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Copyright 2006, IADC/SPE Drilling Conference

This paper was prepared for presentation at the IADC/SPE Drilling Conference held in Miami,Florida, U.S.A., 2123 February 2006.

This paper was selected for presentation by an IADC/SPE Program Committee followingreview of information contained in a proposal submitted by the author(s). Contents of thepaper, as presented, have not been reviewed by the International Association of DrillingContractors or Society of Petroleum Engineers and are subject to correction by the author(s).The material, as presented, does not necessarily reflect any position of the IADC, SPE, theirofficers, or members. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the International Association of DrillingContractors and Society of Petroleum Engineers is prohibited. Permission to reproduce in printis restricted to an abstract of not more than 300 words; illustrations may not be copied. Theabstract must contain conspicuous acknowledgment of where and by whom the paper waspresented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A.,fax 1.972.952.9435.

AbstractWells drilled into the deep Bossier formations of the east

Texas Hilltop Field encounter low-permeability, gas-bearing

formations at over 15,000-psi pressure and 400Ftemperatures. The wells require high-pressure fracture

stimulations and extreme production drawdown to produce at

economic rates. Wellbore temperature variations occurringbetween stimulation and production operations are extreme.

The gases in these formations are also highly corrosive. Two

of the first three wells completed in this area failed fromcasing collapse during completion operations or within the

first few weeks of production.Finite element analysis (FEA) modeling coupled with log-

derived formation properties confirmed that the extreme

stresses applied to these wells rendered previous casings andcement sheaths under-designed. Using an approach that

combined formation, casing, and cement mechanical

properties into a system, the wells were redesigned. Detailed

thermal and mechanical modeling of all wellbore operations

resulted in redesigned casings and a cement sheath moreapplicable to the extreme loads being exerted. Minor changes

were also implemented to the job placement procedures to

lessen the loads placed on the cement sheath.

High-strength, corrosion-resistant casings and specialtycement designs were successfully used on the first two wells.

Since those wells have been on production, additional wells

have been drilled and completed using incrementally-

simplified designs. All the wells have withstood multiplestimulations at treating pressures exceeding 14,000 psi,

production test drawdowns at the perforations of over 13,000

psi, and temperature changes estimated at more than 300F.

The wells have withstood these extreme pressure andtemperature changes without failure of either the casing or

cement sheath.

The cement and casing designs employed have proven

competent for the high-pressure, high-temperature (HPHT)conditions encountered. The successful design methodology

couples well-specific casing and cement designs into a system

capable of surviving the extreme pressure and temperatureconditions imparted on the well during stimulation and

production operations of deep, low-permeability HPHT gas

sands.

IntroductionConstruction of deep gas wells involves a large capita

expenditure, and they are typically prolific wells. In addition

remedial work can be very costly, not only in terms of los

production, but also in the cost of materials and serviceneeded to perform the work. Catastrophic well failure

although rare, does occur and can doom remaining reserves in

place when it happens. Hence, there is a large incentive to do

things right the first time.The traditional focus of the cementing job of designing

adequate slurry properties and getting the slurry properly

placed still applies, but that is only the beginning. As these

wells are completed and produced, the cement sheath isdesigned to survive extreme stresses. Wellbore longevity wil

depend not only on how the cement sheath is designed to

impart maximum sealing properties, but also on how it

behaves when coupled to the casing and formation during alwell operations. All operations and their associated timing

with respect to the completeness of the cement hydration are

fair game for investigation, including: Continued drilling operations (in the case of intermediate

casings). Completion operations (e.g. completion fluid

circulations and stimulation treatments). Well testing (e.g. pressure testing, severe drawdown

tests, etc.). Access to various annuli for pressure control during

thermal changes. The effects of gradual drawdown during long-term

production.

BackgroundPrior well designs in the Hilltop area consisted of what will be

referred to as first-through-third generation designs. The first

generation well was completed with a conventional 2-D casing

design. Completion procedures consisted of nothing more thanacidizing the formation and placing the well on production

IADC/SPE 98869

Finite Element Analysis Couples Casing and Cement Designs for HP/HTWells inEast TexasJ. Heathman, Halliburton, and F.E. Beck, Gastar Exploration


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2 IADC/SPE 98869

This well started producing drilling mud approximately 3

months later, and was subsequently found to have undergone

casing collapse. This was quickly followed with a second wellfor which improved tubular designs were employed. This

design did not collapse, but the well failed because of an

insufficient completion methodology.

The third-generation well was designed with a more robust

and presumably adequate casing and cementing program, asshown in Fig. 1. This casing design was intended to withstand

full evacuation. The wells were cemented, cleaned out with

KCl water, perforated, and multiple formations weresuccessfully stimulated down casing at 20 bbl/min at over

13,000-psi surface pressure using high-strength proppant.

During the course of post-stimulation flowback at full

drawdown rate and maximum heating, this well also collapsed

in the lower part of the well.When the current production company acquired the lease

after the three previous wells had failed, a review of the casing

design using a thermodynamic casing analysis model did notindicate that the casing for the third-generation well had been

under-designed. This observation resulted in speculation about

causes ranging from a faulty coupling or joint of casing,

formation effects, some sort of cement sheath failure, to a

combination of these factors. It appeared that at least one ofthe failures occurred in the tieback string just above the

polished-bore assembly. It was also speculated that a trapped

mud pocket might have existed between the cement above thePBR and the liner top below that subsequently expanded due

to thermal effects when high-rate flow-back and production

started. However, no definitive evidence indicated that any of

this was the case. Subsequent modeling with casing design

software and FEA was never able to determine a cause.

Following the mechanical failure of this well and thesubsequent lack of an obvious cause, or a consensus regarding

the most likely cause(s), this operator elected to step back andrevisit the entire well design. Before drilling another of thesewells, the plan was to perform a detailed analysis of the casing

and its metallurgy, the couplings, and the cement sheath.

Finite Element AnalysisThe coupled wellbore modeling was conducted using asoftware that has as its core the DIANA finite elemental

analysis program from the Diana Corporation. This software is

a practical wellbore model in the sense that it takes intoaccount all forces exerted on the cement sheath, casing, and

formations caused by pressure and thermal changes. This

design software was developed over several years and has

proven itself in numerous situations.1-4

In the model, the system composed of the formation

material, cement, and casing are divided into a finite numberof parts, or elements, so that the governing equations can be

solved. When analyzed, each element must satisfy the

relationships and constraints set forth by the user so that asolution is found. This can enable not only a diagnosis of the

elements, but also a diagnosis of the boundaries between each

layer. Subsequently, the presence and width of microannuli or

cracks resulting from debonding can be predicted.

The radius of the surrounding formation when modeled issuch that far-field stresses remain unchanged. However, near-

field stresses can affect not only wellbore elements but also

the competency of the formation itself. This mode

accommodates all wellbore operations, as well as reservoir

changes caused by pressure drawdown and formation

subsidence. Interpretation of modeling results can produce arange of solutionsranging from simple modifications to

operational procedures or wellbore design to a complex

cement sheath redesign, or any combination thereof.

Problem Setup and Initial AnalysisTable 1and Figs. 1 through6provide a substantial portion of

the initial well design, formation, and operational event data

used in the FEA model. The new casing program, herein

referred to as the fourth-generation design, shown in Fig. 7

addressed metallurgical and well delivery constraints of the

previous design. Because CO2and H2S had been observed in

previous wells, with as much as 400 ppm and 14%

respectively. Additionally, a larger production casing diameter

was desired (than had been used previously) to accommodate

more aggressive stimulation treatments and production ratesBefore beginning the FEA work, a careful design analysis o

the casing was performed using a 3-D casing design model to

ensure that the design was robust enough for the intendedsevere well testing program. The design limit plot of Fig. 8is

a result of that work. Heavy-wall casing, premium couplings

and super-alloy metallurgy became a part of these HTHP

wells.

Model Setup and Initial AnalysisConcerns regarding casing design were alleviated because the

new design enabled greater flexibility in withstanding severeconditions during formation testing and stimulation treatment

The next step was reinitiation of the cement sheath

examination. Using the new casing design as the basis for all

modeling, the original cement sheath design was first

examined to establish a new baseline case. Mechanicaproperties of all cements modeled were determined using atriaxial load cell at unconfined and various confining loads

The wellbore was examined at multiple depths, the most

important being in the top of the reservoir sand, just below theprevious casing shoe, and at depths that offset logs indicated

substantial changes in formation lithology, pressures, and in-

situ stresses. This multiple-depth investigation not only helps

provide an understanding of the cement sheath behavior a

many different conditions, but also can enable a sensitivityanalysis by allowing a review of how the cement is behaving

across the various formations.Fig. 9 is an example of the remaining capacity summary

associated with each operation. Although numerous depthswere modeled, only the modeling at true vertical depth (TVD

of 18,000 ft is shown (for brevity). Despite the robust casing

design, multiple failure modes were predicted in the cement

sheath, most noticeably debonding with subsequen

development of a substantial microannulus and shear failurewithin the cement matrix. This failure pattern occurred to

varying degrees of severity at all depths of investigation. Even

for those load cases where failure was not predicted, someremaining capacity predictions could have been interpreted as

being at high risk. Finally, a sensitivity analysis conducted by

varying the values of parameters such as the casing

eccentricity, hole washout, and Mohr-Coulomb parameters


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IADC/SPE 98869 3

indicated the modeled well was extremely sensitive to

relatively small variations in these key variables.

Scenario ImprovementThe analysis process at this point consisted of altering the

operational and completion parameters to look further at

model sensitivity and for ways to offset the cement failures

predicted. Improvements were seen by (1) reducing the pre-frac pressure drawdown, (2) performing the frac job through

tubing and packer rather than down casing, and (3) altering the

completion plan such that the cement job would be displacedwith brine instead of the previous procedure of displacing it

with the heavy drilling mud and later replacing it with a light

completion brine. While all these changes provided

incremental improvements, only the last change was feasible

for the design of this well.Fig. 10 provides the remaining capacity summary of the

best-case completion scenario using the existing conventional

cement design. While displacing the cement job with 3% KClwater would have been the most desirable plan from a

mechanical standpoint, the resulting surface pressures while

displacing the cement would have been substantial. After

working both job simulation models and the FEA program

congruently, it was decided that the best tradeoff for adisplacement fluid was a completion brine no heavier than 13

lb/gal. But this maximum brine density value was contingent

upon the accuracy of the data being placed in the model; thus,the general idea was still: the lighter the better.

Another advantage of displacing with brine rather than oil-

basesd mud (OBM) is that it eliminates the rig time and

expense of cleaning the OBM from the casing prior to

perforating. However, this still placed an allowable limit of no

less than 5,500 psi during the prestimulation drawdown test;therefore, while improvements would have been gained, shear

failure and debonding were still predicted.To achieve all the desired goals of this well, the only

alternative was to modify the mechanical properties of the

cement sheath. The positive modifications that were

logistically and economically feasible (as shown in Table 2 as

third-geneation completion procedures) were implemented

from this point forward to minimize the changes required tothe cement sheaths mechanical properties.

New Cement DesignSensitivity analysis indicated that any new cement design

would have to possess much lower values for Youngs

Modulus and friction angle and higher values for cohesion,

tensile strength, and Poissons ratio. Also, it was obvious thatbulk shrinkage from cement hydration could not be allowed.

Achieving these goals in a lightweight cement is relativelysimple. However, the high solids content of a 19-lb/gal slurry

does not lend itself to becoming essentially an elastic

cement. Foamed cement would have been the easiest cementin which to achieve the desired mechanical properties, even at

a final downhole density of 19 lb/gal, but foamed cement is

not conducive to an environment that might reach more than

395F bottomhole circulating temperature (BHCT) during

slurry placement. Another option, ground-up recycled tirerubber, used for many years as a lost-circulation material, was

deemed undesirable for these conditions because it could

degrade with time at high temperature.

To achieve the desired properties, a copolymer elastomer

bead was chosen as a large portion of the cement blend. Thismaterial, in conjunction with a gas-generating additive and

careful selection of other conventional components, provided

the cement mechanical properties needed for the anticipated

stresses. Fig. 11provides the remaining capacity summary ofthe final well design at 18,000 ft. Note that the remaining

capacity for the cement-to-formation debonding prediction is

very low. While this level of risk may be unacceptable in

some situations, repeated runs of the model showed very little

sensitivity to change. In addition, this interval was in themiddle of the long lower Bossier sand that was expected to be

perforated and hydraulically fractured. Analysis did not show

a gas/water contact on previous wells at this depth; thereforethe risk was considered acceptable. The remaining capacity of

the debonding prediction was considerably higher at other

depths under investigation.

To conclude the analysis, the cement design chosen for

this high-stress HTHP application was subjected to a varietyof tests. Because of a great variance in the specific gravities of

the major components of this blend, concerns emerged

regarding the deblending during pneumatic transfer andtrucking to location, and about the slurrys mixability. Table 3

shows the results of specific gravity checks pulled from the

blend at different times during the handling process, indicating

no significant effects. Slurry mixability was indeed found to

be slow, thus the decision was made to batch-mix this blend

on location.Flow testing through float equipment for 2 hr at 215

gal/min indicated no issues with float equipment erosion or

plugging. The slurry was then mixed for a yard test andpumped into a wellbore model cured at 420F. This mode

was subjected to pressure and thermal cyclic loads whilemonitoring the integrity of the cement-to-casing bond. Fig. 12

shows a cross-section of the model after cycling for which no

debonding or sheath damage was observed, based onlongitudinal pressure testing with water and nitrogen. For

comparison, Fig. 13shows results for a conventional cement

subjected to the same testing. Note the visible cracks anddebonding that occurred.

All the testing was successful, which instilled confidence

in the team that this blend could be placed and would perform

as designed.

Examination of Shallower (Previous) Casing Strings

After the casing, cementing, and completion designsassociated with the 5-in. production casing had been

thoroughly explored, design analysis progressed to theacceptability of the 7 5/8- and 9 5/8-in. casings and associated

cement sheaths used previously. The 9 5/8-in. casing was a

full casing string that could provide an annular leak path to

surface. The operation was expected to cover potentiallyproductive intervals up through the Travis Peak formation. On

the other hand, the entire 7 5/8-in. liner would be covered with

cement during the production cementing operation. As a resul

of these scenarios, emphasis was placed on the 9 5/8-in. casing

interval. The primary concern, aside from the same long-termzonal isolation as the production casing, was the possibility of


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4 IADC/SPE 98869

sustained casing pressure (SCP) on the 9 5/8-in. casing by the

13 3/8-in. annulus. SCP has been a growing concern of

operators and regulatory agencies alike for both land andoffshore installations.5

FEA Model, 9 5/8-in. Production CasingAs before, the base model for the 9 5/8-in. casing was

established using conventional cementing programs. Themodel was set up from the shoe of the 13 3/8-in. casing to the

anticipated depth of this intermediate casing. Four key depths

were chosen for investigation: (1) the shoe of the previouscasing, (2) the bottom of the lead slurry, (3) the top of the tail

slurry, and (4) total depth (TD) for this interval. Table 4

provides a summary of the basic assumptions used in the

model, and Figs. 14and 15detail the results of this model for

the lead and tail cements. Several modes of failure aredisplayed for both lead and tail cements; of most interest is the

unrecoverable plastic deformation in the cement structure. The

cement-to-formation debonding occurred at all depths ofinvestigation and for all load cases. Both predicted failure

modes could lead to SCP at the surface during the operating

life of this well.

Ensuring the Integrity of the 9 5/8-in. Cement SheathAs with the production casing, the first attempt to improve the

remaining capacity was to look for (1) events that could be

modified or removed that cause prestressing of the cementsheath, and (2) potential modifications to the completion

design or order of events that will not significantly change the

cement design. In this case, the drilling program did not allow

for any changes that would prevent cement sheath damage.

Consequently, the cement design would have to be modified.

The obvious first step was to prevent bulk hydrationshrinkage. This modification would be achieved as before by

using a gas-generating additive in both cement blends. Notethat this only prevented shrinkage; no bulk expansion of theset cement was created nor necessary.

Subsequent runs indicated no further modifications were

necessary for the cement mechanical properties for the initial

conditions assumed. However, because of the possibility of

encountering zones with higher pore pressures, furthersensitivity analysis using the assumed higher values and

associated mud weights indicated that the nonshrinking

version of the recommended water-extended, lightweight leadcement could be fairly sensitive to shear deterioration.

Imparting bulk expansion was not the solution to this potential

problem. However, minor adjustments were made to the ratio

of primary components in the blend to affect the Mohr-Coulomb failure variables and the Youngs Modulus. Thisfinal analysis is provided in Figs. 16and 17.

Finally, unlike the production casing analysis, the goals of

the well-life analysis were carried out for this casing string

through some very simple modifications to the cement blendusing conventional additives.

On-Location DeliveryRefer once again to Table 2 for the operational proceduresapplied to the first well. As expected, the slurry mixability was

slow. A sustained rate of over 4 bbl/min while mixing on-the-

fly would not have been possible; thus, the conservative

decision to batch-mix the 19-lb/gal elastomer slurry was

beneficial. Because of the high concentration of copolyme

beads and other components in this blend, rheology

measurement with a rotational viscometer using aconventional R1/B1 rotor/bob combination was not possible

A B2 bob was found to work somewhat better, but

experiments showed that the new yield point adapter (YPA)

rheometer kit (shown in Fig. 18) was well suited to thisapplication.

6,7Additionally, the newly-developed generalized

Hershel-Bulkley (GHB) rheology model was found to providean excellent pressure prediction.8 Fig. 19 provides the

regression analysis of the data generated using the YPA

instrument. Fig. 20provides the predicted vs. actual surface

pump pressures for one of the 19,200-ft wells, illustrating the

good predictive abilities of this new rheological model forcomplex fluids.

Cement Evaluation Log of Production CasingThis paper would not be complete without a discussion of theobservations made on the cement evaluation log of the 5-in

production casing. Although it was desirable to evaluate thi

unique cement sheath with an ultrasonic tool, no tool available

will withstand the temperatures of this well, as well asaccommodate both the small ID and large wall thickness of

this production casing. Because the copolymer beads used

imparted elastic properties to this 19-lb/gal cement, the log

was expected to indicate poor attenuation and/or free pipemuch like a foamed cement sheath will behave. This is

because elastic cement sheaths often do not attenuate the

casing as does a conventional cement, thus allowing it to ring

in response to sonic and ultrasonic evaluation tools. HoweverFig. 20indicated this was not the case.

At the time this log was run, approximately one month

after the cement had been placed, the wellbore still contained

the 13-lb/gal brine that the cement job had been displacedwith, and the casing had already been pressure-tested to15,000-psi surface pressure. Under these circumstances

cement-to-casing debonding occurs and a microannulus is

nearly always created, as was the case with the nonelastomericlead slurry shown in Fig. 21. Of most interest on this log is the

fact that the elastomer tail slurry deformed without going into

plastic failurejust as it was designed. The lead slurry

though mechanically-altered, was not designed to preven

debonding due to the pressure test, thus a microannulusappeared periodically throughout the lead cement sheath

Though caution should always be exercised when interpreting

an evaluation log of any designer cement sheath, this case

clearly shows the superior mechanical properties of theelastomer cement.9

Ongoing Operational Changes and Evolution to TwoWell DesignsOne of the goals of this project was to continually evolve thecasing and cement designs as confidence in the data improved

so that the wells become optimized to the conditions. This

continuous process has resulted in simplifications to both the

casing design and the cementing procedure.

The high pump pressures associated with the displacemenprogram were of enough concern to revisit the brine density

Further review with the FEA model with improved and greater


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IADC/SPE 98869 5

confidence in the formation property data has allowed the job

to be displaced with a 12.8-lb/gal brine. This same review of

improved wellbore data has also enabled the cementingprogram to be optimized in the sense that the elastomer slurry

volume has been reduced to cover only those portions of the

wellbore needing it. While this still involves a substantial

portion of the openhole section, inclusion of a nonelastomeric

lead slurry with modified mechanical properties has resultedin simplified location logistics and reduced job cost. This step

has also resulted in lower ECDs during placement.

Since the start of this project, these wells have encounteredseveral shallower formations that have proven economically

productive. To speed development field development and cash

flow, these wells at 10,000- to 15,000-ft TVD are being drilled

with a reduced casing program. Because of the shallower

depths and associated smaller pressure and thermaldifferentials, these wells have not required any extensive

slurry redesign and associated mechanical property

modifications to date.

ConclusionsTo date, six HTHP wells have been drilled in the Hilltop Field.

All have been successfully drilled, cemented, tested, and

subjected to multiple-zone frac jobs down casing. Withoutexception, the mechanical integrity of all wells has been

outstanding. Based on tracer surveys, all stimulation

treatments stayed in zone. As each well was drilled and moreformation data was gathered, the FEA model was adjusted to

accommodate the improved data. Since the first well was

drilled and tested, pore pressure/frac gradient confidence in

the area has allowed the operator to simplify the casing design.

Electing to stop performing the severe prestimulation

drawdown testing now that the necessary reservoir data hasbeen gathered has reduced the stresses subsequent wells have

been subjected to, thus allowing the casing design to besimplified. However, because of these reduced casing designs,it has been imperative to maintain the cement sheath designs

as originally planned to maintain wellbore integrity.

This case study shows that, when every facet of a critical

well is incorporated into a total well design, the resulting

structural integrity management process can result in secureand economical wells.

AcknowledgementsThe authors thank the management of Halliburton and FirstSource Gas, LP, and Gastar Exploration, Ltd for permission to

publish this paper. They are also thankful for the hard work

and dedication from all the technical and operations personne

that made this project a success.

References1. Bosma, M., et al.: Design Approach to Sealant Selection

for the Life of the Well, paper SPE 56536 presented athe 1999 ATCE, Houston, TX, October 3-6.

2. Ravi, K.R., et al.: Safe and Economic Gas Wells throughCement Design for Life of the Well, paper SPE 75700

presented at the 2002 SPE Gas Technology Symposium

Calgary, Canada, April 30May 2.

3. Ravi, K.R., et al.: Cement Sheath Design for DeepwaterApplications, paper presented at the 2003 Offshore Wes

Africa Conference, Windhoek, Namibia ,March 11.

4. Griffith, J.E., and Tahmourpour, F.: Use of FiniteElement Analysis to Engineer the Cement Sheath for

Production Operations, paper presented at the 2004

Canadian International Petroleum Conference, Calgary

Canada, June 8-10.

5. Information from Current Methods for Analysis andRemediation of Sustained Casing Pressure, by Staurt

Scott and Adam T. Bourgoyne, Jr., Petroleum

Engineering Department and Louisiana State University.6. Dealy, S.T., Morgan, R.G., and Johnson, J.W.

Viscometer for Multi-Phase Slurries, paper presented at

the 2005 DEA/IADC Workshop, Galveston, TX, May 24

25.

7. Harris, P.C., Morgan, R.G., and Heath, S.J.Measurement of Proppant Transport of Frac Fluids,

paper SPE 95287 presented at the 2005 ATCE, Dallas

TX, October 9-12.8. Becker, T.E., Morgan, R.G., Chin, W.C., and Griffith

J.E.: Improved Rheology Model and Hydraulics

Analysis for Tomorrows Wellbore Fluids Applications,

paper SPE 82415 presented at the 2003 Production andOperations Symposium, Oklahoma City, OK, March 22

25.9. Frisch, G., et al.: Advances in Cement Evaluation Tools

and Processing Methods Allow Improved Interpretation

of Complex Cements, paper SPE 97186 presented at the

2005 ATCE, Dallas, TX, October 9-12.


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6 IADC/SPE 98869

Final mud type (when interval is 18.3-lb/gal Diesel-based OBM

Bottomhole thermal gradient 1.81F/100 ft

MD 19,000 ft

TVD 19,000 ft

Estimated drilled-hole size 6.7-inch (to be drilled with 6.5-inch bit)

TOC 14,000 ftModeled range Previous casing to TD

Designed casing standoff 85%

Displacement fluid for cementing job Drilling mud

Lithology basis for rock properties Sandstone, sandy limestone

Formation properties Derived by FracProPT curve-matching from mini-frac analysis of

previous well. Will be updated with sonic logs as the well is

drilled.

Maximum casing test pressure profile 18.3-lb/gal OBM plus 15,000-psi surface pressure

Parameters assumed for early

production test

5 MMscf/d, 40 BWPD, 72 hr, maximum drawdown to 2,500 psi

at perfs, 0 psi on annulus, minimal drawdown in formation

Frac treatment average parameters Through casing with 3,580 bbl fluid at 35 bbl/min, 13,000-psi

surface pressure

Post-frac flowback production 15 MMscf/d and 300 BWPD for 72 hr

Long-term production 15 MMscf/day and 200 BWPD

Table 1Initial Modeling Assumptions, 5-in. Production Casing


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IADC/SPE 98869 7

Original Second-Generation

Well Design Completion Procedures

Proposed Third-Generation

Well Design Completion Procedures

1. Displace cement job with drilling mud.

2. No specifications on when continued operations

are allowed.3. Pressure test casing and wellhead to 15,000 psi.

4. RIH with workstring and scrapper and circulate

out with KCl water.

5. Perforate and perform production testing to

maximum drawdown possible.

6. Perform fracturing treatment down casing,

20 bbl/min and 14,000-psi surface pressure.

7. Forced-closure flowback and flow to tanks until

cleaned up.

8. Kill well, run tubing, and put on pipeline.

1. Displace cement job with completion brine.

2. WOC for minimum specified time to ensure

mechanical property development.3. Run cement evaluation log.

4. Pressure test casing and wellhead to 15,000 psi.

5. RIH with workstring and circulate out with KCl

water.

6. Perforate and perform production testing.

Maximum allowable drawdown of 5,500 psi at

perforations.

7. Perform fracturing treatment down casing,

20 bbl/min and 14,000-psi surface pressure.


cleaned up.


Final Procedures Used on First Well Procedures Used Today

1. Displace cement job with 10 lb completion brine.


mechanical property development.

3. RIH with workstring and circulate out with 3%

KCl water.


5. Run cement evaluation log.

6. Perforate and perform production test. Maximum

allowable drawdown of 2,500 psi at perforations.

7. Perform fracturing treatment down casing;

35 to 38 bbl/min at 14,500-psi pressure atsurface.


cleaned up.


1. Displace cement job with 12.8 lb completion

brine.


mechanical property development.

3. RIH with workstring and circulate out with 3%

KCl water.


5. Run cement evaluation log.

6. Perforate and perform fracturing treatment down

casing; 35 to 38 bbl/min at 14,500-psi pressure

at surface.7. Forced-closure flowback and flow to tanks until

cleaned up.

8. Kill well, run tubing (when applicable), and put on

pipeline.

Table 2Summary of Operational Changes Before Changing Cement Design

Description Specific Gravity

Initial sample caught at bulk plant 2.98

4 in. from bottom of tank 2.91

10 in. from bottom of tank 2.8614 in. from bottom of tank 2.89





Maximum 2.97

Minimum 2.86

Average 2.90

Standard Deviation 0.04

Final sample caught from pneumatic line during mixing 2.97

Samples Caught after Approximately 160 Miles

Table 3Results of Deblending Check after 300 Miles of Travel


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8 IADC/SPE 98869

Final mud type (when interval is complete) 14 lb/gal WBM

BHST 360oF (1.76

F/100 ft)

MD 16,500 ft

TVD 16,500 ft

Estimated drilled-hole size (from offset calipers) 13.25-in. (drilled with 12 1/4-in. bit)

TOC 5,200 ft

Assumed casing standoff 65%

Displacement fluid for cementing job 14-lb/gal WBM

Lithology basis for rock properties Sandstone, sandy limestone

Maximum casing test pressure profile 14 lb/gal WBM plus 3,000-psi surface pressure

Table 4Initial FEA Modeling Assumptions, 9 5/8-in. Casing


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IADC/SPE 98869 9

20-in., 133-lb K-55 BTC

13 3/8-in. 68-lb HCK-55 BTC

7-in. Tie-back string010,000 ft, 7-in. 41-lb HCQ-125

Top of 7-in. liner

9 5/8-in. 53.5-lb HCP-110 BTC

Bossier "L"

20,022 ft

20,422 ft

10,00014,381 ft,

7-in. 41-lb HCQ-125 STL

18,735 ft

18,833 ft

19,023 ft

4 1/2-in. 18.80-lb Q-125 STL 20,940 ft

2,901 ft

14,910 ft

TOC

7,195 ft

14,381 ft

18,516 ftBossier "C"

Bossier "K"

Top of 4 1/2-in. liner packer

Bossier "D"

7-in. 41-lb Q-125

Fig. 1Original well design.


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IADC/SPE 98869 11

Fig. 3Thermal simulator results for cementing operation.

Fig. 4Thermal simulator results, post-cementing thermal recovery.


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Depth

Surface Casing F MW FIT

24 3/4-in. Wall conductor 70 8.4 10.0

1,000

WBM

2,000

3,000 16-in., 84-lb J/K-55 BTC 131 9.5

8.3 11.0

4,000

5,000

2 7/8-in., 8.7-lb Tubing

9.5

6,000

WBM

14.5 lb/gal Inhibited packer fluid

7,000

8,000

9,000

10,000

258 10.0

9.5 14.0

11,000

12,000

WBM

13,000

14,000

13.5

315 14.5 18.5

15,000

OBM

16,000

18.0

18.0 19.5

17,000

OBM

18,000 5-in. Production casing

0-6,000 ft, 23.2-lb C-110

6,00019,000 ft, 23.2-lb P-110

19,000 408 18.5 107/115

64

82

75

6 1/2-in.

10 5/8-in.

0

4

6

23

14 3/4-in.

Bits

22-in.

Days

7 5/8-in., 39-lb P-110 liner

8 1/2-in.

12

56

11 7/8-in., 71.8-lb TCA-140 and Q-125

9 5/8-in., 53.5-lb Q-125 liner

28

Fig. 7Final well design.


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14 IADC/SPE 98869

Fig. 8Design limit plot of new HTHP casing design.

Fig. 9Remaining capacities, new casing and completion loads with conventional cement design. Risk of damageover load phases; depth along well=18,000 ft; cement material=19.0-lb/gal conventional Class H cement.


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IADC/SPE 98869 15

Fig. 10New casing and optimum completion plan with conventional cement. Risk of damage over load phases; depth alongwell=18,000 ft; cement material=19.0-lb/gal conventional Class H cement.


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16 IADC/SPE 98869

Fig. 11Remaining capacity summary, final HTHP casing and cement sheath design. Risk of damage over load phases;depth along well=18,000 ft; cement material=19-lb/gal elastic system.


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Fig. 12Elastic cement after pressure cycling.

Fig. 13Conventional cement after cycling.


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18 IADC/SPE 98869

Fig. 14Remaining capacities and plastic deformation; original lead cement at 10,500 ft. Risk of damage over load phases; depth alongwell=10,550 ft; cement material=12.7-lb/gal water-extended cement.

Fig. 15Remaining capacities and plastic deformation; original tail cement at 16,500 ft. Risk of damage over load phases; depth alongwell=16,500 ft; cement material=16.4-lb/gal conventional cement.


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IADC/SPE 98869 19

Fig. 16Remaining capacities of new lead cement design for 9 5/8-in. casing at 16,500 ft. Risk of damage overload phases; depth along well=10,550 ft; cement material=13.2-lb/gal Class H cement and pozzolan blend.


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20 IADC/SPE 98869

Fig. 17 Remaining capacities of tail cement for 9 5/8-in. casing at 16,500 ft. Risk of damage over load phases;depth along well=16,500 ft; cement material=16.4-lb/gal Class H nonshrinking cement.

Fig. 18FYSA adapter kit for rotational rheometer.


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Fig. 19Regression analysis of YPA data.

Fig. 20 Job placement summary.

SpacerLeadSlurry

TailSlurry

Displacement


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22 IADC/SPE 98869

Fig. 21CBL of elastomeric tail slurry after 15,000-psi casing pressure test.


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paper spe-98869-ms-p-2 copy.pdf

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