenuation rate (db/ft) at each 60° arc of the casing-cement interface rather than the 360° averaging that is common practice with normal bond log technology. The log presentation of the segmented tool incorporates six tracks that illustrate the attenuation rate, db/ft, measured as the signal travels past the upper to the lower receivers in the pattern denoted in Figure 18.12. It also includes a variable attenuation "Quick Look" map and tool orientation for identifying the low side of the borehole. The "Quick Look" map is recorded as "Variable Attenuation" in Track 1 of the log. On the Quick Look cement map, five levels of shading are used to portray the degree of cement bonding with white indicating no bonding. The lightest shade represents an attenuation of 2 db/ft. Black areas indicate an attenuation of 80% of the value expected for the highest compressive strength cement for specific casing diameter and weight.

Figure 18.12: SBT Configuration

1

5

3

Signal Path

1

Upper Transmitters

Upper Receivers 1

2

3

4

6

5

Signal Attentuation Rate Measurements Lower Receivers

2

4

6

Lower Transmitters

Figure 18.13 illustrates the attenuation measurements (db/ft) recorded by each of the six pads. The recommended scale range for these tracks is 0 - 10 db/ft so more accurate values can be obtained for the lower strength cements and for better delineation between liquids and crystalline cement in the annulus. Attenuation rates greater than 10 db/ft indicate excellent cement and it is felt that it is not necessary to obtain an accurate value of attenuation rate over 10 db/ft. For delineation between a liquid and a crystalline material like cement, regardless of its compressive strength, the "line character" will define the material. If a liquid exists against the casing at one or all of the pads, the attenuation rate will not change. Consequently, a liquid-filled channel at any of the pads will describe a straight line for attenuation rate except at the collars. If cement is bonded to the casing, the density and strength of the cement changes sufficiently that the line will not be straight. In fact, it can radically deviate from minimum to maximum values of attenuation depending on the amount of gas contamination in the cement sheath. Determination of the "line character" is the primary reason for the expanded scale for the six-segmented measurements. The log also contains a cement map that sets the color of the map based on the amplitude from the pads. As with any cement map, the coloring is highly dependent on how the operator has set up the computer and not the data itself.

March 2004

Company Use Only

Section 18 - 25

Cement Sheath Evaluation

18

The SBT has been successfully run in 17.3-lb/gal brine. The maximum temperature recommended for the log is 350°F (177°C). The segmented array portion of the log presentation also delineates the low side of the hole via an orientation curve.

18.6.2. Ultrasonic Evaluation Tools The newer evolution of logging tools generally provides much better definition of the cement sheath quality and quantity than do the conventional bond logs. These tools are referred to as ultrasonic cement evaluation tools. Ultrasonic tools are currently available from Schlumberger and Halliburton. Typically, conventional bond logging devices operate at 15 - 25 kilohertz frequency, whereas the ultrasonic tools operate in the range of 550 - 650 kilohertz.

Figure 18.13: SBT Presentation

The high frequency transmitted pulse minimizes the dissipation of the sound wave in the borehole fluid, thus assuring direct reflection of the pulse to its source, at the same time limiting the distance of penetration. The ultrasonic tools are heavily centralized. The transducer used on these tools is a rotating-type transducer found at the bottom of the tool. Since the signal is focused, the active spot on the casing is essentially the same diameter (see Figure 18.14). The percent of casing circumference investigated will vary

March 2004

Company Use Only

Section 18 - 26

Cement Sheath Evaluation

18

depending on the casing size (approximately 46% of the circumference of 5-1/2 inch casing to approximately 26% of the circumference of 9-5/8" casing). The principle of the tool is the measurement of the ultrasonic signal reflection coefficient (Cr) created by the materials in contact with the inner and outer surfaces of the casing. The reflection coefficient is the ratio of the difference in the acoustic impedance of the intimately coupled materials: to the sum of their acoustic impedance:

Cr =

(Z1 - Z2) (Z1 + Z2)

where Z1 = Acoustic Impedance of the casing, 106 Kg/m2 sec Z2 = Acoustic Impedance of the material in contact with either the inner or outer casing surface Acoustic impedance (Z) is defined as:

Z = VcPb Z where Pb = Bulk density, Kg/m3 Vc = Composite velocity of a sonic signal, m/sec Acoustic impedance is a measurable physical property of a material. Compressive strength is not, in reality, a true measure of the strength of a material since the specimen is not triaxially loaded during testing. Unconfined compressive strength measurements provide a quick method of comparing relative strengths of specimens only. If the test samples were triaxially loaded, failing them in compression would be very difficult. Consequently, acoustic impedance yields a more correct definition of the quality of cement. Figures 18.14 and 18.15 illustrate the signal path taken by a pulse of sound energy transmitted by the transducer. Following the path; when it reaches the ID of the casing, a portion of the signal is reflected back to the transducer face and a portion of the signal is refracted through the wall of the casing (tw) to the second reflective surface, i.e., the interface of the casing OD and the cement sheath. The energy level (Coefficient of Reflection) at each of the reflective surfaces is a function of the acoustic impedance of the materials in contact at that surface. For instance, if fresh water occupies the casing volume, the reflection coefficient at the casing ID (A) would be 0.937 ((46 -1.5) / (46 +1.5)). Thus, 93.7% of the transmitted pulse strength would be reflected back to the transducer face and 6.3 % of the energy level would be refracted through the wall thickness of the casing to the second reflective surface (B). At the second reflective surface (B), with water in the annulus, the reflected energy level would be 93.7% of the 6.3% arriving at that point in time. The decay rate (attenuation rate) of the signal is dependent upon the shear strength of the materials in contact with the casing OD.

March 2004

Company Use Only

Section 18 - 27

Cement Sheath Evaluation

18

Figure 18.14: Signal Path (Part 1)

Figure 18.15: Signal Path (Part 2) A

tw

B

Transducer

Accurate measurements of these and subsequent signal energy levels infer prediction of the acoustic impedance of the materials in contact at each of the reflective surfaces. They also may be used to provide very accurate measurements of casing ID and casing wall thickness. Since acoustic impedance is a measurable physical property, identity of the materials at each reflective surface is also inferred.

March 2004

Company Use Only

Section 18 - 28

Cement Sheath Evaluation

18

The acoustic impedance of some common annular materials is listed in the following table.

Table 18.2: Acoustic Impedance Acoustic Impedance 106 kg.m2 sec

Material Fresh Water

1.5

Free Gas

0.1

Steel (casing)

46.0

12 lb/gal Drilling Mud

2.16

15 lb/gal Drilling Mud

2.70

17 lb/gal Drilling Mud

3.06

9 lb/gal Foamed Class C (250 psi)

2.19

9 lb/gal Foamed Class C (1000 psi)

2.69

13 lb/gal Cement (500 psi)

3.37

13 lb/gal Cement (2000 psi)

4.42

16.5 lb/gal Cement (500 psi)

4.38

16.5 lb/gal Cement (2000 psi)

5.62

Figure 18.16 illustrates the acoustic impedance of various density drilling muds.

Figure 18.16: Acoustic Impedance of Mud Mud Density, lb./gal.

18

16

14

12

10

8 1

2

3

6

4

2

Acoustic Impedance, 10 kg/m sec

March 2004

Company Use Only

Section 18 - 29

Cement Sheath Evaluation

18

Figure 18.17: Acoustic Impedance of Cement 3500

Cement Density

3000

9

10

11

12

4

4.5

13

14

15

16

17

Compressive Strength

2500

2000

1500

1000

500

0 1.5

2

2.5

3

3.5

5

5.5

6

6.5

Acoustic Impedance

Figure 18.17 illustrates the acoustic impedance of various density cement systems. Note the impedance value for the cement is dependent on both the cement density and the compressive strength of the set cement. Comparing this chart with a conventional sonic bond log is similar to taking a single value for cement and equating it to all cements, regardless of density or strength. As noted in the discussion of bonding index (see Section 18.4.3), the bond index is dependent on the expected value of the amplitude of the cement. The ultrasonic tool and its corresponding map will also be dependent on the expected impedance of the cement. This chart can be used to estimate that expected value. Note this chart is for conventionally extended slurries. Use of foam or hollow beads or spheres can have a major effect on the impedance value.

18.6.3. Schlumberger's USIT* Tool Schlumberger's Ultra Sonic Imaging Tool (USIT*) consists of a single transducer mounted on a revolving sonde at the bottom of the tool. The transducer face of the sonde is rectangular, measuring 1.2 inches (width) by 0.8 inch. The sonde rotates at 7.5 revolutions per second. Vertical sampling is a function of logging speed. Rotator subs are available in 5, 6, 7, 9-5/8, and 10-3/4 inch sizes. The 10-3/4 inch sub can be used in casing sizes up to 13-3/8 inches. The rotating transducer provides more available data for analysis of the casing cement interface. The older C.E.T. provided eight, approximately 1-inch sites of measurement out of a sampled casing circumference; the USIT* provides continuous measurement of the casing circumference in a helical pattern with the coils of the helix spaced approximately 1-inch apart vertically. *Service Mark of Schlumberger

March 2004

Company Use Only

Section 18 - 30

Cement Sheath Evaluation

18

Logging Speed Versus Sampling Sampling Azimuth

Vertical Sample, in

Logging Speed Ft./hour

10°

1.5

1600

5°

6.0

3200

5°

3.0

800

5°

1.6

300

5°

0.6

The USIT* scans the entire circumference of the casing, emitting a pulse that strikes the casing at normal incidence and causes the casing to resonate. The transducer operates in a variable frequency range of 195 - 650 kHz. The variations of frequency are for changes in casing wall thickness from 0.18 - 0.59 inches, and changes in the casing fluid density, are tuned from the surface to optimize variations in downhole conditions. The transducer excites the casing by repeatedly emitting short pulses of ultrasound. The same transducer, acting as a receiver, detects the echoes from the casing. Four measurements are made by analyzing the echoes: 1. Echo amplitude (an indication of casing condition) 2. Casing ID (calculated from the transit time of the pulse and echo) 3. Casing wall thickness (calculated from the resonant frequency) 4. Acoustic impedance of the material at the casing OD The amplitude of the reflected signal is a function of the acoustic impedance of the fluid in the casing, the casing steel, and the cement at their respective interfaces. Most of the incident transmitted energy is reflected at the mud-casing interface, typical to the Coefficient of Reflection previously discussed. The small fraction of the energy refracted through the casing thickness is reflected multiple times between reflective surfaces, releasing a transmitted pulse into the cement or mud each time the energy strikes a reflective surface. Thus, the impulse echo consists of a large initial energy level reflected for the casing ID, followed by an exponentially decaying series of inverted pulses. Processing the reflected waveform involves only the initial reflection and the very early part of the wave (immediately beyond the casing OD arrival time) to avoid later reflections from outer casing, borehole, or formations. The color imaging used for the presentation of the USIT is somewhat of an improvement over the older CET Cement Map. However, color imaging can be very misleading. Color imaging works well when a relatively large difference in acoustic impedance exists between the materials being measured (e.g., neat cement and water). Measurement, coloration, and interpretation become a severe problem when a gas-contaminated (or foamed) cement exhibits an acoustic impedance value equal to or less than annular fluids such as mud or water which, in practice, is prevalent across and above most oil

March 2004

Company Use Only

Section 18 - 31

Cement Sheath Evaluation

18

and/or gas producing zones. In these cases, coloration of the log presentation can be accomplished, but is most often not correctly identifying the annular material. These misinterpretations lead to unnecessary, costly, and mostly unsuccessful attempts at remedial cement sheath repairs. More recent innovations in interpretive coloration presents shadings of white through yellow to dark brown, plus linear presentations of minimum, maximum, and average standard deviation. Accepting the concept that liquids exhibit no significant statistical variations in acoustic impedance and thus exhibit a "straight line" acoustic impedance, the standard deviation of the line at zero or near zero should signify a liquid, regardless of its acoustic impedance. Crystalline materials, like set cements (or any non-liquid), vary considerably in acoustic impedance, thus will exhibit a nonlinear depiction of acoustic impedance; in other words, a curve of significant "character." The standard deviation of the non-liquid materials should exhibit standard deviations in excess of approximately 0.5. This type of presentation with accompanying coloration is much more easily interpreted and much more meaningful when trying to identify liquid-filled channels in contact with the casing. These standard deviation colorations are presented in a "vertical," a "horizontal," and two (2) diagonal measurement tracks. Unfortunately, the log must be run in conjunction with the General Purpose Inclination Tool (GPIT) package for absolute orientation of the log to the high side/low side of the hole. Another useful presentation of the USIT is the Acoustic Impedance log. Manipulation of data permits the presentation of acoustic impedance measurement curves every 5° or 10° (optional) circumferentially, with depth. This yields a presentation with either 36 or 72 acoustic impedance curves. Difficult and boring reading, but a significantly accurate exhibition of small channels when and if they exist in contact with the casing.

18.6.4. Halliburton's Cement Evaluation and Casing Inspection (CAST-V) Tool The Halliburton CAST-V tool is for cement evaluation and casing inspection. The CASTV tool is mechanically similar to Schlumberger's USIT* tool in that it is an ultrasonic evaluation tool utilizing a "rotating transducer" configuration. Prior to this date, the CAST-V tool presentation only consisted of a seven-color presentation of a cement map (acoustic impedance), a CBL waveform, amplitude and amplified amplitude (when run in conjunction with a bond log), eccentricity, ovality, and gamma ray. Due to the inability of the computer to differentiate between a liquid and a solid, both exhibiting the same or near same acoustic impedance, this "coloring" process has historically been unacceptable for cement evaluation. An improved presentation is available that can define the cement quality/quantity via measurements from each of nine (9) investigated segments at the casing-cement interface. The new presentation is called the "Altcastave" program. The "Altcastave" presentation is preferred over the previous "colored" presentations available from the tool. The presentation consists of nine (9) tracks, each tracing the minimum and maximum acoustic impedance values measured in each section. The "measurement areas" around the casing may be illustrated as follows.

March 2004

Company Use Only

Section 18 - 32

Cement Sheath Evaluation

18

Figure 18.18: CAST-V Segmentation

Section I

Section A

Section H

Section B

Section G

Section C

Section F

Section D Section E

The presentation is oriented so the high side of the hole, on the presentation, is at the intersection of Sections A and I. The low side of the hole is at Section E. See also Figures 18.19 through 18.24. Tool Specifications Temperature Rating

350°F (175°C)

Pressure Rating

20,000 psi (137.9 MPa)

Tool OD

3.625 inches (92 mm)

Casing Size Range

5-1/2 - 13-/8 inches (130 - 340 mm) (Variable Sizes of Rotating Heads)

Maximum Water Based Mud Weight:

15 lb/gal (1797.4 kg/m3)

The tool has been run in 16-lb/gal (1917.2 kg/m3) water based mud (low solids) and 16.3-lb/gal (1953.2 kg/m3) Zinc Bromide brine. Maximum Oil Based Mud Weight:

14-lb/gal (1677.6 kg/m3).

Vertical Sampling Rate:

6 inches (152.4 mm) 13 inches (330.2 mm) 11 inches (279.4 mm)

Logging Speed, ft/min (m/min):

60 (18.3)

March 2004

Company Use Only

130 (39.65)

110 (33.55)

Section 18 - 33

Cement Sheath Evaluation

18

Each section covers 40° of the casing circumference. The low side of the hole is presented in Section E. The high side of the hole is at the left side of Section A and the right side of Section I. Casing size determines the size of the "section," i.e.: Casing OD, in

Length of Section, in

5

1.75

5-1/2

1.92

7

2.44

9-5/8

3.36

13-3/8

4.67

The CAST-V tool makes 100 measurements at each depth segment (1, 3, or 6-inch samples) in each of the sections defined. (The tool also provides 40 real-time calipers for inspecting the casing or the borehole.) From the incoming data, the computer can select one signal, or any combination of the signals from each segment. The signals that can be retrieved include: 1. Minimum Z (acoustic impedance) 2. Maximum Z 3. Average Z 4. Each of the 100 measurements of Z 5. Any percentage of the 100 measurements of Z desired For the purposes of differentiating between a liquid and a solid at the casing cement interface, the recommendation is to select the minimum and maximum acoustic impedance curves in each of the nine (9) segments on the final log presentation (the "Altcastave" presentation). The minimum and maximum acoustic impedance measurements are selected by the computer from the 100 signals/segment, and represent the lowest and highest value of acoustic impedance calculated in each segment. The assumption is made that as long as the minimum value of acoustic impedance illustrates a "solid" in the annulus, as opposed to a liquid, the remainder of the segment will contain harder or denser solids. The average value is a meaningless number representing only the average of the minimum and maximum measurements in each segment.

18.7. INTERPRETATION OF ULTRASONIC LOGS As noted in the earlier discussion of the principles of tool operation, not only can the tool be used for cement evaluation, but also offers a very good method for determining both casing ID and OD. Casing wear, corrosion, and other properties can be readily evaluated using these tools. Both Halliburton and Schlumberger offer computer-generated cement maps or color processing of the cement evaluation logs from the ultrasonic tools. The theory of the

March 2004

Company Use Only

Section 18 - 34

Cement Sheath Evaluation

18

cement maps is the computer will assign a color to a particular acoustic impedance, and plot the colors around the casing. The map is then used to determine the "relative" quality of the cement in the annulus. The basic problem with the computer-generated color map is the computer is unable to differentiate between mud with an acoustic impedance of 3.0 and cement with the same impedance. The color maps are highly dependent on how the computer is set up and the differential scale used for the map. There is usually very little color change in the low end of the impedance range; this differentiating in the low impedance values is often not possible. The problems involved in calibrating and setting the correct parameters for the coloration of the cement map or bonding image, coupled with the changes that occur to the cement during and after placement make interpretation of the cement sheath quality and quantity rather nebulous at best. Gas cutting of the cement can occur by design with placement of foam cement or naturally during and after the cement hydration and hydrolysis process. When gas influx from the formation into the cement sheath occurs, the quantity of gas is unknown. Consequently, the final density and strength (and resulting acoustic impedance) of the contaminated cement in the annulus is also unknown. In addition to these problems, the true heat-up time of the cement from circulating to static temperature is seldom equal to the four-hour heat-up time used in laboratory compressive strength testing and the rate of strength development decreases up hole due to decreasing temperatures. Based on these non-controllable factors, there is general optimism about cement setting times and the magnitude of strength development for logging purposes. For these reasons, percent bonding has virtually no meaning. VDL or microseismogram signals may be virtually nonexistent, and correct coloration of the cement map is virtually impossible when the acoustic impedance of the cement may be less than or equal to the drilling mud (or sometimes less than water). Over simplification of the more common cement quality/quantity evaluation devices (percent bonding or map coloration) often leads to erroneous cement sheath evaluations and unnecessary remedial squeeze jobs. The annular material is more clearly definable using another presentation of the ultrasonic data known as the acoustic impedance. The magnitude of acoustic impedance or compressive strength of the cement is not important for identification once the cement is placed in the annulus. The character of the line on the acoustic impedance log provides identification of the composition of the annular material. An easy way to evaluate the acoustic impedance data from these logs is to look at the raw impedance data on a separate log plot. Halliburton offers an Altcastave plot of the raw data, and Schlumberger's version is the GZD plot. These displays use nine tracks and plot the minimum, maximum and average impedance for each track. The wellbore is plotted every 40°. The normal scale for these tracks is 0 - 10, however, to better determine the difference in a liquid and low density or low-strength cement, it is important to request the scale be expanded to 0 - 5. In this manner, it becomes very easy to determine the difference between a liquid and solid behind the pipe. If the cement is high density and/or high strength, the impedance value can be more than 5, which will peg the 0 - 5 scale. If this occurs, it simply means the material in the annulus is high strength cement.

March 2004

Company Use Only

Section 18 - 35

Cement Sheath Evaluation

18

Liquid in the annulus: Since liquids do not exhibit drastic density changes over a reasonable annular length, the acoustic impedance of the material will not change. When any transducer records a liquid in the annulus (at the casing wall), that transducer will draw a straight line that defines a liquid-filled annulus. The composition of the material (gas, water, or drilling mud) in the channel is academic, therefore, calculation of the actual acoustic impedance value is not truly necessary for identification purposes. If it is a liquid, it can be replaced with cement through circulation-type remedial cement operations.

Figure 18.19: Liquid in the Annulus

The log in Figure 18.19 shows the minimum, maximum, and average acoustic impedance for each of the nine tracks. Note that all readings are straight, low in value, and very consistent. This is typical of a liquid-filled annulus.

March 2004

Company Use Only

Section 18 - 36

Cement Sheath Evaluation

18

Figure 18.20: Cement in the Annulus

The log in Figure 18.20 shows good quality cement throughout the interval. Throughout the log the impedance values are over 5, and have pegged out the plot. The coloration on the left shows black and brown colors, indicating the difference in the impedance values of the material in the annulus. Regardless of the color of the cement map, this interval is fully cemented. There are no straight lines on the impedance curve, and all show much higher values than the mud. The "lower" impedance material may be due to slightly contaminated cement, lower strength cement as in bypassed lead slurry, etc. The log also shows the lower strength material circling around the casing rather than being isolated to only one side of the pipe. Figure 18.21 is another example of cement in the annulus. In this example, the fully cemented annulus has more consistent material than in Figure 18.20, and is a fully cemented interval.

March 2004

Company Use Only

Section 18 - 37

Cement Sheath Evaluation

18

Figure 18.21: Cement in the Annulus #2

March 2004

Company Use Only

Section 18 - 38

Cement Sheath Evaluation

18

Figure 18.22: Lightweight Cement

Figure 18.22 is an example of well-cemented pipe, with the cement in the annulus being very lightweight cement. There is very little difference in the density of the mud and the cement on this well. There are no straight lines, indicating a solid in the annulus. (The scale on this particular plot is 0-10 rather than the recommended 0-5, which makes evaluation more difficult.)

March 2004

Company Use Only

Section 18 - 39

Cement Sheath Evaluation

18

Figure 18.23: Gas Cut Cement in the Annulus

Figure 18.23 is an example of gas cut cement. This is characterized by very low values, lots of "movement" or wiggling of the signal, and no straight lines. The interval still has isolation, and has cement with gas contamination. Once cement has set in the annulus, regardless of gas contamination or compressive strength development, it cannot be removed and replaced with (what may be considered) "good" cement. Remedial cementing operations (squeezing) will not change the quality or quantity of that type of cement. This can be confirmed by running evaluation logs before and after remedial squeeze treatments. Each track of the acoustic log should be presented on a scale of 0 - 5 (acoustic impedance) for more definitive measurements of the weaker cements and liquids. Greater values of acoustic impedance are academic. It is irrelevant whether the cement in the annulus exhibits 500 psi or 5000-psi compressive strength once it is set. All that is necessary is that the material be identified as cement.

March 2004

Company Use Only

Section 18 - 40

Cement Sheath Evaluation

18

18.8. QUALITY CONTROL - SONIC LOGS 1. The Transit Time curve may be used to determine when the tool is eccentered in the casing (as previously discussed). Eccentering of the logging tool tends to warp the casing arrival signals because of the apparent difference in arrival times. Eccentering also creates extremely erratic formation arrival signals that are difficult to identify. Fast formation effects can be confused with tool eccentering by causing faster arrival times of the signal. Lithology effects must be considered when attempting to determine tool eccentering. Presentation of the Transit Time curve on the log is always recommended. With the Transit Time curve on a maximum scale range of 100 (e.g., 200 - 300 microseconds), decreasing transit times greater than four microseconds indicates the tool is eccentered (unless fast formations are involved) and the tool centralizers are suspect. Pull the tool out of the hole for centralizer replacement or reinforcement. 2. Repeatability of the tool is a vitally important quality control check. Two passes over the same hole section under the same conditions should produce virtually indistinguishable microseismogram and the amplitude curves. Repeats under pressure may not repeat as well because of leaks and cable drag preventing the conditions from being truly identical. Check to see the tool can repeat itself, and that the microseismogram and gamma ray curves are "on depth." 3. The bond logging tools should always be run with and without casing pressure for delineation of microannuli and/or channels. If the entire cement column is to be logged under pressure, ask the service company to print the line tension curve on the log so "line binding and jumping" can be seen. The velocity of sound through low-porosity limestone and/or dolomite formations (Table 18.1) can frequently create erroneous log interpretations. These types of formations are commonly called "fast formations." In these situations, the analyst must diligently search for signs of casing signals such as faint collar responses, "ruler straight" lines, etc. Remember formation responses are seldom ruler straight because of the random nature of the crystalline structure and porosity changes within the rock bed. The measurement gate is fixed or floating in time relative to the transmitter pulse and expects to "see" the first positive casing arrival but is, in fact, receiving some portion of the formation signal. In this case, the amplitude measurement ceases to have any physical meaning and all interpretation must be based on the microseismogram or VDL presentation.

18.9. EXTENUATING CIRCUMSTANCES IN CEMENT EVALUATIONS

Numerous situations exist downhole or can occur in the processing of log data that can cause considerable confusion in interpretation of the quality and quantity of a cement sheath.

March 2004

Company Use Only

Section 18 - 41

Cement Sheath Evaluation

18

18.9.1. Microannulus A microannulus at the interface of the casing and cement sheath may be created by numerous factors. These include pressure changes in the casing once the cement has set, the heat of hydration of the cement causing expansions of the casing with subsequent contraction on cool down, and/or excessively thick mill varnish on the casing surface. It is important that the existence of a microannulus be recognized since it can be confused with a channel, resulting in attempted remedial squeezes. Attempts to repair a microannulus are historically futile. The maximum microannulus size tolerated by the various logging devices are as follows: Microannulus Size Inches

Millimeters

Conventional Bond Logging Tools

0

0

Fluid Compensated Bond Logging Tools

0

0

Pad Tools (Segmented Bond Tool)

0

0

0.01

0.25

Tool Type

Ultrasonic Tools

It is quite common to displace top wiper plugs with drilling mud following the cement placement, then displace that mud with a lower-density completion fluid prior to logging. Sometimes, due to float failure following cement placement, it is necessary to leave the casing shut in. To compensate for pressure change effects, it is recommended the casing be expanded to the cement sheath for logging by placing the equivalent pressure in the casing that was present while the cement was setting, plus a minimum of 500 psi to compensate for the casing expansion caused by the cement's heat of hydration. Nonpressure passes are more effective for collar depth reference for perforating, but pressurized passes are absolutely necessary for cement evaluation. To satisfy both requirements, it is recommended both passes be made. It is also recommended the "Tension" curve be placed on the presentation of the pressurized pass to ascertain line drag problems. The microannulus size may be calculated by:

r= where: r

(OD2 * ∆P) (E * tw) = Microannulus size, in

OD

= Casing OD, in

∆P

= Pressure change, psi

E

= Young's Modulus of Elasticity of Steel

tw

= Wall thickness of Casing, in

March 2004

Company Use Only

Section 18 - 42

Cement Sheath Evaluation

18

18.9.2. Tool Eccentering Cement evaluation tools must be centered in the casing for meaningful logs. Log presentations from eccentered tools are long, meaningless pieces of paper. Tool eccentering must be observed and corrected during the logging process. If evidence of eccentering is observed while logging, pull the tool out of the hole to "beef up," replace, or add additional centralizers. This problem is not one that can be changed after the logging truck leaves the location.

18.9.2.1. Conventional and Compensated Bond Logs Eccentering of conventional and fluid compensated bond logs decreases amplitude (increases percent bonding), increases attenuation rate, and causes "warping" of the VDL or microseismogram. Eccentering of bond logging tools by as much as ¼ inch decreases the amplitude by approximately one-half (Figure 18.24), and causes the first arrival wave to arrive early since it has a shorter distance to travel along the ID of the casing nearest the tool. There is no industry standard for tool eccentering. Placement of a "Transit Time" on the curve on the log presentation can provide eccentering quality control. However, reasonable guidelines for tool eccentering suggest a maximum transit time decrease of four microseconds (µs) as long as the decrease is caused by eccentering and not created by formation effects (fast formation). This requires the lithology must be recognizable from the gamma ray curve. It also suggests the logging tool must have resolution of approximately one (1) microsecond and the maximum range of transit time on the presentation does not exceed one hundred (100) microseconds. (See also Figure 18.8.)

Figure 18.24: Eccentering

0.8 Relative Response

0.6

Eccentering

+ +

0.4 0.2

1/2

1/4

0

-1/4

-1/2

Eccentering (inches) Courtesy of Atlas Wireline Services Division Western Atlas International, Inc.

March 2004

Company Use Only

Section 18 - 43

Cement Sheath Evaluation

18

18.9.3. Eccentering of Ultrasonic Tools Eccentering measurements are generally presented in Track 1 of the log presentation. These are measurements of tool eccentering relative to the wall of the casing, which is calculated by comparing the difference between opposing radii. If the tool gets too far out of center, the signals will strike the casing wall curvature at an angle and will not be reflected directly back into the transducer face. This produces a distorted energy measurement, thus faulty cement quality measurements. Since the ultrasonic sondes are relatively short, stiff, and light compared to bond logging tools, centralization generally does not pose a problem, even in horizontal holes. An acceptable guideline for maximum allowable eccentering of the ultrasonic tools is 4% of the casing OD. For example: in 5.5-inch casing, maximum allowable eccentering is 0.22 inches (.04 x 5.5); in 9-5/8-inch casing, maximum allowable eccentering is 0.385 inch (.04 x 9.625). Signal Cycle Skipping – Generally, signal cycle skipping only occurs in sonic-bond logging and is manifested on the Transit Time curve in Track 1 of the log as a dramatic increase in transit time. Cycle skipping is a function of the threshold detection level of a particular tool and is caused by high-attenuation levels of high-shear strength cements. Bias settings at less than 10% of the free pipe signal peak will generally result in cycle skipping to later amplitude arrivals, e.g., the E3 or even E5 peaks. These later stronger peaks which are detectable above the gate bias setting are generally a result of strong formation signals and bonding. Amplitude levels also are generally higher (lower values of percent bonding) so it is important that "cycle skipping" be recognized for what it is. This phenomenon can also occur in liner overlap sections containing high-shear strength cement, i.e., the transit time can increase to the transit time value of the outer casing string. Signal "Stretch" –.”Stretch" is the slight delay in transit time (generally in the range of 10 - 12 µs) caused by attenuation of the pipe signal (E1) curve. The amplitude of the peak is still sufficiently high for measurement, yet sufficiently attenuated to cause an increase in the signal transit time. Cycle stretch can be interpreted as being caused by cement-shear strength and be a portent of impending cycle skip. Thin Cement Sheath – The bond log (the cement sheath quality) has been shown to be a function of the cement sheath thickness (Figure 18.7). For a thin (less than ¾ inch) cement sheath, recorded amplitude (percent bonding) will be increasingly pessimistic. The response of the ultrasonic tools to a thin cement sheath is much less critical and generally not a problem. Formation Coupling – Coupling to the formation is generally inferred by the presence of clear and concise reflected formation compression and shear waves on the VDL or microseismogram. These formation signals are not always clear and well defined. There may be cases where there are no indications of a VDL or microseismogram on the log.

March 2004

Company Use Only

Section 18 - 44

Cement Sheath Evaluation

18

Four downhole situations can prevent the recording of formation signals. 1. Thick, Soft, Fluffy Wall Cake – The signal velocity is so slow through the poorly compacted filter cake that it does not have time to enter the formation and be reflected back to the tool. These type-filter cakes will often be visible on the open hole caliper survey as decreases in hole size across permeable sections. 2. Non-Cemented Hole Enlargement – Failure to clean the hole properly before and during the cement job can leave a "washout" full of drilling mud instead of cement. If these "poorly bonded" sections conform to identification of hole enlargements on the open hole caliper survey, the enlargements are generally filled with drilling mud. They may or may not present an annular isolation problem. 3. Soft or Poorly to Unconsolidated Formations – Sonic velocity in very soft formations can be sufficiently slow that the formation reflections and refractions will not have time to reach the tool within the measurement window. Marine shales, soft salt or anhydrite beds, and/or fully unconsolidated sands will sometimes present this type of interpretation problem. These situations do not generally pose an annular isolation problem. 4. Foamed or Gas Cut Cement – Adding gas to the cement system, whether by design (as in foamed cement) or naturally (as in formation gas influx), decreases density which in turn can drastically reduce sonic velocity. It is not uncommon to inject 20% to 40% by volume nitrogen (depending on the density required) into the cement during the manufacture of foamed cement. Some commercial lightweight additives can entrain as much as 35% to 45% by volume gas into the cement system. The gas generating type “annular flow additives” generates 2% to 3% gas into the cement sheath. Any of these types of cementing systems can create sufficient decreases in sonic velocity. The formation signals do not have sufficient time to return to the logging tool. Gas entrainment in the cement sheath does not necessarily pose an annular isolation problem. Formation bonding is inferred on the variable density log (VDL) or microseismogram of the sonic bond log. The ultrasonic cement evaluation tools primarily investigate the cement-casing interface and do not infer any magnitude of formation bonding. The magnitude of formation signals being reflected into the receiver of the bond log tool will mask the existence of a channel between the cement sheath and the borehole wall. Consequently, none of the cement sheath evaluation tools to date can identify a channel in the cement sheath unless it exists against the surface of the casing. It is entirely possible to have an excellent cement job according to a bond logging tool or an ultrasonic tool, yet still not have total isolation of the annulus. This is due to the existence of a channel between the cement sheath and the formation borehole. In the event this situation is suspected, it may be advisable to run a temperature log, or in combination with a noise log, to detect communicable flow outside the cement sheath.

March 2004

Company Use Only

Section 18 - 45

Cement Sheath Evaluation

18

18.10. TESTING RECOMMENDATIONS 18.10.1. Cement Testing Prior to cementing and logging for cement evaluation, it is recommended that laboratory testing include the following information. These procedures are recommended for better determination of preferred logging times.

18.10.1.1. Operational Thickening Time This is not API Thickening Time and is much closer to actual thickening time. Operational thickening time uses “placement time” as heat-up time (Casing Volume + Pump Rate) to bottomhole circulating temperature, followed by slurry cool down to circulation temperature at the top of the cement column. Cool-down time is annular volume from TD to cement top divided by the pump rate. These tests may be run using a conventional consistometer or an Ultrasonic Cement Analyzer (UCA). When using the UCA, the sonic velocity may be used to calculate the acoustic impedance of the set cement. Multiply the cement density (lb gal) times 3.0429, then divide by the sonic transit time (microseconds/inch). The resultant value of acoustic impedance is in megaRayles (106mkg/m2-sec).

18.10.1.2. Static Time The time required for the cement (at the top of the cement column) to reach a minimum acoustic impedance value of 1.5 megaRayles greater than the acoustic impedance of the drilling mud. These measurements should be made using the following procedures: 1. Following API slurry mixing procedures, place the sample in a UCA (or similar device). 2. Heat the sample from mixing temperature to bottomhole circulating temperature and expected pressure using the “placement time” as heat-up time discussed above. 3. Cool the sample to circulating temperature at the cement column top. 4. Heat the sample to static temperature at the cement column top. Heat-up time from circulating temperature to static temperature should be eight hours. 5. Record time to reach a strength of 1.5 megaRayles greater than the drilling mud. The elapsed time recorded should be from the time of item 4 (when the “plug is bumped” and the system starts warming towards static temperature). Static time is the minimum time the cement sheath should remain undisturbed prior to logging. All cement below the top of the cement column will be set and have attained a greater acoustic impedance. If a cement evaluation log is required, make sure the cement has in fact set. It costs a lot less to measure the suggested set time in the laboratory than it does to run a cement evaluation log to see if the cement is set. Laboratory testing costs are even less when the log is run without knowing when the upper cement system is supposed to be set and liquid cement is logged instead.

March 2004

Company Use Only

Section 18 - 46

Cement Sheath Evaluation

18

18.10.2. Log Scaling and Parameters 18.10.2.1. Bond Logs •

Travel Time Curve – Range of scaling should be 100 microseconds (µs). For example, 200-300 or 300-400 µs, not 200-400 µs. The purpose is to expand the scale so the tool eccentering is more visible. Maximum tool eccentering should not exceed consistent 4 µs.

•

Amplitude Curve – Scale at 0-100 millivolts (do not use bonding index).

•

Amplified Amplitude – Scale at 0-20 millivolts.

•

Maximum recommended logging speed is 1,800 ft/hour.

•

All bond logs should be run with and without internal casing pressure (Log Examples 18.2 and 18.3).

•

Make a bit and scraper run prior to logging.

•

The maximum temperature for bong log tools is 350°F (177°C).

18.10.2.2. Segmented Bond Tool 1. Coloration of Variable Attenuation – The minimum coloration value should be set using the free pipe value, based on the casing wall thickness. It is recommended all remaining coloration be set at an attenuation rate equal to 100-psi cement at a given casing wall thickness. 2. Filtering – The log presentation is normally filtered. Filtered means the data is averaged every six inches. It is recommended the raw attenuation curves be presented non-filtered. 3. Attenuation Curves – The scaling of the attenuation curves should be set at 0-9 db/ft. Common range for the curves is 0-15 db/ft. The lower value expands the scale for better evaluation of the annular material in the low range of attenuation. Separate solids from liquids, not 2,000-psi cement from 5,000-psi cement. 4. The relative bearing curve should always be put on the log to identify the low side of the hole. This permits orientation of channels. 5. Maximum recommended logging speed is 2,400 ft/hour.

18.11. TOOL SELECTION The choice of cement evaluation techniques depends on what is to be done with the data, and how precise the results must be. For wells where the separation in productive formations is in excess of 100 ft, a CBL will generally suffice. If there is a requirement to determine isolation between intervals of less than 50 ft, an ultrasonic tool is recommended.

March 2004

Company Use Only

Section 18 - 47

Cement Sheath Evaluation

18

For determining only the top of cement, or the location of the lead and tail in the annulus, a temperature log can be used. These basic logs will pick up changes in temperature brought on by cement hydration and are widely used to locate top of cement following cement jobs. These logs must be run within the early set time of the cement, and cannot be used several days following the cement job. In order of expense, the least costly log is a temperature log. This is followed by a sonic log, ultrasonic log, and finally the combination of the sonic and ultrasonic logs. As the cost increases, the amount of data increases and decisions can be made on a more precise level. It is the goal of cementing operations to eliminate the need for cement evaluation logs. If all of the surface indications during the cement job indicate a quality job, there is little value in performing cement evaluation via logs. Quality surface indicators include factors that mean the cement job was properly designed, the casing was centralized and used pipe movement, the cement was mixed to the proper density and fluid rates and pressures were as predicted in pre-job planning. Likewise, attempting to perform cement evaluation from a log in the absence of cement data from location is futile. Without knowledge of the type of cement systems pumped, and other well information, performing cement evaluation solely from a log is suspect at best.

March 2004

Company Use Only

Section 18 - 48

Cement Sheath Evaluation

18

REFERENCES Edgson, J. and Mehts, D., "Evaluating Cement Quality in Canada," Paper 83-34-20 presented at the 34th Annual Technical Meeting of the Petroleum Society of CIM, Banff, Alberta, May 1983. Masson, J. P. and Bruckdorfer, R., "CBL evaluation of foam-cemented casings using standard techniques," SPWLA Twenty-Fourth Annual Logging Symposium, June 1983. Broding, R. A., "Application of the Sonic Volumetric Scan Log to Cement Evaluation," APWLA Twenty-Fifth Annual Logging Conference, June 1984. Epps, D. S. and Tello, L. N., "Improved Compressive Strength Evaluations in Foamed Cements Using the Pulse Echo Tool," Southwestern Petroleum Short Course, Lubbock, TX, 1988. Uswak, G. and Dennis, B., "Evaluating Neat and Foamed Cements," Petroleum Engineer International, April 1991. Dennis, B and Uswak, G., "Improved Evaluation of Neat and Light Cements," Paper 9104, CADE / CAODC Spring Drilling Conference, Calgary, Alberta, April 1991. Hayman, A. J., Gai, H. and Toma, I., "A Comparison of Cementation Logging Tools in a Full-Scale Simulator," SPE paper 22779 presented at the 66th annual conference, Dallas TX, Oct. 1991. Pilkington, Paul E., "Cement Evaluation - Past, Present and Future," JPT, Feb 1992. Gai, H and Lockyear, C, "Cement Bond Logs - A New Analysis to Improve Reliability," SPE Paper 23729 presented at the Second Latin American Petroleum Engineering Conference, Caracas, Venezuela, March 1992. Harness, P. E., Sabins, F. L. and Griffith, J. E., "New Technique Provides Better LowDensity-Cement Evaluation," SPE Paper 24050 presented at the Western Regional Meeting, Bakersfield, CA, March 1992. Goodwin, K. J., "Guidelines for Ultrasonic Cement-Sheath Evaluation," SPE Production Engineering, August 1992. Griffith, J. E., Sabins, F. L. and Harness, P. E., "Investigation of Ultrasonic and Sonic Bond Tools for Detection of Gas Channels in Cements," SPE paper 24573 presented at the 67th Annual Technical Conference, Washington, DC, Oct. 1992. Gong, M. and Morriss, S. L., "Ultrasonic Cement Evaluation in Inhomogeneous Cements," SPE paper 24572 presented at the 67th Annual Technical Conference, Washington, D. C., Oct, 1992. Cement Sheath Evaluation - API Technical Report 10TR1, First Edition, June 1996. Harness, P. E. and Franl, W. E., "Neutron Logs Improve Interpretation of Foamed Cement, Even in Concentric Casing," SPE Drilling & Completion, December 1996. Goodwin, K. J., "Oilwell / Gaswell Cement-Sheath Evaluation," JPT, December 1997.

March 2004

Company Use Only

Section 18 - 49

Cement Sheath Evaluation

18

Goodwin, K. J., "Guidelines for Calibrating Schlumberger's Cement Evaluation Tool," March 1998. Frish, G. F., Graham, W. L. and Griffith, J. E., "Assessment of Foamed-Cement Slurries Using Conventional Cement Evaluation Logs and Improved Interpretation Methods," SPE Paper 55649, presented at the 1999 Rocky Mountain Regional Meeting, Gillette Wyoming, 1999.

March 2004

Company Use Only

Section 18 - 50

Appendix

Primary Cementing Information Resources

Scope This Section covers many information sources.

Company Use Only

Information Resources

A

Table of Contents 1. Books by Subject.......................................................................................... 3 2. Technical Papers by Subject ....................................................................... 4 Additives........................................................................................................ 4 Casing Vibration ........................................................................................... 4 Centralization ................................................................................................ 5 Coiled Tubing Squeeze ................................................................................ 5 Computer Models ......................................................................................... 5 CRETE* .......................................................................................................... 5 Displacement ................................................................................................ 6 External Casing Packer (ECP) ..................................................................... 6 Environmental ............................................................................................... 6 Equipment ..................................................................................................... 7 Evaluation...................................................................................................... 7 Evaluation and Foam.................................................................................... 7 Fluid Loss...................................................................................................... 8 Foam Cement ................................................................................................ 8 Foam Cement and HTHP / Lab Studies..................................................... 10 Gas Migration.............................................................................................. 11 Gas Migration and CRETE* ........................................................................ 12 Horizontal .................................................................................................... 12 HTHP ............................................................................................................ 12 Lab Studies ................................................................................................. 13 Liners ........................................................................................................... 13 Lost Circulation .......................................................................................... 14 Mechanical Properties................................................................................ 14 Mechanics ................................................................................................... 15 Mud Displacement ...................................................................................... 16 Other ............................................................................................................ 17 Plug .............................................................................................................. 17 Quality.......................................................................................................... 18 Quality and Foam........................................................................................ 18 Shoe Tests................................................................................................... 18 Slag .............................................................................................................. 19 Specialty Cements ...................................................................................... 20 Stress Failure .............................................................................................. 20 Stresses....................................................................................................... 20 Temperature ................................................................................................ 20 Water Flow................................................................................................... 22

March 2004

Company Use Only

Appendix A - 2

Information Resources

Book / Standard Title

Author(s)

Publisher

Date

A

Additional Information

1. Books by Subject Cement Sheath Evaluation

API Technical Report 10TR1, First Edition

1996

Cementing Technology and Procedures

Editions Technip, Paris Society of Petroleum Engineers, Richardson, TX. ISO 10427-2-2003 Éditions Technip, Paris PennWell Publishing Company, Tulsa OK.

1993

Cementing, SPE Monograph Volume 4, Henry L Dougherty Series Smith, Dwight K.

Centralizer Placement and Stop Collar Testing Drilling Mud and Cement Slurry Rheology Manual Lost Circulation

Messenger, Joseph U

Petroleum Well Construction

Economides, M. J., Watters, L. T., and Dunn-Norman, S.

Preparation and Testing of Atmospheric Foamed Cement Slurries

John Wiley & Sons, Ltd. West Sussex, England ISO 10426-4-2003

1990

2003 1982 1981 1998

2003

Recommended Practice for Performance Testing of Cementing Float Equipment

API Recommended Practice 10F, Third Ed

2002

ANSI/API 10F/ISO 18165-2001

Specification for Bow-Spring Casing Centralizers

API Specification 10D, Sixth Edition

2002

ANSI/API 10D/ISO 10427-1-2001

Specification for Cements and Materials for Well Cementing

API Specification 10A, Twenty-third Edition

2002

ANSI/API 10A/ISO 10426-1-2001

Technical Report on Temperatures for API Cement Operating Thickening Time Tests

API Report 10TR3, First Edition

1999

Testing of Deep Water Cement Formulations Testing of Well Cement Well Cementing

ISO 10426-3-2003 ISO 10426-2-2003 Schlumberger Educational Services, Houston TX American Petroleum Institute, Washington D.C.

2003 2003 1990

Worldwide Cementing Practices

Nelson, Erik B

1991

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 3

Information Resources

Technical Paper Title

Authors

Source

Year

A

Additional Information

2. Technical Papers by Subject Additives Cementing Multilateral Well With Latex Cement Highly Relaxed Fluid Loss, Surfactant Enhanced Cement Improves Results on Deep Gas Wells

Abdul-Rahman and Chong Dillenbeck and Smith

SPE/IADC 37623

1997

Additives

SPE 38599

1997

Additives

How Fluid Loss Influences Primary Cementing: Literature Review and Methodology

Daccord & Baret

SPE Drilling & Completion

1994

Additives

Improved Primary and Remedial Cementing with Thixotropic Cement Systems

Spangle & Calvert

AIME/SPE 3833

1972

Additives

Liquid Cement Premix Introduces New Solutions to Conventional Rae and Johnston Cementing Problems

IADC/SPE 35086

1996

Additives

Storable Liquid Cementitious Slurries for Cementing Oil and Gas Wells

Rae and Johnston

US Patent 5,447,195

1995

Additives

Surface Set Cements and their Successful Applications for Shallow Gas Migration Control in Southeastern Alberta

Chan, Woolsey, Ackert and Pipchuk

CIM/SPE 90-114

1990

Additives

The Effects of Excess Retardation on the Physical Properties of Cement Slurries

Sabins, Sutton and Crook

SPE 10221

1981

Additives

The Quality of Bentonite and Its Effect on Cement Slurry Performance

Grant, Rutledge & Gardner

IADC/SPE 19940

1990

Additives

Use of Liquid Cement Additives in Offshore Operations

Calvert & Gandy

1986

Additives

Also see Patent 5,547,506, 1996

Casing Vibration Primary Cementing Improvement by Casing Vibration During Cooke, Gonzalez and Cement Curing Time Broussard

SPE Production Engineering

1988

Casing Vibration

The Rheological Properties of Cement Slurries: Effects of Vibration, Hydration Conditions and Additives

SPE Production Engineering

1988

Casing Vibration

Chow, McIntire, Kunze and Cooke

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 4

Information Resources

Technical Paper Title

Authors

Source

Year

A

Additional Information

Centralization Casing Centralization in Horizontal and Highly Inclined Wells Reduce Torque, Drag and Wear - Material Selection for Centralizers used in Highly Inclined and Horizontal Wells

Blanco, Ciccola and Limongi Kinzel and Colvard

IADC/SPE 59138

2000

Centralization

IADC/SPE 47804

1998

Centralizers

1993

Coiled Tubing Squeeze

Coiled Tubing Squeeze Cement Slurry Qualification, Field Mixing and Quality Assurance Procedures for Coiled Tubing Squeeze Operations in Prudhoe Bay Alaska

Vorkinn and Sanders

Coiled Tubing Cement Squeeze at Prudhoe Bay Alaska

Harrison and Blount

SPE 15104

1986

Coiled Tubing Squeeze

Improved Coiled Tubing Squeeze Techniques at Prudhoe Bay

Hornbrook and Mason

SPE 19543

1989

Coiled Tubing Squeeze

New Coiled Tubing Unit Cementing Techniques at Prudhoe Developed to Withstand Higher Differential Pressure

Krause and Reem

SPE 24052

1992

Coiled Tubing Squeeze

SPE 26089

Computer Models Cementing Temperature Predictions Based in Both Downhole Measurements and Computer Predictions: A Case History

Honore, Tarr, Howard and Lang

SPE 25436

1993

Computer Models

Computer Simulation Improves Cement Squeeze Jobs

Bour, Creel and Kulakofsky

CIM/SPE 90-113

1990

Computer Models

A New Approach to Designing High Performance Lightweight Cement Slurries for Improved Zonal Isolation in Challenging Situations Case Studies of Expanding Cement to Prevent Microannular Formation

Revil and Jain

IADC/SPE 47830

1998

CRETE

Baumgarte, Thiercelin and Klaus

SPE 56535

1999

CRETE

Concrete Developments in Cementing Technology Guillot, et. al. High Performance Water Reduced Cement Slurries Prepared Baret, Garnier and with Low Cost Optimized Blend Rashad

Oilfield Review IADC/SPE 35088

1999 1996

CRETE CRETE

Improved Performance of Lightweight Cement Slurries New Cement Systems for Durable Zonal Isolation

JPT IADC/SPE 59132

1997 2000

CRETE CRETE

CRETE*

Moulin and Revil Le Roy-Delage, Baumgarte, Thicerelin, and Vidik

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 5

Information Resources

Technical Paper Title

Authors

Source

Year

A

Additional Information

New Cement Systems for Durable Zonal Isolation

Roy-Delage, Baumgarte, IADC/SPE 59132 Thiercelin and Vidik

2000

CRETE

New Cementing Technology Cures 40 Year-Old Squeeze Problems

Farkas, Roemer, Roy, Dickinson and Hart

SPE 56537

1999

CRETE

Support Requirements and Innovative Solutions for a Remote Location with Difficult Cementing Challenges

Piot, Lamb, Blessen, Schafers and Ferri

SPE 74501

2002

CRETE

Use of Concrete Technology to Improve Performance of Lightweight Cements

Moulin, Revil and Jain

SPE 39276

1997

CRETE

Using Particle Size Distribution Technology for Designing High Density, High Performance Cement Slurries in Demanding Frontier Exploration Wells in South Oman

Jain, Raiturkar, Holmes and Dahlin

IADC/SPE 59134

2000

CRETE

West Africa Deepwater Wells Benefit from Low-Temperature Cements

Piot, Ferri, Mananga, Kalabare & Viela

SPE/IADC 67774

2001

CRETE

1996

Displacement

Cementing High Angle Wells Using Cement Expanded Formation Webster, Otott and Rice SPE/IADC 16136 Packers and/or Casing Rotation

1987

ECP

Development of a One Trip External Casing Packer Cement Inflation and Stage Cementing System

Coronado and Knebel

SPE 39345

1998

ECP

Monitoring and Analysis of ECP Inflation Status Using Memory Gauge Data

Gai and Elliott

SPE 36949

1996

ECP

Predicting Seal Effectiveness of Cement Inflated Packers Zonal Isolation in Stimulation Treatments and Gas/Water Shutoff Using Thermally Compensated Inflatable Packers and Plugs

Suman and Wood Wilson and Hoffman

World Oil IADC/SPE 59139

1995 2000

ECP ECP

Air Emissions Testing at an Oil Field Service Company Bulk Storage Facility

Turner

1998

Environmental

Displacement Tide Flow: A Low Rate Density Driven Cementing Technique for Highly Deviated Wells

Kroken, Sjaholm and Olsen

IADC/SPE 35802

External Casing Packer (ECP)

Environmental SPE 46835

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 6

Information Resources

Technical Paper Title

Authors

Source

Year

A

Additional Information

Equipment Automatic Control of Bulk Cement Tank Levels

Wienck and Pitts

OTC 7069

1992

Equipment

Evaluation A Comparison of Cementation Logging Tools in a Full Scale Simulator

Hayman, Gai and Toma SPE 22779

1991

Evaluation

Application of the Sonic Volumetric Scan Log to Cement Evaluation

Broding

SPWLA

1984

Evaluation

Assessment of Foamed Cement Slurries Using Conventional Cement Evaluation Logs and Improved Interpretation Methods

Frisch, Graham and Griffith

SPE 55649

1999

Evaluation

Cement Bond Log: Determining Wait-on-Cement Time Cement Bond Logs - A New Analysis to Improve Reliability

Jordan and Shepard Gai and Lockyear

SPE 14200 SPE 23729

1985 1992

Evaluation Evaluation

Cement Evaluation - Past, Present and Future Cement Evaluation and Casing Inspection with Advanced Ultrasonic Scanning Methods

Pilkington JPT Graham, Silva , SPE 38651 Leimkuhler and de Kock

1992 1997

Evaluation Evaluation

Improved Evaluation of Neat and Light Cements Investigation of Ultrasonic and Sonic Bond Tools for Detection of Gas Channels in Cements

Dennis and Uswak Griffith, Sabins and Harness

CADE/CAODC 91-04 SPE 24573

1991 1992

Evaluation Evaluation

New Technique Provides Better Low Density Cement Evaluation

Harness, Sabins and Griffith

SPE 24050

1992

Evaluation

Ultrasonic Cement Evaluation in Inhomogeneous Cements

Gong and Morris

SPE 24572

1992

Evaluation

1983

Evaluation and Foam

1988

Evaluation and Foam

1996

Evaluation and Foam

Evaluation and Foam CBL Evaluation of Foam Cemented Casings Using Standard Techniques

Masson and Bruckdorfer SPWLA

Improved Compressive Strength Evaluations in Foamed Cements Epps and Trllo Using the Pulse Echo Tool Neutron Logs Improve Interpretation of Foamed Cement, Even in Harness and Frank Concentric Casing

Southwestern Petroleum Short Course SPE Drilling & Completion

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 7

Information Resources

Technical Paper Title

Authors

Source

Year

A

Additional Information

Fluid Loss Role of Cement Fluid Loss in Wellbore Completion Why Cement Fluid Loss Additives Are Necessary

Bannister and Lawson Baret

SPE 14433 SPE 17630

1985 1988

Fluid Loss Fluid Loss

SPE 12318

1983

Foam Cement

A Novel Lightweight Cement Slurry and Placement Technique for Kulkarni and Hina Covering Weak Shale in Appalachian Basin

SPE 57449

1999

Foam Cement

A Unique Experience with Foam Cement

SPE 28820

1994

Foam Cement

IADC/SPE 47831

1998

Foam Cement

Foam Cement A Case Study of Ultra Lightweight Cementing Practices in the Northeastern United States

Advances in Metering and Control Technology Improves Design and Execution of Foamed Cement Jobs

Edmondson and Benge

Piot, Ferriere and Fraboulet Judge and Benge

Application of Foam Cement and the Stringent Quality Control Techniques Basic to the Use of this New Oil Field Cementing System

Antonovitch. Birch and Murphy

Proceedings Indonesian Petroleum Association

1983

Foam Cement

Application of Foam Cement in the Williston Basin Application of Foam Cements in Alberta Applications of Foamed Portland Cement to Deep Well Conditions in West Texas Automation Brings Foamed Cements Under Control Calculation of Pressures for Foams in Well Completion Processes

Bour and Vennes Olanson Bozich, Mountman and Harms Flatern Buslov, Towler and Amain

SPE 18984 CIM 84-35-72 SPE 12612

1989 1984 1984

Foam Cement Foam Cement Foam Cement

Offshore SPE 36490

1997 1996

Foam Cement Foam Cement

Cementing of Fragile Formation Wells with Foamed Cement Slurries

Harms and Febus

SPE 12755

1984

Foam Cement

Cementing Through High Pressure Coiled Tubing on HTHP Khuff Mazen, Rouatbi and Zaki SPE 53244 Gas Well Offshore Abu Dhabi

1999

Foam Cement

Dynamic Characteristics of Nitrified Cements

Mueller, Franklin and Daulton

1990

Foam Cement

Evaluating Neat and Foam Cements

Uswak and Dennis

1991

Foam Cement

Southwestern Petroleum Short Course Petroleum Engineer International

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 8

Information Resources

Technical Paper Title

Authors

Source

Year

Additional Information

Evaluation of Foamed Cement Squeeze Treatments for Low Pressure Highly Permeable Reservoirs

Kondratoff and Chmilowski

CIM 89-40-80

1989

Foam Cement

Foam Cement for Low Pressure Squeeze Applications

Bour and Creel

1987

Foam Cement

Foam Cement Solves Problems in Alberta, Canada Foam Cementing Applications on a Deepwater Subsalt Well Case History

Peskunowicz and Bour Moore, Miller, Faul and D'Agostino

Southwestern Petroleum Short Course CIM 87-38-89 IADC/SPE 59170

1987 2000

Foam Cement Foam Cement

Foam Rheology characterization as a Tool for Predicting Pressures While Drilling Offshore Wells in UBD Conditions

Martins, Lourenco, Sa and Silva

SPE/IADC 67691

2001

Foam Cement

Foamed Cement - Solving old Problems with a New Technique

Benge, Spangle and Sauer

SPE 11204

1982

Foam Cement

Foamed Cement - Theory and Practice

Moran, Spangle and Evans

Southwestern Petroleum Short Course SPE 17040

1986

Foam Cement

1987

Foam Cement

Foamed Cement Achieves Predictable Annular Fill in Appalachian Colavecchio and Devonian Shale Wells Adamiak Foamed Cement Application in Canada Foamed Cement as a Deterrent to Compaction Damage in Deepwater Production

Smith and Lukay CIM 83-34-21 White, Moore, Miller and SPE 59136 Faul

1983 2000

Foam Cement Foam Cement

Foamed Cement Characterization Under Downhole Conditions and Its Impact on Job Design

Rozieres and Ferriere

IADC/SPE 19935

1990

Foam Cement

Foamed Cement for Squeeze Cementing Low Pressure Highly Permeable Reservoirs: Design and Evaluation

Chmilowski and Kondratoff

SPE 20425

1990

Foam Cement

Foamed Cement Job Successful in Deep HTHP Offshore Well

Benge, McDermott, Langlinais and Griffith

Oil & Gas Journal

1996

Foam Cement

Foamed Cement Restores Wellbore Integrity in Old Wells Garvin and Creel Foamed Cement Solves Producing, Injection Problems Creel and Cook Foamed Cement Squeezing Technology for Conformance Control Creel and Crook in Fractures, Channel Communication and Profile Modification

Oil & Gas Journal Oil & Gas Journal Southwestern Petroleum Short Course

1984 1998 2000

Foam Cement Foam Cement Foam Cement

Foamed Cement vs. Conventional Cement for Zonal Isolation: Case Histories

SPE 62895

2000

Foam Cement

Kopp, Reed, Carty and Griffith

A

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 9

Information Resources

Technical Paper Title

Authors

Foamed Cement: A Second Generation Foamed Cementing Techniques for Liners Yields Cost Effective Results Foamed Cements Reliably Seal Cased Wellbores

Source

Year

Additional Information

Loeffler Pickett and Cole

SPE 12592 SPE 27679

1984 1994

Foam Cement Foam Cement

Petit, Covington, Banse and Decareaux

Oil & Gas Journal

2000

Foam Cement

How Foamed Cement Advantages Extend to Hydraulic Fracturing Deeg, Griffith, Crook and World Oil Operations Benge Low Density Foamed Portland Cements Fill Variety of Needs Mountman, Sutton, Oil & Gas Journal Harmes and Mody

1999

Foam Cement

1982

Foam Cement

2002

Foam Cement

Also World Oil, June 1982

Method Predicts Foamed Cement Compressive Strength Under Temperature, Pressure

Cobb, Maki and Sabins

New Developments in Aerated Mud Hydraulics for Drilling in Inclined Wells Nitrogen and Carbon Dioxide in the Oil Field: Stimulation and Completion Applications

Sunthankar, Kuru, Miska SPE 67189 and Kamp Ward SPE 12594

2001

Foam Cement

1984

Foam Cement

Practical Field Procedures and Techniques for Foam Cementing

Squires and Herbst

1986

Foam Cement

Shell Foam Cements to Surface in California's Mt. Poso Field

Davis

1984

Foam Cement

Successful Squeezing of Shallow and Low Pressure Formations

Grant, White, Smith and IADC/SPE 19937 Miller Mueller, Franklin and SPE 20116 Daulton

1990

Foam Cement

1990

Foam Cement

Geothermal Resources Council, Transactions SPE 46215

1985

SPE 56633

1999

Foam Cement and HTHP Foam Cement and HTHP Foam Cement and Lab Studies

The Determination of the Static and Dynamic Properties of Nitrified Cements

Oil & Gas Journal

Southwestern Petroleum Short Course Drilling

A

Foam Cement and HTHP / Lab Studies Foam Cement for Geothermal Wells

Richard

Foam Cementing Cyclic Steam Producing Wells: Cymric Field Case Study Rheological Properties of Aqueous Foams for Under-balanced Drilling

Miller and Frank Saintpere, Herzhaft, Toure and Jollet

1998

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 10

Information Resources

Technical Paper Title

Authors

Source

Year

A

Additional Information

Gas Migration A Single Technique Solves Gas Migration Problems Across a Wide Range of Conditions

Drecq and Parcevaux

SPE 17629

1988

Gas Migration

An Investigation of Annular Gas Flow Following Cementing Operations

Garcia and Clark

SPE 5701

1976

Gas Migration

Annular Gas Flow After Cementing: A Look at Practical Solutions

Levine, Thomas, Bezner SPE 8255 and Toole

1979

Gas Migration

Annular Pressure and Temperature Measurements Diagnose Cooke, Kluck and Cementing Operations Medrano

JPT

1984

Gas Migration

Blow Out Occurrence Caused by Annular Gas Flow After Cementing

Kahled Kadry

SPE/IADC 57578

1999

Gas Migration

Critical Design Parameters to Prevent gas Invasion During Cementing Operations

Bannister, Benge and Marcinew

CIM 84-35-105

1984

Gas Migration

Development and Use of a Gas Tight Cement

Grinrod, Vassoy and Dingsoyr Bour and East

IADC/SPE 17258

1988

Gas Migration

IADC/SPE 17259

1988

Gas Migration

Field Measurements of Annular Pressure and Temperature During Primary Cementing

Cooke, Kluck and Medrano

JPT

1983

Gas Migration

Gas Channeling and Micro Fractures in Cemented Annulus

Taiabani, Chukwu and Hatzignatiou

SPE 26068

1993

Gas Migration

Gas Flow in Cements Gas Invasion and Migration in Cemented Annuli: Causes and Cures

Cheung and Beirute Stewart and Schouten

SPE 11207 IADC/SPE 14779

1982 1986

Gas Migration Gas Migration

Gas Invasion and Migration in Cemented Annuli: Causes and Cures

Stewart and Schouten

SPE Drilling Engineering

1988

Gas Migration

Interrelationship Between Critical Cement Properties and Volume Changes During Cement Setting

Sutton and Sabins

SPE 20451

1990

Gas Migration

SPE 22776

1991

Gas Migration

Prohaska, Fruhwirth and SPE 27878 Economides

1994

Gas Migration

Expansion: Anti-Fluid Migration Technology Solves South Texas Fluid Migration Problems

Low Rate Pipe Movement During Cement Gelation to Control Gas Sutton and Ravi Migration and Improve Cement Bond Modeling Early Time Gas Migration Through Cement Slurries Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 11

Information Resources

Technical Paper Title

Authors

Source

Year

Additional Information

New Method for Determining Downhole Properties that Affect Sutton and Ravi Gas Migration and Annular Sealing

SPE 19520

1989

Gas Migration

New Model of Pressure Reduction to Annulus During Primary Cementing Parametric Study of Gas Entry into Cemented Wellbores

Zhou and Wojanowicz

IADC/SPE 59137

2000

Gas Migration

Sabins & Wiggins

1997

Gas Migration

Prevention of Shallow Gas Migration Through Cement

Al-Buraik, AlAbdoulqader and Bsaibes Cox and Chan

SPE Drilling & Completion IADC/SPE 47775

1998

Gas Migration

CADE/CAODC 91-05

1991

Gas Migration

SPE 25181

1993

Gas Migration

SPE 4783

1974

Gas Migration

Shallow Gas Migration Control Treatments in Wainwright Area

Surfactants: Additives to Improve the Performance Properties of Cowan and Eoff Cements The Inability of Unset Cement to Control Formation Pressure Stone and Christian

A

Verification of Slurry Response Number Evaluation Method for Gas Migration Control

Harris, Ravi, King, Wilkinson and Faul

SPE 20450

1990

Gas Migration

Verification of Slurry Response Number Evaluation Method for Gas Migration Control

Gai and Greaves

SPE Drilling & Completion

1996

Gas Migration

2001

Gas Migration and CRETE*

2000 1990

Horizontal Horizontal

Also SPE Paper 11206, 1982

Gas Migration and CRETE* Successful Sealing of Vent Flows with Ultra-Low-Rate Cement Squeeze Technique

Slater, Stiles and Chmilowski

Cementation of Horizontal Wellbores Problems in Cementing Horizontal Wells

McPherson Sabins

Cementing Steamflood and Fireflood Wells - Slurry Design Evaluation and Improving Thermal Cementing Practices

Nelson and Eilers CIM 83-34-23 Chmilowski, Frankiw and CIM 84-35-115 Ford

1983 1984

HTHP HTHP

Improved Cement Slurry Designed for Thermal EOR Wells New Design Guidelines for Geothermal Cement Slurries

Nelson Koons, Free and Fredrick

1986 1993

HTHP HTHP

SPE/IADC 67775

Horizontal SPE 62893 JPT

HTHP

Oil & Gas Journal Geothermal Resources Council Transactions

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 12

Information Resources

Technical Paper Title

Authors

Source

Year

A

Additional Information

Novel Cements Materials for High Pressure / High Temperature Wells

Noik, Rivereau and Vernet

SPE 50589

1998

HTHP

Successful Cementing of Shallow Steamflood Wells in California

Goodwin, Calvert, Root and Henderson

SPE 21777

1991

HTHP

The Effect of Microsilica on the Thermal Stability of Lightweight Cement Systems

Dillenbeck, Mueller and Orr

CIM 90-116

1990

HTHP

Lab Studies Characterization of the Initial, Transitional and Set Properties Mueller, Lacy and Go of Oilwell Cement Boncan

SPE 36475

1996

Lab Studies

Characterizing Curing Cement Slurries by Permeability, Tensile Strength and Shrinkage

Backe, Lile, Lyomov, Elevbakk and Skalle

SPE Drilling & Completion

1999

Lab Studies

Laboratory Study on Oilwell Cement and Electrical Conductivity Removing Subjective Judgement from Wettability Analysis Aids Displacement

Backe, Lyomov and Lile SPE 56539 Heathman, Wilson, IADC/SPE 59135 Cantrell and Gardner

1999 2000

Lab Studies Lab Studies

Thickening Time Test Apparatus Provides Method of Simulating Actual Shear History of Oilwell Cements

Purvis, Mueller, Dawson SPE 26576 and Bray

1993

Lab Studies

Liners An Assessment of the Performance of Liner Hanger Bearings

Archer, Jacobs and Rabia

SPE 22572

1991

Liners

An Expandable Slotted Tubing, Fiber Cement Wellbore Lining System

Setwart, Gill, Lohbeck and Baaijens

SPE Drilling & Completion

1997

Liners

Distributed Load Liner Hanger and Method of Use Thereof Innovative Way to Cement a Liner Utilizing a New Inner String Cementing Process

Garcia US Patent 4,010,804 Fuller, Littler and Pollock SPE 39349

1977 1998

Liners Liners

Productive Innovations for Cementing Liners in Deep Wells Rainbow Lake Liner Setting and Cementing Practices Rotary Liner Drilling for Depleted Reservoirs

Valles and Gonzalez SPE 69621 Teichrob and Saponja CADE/CAODC 93-604 Sinor, Tyberoe, Eide and World Oil Wenande

2001 1993 1998

Liners Liners Liners

Rotating Liner Hanger Development and Cement Improvement

Garcia

1986

Liners

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 13

Information Resources

Technical Paper Title Rotating Liner Hanger Helps Solve Cementing Problems

Authors Garcia

Rotating Liners During Cementing in the Grand Isle and West Landrum, Porter and Delta Areas, Louisiana Turner The Leaking Liner Top

Agnew and Klein

Source

Year

A

Additional Information

Petroleum Engineer International SPE 11420

1985

Liners

1985

Liners

SPE 12614

1984

Liners

Lost Circulation Cement Surface Casing after Drilling Without Returns Design of Special Cement Systems for Areas with Low Fracture Gradients

Long and Long Wieland, Calvert and Spangle

World Oil SPE 2556

1999 1969

Lost Circulation Lost Circulation

Light Cements Take Durability Test Lost Circulation Control: Evolving Techniques and Strategies to Reduce Downhole Mud Losses

Lyle Bruton, Ivan and Heinz

Hart's E&P SPE/IADC 67735

2001 2001

Lost Circulation Lost Circulation

New Solutions for Subsalt Well Lost Circulation and Primary Cementing

Sweatman, Faul and Ballew

SPE 56499

1999

Lost Circulation

New Solutions to Remedy Lost Circulation, Crossflows and Underground Blowouts

Sweatman, Kessler and SPE/IADC 37671 Hillier

1997

Lost Circulation

Primary Cementing Across Massive Lost Circulation Zones

Turki and Mankay

SPE 11490

1983

Lost Circulation

IADC/SPE 19937

1990

Lost Circulation

Unique Crosslinking Pill in Tandem with Fracture Prediction Model Caughron, Renfrow, IADC/SPE 74518 Cures Circulation Losses in Deepwater Gulf of Mexico Bruton, Ivan, Broussard, Bratton and Standifird

2002

Lost Circulation

Unique Ultra Light weight Cement Slurry Compositions for Use in Tanner and Harms Unique Well Conditions, Laboratory Evaluation and Field Performance

1983

Lost Circulation

1998

Mechanical Properties

1997

Mechanical Properties

Successful Squeezing of Shallow and Low - Pressure Formations Grant, White, Smith and Miller

SPE 11486

Mechanical Properties A Soil Mechanics Approach to Predict Cement Sheath Behavior

Thicerelin, Baumgarte and Guillot

Cement Design Based on Cement Mechanical Response

Thicerlin, Dargaud, Baret SPE 38598 and Rodriguez

SPE/ISRM 47375

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 14

Information Resources

Technical Paper Title

Authors

Source

Year

A

Additional Information

Cement Design Using a Computer Model to Predict Zonal Isolation

Rae, diLullo and Aboud

SPE/GSTT WC06

2000

Mechanical Properties

Cements for Long Term Isolation - Design Optimization by Computer Modeling and Prediction

diLullo and Rae

SPE 62745

2000

Mechanical Properties

Design Approach to Sealant Selection for the Life of the Well Bosma, Ravi, van Driel and Schreppers

SPE 56536

1999

Mechanical Properties

Oil Well Cement Durability Safe and Economic Gas Wells Through Cement Design for the Life of the Well

Noik and Rivereau Ravi, Bosma and Gastebled

SPE 56538 SPE 75700

1999 2002

Mechanical Properties Mechanical Properties

Variation of the Mechanical Properties For Cementing Slurries with Different Compositions

Altuna, Ipina

SPE 69616

2001

Mechanical Properties

A Proven Technique for Economic, In Place Casing Lining and Repair

King, Vloedman, Ford and Westermark

SPE 38758

1997

Mechanics

An Extraordinary Drilling Challenge in the Anadarko Basin Application of Very Heavy Mud and Cement in a Wildcat

Koenig Ezzat, Jennings, AlAbdulgader and AlHammad Rogers, Bolado and Sullaway

SPE 22575 SPE 62802

1991 2000

Mechanics Mechanics

SPE 50680

1998

Mechanics

Dusseault, Bruno and Barrera Vidik

SPE Drilling & Completion JPT

2001

Mechanics

1990

Mechanics

Development of an Open Hole Sidetracking System Drilling and Production of Kuhff Gas Wells, Saudi Arabia Effect of Mixing Energy Levels During Batch Mixing of Cement Slurries

Stokley and Seale Turki Hibbert, Kellingray and Cidik

IADC/SPE 59201 SPE/IADC 21975 SPE Drilling & Completion

2000 1991 1995

Mechanics Mechanics Mechanics

Expandable Liner Hanger Provides Cost-Effective Alternative Solution

Loheofer, Martins, Brisco, Weddell, Ring and York

IADC/SPE 59151

2000

Mechanics

Mechanics

Buoyancy Assist Extends Casing Reach in Horizontal Wells Casing Shear: Causes, Cases, Cures Critical Mixing Parameters for Good Control of Cement Slurry Quality

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 15

Information Resources

Technical Paper Title

Authors

Guidelines for Selecting a Cement that will be Perforated

Crump and Sabins

Horizontal Casings/Liners can be Cemented with Success Equal to that of Vertical Ones

McPherson

Source

Year

Additional Information

Southwestern Petroleum Short Course Offshore

1989

Mechanics

2001

Mechanics

Calvert, Webster and Lafleur Improved Experimental Characterization of Cement/Rubber Zonal Bosma, Cornelissen, Isolation Methods and Schwing

SPE 23987

1992

Mechanics

SPE 64395

2000

Mechanics

The Importance of Heat of Hydration on Cement Strength Development for Deepwater Wells

SPE 62894

2000

Mechanics

Improved Cementing Operations: A Field Study

Romero and Loizzo

A

Mud Displacement A New Method of Evaluating the Filter Cake Removal Efficiency

Miranda, Leite, Lopes and Oliveira

SPE 74502

2002

Mud Displacement

A Quantitative Investigation of the Laminar-to-Turbulent Transition: Application to Effect Mud Cleaning

Brand, Peixinho and Nouar

SPE 71375

2001

Mud Displacement

All Purpose Cement-Mud Spacer An Evaluation of a Primary Cementing Technique Using Low Displacement Rates

Beirute SPE 5691 Parker, Ladd, Ross and SPE 1234 Wahl

1976 1965

Mud Displacement Mud Displacement

Cement Spacer Fluid Solids Settling Cement Spacer Fluid Solids Settling Design Rules and Associated Spacer Properties for Optimal Mud Removal in Eccentric annuli

Carney Moran and Lindstrom Couturler, Guillot, Hendriks and Callet

JPT SPE 19936 SPE 21594

1974 1990 1990

Mud Displacement Mud Displacement Mud Displacement

Field Data Demonstrate Improved Mud Removal Techniques Lead to Successful Cement Jobs

Kelessidis, Guillot, Rafferty, Borriello and Merlo Benge Schumaker, Bell, Morrison, Chan and Wydrinski

SPE 26982

1996

Mud Displacement

SPE 19864 SPE 36486

1990 1996

Mud Displacement Mud Displacement

1980

Mud Displacement

Field Study of Offshore Field Spacer Mixing Improved Primary Cement Jobs Through the Use of Unique Spacer Design Technology: Gulf of Mexico Case History Study Improving Cement Bond in the Rocky Mountain Area by the use of Spacer, Wash and Thixotropic Cement

Waremburg, Kirksey and SPE 9031 Bannister

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 16

Information Resources

Technical Paper Title

Authors

Source

Year

A

Additional Information

Investigation of Drilling Fluid Properties To Maximize Cement Displacement Efficiency

Smith and Ravi

SPE 22775

1991

Mud Displacement

Mud Displacement During Cementing State of the Art Mud Displacement in Primary Cementing Mud Displacement with Cement Slurries New Down-Hole External Casing Mud Removal Technology Improves Primary Cement Results

Sauer Zuiderwijk Clark and Carter Dillenbeck and Simpson

SPE 14197 SPE 4830 JPT SPE 53943

1987 1974 1973 1999

Mud Displacement Mud Displacement Mud Displacement Mud Displacement

Primary Cementing: The Mud Displacement Process Setting Rheological Targets for Chemical Solutions in Mud Removal and Cement Slurry Design

Haut and Crook Frigaard, Allouche and Gabard-Cuoq

SPE 8253 SPE 64998

1979 2001

Mud Displacement Mud Displacement

Setting Rheological Targets for Chemical Solutions in Mud Removal and Cement Slurry Design

Friggard, Allouche and Gabard-Cuoq

SPE 64998

2001

Mud Displacement

Thickness Optimization of Drilling Fluid Filter Cakes for Cement Slurry Filtrate Control and Long-Term Zonal Isolation Use of Water Base Spacer with Thixotropic Cement Systems Improves Cement Jobs

Griffith and Osisanya

SPE 29473

1995

Mud Displacement

Crinklemeyer, Putney and Sharpe

SPE 6367

1976

Mud Displacement

Viscous Fluid Mud Displacement Technique Water Base Spacer Increases Success Ratio of Cement Jobs in Illinois Basin

Ritter and McDaniel Griffin and Crowe

SPE 1772 SPE 6489

1967 1977

Mud Displacement Mud Displacement

Other An Investigation of Factors Contributing to the Deposition of Cement Sheaths in Casing Under Highly Deviated Well Conditions

Sabins, Smith, Broussard, Talbot and Olaussen

IADC/SPE 19934

1990

Other

Case Histories and Laboratory Studies of Cement Sheath Deposition Inside Casing Strings

Griffith and Osisanya

SPE 29476

1995

Other

Plug Issues and Techniques of Plugging and Abandonment of Oil and Gas Wells

Calvert and Smith

SPE 28349

1994

Plug

Novel Technique for Open Hole Abandonment Saves Rig Time A Case History

Chong, Butterfield and Conwell

SPE 64481

2000

Plug

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 17

Information Resources

Technical Paper Title Optimization of Balanced Plug Cementing

Plug Cementing: Horizontal to Vertical Conditions

Authors Harestad, Herigstad, Torsvoll, Nodland and Saasen Calvert, Heathman and Griffith

Source

Year

A

Additional Information

SPE Drilling & Completion

1997

Plug

SPE 30514

1995

Plug

Quality Evaluating Cement Quality in Canada Integrated Controls Ease Precision Cementing Modifying Set Cement Performance for Improving Cement Job Quality

Edgson and Mehta Padgett and Brown Shi, Liu and Gao

CIM 83-34-20 Drilling Contractor SPE 29924

1983 1999 1995

Quality Quality Quality

Obtaining and Verifying Quality Cement Blends Real Time Monitoring and Performance Control of Primary Cementing Operations as a Way to Total Quality Management (TQM)

Kunze Spoerker

SPE 15576 SPE 28310

1986 1994

Quality Quality

Quality and Foam Real Time Monitoring Provides Insight to Flow Dynamics During Foam Cementing

Purvis and Smith

SPE 24570

1992

Quality and Foam

Real Time Quality Control of Foamed Cement Jobs: A Case Study

Thayer, Ford, Holencamp and Pferdehirt

SPE 26575

1993

Quality and Foam

Application of a New Model to Analyze Leak-Off Tests

Altun, Langlinais and Bourgoyne

SPE 72061

1999

Shoe Tests

New Treatments Increase LOT/FIT Pressures New Treatments Substantially Increase LOT/FIT Pressures to Solve Deep HTHP Drilling Challenges

Bybee Webb, Anderson, Sweatman and Vargo

JPT SPE 91390

2002 2001

Shoe Tests Shoe Tests

Obtaining Successful Shoe Tests in the Gulf of Mexico: Critical Cementing Factors

Harris, Grayson and Langlinais

SPE 71388

2001

Shoe Tests

Pressure Integrity Test Interpretation Shallow Casing Shoe Integrity Interpretation Technique

Postler Wojanowicz and Zhou

SPE/IADC 37589 SPE/IADC 67777

1997 2001

Shoe Tests Shoe Tests

Shoe Tests

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 18

Information Resources

Technical Paper Title

Authors

Source

Year

A

Additional Information

Slag Blast Furnace Slag Technology: Features, Limitations, and Practical Applications

SPE 28475

1994

Slag

Conversion of Drilling Fluids to Cements With Blast Furnace Cowan, Hale and Nahm SPE 24575 Slag: Performance Properties and Applications for Well Cementing

1992

Slag

Critical Evaluation of Blast Furnace Slag Mud Converted To Cement

Sabins, Edwards, Maharidge and Weiss

SPE 35085

1996

Slag

Downhole Performance Evaluation of Blast Furnace Slag-Based Cements: Onshore and Offshore Field Applications

Leimkuhler, Rainbow, Warren, Javanmardi, Ladner and Smith

SPE 28474

1994

Slag

Drilling Fluid Conversion: Selection and Use of Portland or BlastFurnace-Slag Cement

Schlemmer, Branam and SPE 26324 Valenziano

1994

Slag

Evaluation of Blast Furnace Slag Slurries for Oilfield Application

Benge and Webster

SPE 27449

1994

Slag

Field Experience With Application of Blast Furnace Slag to the Drilling and Cementing Program in the Stratton Field, South Texas

Daulton, Bosworth, SPE 29472 Pumphrey, McCathy, Cantu, Clendennen and Zarsky Sweatman, Nahm, Loeb SPE 30512 and Porter

1995

Slag

1995

Slag

Investigation of Blast Furnace Slag Addition to Water-Based Drilling Fluids for Reduction of Drilling Fluid Invasion into Permeable Formations

Tare, Growcock, Takach, Miska and Davis

1998

Slag

Low Density Slag/Mud Mix Slurries Applied in Changing Oilfield for Sealing Long Annuli

Wu, Sun, Yuan, Xie and SPE 50891 Han

1998

Slag

Portland Cement - Blast Furnace Slag Blends in Oilwell Cementing Applications

Mueller, DiLullo, Hibbler SPE 30513 and Kelly

1995

Slag

Slag Cementing Versus Conventional Cementing: Comparative Bond Results

Silva, Miranda, SPE 39005 D'Almeisa, Campos and Bezerra

1997

Slag

First High-Temperature Applications of Anti-Gas Migration Slag Cement and Settable Oil-Mud Removal Spacers in Deep South Texas Gas Wells

Mueller and Dickerson

IADC/SPE 47800

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 19

Information Resources

Technical Paper Title

Authors

Source

Year

A

Additional Information

Slag MTC Techniques Solve Cementing Problems in Complex Wells

Song, Wang and Ma

SPE 64758

2000

Slag

The Use of Blast Furnace Slag in North Sea Cementing Applications

Sadden, Salmelid, Blomberg, Young and Justnes

SPE 28821

1994

Slag

Acid-Soluble Magnesia Cement: New Applications in Completion and Workover Operations

Sweatman and Scoggins SPE 18031

1988

Specialty Cements

1992

Stress Failure

1999

Stress Failure

Specialty Cements

Stress Failure Cement Sheath Stress Failure Field-Scale and Wellbore Modeling of Compaction Induced Casing Failures

Goodwin and Crook

SPE Drilling Engineering Hilbert, Gwinn, Moroney SPE Drilling & and Deitrick Completion

SPE 20453, 1990

Stresses Burst-Induced Stresses in Cemented Wellbores

Fleckenstein, Eustes and Miller Evaluation of Collapse Strength of Cemented Pipe in Pipe Casing Marx and El-Sayed Strings

SPE Drilling & Completion SPE/IADC 13432

2001

Stresses

1985

Stresses

Laboratory Tests on Collapse Resistance of Cemented Casing

SPE 4088

1972

Stresses

Evans and Harriman

Temperature A Cementing Temperature Simulator to Improve Field Practice

Guillot, Boisnault and Hejeux

SPE/IADC 25696

1993

Temperature

A Circulating and Shut In Well - Temperature Profile Simulator

Beirute

JPT

1991

Temperature

A Joint Industry Project to Assess Circulating Temperatures in Deepwater Wells

Ward, Granberry, SPE 71364 Campos, Rausis, Sledz, Weber, Guillot, Nazri and Romero Lewis and Rose JPT Bittleston SPE 20448

2001

Temperature

1990 1990

Temperature Temperature

A Theory Relating High Temperature and Overpressures A Two - Dimensional Simulator to Predict Circulating Temperatures During Cementing Operations

Also SPE 17591, 1988

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 20

Information Resources

Technical Paper Title

Authors

Source

Year

Additional Information

Cementing Temperatures for Deep-Well Production Liners

Wooley, Gissani, Galante and Wedelich

SPE 13046

1984

Temperature

Determination of Design Temperature for Cement Slurries Determination of Temperatures for Cementing in Wells Drilled in Deep Water

Zacarias Calvert and Griffin

SPE 23714 IADC/SPE 39315

1992 1998

Temperature Temperature

Determining Accurate Bottomhole Circulating Temperature for Optimum Cement Slurry Design

Kabinoff, Ekstrand, Schultz, Tilghman and Fuller Cloud

SPE 24048

1992

Temperature

Oil & Gas Journal

1992

Temperature

ARCO Engineering Report SPE/IADC 21973

1970

Temperature

1991

Temperature

Downhole Temperature Tool Accurately Measures Well Bore Profile Earth Temperatures

Bell

Field Studies of Circulating Temperatures Under Cementing Conditions

Davies, Gunningham, Bittleston, Guillot and Swanson

Key Factors that Affect Cementing Temperatures

Wedelich, Goodman and SPE/IADC 16133 Galate

1987

Temperature

Method Corrects API Bottom Hole Circulating Temperature Correlations

Kurasov

Oil & Gas Journal

2002

Temperature

New Correlations Improve Temperature Predictions for Cementing and Squeezing

Cowan and Sabins

Oil & Gas Journal

1995

Temperature

Prediction of Downhole Temperatures Can Be Key for Optimal Wellbore Design

Mitchell and Wedelich

SPE 18900

1989

Temperature

Temperature Data for Optimizing Cementing Operations

IADC/SPE 19939

1990

Temperature

Temperature Data from Cement Interval Extremities Give Reduced WOC Time

Tighman, Benge and George Sikes, Stehle and Venditto

SPE 16210

1987

Temperature

Temperature Field Measurements and Computer Program Predictions Under Cementing Operations Conditions

Merio, Maglione, Guillot SPE 28822 and Bodin

1994

Temperature

Temperature Prediction for Deepwater Wells: A Field Validated Methodology

Romero and Touboul

1998

Temperature

SPE 49056

A

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 21

Information Resources

Technical Paper Title

Authors

Source

Year

A

Additional Information

Water Flow Cementing the Conductor Casing Annulus in an Over Pressured Water Formation

Griffith and Faul

OTC 8304

1997

Water Flow

Combating Shallow Water Flows in Deepwater Wells Controlling Shallow Water Flows in Deepwater Drilling Cost Analysis of SWF Preventative, Remedial Measures in Deepwater Drilling

Flatern Holm Alberty

Offshore Offshore Offshore

1997 1998 2000

Water Flow Water Flow Water Flow

DeepStar's Evaluation of Shallow Waster Flow Problems in the Gulf of Mexico

Nations,& Medley

OTC 8525

1997

Water Flow

Drilling Through Deepwater Shallow Water Flow Zones at Ursa

Eaton

SPE/IADC 52780

1999

Water Flow

Foamed Cement for Shallow Water Flows

Reddy, Griffith, Faul, Fitzgerald and Waugh

Offshore

1998

Water Flow

Guidelines for Cementing Deepwater Conductor Strings How One of the Biggest Fields in the US Gulf Almost Got Away

Griffith Furlow

Offshore Offshore

1995 1999

Water Flow Water Flow

Identification of "Flowing Water Sand" Drilling Hazards in the Deepwater Gulf of Mexico

OTC 7971

1996

Water Flow

Industry Zeroes in on Shallow Water Flow Problems/Solutions

Byrd, Schneider, Reynolds, Alberty and Hafle Snyder

Deepwater Technology

1997

Water Flow

Mechanisms of Shallow Waterflows and Drilling Practices for Intervention

Alberty, Hafle, Mingle and Byrd

SPE Drilling & Completion

1999

Water Flow

Mud Management, Special Slurries Improve Deepwater Cementing Operations

Griffith and Faul

Oil & Gas Journal

1997

Water Flow

Panel Urges More SWF Detection, Pre Drill Planning Furlow Redefining the Static Gel Strength Requirements for Cements Mueller Employed in SWF Mitigation

Offshore OTC 14282

1999 2002

Water Flow Water Flow

Seismic Interpretation, Identification of Shallow Water Flow Potential

McConnell and Campbell

Offshore

2000

Water Flow

Shallow Water Flow Database

Energy Research Clearing House

1999

Water Flow

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 22

Information Resources

Technical Paper Title

Authors

Shallow Water Flow Detection Best Method of Intervention Shallow Water Flow Forum Shallow Water Flow Planning and Operations: Titan #1 Exploration Well, Deepwater Gulf of Mexico

Kashikar Shell Schuberth and Walker

Shallow Water Flow Technology Update Shallow Water Flows: A Solved or a Problem Emerging Shallow Water Flows: A Solved or an Emerging Problem Shallow Water Flows: How They Develop; What to do About Them

Source Offshore

Year

A

Additional Information

SPE/IADC 52781

2000 1994 1999

Water Flow Water Flow Water Flow

Medley Alberty Alberty Furlow

OTC 8731 JPT OTC 11971 Offshore

1998 2001 2000 1998

Water Flow Water Flow Water Flow Water Flow

Successful Cementing in Areas Prone to Shallow Saltwater Flows in Deep Water Gulf of Mexico

Stiles

OTC 8305

1997

Water Flow

SWF Cement Jobs Only as Good as Well Design Understanding, Innovations Continue in Shallow Water Flows Ursa Wells Extreme Example of Shallow Flow Difficulties

Furlow Furlow Furlow

Offshore Offshore Offshore

1998 1998 1998

Water Flow Water Flow Water Flow

Bold denotes a significant information resource.

March 2004

Company Use Only

Appendix A - 23

Appendix

Primary Cementing Glossary of Terms Scope This Section covers the terms used for the Primary Cementing Manual.

Company Use Only

Glossary of Terms Term

B

Definition

Absolute Volume

The volume per unit mass, reciprocal of absolute density. This is the volume of a material with no air.

American Petroleum Institute (API)

Group of industry technical specialists who work to develop a standard set of test procedures. The API will also set specifications in the form of chemical and performance requirements for materials and systems.

American Society of Testing and Materials (ASTM)

A group of industry technical specialists that work to develop standard testing procedures for the construction industry.

Annular Gap

The distance from the outer pipe to the inner surface of either the formation or the previous casing string.

API Recommended Practice

A set of test procedures developed to give a starting point for performance testing. The recommended practice is not a specification, and changes to the procedures to match field conditions are encouraged.

API Specification

A set of chemical and physical requirements for a material or system. The test procedures in a specification can not be changed, and are not intended for use in field conditions. The specification test is a minimum requirement, and in the case of cement is applicable only to the neat cement with no additives.

Atmospheric Balance

Also called a mud balance, or atmospheric fluid density balance.

Autoclave

Pressurized curing chamber for cement. Run at test temperature and 3,000 psi and used to cure cement samples.

Automatic Density Control (ADC)

A field mixing system that utilized computer control to help maintain cement density and slurry rate.

Bearden Units of Consistency (Bc)

A measure of cement "viscosity" on a consistometer. The value is related to the torque placed on a consistometer paddle by a cement slurry.

Blow Dry

When nitrogen gas blows out of a fluid loss test sample. No additional filtrate is obtained from the sample.

Bottomhole Circulating Temperature (BHCT)

The temperature in a well with a fluid that is being circulated. The BHCT can vary with pump rate, velocity, injection temperature, etc.

March 2004

Company Use Only

Appendix B - 1

Glossary of Terms Term

B

Definition

Bottomhole Static Temperature (BHST)

The undisturbed temperature in the well. The BHST at a particular depth will be constant.

Bulk Loading Factor

A factor applied to the volume of cement to account for entrained air in a bulk system.

Bulk Volume

The total volume of solids and air. The bulk volume of a sack (94 lbs) of cement is one cubic foot.

By Weight of Cement (BWOC)

Used to calculate amounts of additives to be added per sack of cement.

By Weight of Water (BWOW)

Used to calculate weights of salt, typically sodium chloride, added to a cement system.

Carbon Dioxide Gas (CO2)

The same gas found in carbonated drinks. When in the presence of water will convert Portland Cement to calcium carbonate.

Cement Class

API designation for A through H cements that meet the requirements of API Specification 10A.

Cement Type

ASTM designation for cements meeting the requirements for construction Portland Cement, ASTM C150. ASTM designates Types I - V.

Compressive Strength

The unconfined crush strength of a cement sample.

Consistometer

Device used to measure the thickening time of a cement slurry at temperature and pressure.

Cubic Foot

Volume used to express the yield of a sack of cement. A volume equal to 7.48 gallons.

Densitometer (or densiometer)

Device used to determine the density or weight of a slurry on location as it is being mixed.

Diesel Oil Bentonite, 2 Cement (DOB2C)

A lost circulation formulation and technique for dealing with severe lost circulation problems in wells drilled with water-based mud systems. The system consists of one sack of bentonite blended with two sacks of cement in a diesel or oil carrying fluid.

Dynamic

Test being performed where the cement is stirred throughout the test. (i.e., thickening time, rheology - see static).

March 2004

Company Use Only

Appendix B - 2

Glossary of Terms Term

B

Definition

Equivalent Circulating Density (EDC)

The pressure at the bottom of the well, expressed as a mud weight, that takes into account the hydrostatic pressure of the fluid column plus the frictional pressures in the annulus.

Extender

Material that either takes up excess water, or has a very low specific gravity used to increase the yield of a sack of cement and allow mixing at a lower density without excessive free water development.

Filtrate

The fluid forced out of a cement sample in a fluid loss test. The filtrate will contain only water and soluble additives, but no cement particles.

Float Collar

A mechanical check valve placed in the casing string to prevent back flow of fluids. The float collar is placed between two joints of casing.

Float Shoe

A mechanical check valve placed in the casing string to prevent back flow of fluids. The float shoe is placed at the bottom of the casing string.

Flyash

Cementitious material obtained as a byproduct of burning coal. Used as an extender for cement. Also called (incorrectly) pozzolan.

Free Water

Fluid that has separated from cement when left quiescent for a period of two hours, and is normally expressed as a percentage.

Gas Invasion

Formation gas entering the matrix of the cement, but that does not move up the wellbore. Gas invasion does not usually result in well problems.

Gas Migration

The flow of gas in an annulus following a cementing operation. This can be at the interface of the cement and pipe, cement and wellbore, or rarely, through the matrix of the cement. It can also be a result of a free water channel at the top of the wellbore.

Gas Tightness

The ability of a cement slurry to prevent gas migration. This does not necessarily include prevention of gas invasion.

Gel strength

A time dependant behavior of cement, that is a measure of the initial resistance to flow, measured in pounds per 100 square feet.

March 2004

Company Use Only

Appendix B - 3

Glossary of Terms Term

B

Definition

Heat-up Rate

The rate of temperature increase from room temperature to test temperature on a thickening time test. The heat up rate is determined from casing volume divided by anticipated pump rates.

High Temperature High Pressure (HTHP)

Term applied to particular wells or projects that have temperatures and pressures exceeding some predetermined number. There is no standard point above which a well is deemed HTHP. It will vary with operator.

Hydrogen Sulfide (H2S)

A poisonous gas that forms an acidic solution when dissolved in water. Normally it is not a problem for cementing, as H2S will not react with Portland Cement in a dry environment.

International Standards Organization (ISO)

Governing body for international standardization of manufactured products. The ISO manages standards and quality programs for those products, and sets requirements for manufacturer certification.

Job Time

Job time is the amount of time required to mix and pump all of the cement, plus the time to displace the cement into the well. Estimation of job time requires assuming a particular mixing rate as well as a displacement rate.

Landing Collar

A plate placed in the casing string that allows plugs to land. Unlike a float collar, there are no valves associated with a landing collar. Its purpose is only to provide a landing point for plugs, darts or balls.

Latex

Liquid cement additive that has been shown to be highly effective in preventing gas migration. Normally sold as a Styrene Butadiene Latex.

LCM

Lost circulation material

Lead Cement Slurry

The first slurry pumped in a well that typically is lighter weight and has a longer thickening time.

Liner

Any string of casing whose top is below the top of the well.

Liner Overlap

The distance from the top of the liner down to the previously set casing string. This area will have a pipe x pipe annulus.

March 2004

Company Use Only

Appendix B - 4

Glossary of Terms Term

B

Definition

Liner Top Packer

A device that is set at the top of a liner following a cement job to provide an additional mechanical seal in the wellbore. A liner top packer can be either integral to the liner, thus is set immediately following the cement job, or a two trip system where the packer is run and set at a later date.

Liquid Additive System (LAS)

Also called a liquid additive proportioner (LAP).

Neat Cement

Cement that contains no additives.

Percent Mix Water

The amount of water, expressed as a percentage of the weight of cement.

Performance Testing

Physical testing to determine how a material performs under specific test conditions.

Point of Departure

Point on a thickening time curve where the viscosity leaves the baseline value. Important when determining the thickening time of slurries extended with silicates.

Porosity

1. A measure of the void space in formation rock. 2. Within Schlumberger, it is a calculated ratio of the amount of solids to liquids in a slurry.

Portland Cement

The most common form of cement; also called hydraulic cement.

Pozzolan

A naturally occurring cementitious material used as an extender for cement. Originally a volcanic ash. Often confused with flyash (byproduct of burning coal).

Pressure Up Rate

On a thickening time test, the rate at which the slurry is taken from atmospheric pressure to the test pressure.

Pressurized balance

Fluid density balance that is capable of being pressurized with a hand pump to approximately 100 psi. Used to measure fluid densities.

Pumpable

Capable of being pumped in a well without excessive pressures.

Recirculating cement mixer (RCM)

A mixing system that recirculates a portion of the mixed slurry through the mixing tank to improve density control.

March 2004

Company Use Only

Appendix B - 5

Glossary of Terms Term

B

Definition

Recommended Practice

A set of testing guidelines designed to give standard testing methodologies. Recommended Practices should be modified to meet individual well requirements.

Rheology

The study of fluid flow. For cement slurries, the rheology is normally measured on a rotating sleeve viscometer.

Rheometer

A device used to measure the viscosity of a fluid. With drilling fluids and cements, a rotating sleeve rheometer is normally used.

Scratcher

A mechanical device placed on the casing to aid in mud removal. A scratcher is normally made of stiff wire much like a metal brush, but with only a few (8 - 10) bristles.

Silicate extenders

Materials that tie up water by a reaction with calcium and silicate to form a gel.

Slurry

A dispersion of solids in a liquid. The solids in a slurry do not dissolve in the fluid phase.

Slurry Fraction Monitor (SFM)

A device used by Schlumberger to calculate the amount of water and cement being mixed on location. It is used in place of a densitometer when mixing very lightweight slurries that contain beads or hollow spheres.

Sonic Strength

The strength of a cement slurry when measured on a UCA and calculated by a measurement of the sonic travel time.

Spacer

A viscous fluid, capable of being weighted, that is used to separate the mud from the cement, and aid in mud removal.

Specification

A set of test protocols that must be used precisely to qualify a material to a particular set of requirements. For cements, the API Spec 10A is the testing protocol that allows a cement to be designated as an API cement. The specification does not apply to any cement that contains an additive, and is only applicable to the manufacture of cement.

Squeeze

The process of forcing a cement slurry under pressure into a void.

Standard Cubic Foot (SCF)

The volume of one mole of gas at standard temperature and pressure (20°C and one atmosphere of pressure).

March 2004

Company Use Only

Appendix B - 6

Glossary of Terms Term

B

Definition

Static

Sitting still without movement. Many cement tests are performed in a static condition. (i.e., fluid loss, free water, strength - see dynamic).

Strength Retrogression

Chemical reactions that occur in Portland Cement at temperatures above 250°F (119°C) if the system has not been stabilized with added silica. Characterized by a loss of strength and an increase in permeability.

Tail Cement

Generally, higher-density slurry pumped at the end of a cement job. The tail slurry has less thickening time and is designed to gain strength faster.

Thickening Time

The time for a cement to become unpumpable when measured at temperature and pressure on a consistometer. The thickening time is measured from the time temperature and pressure is applied to a sample until the consistency reaches a predetermined value (typically 70 or 100 Bc).

Thixotropic

Literally "change to touch." A specialty system that will rapidly gel when not under shear, but will return to a very thin fluid when sheared.

Time to Bottom

The amount to time required to displace the first sack of cement to the bottom of the casing string. The time to bottom is calculated by taking the total displacement volume and dividing by the anticipated pump rate.

TOL

Top of Liner

Transition Time

The amount of time for a cement slurry to go from 100 to 500 pounds per 100 square feet gel strength when measured at a shear rate of less than 0.005 sec-1. The transition time can not be measured on a consistometer or conventional rheometer.

Tricalcium Aluminate (C3A)

One of the fastest reacting materials in cement. The material is integral for thixotropic behavior, sulfate resistance, and early set properties.

Ultrasonic Cement Analyzer (UCA)

A device used to determine the sonic strength of cement. This is a nondestructive device that cures cement at temperature and pressure, constantly measures the sonic travel time of a signal sent through the sample, and displays a calculated strength.

March 2004

Company Use Only

Appendix B - 7

Glossary of Terms Term

B

Definition

Waiting on cement time (WOC)

The time required for cement to gain adequate strength to continue operations.

Wash

A thin fluid, usually water or base oil that has additional surfactants to help with mud removal.

Yield

The volume of cement slurry obtained from a given amount of dry cement, typically one sack or one tonne. Yield is given in units of cubic foot per sack or cubic meters per tonne of cement.

Zero Gel Time

The time required for a cement slurry to get to 100 pounds per 100 square feet gel strength when measured on the same device as the transition time. This is the starting point for the transition time measurement.

March 2004

Company Use Only

Appendix B - 8

Appendix

Primary Cementing Subject Index

Company Use Only

Subject Index

C.

C

SUBJECT INDEX

acid solubility, see Section 6.5 additives – cross reference, see Section 2.3 annular gap, see Sections 3.9.3, 5.13, 7.4.1, 9.4.5.2, 11.4.1, 14.4.1.5 annual volume, see Section 10.4.1 API cement classification, see Sections 1.6, 1.9 testing, see Sections 3.3, 4.3.1 water content, see Sections 1.7.1, 5.4, 10.3.1 batch mixing, see Sections 3.5.3, 4.3.2, 14.3.2.1 Bearden Units of Consistency (Bc), see Sections 2.9.3, 3.5, 4.3.2 blending, see Sections 2.20, 14.3.1 bulk cement, see Section 14.3.1 bulk equipment, see Sections 13.5.1, 14.3.1 bulk factors, see Section 14.3.1.3 bulk volume, see Section 10.3.3

calcium chloride, see Section 2.4.1 CAST V Log, see Section 18.6.4 Cement Bond Log (CBL), see Sections 18.3, 18.4 quality control, see Sections 18.8, 18.10.2.1 centralizers, see Sections 9.4.2, 11.4.7, 14.4.1, 16.2.2.2, 17.3 CO2 / H2S, see Sections 1.10, 6.6, 6.7, 13.6 compressive strength (see also strength), see Sections 3.6, 4.3.3

data recording, see Sections 13.3, 13.5, 16.2.7, 17.12 density API, see Sections 1.7.1, 5.4, 10.3.1, 13.3, 14.3.4, 17.9 calculation, see Section 10.3.6 control, see Sections 2.19.2, 3.11, 9.3.3

March 2004

Company Use Only

Section C - 2

Subject Index

C

excess, see Sections 10.4.1, 15.3.2, 17.10

fibers, see Sections 2.13, 2.18, 8.6.1 float equipment, see Sections 14.4.2, 17.5 fluid loss, see Sections 2.8, 3.9,4.3.5, 5.5.1 recommended ranges, see Sections 3.9.3, 5.13, 7.4.1, 11.5 foamed cement, see Sections 2.9.7, 2.18, 6.3, 13.4 free water, see Sections 2.11, 3.8, 5.14 ranges, see Sections 3.8.3, 5.14

gas migration, see Sections 2.12, 2.17, 3.13, 5.5.4, 7, 15.2.2

heat up rate, see Sections 3.5.4, 4.3.2 hole size (see annular gap)

job time calculating, see Sections 10.4, 10.4.6, 16.2.4.3 safety factors, see Section 10.4.8

latex, see Sections 2.12, 2.17, 6.4.5, 7.4.1, 11.6.6 liners, see Sections 3.18, 4.4.1, 4.4.3, 11 liner top packers, see Sections 4.4.2, 11.5, 11.6.6 liner overlap, see Section 11.4.8 liquid additives, see Sections 2.19, 13.3.1, 16.2.1.3 liquid additive pumps, see Section 13.3.1 lost circulation, see Sections 2.13, 5.5.3, 8, 12.2.4, 12.4.4, 15.2.2

metering of liquid additives, see Sections 2.19.1, 6.3.8

Non-API cement, see Section 1.10

March 2004

Company Use Only

Section C - 3

Subject Index

C

permafrost, see Section 6.9 permeability, see Section 2.14 pipe movement, see Sections 9.4.1, 11.4.3, 12.6.8, 14.4.1.8, 17.2 point of departure, see Sections 2.9.3, 3.5.3 Pozzolan, see Sections 2.9.4, 10.3.7 premium cement, see Section 1.8 pressure to lift casing, see Section 10.5.1 pump equipment, see Sections 13.3, 14.3.2, 14.3.3 pump rates, see Sections 10.4.7, 11.6.5 displacement, see Sections 4.3.2, 9.4.3 mixing, see Section 9.4.3

sampling cement, see Section 4.3.1 Schlumberger CemNet, see Sections 2.13, 8.6.1 CRETE cements, see Sections 2.12, 2.20, 6.4, 14.3.1.1 Porosity, see Section 6.4.3.2 Segmented Bond Tool (SBT), see Sections 18.6.1, 18.10.2.2 settling, see Section 3.10 silica, see Sections 2.10.3, 2.14, 5.3, 6.8.1, 10.3.6.3, 12.4.2.1 silicate extenders, see Sections 2.4.4, 2.9.3, 3.5.3, 4.3.2 sodium chloride (NaCl), see Sections 2.4.2, 2.6, 2.8.4, 2.16, 5.5.2, 10.3.7.2 spacers, see Sections 5.4, 9.3.2, 9.3.3, 11.4.2, 12.7.1, 15.4.1, 16.2.1.4, 17.8 compatibility, see Section 3.16 wettability, see Section 3.14 stage cementing, see Section 14.4.4 standard cement, see Section 1.8 strength, see Sections 1.7.2, 3.6, 3.7, 3.18, 4.3.3, 4.4.3, 5.12, 6.8, 6.4.3.1 amount required, see Sections 5.12, 12.2.2

March 2004

Company Use Only

Section C - 4

Subject Index

C

temperature determination, see Sections 5.3, 11.4.5 mix water, see Section 2.5 retarders, see Sections 2.6, 2.6.3 use in design, see Sections 2.6.3, 2.14, 6.8 use in testing, see Sections 3.7.1, 3.8, 4.3.3, 11.4.6 stop collars, see Section 14.4.1

thixotropic cement, see Section 8.7.1 transit time, see Section 18.4.3.1 transition time, see Section 3.13

UCA (Ultrasonic Cement Analyzer), see Section 3.6.2 ultra lightweight additives, see Section 2.9.6 ultrasonic logs, see Section 18.6.2 interpretation, see Section 18.7 USIT, see Section 18.6.3

wiper plugs, 14.3.8.2, 16.2.3, 17.8

March 2004

Company Use Only

Section C - 5