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SPE 14135 Successful Primary Cementing: Fact or Fiction by R.C. Smith, Amoco Production Co. SPE Member

Copyright 1988, Society of Petroleum Engineers This paper was presented at the SPE 1986 International Meeting on Petroleum Engineering held in Beijing, China March 17-20, 1988. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write SPE. P.O. Box 833836, Richardson, Texas 75083-3836. Telex: 730989 SPE DAL.

ABSTRACT

The producing performance of a well depends in great parz on a good primary cementing job. In a high-quality cement job, all mud and gas channels have been permanently prevented and there is a complete hydraulic seal between the casing and the formation throughout the zones of interest. If the cementing operation is not carried out correctly, the well will never reach optimum performance. A successful primary cementing operation requires a positive attitude and commitment, proper supervision and quality control, detailed planning, and careful preparation. This paper discusses the application and interaction of these aspects of the job, as well as other factors that contribute to successful cementing. Examples of unique quality control procedures are included, The actual mechanics of performing a cementing job are not covered; they can be obtained from references included in the paper. DISCUSSION A recent editorial contained this comment: "There is no excuse for a bad cement job but there is no such thing as a good cement job." In my opinion, only the first half of this statement is true. My feeling is that successful primary cementing can be a reality.2 It does not come cheap or without effort, but it can be achieved.

The Cementable Wellbore The planning of the cement job begins long before the well is drilled. Uppermost in all planning and drilling decisions is the the objective of obtaining complete zonal isolation in the wellbore (see Fig. 1). A hydraulic seal must be obtained between the cement and the casing and between the cement and the formation; at the same time, mud and gas channels within the cement sheath must be eliminated. If these goals are to be accomplished, the wellbore must be designed and drilled to be cementable. The ideal cementable wellbore (see Fig. 2) is one that is (1) 3 in. (7.62 cm) larger than the outside diameter of the casing - the absolute minimum is 1-1/2 in. (3.81 cm) larger2'5, (2) as nearly gauge as possible (without washouts), (3) as straight as possible (without severe dog-legs), and (4) stabilized and properly conditioned (without sloughing or flowing or losing circulation). The drillers must keep these requirements foremost in all plans. It is imperative that the cementable wellbore not be sacrificed in the efforts to reduce drilling days and mud costs. The cost of repairing the cement job can far exceed savings in drilling costs. Lost production and lost reserves must also be included in any analysis of costs. The Positive Approach A positive cementing philosophy must be developed and followed. It is the very foundation of the successful cementing block pyramid, as shown in Rig. 3. One must believe that a successful cementing job is possible. Such an attitude carries a real commitment to a successful job and involves a dedication of people, time, and money.

The primary cementing job on the production string is perhaps the most important operation performed on a well, yet it remains one of the most neglected of all operations. It is also subject to severe cost-cutting through bidding and turnkeying.3'4 But, as always, you get what you pay for. Successful cementing requires the application of technology, and technology is not free.

Priorities must be set, and the top priority is to obtain a successful cementing job on the first attempt.

References and illustrations at end of paper.

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2

SUCCESSFUL PRIMARY CEMENTING - FACT OR FICTION

14135 •

The Team Effort The team effort - the next tier in the block pyramid - is essential to a successful job. The team consists of employees of the the service company, the operating company and the drilling contractor. Communication and cooperation must be established early among all parties, but particularly between the drilling engineers and the service company engineers. The engineered design of the cementing job to fit the well requirements takes time. All personnel must apply the total engineered concept which starts with planning and design, continues through blending and mixing the cement, and culminates in pumping the cement. The operation is too big for one or two people. A team effort is required to handle the many and varied quality control measures necessary for a successful job. Usually, the operator should dedicate one drilling foreman and at least one drilling engineer to quality control. The Application of Technology The third tier of blocks in Fig. 3 involves application of cementing technology. This tech-

the

nology includes procedures, techniques, materials, and job execution. We must link technical know-how to field execution. To accomplish this task, field personnel must have access to the best technology. Therefore, a program to transfer technology across company boundaries and from research and the industry to field personnel is mandatory. Such a continuing-education program includes seminars, classroom courses, job experiences, and on-site expert assistance. Then to assure success, a conscientious effort must be made to apply the proven

ening time) is illustrated in Fig.

Fracture Pressure Gradient: During the planning stage for drilling a well, tentative decisions must be made about casing seats, mud weights, and cementing requirements. The decisions become firmer as more information becomes available during drilling. Sufficient knowledge of formation fracture pressure, pore pressure, and lithology is required not only to optimize the casing and drilling plan, but also to provide for a successful cementing job. Casing setting depths must be selected to prevent lost circulation problems and to permit proper control of the well at all times. It becomes imperative, therefore, to know the total hydrostatic pressure at which the exposed formations will fracture. For safe operations, formation fracture pressure is defined for cementing purposes as the fracture extension pressure. It should not be confused with fracture initiation pressure, which is usually higher because of the tensile strength of the exposed rocks. However, since rock strength cannot be accurately measured in situ, fracture initiation pressure cannot be predicted very accurately. Fig. 5 presents two formation control capability tests that show the difference between fracture initiation pressure and fracture extension pressure. one hour apart on an The tests were conducted about 8,000-ft (2438-m) well. Note on Test 2 the absence of a breakdown or fracture initiation pressure, yet fracture extension pressure on the two tests remained essentially unchanged. In Test 1, fracture initiation pressure was about 450 psi (3.1 mPa) or 1 lb/gal (120 kg/m8) higher than fracture extension pressure. It appears that once the formation has been broken, this extra pressure due to rock strength can no longer be counted on for control of the well. It seems possible that during normal drilling operations the formation could be broken unintentionally without its being indicated at the surface. Designing for maximum slurry density on the basis of initiation pressure could easily lead to lost circulation during the cementing job. Therefore, the fracture extension pressure should be considered the maximum safe pressure for cementing.

Cement Job Planning: The major areas of consideration in any cementing operation are job planning, slurry design, blending of bulk materials, slurry mixing, well preparation, and slurry pumping.8'7 Each area requires special attention and offers many challenges. A properly engineered slurry design satisfies all well requirements and is affected by well depth, downhole temperature, downhole fracture pressure gradient, slurry density, gas migration, fluid loss, pumping time, strength development, type and quality of mix water, type and density of drilling mud, displacement flow regime, and brand and kind of cement. The design proceeds in a logical manner from one property to the next until all well requirements are fulfilled. The Literature contains procedures for determining most of these properties.8'7'10 The steps that offer the most challenge are (1) determining the downhole temperature, (2) determining the downhole fracture pressure gradient, (3) controlling gas migration, (4) conditioning the mud and hole, and (5) blending the bulk cement. Well

temperature

Note that

with only a small increase in downhole circulating temperature there is a pronounced decrease in pumping time; therefore, temperature must be determined fairly accurately. One source of information on downhole temperature is primary logs run on the well at the casing setting depth. The maximum recorded log temperature often is considered psuedostatic, provided it is obtained about 24 hours after the last circulation ceased. If less than 24 hours has elapsed, another temperature log or bottomhole circulation survey should be run. Once a static temperature is determined, the appropriate temperature schedule for slurry design purposes can be obtained from API tables." If a circulation survey has been made, the temperature from that survey should be used in developing a temperature schedule.

technology.

Well Temperature:

4.

is impor-

tant because it affects all properties of cement, particularly pumping time and strength development.6'9 Pumping time is the length of time the slurry remains pumpable. Downhole cementing temperature can vary widely, depending on the type and weight of drilling mud, well depth, circulation time, geographic location, and many other factors.8 The effect of temperature on pumping time (or thick-

Formation fracture pressure is affected by the interrelationship of overburden stress, pore pressure and matrix stress coefficient as given by the following expression:" 14

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R. C. SMITH

3

Cement Slurry Density: For a casing program like that of Fig. 7, the maximum slurry density to Pf x Pp + K

(Sov

Pp)'

(1)

prevent losing circulation would be: (1) about 17.5 lb/gal (2096 kg/m3) for the production liner, (2) nearly 15 lb/gal (1797 kg/m3) for the drilling liner, and (3) 11.5 to 12.5 lb/gal (1378 to 1498 kg/m3) filler slurry followed by 15.8 lb/gal (1893 kg/m3) tail-in slurry for the intermediate string.

where Pf = formation fracture pressure, psi, pp = formation pore pressure, psi,

To determine optimum slurry density involves considerable effort but the extra effort pays diiidends in successfully cementing the well.

Sov = overburden stress, psi, K = matrix stress coefficient, dimensionless, To obtain a reasonable prediction'of formation fracture pressure using Eq. 1, one must have representative estimates for overburden stress, formation pore pressure, and matrix stress coefficient. Overburden stress is obtained from formation density logs, and pore pressure usually is obtained from empirical correlations using wireline log parameters and measured pore pressures for the drilling area.27 However, matrix stress coefficient, K, must be determined from actual destructive testing of the formation--i.e., hydraulic fracturing, or formation control capability testing at the casing shoe where the formation was fractured--or from leakoff test data. Care must be exercised in developing empirical correlations for stress coefficient. Usually it is back calculated from Eq. 1 when the other parameters are known. The value of formation fracture pressure, pf, must be the value of fracture extension pressure determined in the destructive test. For some active drilling areas, a correlation has been developed by Matthews and Matthews." Sometimes Poison's ratio14 is used in place of the stress coefficient; however, reliable values for Poison's ratio are not always available. Ref. 13 provides an updated procedure for determining downhole fracture pressure from which maximum slurry density can be obtained. An example of a curve of calculated onshore fracture pressure gradient in relation to curves of overburden stress and pore pressure is presented in Fig. 6. Notice that the overburden stress, which is calculated from density logs, is not constant. For offshore application, the fracture pressure gradient must be adjusted for depth of water and height of mud line above water level." Casing Setting Depths: The casing setting depths must be selected such that the well can be controlled and lost circulation can be prevented during drilling And cementing. Assuming an overbalanced drilling oituation, a mud weight curve is established as shown on Fig. 7. From this curve and the fracture pressure curve casing seats can be The Regulatory Body having selected (see Fig. 7). jurisdiction over the drilling area and established field rules often dictate maximum and minimum setting depths for surface casing. Also, guidelines are often given for pressure gradients for the other casing strings; therefore, these requirements, field rules and guidelines must be followed in selecting the final casing string setting depth and size program.

171

A wide range of slurry densities can be obtained using the nine API classes of cement, other non-API cements, and various additives. Fig. 8 shows slurry density vs a generalized grouping of cements ranging from neat (with no additives) to cements variously weighted with density-altering additives. Each group has distinct advantages and properties. Laboratory testing will determine the upper and lower limits for application. Gas Migration: Natural gas is often present in formations exposed to the wellbore at the time of cementing. This gas must be prevented from migrating through the cement column during WOC (waiting on cement) time. Failure to prevent gas migration can cause such problems as high annular pressures at the surface, blowouts, poor zonal isolation, loss of gas to nonproductive zones, poor stimulation, low producing rates, etc., (see Fig. 9). All of these are costly to correct. Before it begins to hydrate, a cementing slurry in the annulus can transmit hydrostatic head and thus prevent gas invasion into the slurry. However, during the early stages of hydration, the slurry develops gel strength and tends to become loadbeering," which causes it to lose its ability to transmit hydrostatic head. In this condition, gas invasion can occur. There are several successful methods to control gas migration, each with its advantages. Early methods included controlling fluid loss," pressuring the annulus, increasing slurry density, and eliminating free water.17 Those techniques, which still are used, solve some gas migration problems, but not all. Another method uses a cement slurry that interacts with the incoming gas to form an impermeable barrier in the cement pore spaces.18 Still another technique uses an impermeable cement system for controlling gas migration." Other approaches involve cements containing gas" or other additives" to cause expansion of the cement during hydration. In selecting the optimum mechanism or combination of mechanisms for controlling gas invasion and migration many well conditions must be considered. For example, formation pressure, permeability, gas flow rate, bottomhole temperature, wellbore geometry, well deviation, height of the cement column, formation fracture pressure. Some of the techniques for preventing gas migration involve the use of an external casing packer,7 which provides a positive seal in the annulus (see Fig. 10). It eliminates all three avenues of communication: the formation/cement interface, the microannulus between casing and cement, and channels within the cement sheath.

4

SUCCESSFUL PRIMARY CEMENTING

Mud and Hole Conditioning: To enhance mud displacement efficiency during a primary cementing job, the hole and the mud must be properly condierationed.21'22 This is one phase of the entire op 24 hrs may be tion that should not be rushed-- up to required to properly condition the mud and wellbore nt after the casing is on bottom. At best, a ceme ud slurry can only follow the path of the drilling m circulating ahead of it in the annulus. Therefore, the time required to properly condition the mud and the hole will be very well spent. Some of the important procedures that have proven successful are summarized here. The mud and the hole are initially conditioned with drillpipe in the hole before the casing is run. Wiper trips are made to check for caving, hole instability, and tight spots. The casing should not be run until the hole is free of cavings and all tight spots are eliminated. Then the running speed of the casing is controlled carefully to prevent fracturing and lost circulation. Once the casing is on bottom, pipe movement and mud conditioning are begun and are continued throughout the entire cementing operation.8'7'21 Cement pumping should not begin until at least 95% of the hole volume is being circulated.2 Generally this can be determined with fluid calipers. The drilling mud should be conditioned to as low a plastic viscosity and yield point as the (In system permits without dropping out solids.7 some highly deviated holes, this may not be advisable.2') The hole should be conditioned with good surface conditioned mud at rates as high as the expected cementing pump rates. Such high circulation rates are necessary to remove the gelled mud that has developed during the static period as a result of temperature rise and filtrate Loss. In addition, improved displacement efficiency is obtained by following these guidelines: (1) the properties of the mud returned should be close to those of the mud being pumped. into the well, (2) the funnel viscosity nf the mud returned should be less than SO seconds ;:tlial be within 5 seconds of the viscosity of the mud being pumped into the well, and (3) the gas content of the returning mud should be within 10 units of normal background-gas. Following those guidelines has resulted in more successful cementing. The Importance of Bulk Blending:

It is appro-

priate to single out bulk blending, or dry blending, for additional discussion. Blending of bulk materials often is taken for granted, yet it is a process in which serious errors can occur undetected, and if not corrected, can lead to a cementing failure. After the cementing system has been carefully designed in the laboratory, the composition or recipe must be correctly blended to ensure proper slurry performance in the wellbore. The two major factors affecting this performance are the concentration and the distribution of the additives in the cement Liend.24 Small variations in concentrations of additive can significantly alter the performance properties of the cement slurry. Therefore, quality control during this phase is extremely important." Following are steps that should be carefully fn% lowed.24'25 1.

Visually inspect all bulk tanks before transferring any bulk material. Any cement remaining in tanks from previous jobs can con-

- FACT OR FICTION

14135

taminate a cement slurry to the point that it will not perform downhole. A tank should be cleaned if it contains excess cement. 2.

Verify the calculations of additive weights.

3.

Verify the weights of all additives put in the batch tank for each blend. In addition, count and stack the sacks of each additive placed in the cement blend.

4.

Limit the batch size to 50 capacity of the tank.

5.

Verify the air valve positions made by the operator.

6.

Blend materials with air and then transfer them between tanks a minimum of three times.

7.

Collect representative samples of the blend for analysis.

% of the total

Close attention should be paid to the proper collection of samples. Although investigations into proper sampling techniques have been limited, the industry consensus is that three transfers of the blend should be made before sampling. With a continuous in-line sampling device, a representative sample can be taken of each blend. A minimum of two 1-gal samples of bulk material should be collected and identified for every weigh tank batch. After the blending, laboratory tests should be conducted to determine the chemical composition28 or the pumping timel° at the expected temperature and pressure. Job Execution and Monitoring Proper job execution includes monitoring and controlling several factors. Certain data must be collected and analyzed to ensure timely decisions affecting the overall operation. Recorded data should include pump rate in, annulus rate out, wellhead pressure (at the cementing head), density of fluids pumped in and those returning (using radioactivity devices or equivalent), cumulative displacement volume, cumulative return volume, hook load during pipe reciprocation. To enable the job supervisor to make timely decisions, he should have a central monitoring point such as a monitoring van or portable electronic data recorder from which he can observe the entire operation. It is especially important to measure the mud return rate. Because of free-fall" of cement in the casing, the mud return rate can exceed displacement rates while a well is on a vacuum. However, later in the job, as the free-fall rate slows down, the return rate can be significantly less than the displacement rate. This lowering of return rate is often mistaken for losing circulation. Therefore, it is important to calculate job performance using a downhole simulator with which to compare real-time data during the job. Full-opening magnetic flow meters are available for measuring return rate for water-based systems. These are much more accurate than trip tanks which are o:casionally used.

172

14135

R. C. SMITH

rate

Another reason to measure the mud return nis so the downhole displacement rate can be co ring distrolled to ensure the proper flow regime du is placement. For example, if turbulent flow s return required throughout the job, then the annulu his minrate should not be allowed to drop below t g flow imum return rate. On the other hand, if plu n rate displacement is desired, the aluutlus retur must not exceed the maximum calculated rate.

12.

Successful primary cementing can be a reality.

2.

Successful primary cementing requires intense quality control.

3.

Matthews, J. C. and Matthews, W. R.: "Program Calculates Frac Gradients for Many Basins," Oil and Gas Journal (July 8, 1985) 39-43.

14.

Eaton, B. A.: "Fracture Gradient Prediction and Its Application in Oilfield Operations," J. Pet. Tech. (Oct. 1969), 1353.

15.

Cheung, P. R. and Beirute, R. M.: "Gas Flow in Cements," J. Pet. Tech. (June 1985), 1041-1048.

16.

Garcia, J. A. and Clark, C. R.: "An Investigation of Annular Gas Flow Following Cementing Operations," Paper SPE 5701 presented at the 1976 SPE Symposium on Formation Damage Control, Houston, Jan. 20-30.

17.

Webster, W. W. and Eikerts, J. V.: "Flow After Cementing - A Field Study and Laboratory Model," Paper SPE 8259 presented at the 54th SPE Annual Technical Conference and Exhibition, Las Vegas, Sept. 23-26, 1979.

18.

Bannister, C. E., Shuster, G. E., Wooldridge, L. A., Jones, M. J. and Birch, A. C.: "Critical Design Parameters to Prevent Gas Invasion During Cementing Operations," Paper SPE 11982, presented at the SPE 58th Annual Technical Conference and Exhibition, San Francisco, Oct. 5-8, 1983.

19.

Tinsley, J. M., Miller, E. C., and Sutton, D. L.: "Study of Factors Causing Annular Gas Flow Following Primary Cementing," J. Pet. Tech. (Aug. 1980) 1427-1437.

20.

Griffin, T. J., Spangle, L. B., and Nelson, E. B.: "New Expanding Cement Promotes Better Bonding," Oil and Gas Journal (June 25, 1979), 143-151.

21.

Haut, R. C. and Crook, R. J. Jr.: "Primary Cementing: Optimized for Maximum Mud Displacement," World Oil (Nov. 1980).

22.

Clark, C. R. and Carter, L. C.: "Mud Displacement with Cement Slurries," J. Pet. Tech. (July 1973), 775-783.

23.

Keller, S. R., Crook, R. J., Haut, R. C., and Kulakofsky, D. S.: "Problems Associated with Deviated Wellbore Cementing," Paper SPE 11979 presented at the SPE 58th Annual Technical Conference and Exhibition, San Francisco, Oct. 5-8, 1983.

24.

Pace, R. S., McElfresh, P. M., Cobb, J. A., Smith, C. L., and Olsberg, M. A.: "Improved Bulk Blending Techniques for Accurate and Uniform Cement Blends," Paper SPE 13041 presented at the SPE 59th Annual Technical Conference and Exhibition, Houston, Sept. 16-19, 1984.

25.

Smith, R. C.: "Successful Primary Cementing Checklist," Oil and Gas Journal (Nov. 1, 1982).

cementing requires a proper Successful primary positive attitude, commitment, and dedication.

SI METRIC CONVERSION FACTORS bbl x 1.589873 ft x 3.048 °F (°F-32)/1.8 gal x 3.785412 lbm x 4.535924 psi x 6.894757 lb/gal x 1.198 in. x 2.54

E-01 E-01

= m3 =m

E-03 E-01 E-03 E+02 E+00

m m3 a kg

c

mPa a kg/m3 = cm

REFERENCES 1.

"Cogent Comment," World Oil (Jan. 1985).

2.

Smith, R. C.: "Successful Primary Cementing Can be a Reality," J. Pet. Tech. (Nov. 1984), 1851-1858.

3.

"Dialog", J. Pet. Tech. (Mar. 1985).

4.

Jenkins, Dean: "President's Outlook," Well Servicing (Mar./Apr. 1985), 9.

5.

Shryock, S. H. and Smith, D. K.: "Geothermal Cementing - The State-of-the-Art," Halliburton Services Brochure C-1274.

6.

Smith, D. K.: c!Eisnias, Monograph Series, SPE, Dallas (1970

7.

Suman, G. 0., Jr., and Ellis, R. C.: Handbook, World Oil (1977).

8.

Cementing

API Task Group: "Better Temperature Readings Promise Better Cement Jobs," Drilling-DCW (Aug. 1917).

9.

Pilkington, P. E.: "Fracture Gradient Estimates in Tertiary Basins," Pet. Eng. Intl. (May 1978).

13.

CONCLUSIONS 1.

5

Venditto, J. J. and George, C. R.: "Better Wellbore Temperature Data Equal Better Cement Job," World Oil (Feb. 1984).

10.

API Specifications for Materials and Testing for Well Cements, API Spec. 10, 2nd Ed., API Production Dept., Dallas (1984).

11.

Matthews, W. R. and Kelly, J.: "How to Predict Formation Fracture Pressure and Fracture Gradient," Oil and Gas Journal (Feb. 20, 1967), 92.

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SUCCESSFUL PRIMARY CEMENTING

26.

Christman, S. A.: "Offshore Fracture Gradients," J. Pet. Tech. (Aug. 1973).

27.

Hottman, C. E. and Johnson, R. K.: "Estimation of Formation Fracture Pressures from LogDerived Shale Properties," J. Pet. Tech. (June 1965), 717.

28.

McElfresh, P. M.: "Chemical Thickening-Time Test for Cements," J. Pet. Tech. (Feb. 1983).

29.

Beirute, R. M.: "The Phenomenon of Free Fall During Primary Cementing," Paper SPE 13045 presented at the SPE 59th Annual Technical Conference and Exhibition, Houston, Sept. 16-19, 1984.

1-74

- FACT OR FICTIC3

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SPE

14135

Complete Cement Sheath without Mud or Gas Channels + 3" (7.62 cm)

Properly Conditioned Hole & Mud No Sloughing

Cement Bonded To Formations Gauge Diameter Cement Bonded To Casing

Straight As Possible

Pay Zone

No Flow No Lost Circulation

Figure 2 The Cementable Wellbore

Figure 1 Job Objectives of a Primary Cementing

I

successful Cementing Job Duality Control

Procedures and Techniques

Transfer of Cementing Technology Knowledge

Service Company

Attitude

Training Program

Rig Drilling Operato Contactor Foreman r Team Concept Commitment

Drilling Engineers

Dedication

Cementing Philosophy Figure 3 Structure of a Successful Primary Cementing Job

175

Proper Priorities

•

14135

sp 2500 (17.24)

API Class E Cement

ui cc a_ 2 I

Test 2

a.

1500 (10.34)

cn

160 (71.1) Class G

Shut-In

cc a 0 u. cr cn

Cement

LL

120 (48.9)

1000 (6.89)

500 (3.45)

80 (26.7) Class G Cement + 2% Caa 2 40 (4.4)

Fracture Extension Pressure

(13.79)

2

Class D Cement c.7s

Test 1

2000

E

200 (93.3)

Fracture Initiation Pressure

2

4

6

I I I I 2 4 6 2 4 (.22) i-;3) ShUT-IN TIME, MINUTES VOLUMED PUMPED, bbl (m3) 0

8

10

PUMPING TIME, HOURS

Figure 5

Figure 4 Effect of Temperature on Pumping Time of Various API Cements at Atmospheric Pressure.

2000 4000

Formation Control Capability Tests

Surface Casing

Overburden Stress Fracture Gradient Pressure Gradient

2000 -

4000 6000

6000 fp

8000

Pore Pressure Gradient

La' moo

Fracture Pressure

I

. Intermediate Casing

Mud Weight

g-

141'

Drilling Liner

10000

10000

Pore Pressure 12000

14000 04

\.Production Liner

12000 I I 1 r I 0.5 0.6 0.7 0.8 0.9 PRESSURE GRADIENT, PSI/ft

14000 8

10

I

12

14

16

18

EQUIVALENT MUD WEIGHT, lb/GAL Figure 7 Casing Setting Depths

Figure 6 Formation Fracture Pressure Onshore

_ -176 _ -

20

SPE

14135

25

Figure 8 Density Range of Cement Slurries 2

Channels Gas Leakage

Mud mpermeable or Expanding Cement Low Fluid Loss Zero Free Water External Inflatable Casing Packer U Gas Zone

Figure 9 Gas Migration in a Cemented Annulus. 6

Figure 10 Use of a Casing Packer To Prevent Gas Migration in a Cemented Annulus (Modified from Ref. 6)

177