Welcome To The Students: Presented By

WELCOME TO THE STUDENTS 7th Semester (Mining) Bogura Polytechnic Institute, Bogura.

Presented By Md. Majedur Rahman B. Sc (Hon’s), M. Sc in Geology & Mining, RU

Instructor (Tech) Mining and Mine Survey Technology Bogura Polytechnic Institute, BOGURA. 5/29/20

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Petroleum Well Design & Completion Course Code No. 69372

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Chapter-10 Understand the well completion and testing 10.1 Describe well completion methods. 10.2 State well head equipment. 10.3 Define well testing. 10.4 Describe Drill Stem Test (DST) 10.5 Describe well testing operations. 10.6 Describe high pressure and high temperature testing. 10.7 Mention benefits and limitations of well stimulation.

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10.1 Describe well completion methods. Informal definition: The high time of the well when engineer and personnel comes to decide whether to install the production casing in order to initiate the production at the surface or it should be abandoned . Technical Definition: Well completion means to prepare the well for production by installing the necessary equipments into the well in order to allow the safe and controlled flow of HCS at the surface.

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Well completion is the process of making a well ready for production (or injection) after drilling operations. This principally involves preparing the bottom of the hole to the required specifications, running in the production tubing and its associated down hole tools as well as perforating and stimulating as required. Sometimes, the process of running in and cementing the casing is also included. After a well has been drilled, should the drilling fluids be removed, the well would eventually close in upon itself. Casing ensures that this will not happen while also protecting the wellstream from outside incumbents, like water or sand

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General Procedure To understand the concept of well completion the following equipment's must be studied clearly: 1. Casing 2. Tubing 3. X-Mass tree

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1. Casing

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2. Tubing

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3. X-Mass tree

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Open hole well completion In an open hole well completion the production casing is just set above the pay zone, while the entire deepen bottom of pay zone is left uncased.

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Open hole well completion Advantage • Maximum exposure of pay zone • Less pressure drawdown during flow • No formation damage occurs due to cementing and perforation. • Less formation damage

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Open hole well completion Disadvantage • Inability to plug off water or gas zones • Inability to stimulate the separate zones within the productive zones

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Close hole well completion • For the most common type of well completion today involves the cased hole completion, in which the production casing and liner are cemented and perforated subsequently. • Select the sections of the pay zone we wish to produce • Stimulate the separate pay zone from the well • Multiple completion zones

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Liner Completion • A Liner is installed across the pay zone • It can be divided into two: Screen Liner and perforated liner Screen Liner : Casing is set above the producing zone and • an uncemented screen and liner assembly is installed • across the pay zone 5/29/20

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Perforated Liner Completion Casing is set above the producing zone and a liner assembly is installed across the pay zone and cemented in place. The liner is then perforated selectively for production.

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Perforated Casing Completion Production casing is cemented through the producing zone and pay section is selectively perforated.

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Tubingless or reduced diameter Completion Production tubing is perforated and cemented

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Single tubing completion • Simplest way of completing the well • In this method well is completed by single zone with single tubing

Multilateral completion • In this multiple branches are drilled from a single zone • •It is used to improve productivity from closely spaced target zones. 5/29/20

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Type of Flow • Casing flow: large flow rate no tubing is required, used in middle east. • Tubing and Annulus flow: large flow rate flow segregation. • Tubing flow: Used widely in Malaysia due to safety, may use one more tubing strings.

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10.2 State well head equipment.

Wellhead equipment is used to connect the tubing and casing to an oil or gas pipeline. The casing is a permanently-installed pipe for lining the well hole to provide pressure containment and prevent collapse. The wellhead is a flanged device that attaches to the casing. Components of Wellhead Equipment • Wellhead equipment includes components such as casing heads, casing spools, tubing head spools, tees, and crosses. The casing head is part of the connection between the casing and the wellhead itself. Typically, multiple pieces of wellhead equipment are integrated into a wellhead assembly called a "Christmas tree". This wellhead assembly allows tubes to be placed into the well while valves and chokes are used to control the flow of oil and/or gas at the surface. • Wellheads and wellhead equipment may be located on offshore platforms, in sub-sea locations, or onshore. Wellheads are cemented in place and, typically, kept in place; however, with exploration wells, wellhead equipment may be recovered for subsequent re-use. Wellhead equipment is designed to support the casing and tubing strings, which may also be suspended from the Christmas tree.  5/29/20

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The primary components of a wellhead system are: • • • • • • • • • •

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casing head casing spools casing hangers choke manifold packoffs (isolation) seals test plugs mudline suspension systems tubing heads tubing hangers tubing head adapter

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Functions of Wellhead A wellhead serves numerous functions, some of which are: • Provide a means of casing suspension. (Casing is the permanently installed pipe used to line the well hole for pressure containment and collapse prevention during the drilling phase). • Provides a means of tubing suspension. (Tubing is removable pipe installed in the well through which well fluids pass). • Provides a means of pressure sealing and isolation between casing at surface when many casing strings are used. • Provides pressure monitoring and pumping access to annuli between the different casing/tubing strings. • Provides a means of attaching a blowout preventer during drilling. • Provides a means of attaching a Christmas tree for production operations. • Provides a reliable means of well access. • Provides a means of attaching a well pump, 5/29/20

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10.3 Define well testing. • In the petroleum industry, a well test is the execution of a set of planned data acquisition activities. The acquired data is analyzed to broaden the knowledge and increase the understanding of the hydrocarbon properties therein and characteristics of the underground reservoir where the hydrocarbons are trapped. • A Well test is simply a period of time during which the production of the well is measured, either at the well head with portable well test equipment, or in a production facility.

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Overview of Well Test Most well tests consist of changing the rate, and observing the change in pressure caused by this change in rate. To perform a well test successfully one must be able to measure the time, the rate, the pressure, and control the rate. Well tests, if properly designed, can be used to estimate the following parameters: • Flow conductance • Skin factor • Non-Darcy coefficient (multirate tests) • Storativity • Fractured reservoir parameters • Fractured well parameters • Drainage area • Distance to faults • Drainage shape 5/29/20

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Purpose of Well Testing Exploration wells • • • • •

Fluid sampling (Primary reason) Measuring the initial pressure Estimating a minimum reservoir volume Evaluating the well permeability and skin effect Identifying heterogeneities and boundaries.

Producing wells • • • • • 5/29/20

Verifying permeability and skin effect Identifying fluid behavior Estimating the average reservoir pressure Confirming heterogeneities and boundaries Assessing hydraulic connectivity. Prepared by Md. Majedur Rahman, E-mail: [email protected]

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10.4 Describe Drill Stem Test (DST) A drill stem test (DST) is a procedure for isolating and testing the pressure, permeability and productive capacity of a geological formation during the drilling of a well. Originally, the objective of a drill stem test was to take a representative fluid sample which, in the very early days of the oil industry, was obtained by either bailing or swabbing. Following the introduction of a packer and a downhole valve, the next step was the possibility of recording accurate bottomhole reservoir pressures and temperatures. With the development of downhole tools, which operated on annulus pressure and a downhole shut-in valve with surface readout, drill stem testing has become a generally accepted safe method to meet the original objectives; to obtain a fluid sample and reservoir data. 5/29/20

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In a drill stem test, information on the following parameters can be obtained: • • • • •

Reservoir fluid type and properties Production rates and potential production problems Initial reservoir pressure Effective permeabilities Type of flow system

A drill stem test is the temporary completion of a well to gather reservoir data. The three fundamental components are a retrievable mechanically set packer, a downhole valve assembly (DST tools) and drill pipe/tubing to surface. 5/29/20

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A drill stem test is the temporary completion of a well to gather reservoir data. The three fundamental components are a retrievable mechanically set packer, a downhole valve assembly (DST tools) and drill pipe/tubing to surface.

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10.5 Describe well testing operations. Well testing procedures are carried out on all newly drilled wells to determine the characteristics of the well and the formations it passes through. Most often the main goal of the well tests is to determine the productivity potential of a new well. Well testing involves an array of measurements and multiple types of downhole instruments for gathering information on the well characteristics. Well tests are conducted to quantify well characteristics, production potential, and reservoir properties. Well tests are essential for exploration and production drilling, well maintenance, and geothermal field management. The tests ultimately help in optimal and sustainable utilization of the geothermal resource.

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Well Testing Techniques •Borehole Seismic Techniques •Single-Well And Cross-Well Seismic Imaging •Vertical Seismic Profiling •Formation Testing Techniques •Well Log Techniques •Acoustic Logs •Cement Bond Log •Cross-Dipole Acoustic Log •Caliper Log •Chemical Logging •Density Log •Gamma Log •Image Logs •Mud Logging •Neutron Log •Pressure Temperature Log 5/29/20

•Single-Well and Cross-Well Resistivity •Spontaneous Potential Well Log •Well Testing Techniques •Downhole Fluid Sampling •Earth Tidal Analysis •Flow Test •Injectivity Test •Static Temperature Survey •Stress Test •Tracer Testing •Vertical Flowmeter Test

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10.6 Describe high pressure and high temperature testing. High pressure/high temperature (HP/HT) wells are those where the undisturbed bottom hole temp at prospective reservoir depth or total depth is greater than 300°F or 150°C, and either the maximum anticipated pore pressure of any porous formation to be drilled through exceeds a hydrostatic gradient of 0.8 psi/ft, or a well requiring pressure control equipment with a rated working pressure in excess of 10000 psi. Drilling wells with these characteristics pose special challenges. A test to measure static filtration behavior of water mud or oil mud at elevated temperature, up to about 380°F [193°C] maximum (450°F [227°C] maximum if a special cell is used), usually according to the specifications of API. Although the test can simulate downhole temperature conditions, it does not simulate downhole pressure. Total pressure in a cell should not exceed 700 psi [4900 kPa], and the differential pressure across the filter medium is specified as 500 psi [3500 kPa]. Because these cells are half the size of the ambient filtration area, HPHT filtrate volumes after 30 minutes are doubled. 5/29/20

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Drilling fluid considerations Where possible, high temperature wells are drilled with oil-based fluids (OBFs) or synthetic-based fluids (SBFs), because of the thermal limitations of most water-based fluids (WBFs). Such limitations of WBFs include: • Temperature-induced gelation • High risk of CO2 contamination from the formation being drilled and/or from the degradation of organic mud additives • Increased solids sensitivity that is related to high temperatures

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HPHT or High Pressure, High Temperature is defined as those Wells with a bottom hole temperature greater than 150°C (300°F) and requiring pressure control equipment with a rated working pressure of above 69 MPa (10,000psi) (S.P.E E&P Glossary, HPHT, 2013).

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An HP/HT viscometer typically is used to monitor the temperature stability of the drilling fluid, and to evaluate its rheological properties at up to 500°F and 20,000 psia. This test is especially useful for determining whether hightemperature flocculation occurs in water-based muds. The test results can be presented graphically by plotting the change in viscosity with respect to temperature over the heating and cooling cycle, which establishes a baseline for recognizing indicators of temperature instability. There are a number of ways to minimize problems with temperature gelation, including: • Eliminating lignite and lignite derivatives from the WBF formulation • Lowering the bentonite concentration • Supplementing the high-temperature water-based system with synthetic polymers and copolymers 5/29/20

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10.7 Mention benefits and limitations of well stimulation. Well stimulation is a well intervention performed on an oil or gas well to increase production by improving the flow of hydrocarbons from the reservoir into the well bore. It may be done using a well stimulator structure or using off shore ships / drilling vessels, also known as "Well stimulation vessels"

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Any Questions

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THANKS TO ALL 5/29/20

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