Module 10_remedial Cementing.pdf

PE-103

Applied Completions and Workover Remedial Cementing Module 10

Course Contents 1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

Introduction: Definitions and Objectives Reservoir and Mechanical Considerations in Well Completion Design Well Completion Design: Types and Applications Tubing Design Subsurface Production and Control Equipment Completion and Workover Fluids Perforating Sand Control Stimulation Remedial Cementing

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Module 10: Remedial Cementing 10.1 Typical Applications 10.2 Effect of Wellbore Parameters on Cement 10.3 Slurry Design 10.4 Remedial Cementing Techniques

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Remedial Cementing 

Definition:  

A "remedial cementing" operation is any cementing operation performed on the well after the primary cementing (casing cementing) operation It involves placement of cement in a specific location in a well to control the movement of fluids into or around the wellbore

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10.1 Typical Applications Channel Repair  Control of GOR and WOR  Re-Completion  Casing Leak Repair  Augmentation of Top of Cement  Setting Liners  Abandonment 

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10.1 Typical Applications 1. Channel Repair  

Channels may be in the form of voids or damaged permeable cement Reasons for channel formation: • Mud bypassed during primary cementing • Contaminated or cracked cement • Natural or induced

formation fractures

• Migration of gas or liquid

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into the cement during the initial setting stage

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10.1 Typical Applications 1. Channel Repair

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10.1 Typical Applications 2. Control of GOR & WOR   

Sealing perforations producing the gas or water can stop undesired increase in GOR or WOR due to encroachment Selective sealing of perforations Sealing entire interval and reperforating desired zone only

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10.1 Typical Applications 2. Control of GOR & WOR

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10.1 Typical Applications 3. Recompletion

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10.1 Typical Applications 3. Recompletion (cont.)

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10.1 Typical Applications 4. Casing Leak Repair 

Depending on the type of leak, its location in the well, future operations and cost, casing leaks may be repaired using: • Cementing • Casing replacement • Metal liner and patches • Epoxy

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10.1 Typical Applications 4. Casing Leak Repair 

Leaks due to corrosion: • Expandable, corrugated metal insert liners may be used if wellbore

clearance permits • Remedial cementing if full casing ID needed • In severe cases, replacement of CSG section



Leaks from previously squeezed perforations: • Remedial cementing • In severe cases Epoxy, squeezed into cracks in original cement and allowed

to harden

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10.1 Typical Applications 5. Augmentation of Top-of-Cement (TOC)  

To complete a zone (above original "TOC") which may have been bypassed (not recognized after completion) Cement is required to hydraulically seal the potential zone from others

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Typical Applications 5. Augmentation of Top-of-Cement (TOC)

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Typical Applications 6. Setting Liners

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Typical Applications 7. Abandonment

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10.2 Effect of Wellbore Parameters on Cement Effect of bottom hole static temperature  Effect of bottom hole circulating temperature  Effect of bottom hole pressure  Effect of formation characteristics  Effect of mix water  Effect of completion fluid in the well 

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10.2 Effect of Wellbore Parameters on Cement 1. Bottom hole static temperature (BHST)  



Rate of developing compressive strength increases with increasing BHST Long term stability at high T, compressive strength decreases with time (strength retrogression) At T>250oF, add silica flour

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10.2 Effect of Wellbore Parameters on Cement 2. Bottom hole circulating temperature (BHCT)  

Thickening time decreases as BHCT increases Fluid loss rate increases with increasing BHCT

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10.2 Effect of Wellbore Parameters on Cement 3. Bottom Hole Pressure (BHP)  

BHP affects thickening time but to a lesser degree than the effect of temperature Hydrostatic head should be < formation fracture pressure but > pressure of formation fluids

4. Formation Characteristics 

For carbonate or fractured formations, use medium or high fluid loss rate cement or thixotropic cement

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10.2 Effect of Wellbore Parameters on Cement 5. Mix Water Composition  

Pumping time & strength (sea & low salinity water accelerate thickening time) Salts affect additives behavior

6. Type of Workover Fluid  

Fresh water: no need for spacers or washes Brines must be separated from cement slurry (use a pad of 250 ft to 500ft of fresh water)

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10.3 Slurry Design 

Properties of Cement Slurry       

Thickening time Fluid loss rate Density Compressive strength Water requirement Slurry volume Yield and total sacks of cement

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Properties of Cement Slurry 1. Thickening Time 

It is the estimated job time: • Job time = Mixing time + Surface time + Pumping time + Other

   

Mixing time: Time to mix cement & water and measure density and fluid loss Surface time: Any time slurry is held on surface before pumping Pumping time: Time to pump total volume of slurry & displacing fluid (0.5 BPM to 3 BPM) Other: E.G., time to reverse our cement before squeezing, time to pull a workstring out of a plug of cement that has been pumped down the hole, an additional hour, etc.

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Salt Effect 

Effect of salt on thickening time of API class G cement

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Properties of Cement Slurry 2. Fluid loss rate (FLR)        

For neat cement, FLR = 1000 cc/30 min High FLR = 400 – 1000 cc/30 min Medium FLR = 150 – 400 cc/30 min Low FLR = < 150 cc/30 min FLR control is recommended for most jobs except for setting plugs inside CSG and squeezing off CSG leaks In sandstone formations, low FLR (100 – 150) is desirable for most jobs In carbonates & fractured formations, medium or high FLR Avoid bridging

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Effect of Fluid Loss Rate on Cement Squeeze 

45 min. squeeze using slurries with different water loss 

30 min. fluid loss rate at 100 psi 80oF

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Properties of Cement Slurry 3. Density of slurry 

Important in calculating BHP during the job • Density = Weight of all components / total volume



Normally on basis of 94 lb sack of cement

4. Compressive strength  

A compressive strength of 500 psi is required before additional operations Service company provides shut-in time

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Silica Effect 

Effect of silica concentration on the compressive strength of API class A cement cured at 320oF

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Properties of Cement Slurry 5. Water requirement  

Is the water required for all ingredients of the slurry as taken from cementing tables Amount of water required to give the slurry proper fluidity without free water breakout or solid settling

6. Slurry volume   

Service-company handbooks provide volume estimates for different geometries & dimensions For most squeeze jobs 5-20 bbl are used Determine the sacks of cement required

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Properties of Cement Slurry 7. Slurry yield & total sacks of cement

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10.4 Remedial Cementing Techniques Pump down or bullhead squeeze  Bradenhead or balanced plug technique  Packer squeeze  Circulation squeeze 

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Bullhead or Pump Down Technique

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Bullhead or Pump Down Technique 

Advantages:   

Low cost due to minimal equipment resource requirements Production equipment does not have to be removed from the well Particularly suited for 2 1/8 inch tubingless completions, which will accept only a small O.D. concentric workstring, resulting in high pumping pressures

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Bullhead or Pump Down Technique 

Disadvantages:    

At least one TBG/CSG volume of workover fluid will be displaced into formation; thus, the fluid used must be solids-free and non-damaging No means of reverse circulating, cement must be fractured into the formation if problems arise Cement may solidify in the hole and a workover rig is needed to mill out the cement, (very costly) Fracture pressure must be exceeded during placement in low injectivity wells (gas or water invasion)

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Braden-head Squeeze / Balance Plug

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Braden-head Squeeze / Balance Plug 

Procedure 1. Production equipment is removed: artificial lift devices, production TBG, packers, and production control devices 2. The workover (WO) string is run into the hole 3. WO string & surface connections are tested for leaks 4. Cement is mixed and circulated down the hole 5. Cement is displaced with the volume of fluid required to place a balanced plug

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Braden-head Squeeze / Balance Plug 

Procedure (cont.) 6. The workstring is pulled out of the unset cement 7. The top of the cement is reverse circulated to remove contaminated cement in the top part of the plug 8. Squeezing pressure is applied; final squeeze pressure may already have been achieved during reverse circulation 9. The cement is allowed to set, drilled out if necessary, and tested, then the well is recompleted; excess cement may be removed by reverse circulation before cement is allowed to set

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Braden-head Squeeze / Balance Plug 

Advantages:  



Requires special tools (circulation or squeeze packers) Permits a cement squeeze in small diameter or restricted CSG

Disadvantages:    

Production CSG is subjected to squeeze pressures, may exceed burst limits Not possible to test the CSG for leaks before operation In old CSG, leaks developing during the application of squeeze pressure may result in an ineffective cement job A special tool is required to test the tubing

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Packer Squeeze

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Packer Squeeze 

Procedure 1. The packer is run in on the end of tubing to a point 50-60 ft. above the perforations. A section of tailpipe may be connected to the bottom of the packer to protect the packer sealing elements when cleaning out the well and to minimize contamination of the cement when placing the plug. The tailpipe eliminates the necessity of lowering the packer through the perforations, which may cause damage to the rubber-sealing element 2. The end of the tailpipe is positioned above the perforations, the packer is set and the tubing casing and packer are pressure tested

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Packer Squeeze 

Procedure (cont.) 3. The packer circulated port is reopened, and cement is circulated to the bottom of the tubing without displaying workover fluid into the formation 4. Just before the slurry reaches the circulation port, the port is closed, and cement is pumped (bullhead) into the perforations 5. When the designed squeeze pressure is obtained the packer circulation port is reopened, and the excess cement remaining in the tubing is reversed out

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Packer Squeeze 

Advantages:   

The packer squeeze allows a test of the casing and tubing for leaks The production casing is protected from high pressures The cement is kept inside the tubing above the packer, thereby minimizing the possibility of sticking the tubing in the hole

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Packer Squeeze 

Disadvantages: 

  

Packer squeezes are higher cost operations due to the need for a special packer, and due to the need for a workover rig to trip the workstring in and out There is a risk of sticking the packer due to packer malfunction or collapsed casing Small diameter packers are not reliable, therefore this technique is not commonly used in tubingless wells Because of the need to manipulate the workstring and packer there is a risk of leaving junk in the well

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Circulation Squeeze

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Circulation Squeeze

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Circulation Squeeze 

Advantages  

Placement of cement in a circulation squeeze is effectively controlled The areas to receive cement, such as behind pipe channels, or the production casing annulus, can be cleaned prior to placing the cement

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Circulation Squeeze 

Low vs. high squeeze pressure    

During a low pressure squeeze, pressure is kept below the formation fracture pressure In a high pressure squeeze, the formation fracture is exceeded Low pressure squeeze techniques are preferred for most remedial cementing operations The areas into which cement is placed during a remedial job are all in the near wellbore region: the perforations or channels in the annulus

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Hesitation Squeeze Involves alternate pump-wait cycles to allow cement filter cake to form in the most permeable perforations  When pumping resumes the cement slurry will be diverted to other perforations or channels  May be useful in low fracture gradient areas, where risk of fracturing the formation is high 

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Hesitation Squeeze

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