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Solid-Expandable Liner System WithCustom Composite Frac Plugs Enables

Recovery of Lost Reserves in thePiceance Basin

Chris Caplis, SPE, WPX Energy Rocky Mountain; John Cameron, SPE, Enventure Global Technology;

Darwin Holte, SPE, Mesa Wireline; and Garrett Frazier, SPE, Magnum Oil Tools International

Summary

Casing-integrity failure, whether through parted casing, leaky col-lars, or some other issue, may result in less-effective stimulationwork caused by abandonment of the plug-and-perforate methodand/or completing through a frac liner. In more-extreme cases, itcould result in lost reserves below the casing-failure point. Mod-ern technology has provided a cost-effective solution to thisproblem.

In this case, the operator confirmed parted 4 1/2-in. production

casing at 9,761 ft (Fig. 1) in their northern Piceance basin acreage.The operator would have to repair the parted casing to fracture thelower six zones of the well. The plug-and-perforate method for zonal isolation was required to effectively complete the 2,825-ftvertical pay interval. To complete the stimulation program, thegoals were to repair the short section of damaged casing andrestore pressure integrity to the well while maintaining a sufficientinner diameter (ID) to allow composite frac plugs to pass throughthe repair and set in the base casing’s larger ID below the split. Af-ter a corrugated patch failed to provide casing integrity, the solu-tion was a 3 1/2-in. single-joint solid-expandable system that wasexpanded downhole to cover and seal the parted 4 1/2-in. casing inconjunction with the use of custom-made composite frac plugs.

The 30-ft, 3 1/2-in. solid-expandable high-pressure/high-tem-perature (HP/HT) liner system was deployed and expanded in a

single trip. This system provided the required pressure integrity towithstand the fracturing pressures needed in this area. The 3.261-in. drift ID of the expanded-solid liner allowed the operator to runcustom 3.06-in.-outer-diameter (OD) composite frac plugs belowthe repaired section and successfully complete the well.

This installation was a success because the operator had essen-tially written off 63% of the well’s reserves caused by the casingpart occurring above a majority of the pay interval. The operator is now realizing full production from the entire well. Moreover,this single-joint solid-expandable liner technology coupled withthe special drillable composite frac plugs can be used in any HP/ HT formation to repair the common issue of damaged casing toallow plug-and-perforage completions to continue.

Introduction

Casing failures are one of the oldest and potentially costliestissues in the oil and gas industry. Immeasurable time, energy, andcapital have been spent over the years trying to find a solution tothis common but debilitating problem. Solid-expandable-tubular technology has proved to be a cost-effective solution to many cas-ing-integrity issues. Originally designed for, among other things,high-pressure zones in deepwater environments*, solid-expanda-

ble technology has evolved from isolated applications inextremely expensive cases to the inland-development programfound in many basins throughout the world (Waddell and Schuur-mans 2004). In addition to the improvements in solid-expandable-tubular technology, engineering advancements in coiled-tubingand frac-plug technology have also provided answers to histori-cally expensive and perplexing casing-failure questions.

Because operators use solid-expandable-tubular technology inincreasingly creative ways, other limitations present themselves.One example is the ID restriction an operator inherits resultingfrom a casing patch/liner. An issue such as parted casing might beresolved, but if the casing patch is above a portion, or all, of theidentified pay zone, then creative engineering is needed to effec-tively complete the reservoir below the patch.

An ID restriction in a wellbore provides additional frictionalpressure loss during stimulation operations. It also provides a bot-tleneck for proppant to settle and eventually stuck tubing andwireline operations. More pertinent to this paper, the ID restric-tion of an expandable casing patch, though much less than for conventional frac liners, prevents conventional frac plugs frompassing through the casing patch and setting in the existing casingbelow the repaired section of pipe, that, in this case, left six of the10 identified completion intervals stranded (Fig. 1). The operator chose not to immediately complete the upper four zones in the

well because that would have compounded the problem by havingto isolate the perforations placed above the casing patch if andwhen the operator desired to complete the lower six intervals.

The remedy to this particular problem would come in the formof a frac plug that could pass through the restricted ID of the ex-panded casing patch and set in the casing below. Finally, the cas-ing patch and frac plug would have to be able to withstand thehigh differential pressures typically seen in this portion of thePiceance basin.

ScenarioDescription

With more than 4,000 wells producing in the basin, the operator has encountered casing-integrity issues on several occasions. Pastremedies include stimulating past frac liners with sand plugs, try-ing to contact reserves from nearby wells with large-volume frac

jobs, or simply abandoning the reserves below the casing-failurepoint. These have not proved to be cost-effective. The desired so-lution has always been to repair the casing and continue to use theplug-and-perforate completion method.

During the casing-integrity test before completion, the opera-tor witnessed a rapid pressure loss at 2,500 psi. A multifinger-imaging-tool (MIT) log was run and identified a radial casing partfrom 9,761 to 9,762 ft. A cast-iron bridge plug was set at 9,815 ftalong with a cement retainer set above the part; the part was thensqueezed with cement. After the retainer and cement were drilledout, a pressure test was attempted and failed. Though its internalyield strength would have limited completions, a 60-ft corrugatedpatch was selected because its final ID would allow existing frac

plugs to pass through and set below the repair. However, after thecorrugated patch was deployed and installed across the casing

CopyrightVC 2013 Society of Petroleum Engineers

This paper (SPE 159751) was accepted for presentation at the SPE Annual TechnicalConference and Exhibition, San Antonio, Texas, USA, 8–10 October 2012, and revised forpublication. Original manuscript received for review 8 October 2012. Revised manuscriptreceived for review 28 November 2012. Paper peer approved 28 February 2013.

* The advent of solid expandable tubular technology has proved to be a cost-effective solu-tion to many casing-integrity issues.

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split, the pressure test was again unsuccessful. The pressure leakwas determined to be at the patch. An injection test was per-formed and the patch was squeezed with cement. Again, the cas-ing-pressure test failed. At this point, the operator decided to millthe patch and re-evaluate available options.

No activity occurred on the well for the next year. Remedia-tion capital was eventually allocated to repair the split, but thisquestion remained—Should the operator attempt the repair, or should he salvage what reserves he could through the upper four stages? The decision was made to explore repair options. Thesearch began for an HT/HP solid-expandable casing patch thatwould have a sufficiently large post-expansion ID for the passingof a composite frac plug and an internal yield-strength rating greatenough to withstand the high treating pressures in this area. Thesingle-joint, 30-ft, 3 1/2-in., tubing-conveyed, solid-expandable,HP/HT liner system was chosen because it met all these require-

ments. The selection of a patch provided the post-expansion driftID needed to design the frac plug. Because this specific frac plug

did not exist at the time, the operator began working with a ven-dor that could create the composite frac plug that was drillableand could pass through the single-joint expandable liner, set in thebase casing, and withstand 300F temperature and a minimum6,000-psi differential pressure.

WorkflowThroughApplicationDesign

After a year of no activity, several aspects of the damaged wellwere reviewed for a second time to reorient the team as to theexact status of the wellbore. A second MIT log was run to deter-mine casing damage incurred during milling operations and toconfirm the orientation and length of the split (Fig. 2). With a 1-ft, 45 radial split from 9,761 to 9,762 ft, the single-joint, 30-ft, 31/2-in., solid-expandable, HP/HT liner system (with an internalyield strength of 11,560 psi) became the strongest section of thewell after installation. Schematics of the launcher assembly andelastomers were reviewed. Preinstallation activities were dis-cussed, and a full-installation procedure was written up andapproved by the operator’s field and office personnel. During thereview of the installation process, several topics were discussed atlength, including

Casing was pressure tested above and below the proposedsetting depth to make sure there are no unknown leaks above or below the target leak.

Preparation of the wellbore was critical. During pressuretesting above and below the casing split, the base casing neededto be cleaned, free of any obstructions, and drifted to ensure that

the launcher could be run to the prescribed setting depth. This canbe performed with either a tandem stabilizer assembly or a built-

100% penetration

Fig. 2—MIT image showing radial casing split at 9,761 ft.

Fig. 1—Wellbore schematic with casing part and pay zonesidentified.

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for-purpose drift. In either case, the assembly used to achieve thiswas the test packer with an OD of 3.77 in. This assembly gave theteam confidence that the wellbore was in suitable shape for the ex-pandable-liner installation. This assembly should be at leastapproximately 6 ft and have a diameter equivalent to the largestOD of the pre-expanded single-joint liner, which in this case isthe elastomer-seal OD (3.840 in.) that is slightly less than the driftof the casing (3.875 in.). It is recommended that the drift assem-bly be run with a positive-blade casing scraper and a bit or mill onbottom and that the drift be run below the total depth at which theliner will be set.

The tubing used to convey the single-joint solid-expandableliner was 2 3/8 in., 4.6 lbm/ft, EUE 8rd P-110, necessitated by thedepth and the 8,000-psi internal pressure needed to expand theliner. This grade of tubing also provided adequate joint yieldstrength, if needed.

Placement of the patch was corrected back to wireline depthwith a gamma ray/casing collar locator tool. Tubing joints werealso counted before and after the single-joint solid-expandableliner was in place before expansion and ready to be expanded.

The drilling assembly used to drill out the single-joint solid-expandable-liner pressure plate was gauged and consisted of a 31/4-in. mill, bit sub, and 2 3/8-in. P-110 EUE tubing.

Because confidence was built with the single-joint solid-ex-pandable liner, focus turned to the composite frac plug that wouldbe needed to pass through the expanded single-joint liner and set

in the base casing. The frac-plug vendor was given a post-expan-sion drift ID of 3.261 in. and a base-casing drift ID of 3.875 in.;

however, the plug would have to set in the nominal casing ID of 4.00 in. and withstand the differential pressure anticipated duringfrac treatments. The plug would have to be drillable and containminimal aluminum components. The operator also requested thatthe plug have flow-through capabilities and a temperature ratingup to 300F (Fig. 3).

To determine the pressure rating needed, the operator eval-uated 29 frac stages from wells in the same section/township/ range as the damaged well. Bottomhole pressures were calculated,and flowback rates and pressures were analyzed along with sur-face treating pressures. It was determined that the composite plug

would need a differential-pressure rating of at least 6,000 psi. Theoperator requested an 8,000-psi rating. Finally, a 3 1/4-in. com-posite frac plug was modified to 3.06 in. and tested for pressureand temperature capacity. The test revealed that 300F tempera-ture was not a problem; however, even though the plug couldwithstand pressures more than 6,000 psi, the vendor was not com-fortable rating the custom plug at greater than 6,000 psi.

The final plug test occurred in a different well to be completedbefore the casing repair. A nearby offset was chosen, and comple-tion operations were performed. The lower six zones of the offsetwell were completed with the wireline-conveyed custom-compos-ite frac plug run on the bottom of the perforation gun. The bottomstage was fracture stimulated, the gun and plug for the next stagewere run, and the plug was set and perforations were made. Next,the stage was completed, exposing the plug to fracturing pressure.

After this stage, the next plug and gun were run, and the processwas repeated until the bottom six stages were completed. At thispoint, the well was flowed back. After a couple of days, a serviceunit was brought in to drill out the test plugs. The custom plugs per-formed to specification because each one was exactly where it wasplaced before stimulation operations and was drilled without issue.

Now that the single-joint solid-expandable-liner and plugdesigns were reviewed and tested, the final design component hadto do with drilling out the plugs with the restricted ID of the liner and the production tubing string to be run in the well after com-pletion operations were finished. Coiled tubing (CT) with a 1.688-in. OD would be used to drill out the frac plugs above and belowthe repair. After all plugs were drilled out, the production-tubingstring would be landed in the well.

One production-string issue that required attention was theneed to increase the annular space between the ID of the expandedliner and the OD of the tubing collar. The expanded-liner ID of 3.261 in. combined with the 2 3/8-in. EUE-collar OD of 3.063 in.warranted the flush-joint tubing option through the liner to miti-gate particles packing off in the annular space between theexpanded liner and the tubing collar. Therefore, the productiontubing string would consist of the following components:

1,990 ft. of 2 3/8-in., 4.6-lbm/ft L-80 flush-joint tubing(open-ended)

Crossover sub 9,330 ft of 2 3/8-in., 4.6-lbm/ft N-80 EUE tubing.

Installation andPerformance

To begin the installation process, a service unit was rigged up over the well, and a 2 3/8-in., 4.6-lbm/ft, P-110 tubing was run in thehole to 9,900 ft to circulate the wellbore. After consistent, cleanreturns were coming back, the tubing was pulled. The single-jointsolid-expandable liner was run in the hole along with a crossover,one 6-ft. P-110 pup joint, and 307 joints of 2 3/8-in., 4.6-lbm/ft, P-110 tubing to place the center of the liner across from the part. Apipe tally was performed, and a wireline gamma ray tool was runto correlate tubing and patch depth. After a safety meeting, thewell was circulated at 1 bbl/min to clean the liner-setting ball seat.At this point, the ball was dropped, and circulation began until apressure increase was witnessed, signaling the landing of the ballin the liner-setting ball seat. After the ball landed, expansion wasstarted by pressuring up the tubing to 8,000 psi. The liner was then

expanded with a 10,000-lbf overpull on the work string and an av-erage of 6,000 psi of hydraulic pressure as the expansion cone

3.25" 3.06"

Green composite

components were trimmed

down from 3.25 inches to

3.06 inches

Fig. 3—Custom-composite frac plug.


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slowly expanded the liner from bottom to top. After the liner wasexpanded and the launcher assembly was stung out of theexpanded single-joint liner, a casing-pressure test was performedto 4,000 psi as an immediate test to determine whether casing in-tegrity had improved. The 4,000-psi pressure test was a success.Tubing was pulled; a 3 1/4-in. mill, a bit sub, and tubing were runin the hole to drill out the pressure plate in the liner. Tubing taggedthe pressure plate at 9,775 ft (after correcting to wireline depth),confirming the liner was set at the correct depth. After operationswere drilled and reamed, the pressure plate then circulated the wellwhile working through the lower portion of the expanded single-

joint liner. Confident that the pressure plate had been drilled andall components had been circulated out of the wellbore, one couldprepare for stimulation operations to begin.

A final pressure test to 8,500 psi was performed, and the casingpassed. It was decided to run a 3.25-in. gauge ring through the

expanded single-joint liner before every perforating run to ensureplugs and guns would not get hung up in the liner. The first gauge

ring that was run before perforating the bottom interval would notpass through the expanded single-joint liner. After sizing down to3.15 in., the gauge ring still would not pass through the expandedsingle-joint liner ID of 3.261 in. A 3.20-in. watermelon mill wasrun in the hole and milled the top of the expanded liner brieflybefore falling through the rest of the expanded single-joint liner with no issue. After the frac head was reinstalled and tested, thebottom frac interval was perforated; the 2.50-in. guns went throughthe expanded liner without incident. The bottom stage was com-pleted, a 3.20-in. gauge ring was run through the expanded single-

joint liner, and the custom plug with perforation gun for the nextstage was run without issue. The plug was set, and perforationswere shot. The stage was completed, and the process was repeatedup the wellbore for the remaining stages below the repair withoutincident. The four stages above the expanded liner were then com-pleted with conventional composite frac plugs. With no sand or hang-up issues through the expanded single-joint liner duringcompletions, attention was turned to the drill-out process.

The 1.688-in. CT was used to drill out all plugs. After drillingthe frac plugs above the liner, the 3.875-in. underreamer could notget past 9,700 ft. It was pulled out of the hole (POOH), and a3.15-in. mill, motor, and CT were run to 9,700 ft to work throughthe tight spot. The mill was used to clean through the liner, tag thefirst custom frac plug below the liner, and was POOH. In prepara-tion to drill out the remaining frac plugs below the liner, the CTbottomhole assembly consisted of a 3.15-in. mill, a 3.875-in.

underreamer, a mud motor, and jars. With minimal sand on plugs,the plug location was correct for every plug run below the liner (Fig. 4). At this point, the CT was POOH, and the well was put onflowback/sales. After flowback pressures and water rates dropped,a snubbing unit was moved in and rigged up to snub in productiontubing. The production-tubing string consisted of 60 joints of 2 3/ 8-in. flush-joint tubing to be run through the liner and below, fol-lowed by 286 joints of 2 3/8-in., 4.6-lbm/ft L-80 tubing landed inthe production tree.

The final wellbore schematic is shown in Fig. 5.

Summary Discussion

The operator was faced with the issue of casing-integrity failurein one of their Piceance basin wells. It is a problem that the opera-

tor has faced several times over the course of drilling and com-pleting more than 4,000 wells in the basin. The economics of running a frac liner with slimhole perforating guns and possiblyfishing the liner out of the hole, combined with a less effectivestimulation, did not appeal to the operator. Writing off two-thirdsof the well reserves by completing only the upper four zones wasalso uneconomical. Furthermore, after unsuccessful attempts torepair the well with a corrugated liner and cement squeezes, thewell sat dormant for a year as the team re-evaluated how best tomove forward. A different expandable liner was chosen becauseof its solid, single-joint design; high internal yield strength; andlarge post-expansion ID. Custom frac plugs were designed, tested,and used along with CT to put the well on full production.

With minimal operational problems throughout the installationof the single-joint solid-expandable liner, the running of the plugs,and drillout/flowback of the well, opportunities for improvementare largely focused on cost. CT worked for this project; however,moving forward, the use of a service unit with slim tubing wouldbe more cost-effective to drill out plugs below the expanded sin-gle-joint liner.

Ultimately, the operator was able to address a familiar issue ina way that enabled full recovery of the well’s reserves. This was afirst for the operator, considering the high treating pressure andlocation of the split. The plug-and-perforate method had not beenan option in the past; however, in the future moving forward, theoperator has a cost-effective solution that enables the use of plugsand ensures the operator that effective stimulation of the payinterval is still possible.

Solid-expandable-tubular technology, engineering advance-

ments in frac-plug design, and CT advancements have given theoil and gas industry tools that were not available in the past.

Fig. 4—Single-joint solid-expandable liner installed, indicatingfrac-plug type and location post-stimulation.

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Supplemental to the case outlined in this paper, the application of these technologies could involve, but certainly are not limited to,

multiple parts in a casing string, sliding-sleeve bypass, or isolationof perforations that are no longer necessary.

This paper strives to convey the benefit of stepping back from afamiliar issue and thinking through all possible solutions, particu-larly those solutions that have not been tried in the past. Finally, thiscase study should be viewed as yet another example of how a teamcan accurately diagnose a problem, think through a solution thatclearly meets the defined criteria, and show how field testing the so-lution before application is the wayto ensure safe and reliable wells.

Acknowledgments

The authors wish to thank management at WPX Energy, Enven-ture Global Technology, and Magnum Oil Tools for approval topublish and present this paper. In addition, the authors wish tothank the WPX EnergyÀPiceance Field completions staff andoffice, including Jay Foreman, Kent Hejl, and Brian O’Dell;members of the Enventure Global Technology engineering andoperations teams, including Chris Cornelius, Kris Mitrushi, andRobert Goss; and the design staff at Magnum Oil Tools, includingLynn Frazier, Mark Chaudoir, Ken Yong, and Derrick Frazier.

References

Waddell, K. and Schuurmans, R. 2004. Installation of Solid Expandable

Tubular Systems Through Milled Casing Windows. Paper SPE 87208

presented at the IADC/SPE Drilling Conference, Dallas, texas, 2À4

March. http://dx.doi.org/10.2118/87208-MS.

Chris Caplis is Completions Team Lead for the Piceance basinfor WPX Energy Rocky Mountain, LLC in Denver. He has 15 yearsof oil and gas experience in drilling and completion engineer-ing, with most of his time spent in the Rocky Mountains. Capliscurrently oversees completions in the Niobrara formation forWPX Energy in the Piceance basin. He earned a BS degree inpetroleum engineering from Louisiana Tech University.

John Cameron is currently the Well Services Solutions Managerat Enventure Global Technology in Houston, where he hasbeen working for nearly 2 years. At Enventure, Cameron pro-motes and develops solutions with solid-steel expandable cas-ing and liners for well-production and completion challenges.Before coming to Enventure, he worked as a consultant for 11/2 years with Eclipse Petroleum Technology in Houston, andas a consultant for 9 years for PCM Technical in Tulsa. At thesecompanies, Cameron consulted in the areas of drilling, wellcompletions, unconventional reservoirs, and geomechanics.Before his role as a consultant, he worked as a staff engineerfor 18 years at Amoco Production Technology Center in Tulsain completions and drilling-technology development, with afocus on hydraulic-fracturing materials evaluation and specifi-cation, drilling-fluid hydraulics, formation-damage evaluationand remediation, and completions optimization. Cameronhas authored a number of SPE publications and has published

in the Oil & Gas Journal, Journal of Rheology, and Colloids and Surfaces. He earned PhD and MS degrees in chemical en-gineering at the University of Michigan and The Ohio State Uni-versity, respectively, and a BS degree in mathematics at TheOhio State University. He is a registered petroleum engineer inOklahoma.

Garrett Frazier is the Director of Sales and Marketing for Mag-num Oil Tools International. He graduated with a Bachelors ofBusiness Administration degree majoring in marketing fromTexas A&M University, Corpus Christi. While pursuing his market-ing degree, Frazier began his career in the oil and gas industryas an assembly manager and ran jobs for Magnum Oil Tools inCorpus Christi, Texas. Since that time, he has worked closelywith his father and CEO of Magnum Oil Tools International,Lynn Frazier, helping him develop and market Magnum’s cur-rent line of patented well-completion products. Today, Frazieroversees all marketing and US sales efforts with offices in Cor-pus Christi, Texas; Midland, Texas; Oklahoma City, Oklahoma;and Calgary.

Darwin Holte has 40 years of oil-and-gas-industry experience,most of it in the electric wireline business. He has spent the last10 years as part owner and General Manager/Vice of MesaWireline in Grand Junction, Colorado. Holte recently took aposition as Technical Sales Manager/Rocky Mountains forMagnum Oil Tools based in Grand Junction, Colorado.

Fig. 5—Final completed wellbore with production tubinglanded.


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