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8/10/2019 Paper SPE-98869-MS-P-2 copy.pdf
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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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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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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.
8. Forced-closure flowback and flow to tanks until
cleaned up.
9. Kill well, run tubing, and put on pipeline.
Final Procedures Used on First Well Procedures Used Today
1. Displace cement job with 10 lb completion brine.
2. WOC for minimum specified time to ensure
mechanical property development.
3. RIH with workstring and circulate out with 3%
KCl water.
4. Pressure test casing and wellhead to 15,000 psi.
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.
8. Forced-closure flowback and flow to tanks until
cleaned up.
9. Kill well, run tubing, and put on pipeline.
1. Displace cement job with 12.8 lb completion
brine.
2. WOC for minimum specified time to ensure
mechanical property development.
3. RIH with workstring and circulate out with 3%
KCl water.
4. Pressure test casing and wellhead to 15,000 psi.
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
20 in. from bottom of tank 2.87
25 in. from bottom of tank 2.91
31 in. from bottom of tank 2.86
41 in. from bottom of tank 2.97
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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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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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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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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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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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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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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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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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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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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Fig. 21CBL of elastomeric tail slurry after 15,000-psi casing pressure test.
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