60 Oilfield Review

Isolate and Stimulate Individual Pay Zones

Kalon F. DegenhardtJack StevensonPT. Caltex IndonesiaRiau, Duri, Indonesia

Byron GaleTom Brown Inc.Denver, Colorado, USA

Duane GonzalezSamedan Oil CorporationHouston, Texas, USA

Scott HallTexaco Exploration and Production Inc. (a ChevronTexaco company)Denver, Colorado

Jack MarshOlympia Energy Inc.Calgary, Alberta, Canada

Warren ZemlakSugar Land, Texas

ClearFRAC, CoilFRAC, CT Express, DepthLOG, FMI (FullboreFormation MicroImager), Mojave, NODAL, PowerJet,PowerSTIM, PropNET, SCMT (Slim Cement Mapping Tool)and StimCADE are marks of Schlumberger.For help in preparation of this article, thanks to TarynFrenzel and Bernie Paoli, Englewood, Colorado; Badar ZiaMalik, Duri, Indonesia; and Eddie Martinez, Houston, Texas.

Coiled tubing-conveyed fracturing is a cost-effective alternative to conventional

reservoir-stimulation techniques. This innovative approach improves hydrocarbon

production rates and recovery factors by providing precise, reliable placement of

treatment fluids and proppants. What began as a fracturing service is evolving into

broad technical solutions for new completions, as well as workovers in mature fields.

Operators traditionally rely on drilling programs toachieve peak productivity, maintain desired pro-duction levels and optimize hydrocarbon recovery.As oil and gas developments mature, however,reservoir depletion reduces field output and feweropportunities exist to drill new wells. Drilling pro-grams alone may not effectively stem the naturaldecline of production. In addition, infill and reen-try drilling often become less profitable and pre-sent greater operational and economic risksrelative to their higher capital investments.

In many fields, operators intentionally andunintentionally bypass some pay zones duringinitial phases of field development by focusingonly on the most prolific producing horizons.Cumulatively, these marginal pay intervals con-tain substantial hydrocarbon volumes that can beproduced, especially from laminated formationsand low-permeability reservoirs. Accessingbypassed pay zones is economically attractive toenhance production and increase reserve recov-ery, but poses several challenges.

Typically, bypassed zones have lower perme-abilities and require fracturing treatments toachieve sustainable commercial production.Conventional well-intervention and stimulationmethods involve extensive remedial operations,such as mechanically isolating existing perfora-tions or squeezing them with cement and utiliz-ing multiple runs to perforate bypassed pay.

These procedures are expensive and cannot bejustified for zones with limited production poten-tial. In the past, fracture stimulations were notcommonly attempted on bypassed pay, especiallywhen multiple stringers were involved.

The mechanical condition of wellbores can bea limitation as well. If fracture stimulations are notanticipated during well planning, completion tubu-lars may not be designed to withstand high-pressure pumping operations. Also, scale buildupand corrosion from prolonged exposure to forma-tion fluids at reservoir temperatures and pressurescan compromise tubular integrity in older wells. Inslimhole wells, workover options are further lim-ited by small tubulars. These operational and eco-nomic constraints often mean that bypassed ormarginal pay remains untapped. Ultimately, hydro-carbons in these intervals are left behind whenwells are plugged and abandoned.

Integration of coiled tubing with fracturingoperations overcomes many of the constraintsassociated with stimulating bypassed ormarginal pay zones using conventional tech-niques, allowing additional reserves to be tappedeconomically. High-strength continuous coiledtubing strings transport treatment fluids andproppants to target intervals and protect existingwellbore tubulars from high-pressure pumpingoperations, while specialized downhole toolsselectively isolate existing perforations withincreased precision.

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> A fit-for-purpose CT Express coiled tubing unit performing a selective fracturing treatment in Medicine Hat, Alberta, Canada.

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This article describes operational and designaspects of coiled tubing-conveyed fracturingtreatments, including enabling technologies suchas surface equipment improvements, high-pres-sure coiled tubing, low-friction fracturing fluidsand new downhole isolation tools. Case historiesdemonstrate how this technique reduces comple-tion time and cost, improves post-treatmentcleanup, increases production and helps tapreserves bypassed by conventional completionand fracturing methods.

Conventional StimulationsAverage recovery factors for most reservoirs fromprimary- and secondary-drive mechanisms arejust 25 to 35% of original hydrocarbons in place.Producible reserves also are left behind in thin,lower permeability zones of many mature reser-voirs. One North Sea study, for example, deter-mined that more than 25% of recoverablereserves lie in the low-permeability, laminatedhorizons of Brent sandstone reservoirs.1

Matrix acidizing and hydraulic fracturing arecommon reservoir-stimulation techniques used toenhance well productivity, increase recovery effi-ciency and improve well economics.2 However,effectively completing and stimulating heteroge-

neous reservoirs and discontinuous pay zonesamong numerous shale intervals are challenging,particularly when fracture stimulations arerequired. Reservoir pay thickness, quality, pres-sure and stage of depletion, and cost to treat anentire productive horizon all must be consideredwhen choosing completion strategies.

Conventional fracture stimulations attempt toconnect as many producing zones as possiblewith single or multiple treatments performed dur-ing separate operations. Historically, net payzones over several hundred feet of gross intervalare grouped into “stages,” with each stage stim-ulated by a separate fracturing treatment. Thesemassive hydraulic fracturing jobs, pumpeddirectly down casing or through standard jointedtubing, are designed to maximize fracture heightwhile attempting to optimize fracture length.However, uncertainty associated with predictingheight growth often compromises the stimulationobjectives of large treatments and precludes cre-ation of the fracture lengths required to optimizeeffective wellbore radius and reserve drainage.

Proppant placement in individual zones is dif-ficult to achieve when a single treatment is per-formed across numerous perforated zones(below). Thin or low-permeability zones grouped

with thicker zones may remain untreated or maynot be stimulated effectively, and some zones areoccasionally bypassed intentionally to ensureeffective stimulation of more prolific pay. Limited-entry perforations and ball sealersdistribute fluid efficiently during pad injection,but less effectively during proppant placement as perforations are enlarged by erosion or treatment fluids flow preferentially into higherpermeability zones.3

Unintentionally bypassed and untreatedzones also are attributed to variable in-situstresses. In past conventional fracturing designs,the fracture gradient, or stress profile, wasassumed to be linear and to increase graduallywith depth. In reality, formation stresses oftenare not uniform across an entire geologic horizon,and again, some zones may be difficult to treatand stimulate effectively (next page, top).

Grouping pay zones in smaller stages over-comes some of these limitations and helpsensure sufficient fracture coverage, but multi-stage treatments usually require several perfo-rating and fracturing operations in succession.Isolating individual zones for conventional frac-ture stimulations with workover rigs and jointedtubing is problematic as well, requiring addi-tional equipment and workover procedures.There are fixed costs associated with each stageof multistage fracturing operations. Conventionalfracturing operations add redundancy to stimula-tion operations and increase overhead costs.

Every time wireline units and pumping equip-ment are moved onto a wellsite for perforatingand stimulation operations there are separatemobilization and setup charges. There are alsoseparate coiled tubing or slickline costs to washout sand plugs or set and retrieve bridge plugs,which have to be purchased or rented. Hauling,handling and storing stimulation and displacementfluids for each nonconsecutive fracturing opera-tion involve additional costs. Testing each individ-ual stage in a well again requires multiple setupsand significantly increases completion time.

Some gas wells with several large treatmentstages may take weeks to complete. Redundantcharges accumulate quickly on wells with morethan three or four stages and significantly affectthe economics of stimulation procedures. Thesehigher costs typically become a major influenceon completion or workover decisions and strate-gies and may limit development of marginal payzones that cumulatively contain sizeable volumesof oil and gas.

To stimulate bypassed zones in existingwells, conventional fracturing requires that lowerproducing zones be isolated by a sand plug or

62 Oilfield Review

> Single-stage treatment diversion: radioactive tracers and production logs. With limited-entry tech-niques, some zones are not stimulated effectively and others may remain untreated. In this example,six pay zones over a 300-ft [90-m] gross interval were fractured through 24 perforations. A radioactive-tracer survey shows that the three upper zones received most of the treatment fluids and proppant,while the three lower zones were not adequately stimulated (left). If an interval did not take fluid at thebeginning of a treatment, perforation erosion in other sands eliminated the backpressure necessaryfor diversion. The lowest zone contributes no production; the other two contribute very little flow onthe production log spinner survey (right).

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downhole mechanical tool such as a retrievableor drillable bridge plug. Upper perforations aresealed off by cement squeezes that are often dif-ficult to achieve, require additional rig time andadd to completion costs. There also is a risk thatsqueezed perforations will break down duringhigh-pressure pumping operations.

These limitations, inherent in conventionalfracturing techniques, reduce stimulation effec-tiveness. Unconventional well intervention andstimulation techniques are needed to ensurehydrocarbon production from as many intervalsas possible, especially from zones that previouslycould not be completed economically. Coiled tub-ing-conveyed fracturing techniques overcomemany of the limitations associated with conven-tional fracturing treatments (below left).4

Selective StimulationsCombining coiled tubing and stimulation servicesis not new. In 1992, coiled tubing was used tofracture wells in Prudhoe Bay, Alaska, USA. The31⁄2-in. coiled tubing was connected into the well-head and left in the well as production tubing tohelp maintain flow velocity. This technique never gained wide acceptance because it waslimited to smaller intervals and lower treatingpressures in wells where a single zone was targeted for completion.

1. Hatzignatiou DG and Olsen TN: “Innovative ProductionEnhancement Interventions Through Existing Wellbores,”paper SPE 54632, presented at the SPE Western regionalMeeting, Anchorage, Alaska, USA, May 26-28, 1999.

2. In matrix treatments, acid is injected below fracturingpressures to dissolve natural or induced damage thatplugs pore throats.Hydraulic fracturing uses specialized fluids injected atpressures above formation breakdown stress to createtwo fracture wings, or 180-degree opposed cracks,extending away from a wellbore. These fracture wingspropagate perpendicular to the least rock stress in apreferred fracture plane (PFP). Held open by a proppant,these conductive pathways increase effective wellradius, allowing linear flow into the fractures and to thewell. Common proppants are naturally occurring orresin-coated sand and high-strength bauxite or ceramicsynthetics, sized by screening according to standard USmesh sieves. Acid fracturing without proppants establishes conductiv-ity by differentially etching uneven fracture-wing sur-faces in carbonate rocks that keep fractures fromclosing completely after a treatment.

3. Limited entry involves low shot densities—1 shot per footor less—across one or more zones with different rockstresses and permeabilities to ensure uniform acid orproppant placement by creating backpressure and limit-ing pressure differentials between perforated intervals.The objective is to maximize stimulation efficiency andresults without mechanical isolation like drillable bridgeplugs and retrievable packers. Rubber ball sealers canbe used to seal open perforations and isolate intervalsonce they are stimulated so that the next interval can betreated. Because perforations must seal completely, holediameter and uniformity are important. The pad stage of a hydraulic fracturing treatment is thevolume of fluid that creates and propagates the fractureand does not contain proppant.

4. Zemlak W: “CT-Conveyed Fracturing Expands ProductionCapabilities,” The American Oil & Gas Reporter 43, no. 9(September 2000): 88-97.

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> Variations in formation stress. In single, multizone treatments, pressurechanges are assumed to be linear with depth (far left). Depleted zones causepressure to decrease abruptly (middle left). Excessively depleted sands alsoreduce pressure over extensive intervals (middle right). In some cases, for-mations have pressure and stress variations that make diversion of treatmentfluids and stimulation coverage during a single-stage treatment extremelydifficult (far right).

> Conventional and selective stimulations. Fracturing several zones groupedin large intervals, or stages, is a widely used technique. However, fluid diver-sion and proppant placement are problematic in discontinuous and heteroge-neous formations. Conventional treatments, like this four-stage example,maximize fracture height, often at the expense of fracture length and com-plete interval coverage (left). Some zones remain untreated or may not bestimulated adequately; others are bypassed intentionally to ensure effectivetreatment of more permeable zones. Selective isolation and stimulation withcoiled tubing, in this case nine stages, overcome these limitations, allowingengineers to design optimal fractures for each pay zone of a productive interval (right).

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By 1996, coiled tubing-conveyed fracturingwas identified as a preferred completion strategyfor shallow gas fields in southeastern Alberta,Canada.5 Selective placement of proppant in allthe productive intervals of a wellbore reducedcompletion time and enhanced productivity. Thebest candidates were wells with multiple low-permeability zones where gas production wascommingled after fracturing. Previously, thesewells were stimulated by fracturing one intervalper well and then moving to the next well. Whilea fracturing crew treated the first interval of thenext well, a rig crew prepared previous wells forfracturing of subsequent intervals.

Extensive rig-up and rig-down times wererequired to treat as many as four wells a day. Interms of number of treatments performed, thisprocess was efficient, but moving equipmentfrom one location to another took more time thanactually pumping the fracturing treatments.Operators evaluated the possibility of groupingzones into stages for conventional multizonestimulations using limited-entry perforating, ballsealers or other diversion techniques to individu-ally isolate zones, but could not justify thesestandard industry practices economically.

One solution was to use a coiled tubing ten-sion-set packer and sand plugs for zonal isolation.The lowest zones were treated first by setting the

packer above the interval to be fractured.Proppant schedules for each zone included extrasand to leave a sand plug across fractured inter-vals after pumping stopped and before treatingthe next zone. Each treatment was underdis-placed, and wells were shut in to allow the extrasand to settle into a plug. A pressure test verifiedsand-plug integrity and the packer was resetabove the next interval. This procedure wasrepeated until all pay intervals were stimulated(above). The larger coiled tubing string was riggeddown and smaller coiled tubing was brought in towash out sand and initiate well flow.

Coiled tubing-conveyed fracturing has sinceexpanded to slimhole wells—23⁄8-, 27⁄8- and 31⁄2-in.tubulars cemented as production casing—and towells with open perforations or questionabletubular integrity that prevented fracturing downcasing. Conventional workovers and stimulationsthat require cement squeezes to isolate openperforations are expensive and risky under theseconditions. Shallow gas and deeper coiled tubingstimulations in mature oil and gas regions of thecontinental region of the United States formedthe basis for CoilFRAC selective isolation andstimulation services.

In east Texas, USA, coiled tubing was used tostimulate wells with open perforations abovebypassed zones and wells with low-strength 27⁄8-in. production casing weakened further by

corrosion. After the target zone was perforated, atension-set packer on coiled tubing isolated thewellbore and upper perforations (next page, topleft). In south Texas, bypassed pay zonesbetween open perforations in wells with casingdamage near the surface were stimulated suc-cessfully by setting a bridge plug below the tar-get zone and then running a tension-set packeron coiled tubing (next page, top right). Thesefracture stimulations were performed withoutcementing existing perforations or exposing pro-duction casing to high pressures.

Early CoilFRAC techniques with tension-setpackers improved stimulation results, but werestill time-consuming and limited by having to setand remove plugs. The next step was to developa coiled tubing straddle-isolation tool that sealedabove and below an interval to eliminate sepa-rate operations for spotting sand or setting bridgeplugs with a wireline unit (next page, bottom). Thismodification allowed coiled tubing strings to bemoved quickly from one zone to the next withoutpulling out of the well.

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5. Lemp S, Zemlak W and McCollum R: “An EconomicalShallow-Gas Fracturing Technique Utilizing a CoiledTubing Conduit,” paper SPE 46031, presented at theSPE/ICOTA Coiled Tubing Roundtable, Houston, Texas,USA, April 15-16, 1998. Zemlak W, Lemp S and McCollum R: “Selective HydraulicFracturing of Multiple Perforated Intervals with a Coiled Tubing Conduit: A Case History of the UniqueProcess, Economic Impact and Related ProductionImprovements,” paper SPE 54474, presented at theSPE/ICOTA Coiled Tubing Roundtable, Houston, Texas,USA, May 25-26, 1999.

> Coiled tubing-conveyed fracturing with a single tension-set packer and sand plugs.

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> Multistage coiled tubing-conveyed fracturing operation with early straddle-isolation tools.

> Coiled tubing-conveyed fracturing with a singletension-set packer for casing and tubing protection.

> Coiled tubing-conveyed fracturing with a singlepacker and mechanical bridge plugs. In southTexas, a well with casing damage near the sur-face and a bypassed zone between existing openperforations was stimulated successfully withcoiled tubing. The operator set a bridge plug toisolate the lower zone before running a tension-set packer on coiled tubing to isolate the upperzone and protect the casing. This technique elimi-nated a costly workover and remedial cement-squeeze operations.

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Elastomer cup-type seals were added above atension-set packer to isolate perforated intervalsand eliminate separate plug-setting operations.However, additional modifications were requiredto further reduce time and cost. In Canada, anisolation tool with elastomer cups above andbelow an adjustable ported spacer assembly, ormandrel, was developed to allow multiple zonesto be treated in one trip (right).

This version of the straddle-isolation tool,which had no mechanical slips to facilitate quickmoves and fishing, carried shallow-gas projectsin Canada through more than 200 wells and 1000individual CoilFRAC treatments. Continuingimprovements to this tool allow bypassed andmarginal zones to be stimulated at nominal incre-mental cost. Efficient isolation and stimulation ofindividual sands maximized completed net payand made zones previously considered marginaleconomically viable.

More Experience in CanadaWildcat Hills field is located west of Calgary,Alberta, Canada, on the eastern slope of theRocky Mountains in a protected grassland area.6

This area has produced natural gas from deepMississippian discoveries since 1958. During theearly 1990s, two Olympia Energy wells testedshallower Viking sands. The wells initially pro-duced about 900 Mcf/D [25,485 m3/d], butdeclined rapidly to 400 Mcf/D [11,330 m3/d].Although pressure-buildup and production testsindicated substantial reserves, the low reservoirpressure, poor deliverability and high completioncosts precluded development of marginal Viking zones.

A 1998 seismic survey identified a third Vikingtarget in an area where the formation wasuplifted by more than 3000 ft [914 m], potentiallycreating natural fractures that might enhance gasdeliverability. The 3-3-27-5W5M well encoun-tered about 45 ft [14 m] of pay in five zonesacross 82 ft [25 m] of gross interval (next page,top). An FMI Fullbore Formation MicroImagermicroresistivity log verified existing natural frac-tures in the reservoir, but drillstem testing indi-cated a low pressure of 1100 psi [7.6 MPa].Pressure-buildup tests before setting 41⁄2-in. cas-ing and after perforating indicated drilling-fluidinvasion into natural fractures and additional for-mation damage from completion fluids.

A mud-solvent treatment failed to remove thedamage, so a fracturing treatment was selected

to increase gas deliverability. Fracturing downcasing with limited-entry diversion was not anoption because the well had already been perfo-rated. The operator evaluated diversion with ballsealers as well as mechanical zonal isolationwith sand plugs, bridge plugs or coiled tubing.Ball-sealer effectiveness is questionable, espe-cially during fracturing treatments, so mechani-cal diversion was deemed the most reliablemethod to ensure stimulation of all pay zones.

With only 13 to 16 ft [4 to 5 m] between fourzones, engineers eliminated use of sand plugsbecause close spacing made it difficult to accu-rately place the correct sand volumes.Conventional jointed tubing with packers andbridge plugs for isolation involved separate oper-ations to treat individual zones one at a time fromthe bottom up. This required repeated equipmentmobilization and demobilization, redundant ser-vices for each zone and retrieving or movingbridge plugs after each treatment—all of thesemade the costs prohibitive.

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> Coiled tubing isolation tools. The first CoilFRAC operations used a single tension-set packer above a zone with sand plugs or bridge plugs to isolatebelow the zone (left). Subsequent versions were modified to include an upperelastomer seal cup above the zone and a lower packer to isolate below (mid-dle). This second-generation tool was followed by a straddle design with elas-tomer seal cups on the top and bottom of a ported spacer, which increasedthe speed of packer moves, and reduced execution time as well as operationalcosts (right). These specialty tools eliminated rig and wireline operationsbecause sand plugs and bridge plugs were not needed. Coiled tubing could be moved quickly from one zone to the next without pulling out of the well.

6. Marsh J, Zemlak WM and Pipchuk P: “EconomicFracturing of Bypassed Pay: A Direct Comparison ofConventional and Coiled Tubing Placement Techniques,”paper SPE 60313, presented at the SPE Rocky MountainRegional/Low Permeability Reservoirs Symposium,Denver, Colorado, USA, March 12-15, 2000.

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The operator selected CoilFRAC services tostimulate each zone separately and treat severalzones in a single day. On the first day, the jointedtubing string used to perform production tests andthe solvent treatment was pulled from the well.Coiled tubing, fracturing and testing equipmentwas moved to location on the second day while awireline unit set a bridge plug to isolate the lowerViking formation. The maximum recommendedinterval that the isolation tool could straddle atthat time was 12 ft [3.7 m], which was less thanthe length of the lowest interval, so a tension-setpacker was used to fracture the first zone.

Three fracture stimulations were attemptedon the third day. Sticking problems required thestraddle-isolation tool to be pulled for repair ofthe elastomer seal cups. A casing scraper runsmoothed the rough casing. This step is now performed routinely before CoilFRAC treatmentsas part of wellbore preparation. Annulus pres-sure increased while pumping pad fluids in thesecond interval, indicating possible communica-tion behind pipe or fracturing into an adjacentzone. This treatment was cancelled before initi-ating proppant, and the tool was moved to thethird interval.

After the fourth interval was stimulated, thestraddle-isolation tool was pulled, so that open-ended coiled tubing could be used to clean outsand and unload fluids. On the fourth day, a snub-bing unit ran jointed production tubing in the wellunder pressure to avoid formation damage fromcompletion-fluid invasion.

To eliminate the snubbing unit, coiled tubingnow is used to run a packer with an isolationplug. After the packer is set, coiled tubing isreleased and removed from the well. The packerplug controls reservoir pressure until jointed pro-duction tubing is run. A slickline unit thenretrieves the isolation plug, initiating well flow.

Before stimulation, the 3-3-27-5W5M wellflowed 3.5 MMcf/D [99,120 m3/d] of gas at 350-psi [2.4-MPa] surface pressure. After threeof the upper four zones were fractured success-fully, the well produced 6 MMcf/D [171,818 m3/d]at 350 psi. The well continued to produce at 5 MMcf/D [143,182 m3/d] and 450 psi [3.1 MPa]for several months. The CoilFRAC treatmentdelivered an economic production gain in addi-tion to reducing cleanup time and simplifyingcompletion operations (left). Minimal operationsand faster cleanup helped bring production online sooner by reducing completion cycle timefrom 19 to 4 days.

>Well 3-3-27-5W5M, Wildcat Hills field. Previous attempts to stimulate the Viking formation as a contin-uous interval were not successful because of difficulty in intersecting multiple zones with conventionalsingle-stage fracture treatments. Closely spaced perforated intervals prohibited isolation with a packerand sand or bridge plugs. Selective CoilFRAC treatment placement simulated four zones individually toincrease recovery by isolating and fracturing pay that often is bypassed or left untreated. Secondarygoals were to simplify several days of completion operations into a single day and reduce cost.

> Comparison of conventional and CoilFRAC Viking completions. Coiled tub-ing-conveyed fracture stimulations required 58% less total proppant, reducedoverall completion operations from 19 days to 4, and improved well cleanupand fracturing fluid recovery. CoilFRAC treatment placement and simultane-ous flowback improved fluid recovery and saved Olympia Energy about$300,000 per well in the Wildcat Hills field, which reduced cost per Mcf/D byabout 78%.

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Olympia Energy drilled six more wells in theWildcat Hills field after completion of the 3-3-27-5W5M well. Because the Viking formation variesfrom well to well, the operator selected fractur-ing techniques based on sand thickness, fracturecontainment barriers, vertical spacing betweensands and required number of treatments. Threeof these wells contained two or three thick Vikingsands that were fractured down casing. Thelarger zones required higher pump rates to opti-mize fracture height and length, which ruled outuse of coiled tubing because of potentially exces-sive surface treating pressures.

Like the 3-3-27-5W5M well, the other threewells had similar interbedded sand-shalesequences and 6- to 13-ft [2- to 4-m] pay zones,so Olympia Energy used CoilFRAC selective stim-ulations. This approach increased productivityand recovery by selectively treating pay that hadbeen bypassed or not stimulated effectively, andit ultimately decreased operational costs.

Pre- and post-treatment production logs wererun on the 4-21-27-5W5M well to evaluateincreased production from zones in one of the

wells that was fractured using coiled tubing (below). Prior to fracturing, the well produced2 MMcf/d [57,300 m3/d] with flow from two intervals. After CoilFRAC treatments on five intervals, gas production increased to4.5 MMcf/D [128,900 m3/d] with flow from fourof the five intervals. Olympia Energy saved$300,000 per well on fracturing operations aloneby using CoilFRAC techniques to stimulateWildcat Hills Viking wells. One of the original Vikinggas wells has been reevaluated and identified asa candidate for stimulation with coiled tubing.

At a depth of 8200 ft [2500 m], this coiled tub-ing-conveyed application demonstrated theimpact of combining coiled tubing and stimula-tion technologies on well productivity andreserve recovery. The smaller surface footprint,less time on location and fewer wellsite visitscombined with less gas emissions and flaring asa result of flowing, testing and cleaning up all thepay zones at one time make CoilFRAC treatmentsparticularly attractive in environmentally sensi-tive areas like the grasslands around WildcatHills field.

Fracturing Designs and OperationsCoiled tubing-conveyed fracturing is constrainedby restrictions on fluid and proppant volumesrelated primarily to smaller tubular sizes andpressure limitations. The application of CoilFRACservices requires alternative fracture designs,specialized fluids, high-pressure coiled tubingequipment, and integrated fracturing and coiledtubing service teams to ensure effective stimula-tions and safe operations.7

Injection rates, fluid parameters, treatmentvolumes, in-situ stresses and formation charac-teristics determine the net pressure availabledownhole to create a specific fracture geo-metry—width, height and length. Minimumpump rates are required to generate the desiredfracture height and to transport proppant alongthe length of a fracture. Minimum proppant con-centrations are needed to attain adequate frac-ture conductivity.

Coiled tubing strings have a smaller internaldiameter (ID) than the standard jointed work-strings used in conventional fracturing opera-tions. At the injection rates required for hydraulicfracturing, frictional pressure losses associatedwith proppant-laden slurries can lead to hightreating pressures that exceed surface equip-ment and coiled tubing safety limits. Using largercoiled tubing reduces friction pressures, butincreases equipment, logistics and maintenancecosts, and may not be practical for small-diame-ter slimhole and monobore wells.

This means that treatment rates and proppantvolumes for coiled tubing-conveyed fracturingmust be reduced compared with those of con-ventional fracturing. The challenge is to achieveinjection rates and proppant concentrations thattransport proppant effectively and create therequired fracture geometry. Coiled tubing-con-veyed fracturing requires alternative equipmentand treatment designs to ensure acceptable sur-face treating pressures without compromisingstimulation results.

Reservoir characterization is the key to anysuccessful stimulation treatment. Like conven-tional fracturing jobs, coiled tubing treatmentsmust generate a fracture geometry consistentwith optimal reservoir stimulation. The preferredapproach is to design CoilFRAC pumping sched-ules that balance required injection rates andoptimal proppant concentrations with coiled tub-ing treating-pressure constraints. Fracturing fluidselection depends on reservoir characteristicsand fluid leakoff, downhole conditions, requiredfracture geometry and proppant transport. Fluids

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> Pre- (left) and post-stimulation (right) evaluation. Production log spinner surveys in Viking Well 4-21-27-5W5M confirmed that CoilFRAC selective fracturing treatments in each Viking sand improved theproduction profile and total gas rate (right).

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for CoilFRAC treatments include water-base lin-ear or low-polymer systems and polymer-freeClearFRAC viscoelastic surfactant (VES) fluids.8

In the past, polymers provided fluid viscosityto transport proppant. However, residue fromthese fluids can damage proppant packs andreduce retained permeability. Engineers oftenincrease proppant volumes to compensate forany reduced fracture conductivity, but slurry friction increases exponentially with higher prop-pant concentrations and can limit the effective-ness of CoilFRAC treatments. Increased surfacetreating pressure from frictional pressure lossesis the dominant factor in coiled tubing-conveyedfracturing, so reducing surface pump pressures iscritical in CoilFRAC applications, particularly indeeper reservoirs.

Because of their unique molecular structure,VES fluids exhibit as much as two-thirds lower frictional pressures than polymer fluids (right). Nondamaging ClearFRAC fluids may pro-vide adequate fracture conductivity with lowerproppant concentrations at acceptable surfacetreating pressures. This facilitates optimized frac-ture designs. These fluid characteristics makecoiled tubing-conveyed fracturing feasible at com-monly encountered well depths.

Another advantage of ClearFRAC fluids isreduced sensitivity of fracture geometry to fluidinjection rate. Height growth is better contained,resulting in longer effective fracture lengths,which is particularly important when treating thin,closely spaced zones. Fluids based on a VES alsoare less sensitive at downhole temperatures and conditions that cause fracturing fluids to break prematurely.

If pumping stops because of an operationalproblem or fracture screenout, the stable suspen-sion and transport characteristics of ClearFRACfluids prevent proppants from settling too quickly,especially between the seal cups of straddle-iso-lation tools. This allows time to clean out remain-ing proppant and decreases the risk of stuck pipe.In addition, these fluids provide a backup contin-gency in high-risk environments, such as high-angle or horizontal wells, where proppant settlingalso can be a problem.

Recovering treatment fluids is critical whentarget zones have low permeability or low bot-tomhole pressure. Another benefit of VES fractur-ing fluids is more effective post-stimulationcleanup. Field experience has shown that VESfluids break down completely in contact withreservoir hydrocarbons, through extended dilu-tion by formation water or under prolonged expo-sure to reservoir temperature, and aretransported easily into wellbores by produced flu-ids. Retained permeability is close to 100% of

original permeability with VES fluids. In addition,treating and flowing back all the zones at onetime improve fluid recovery and fracture cleanup.

High-strength, 13⁄4- to 27⁄8-in. coiled tubing isused to accommodate higher injection pressures.Coiled tubing for fracturing operations is fabri-cated from high yield-strength, premium-gradesteels with high burst pressure. For example, 13⁄4-in., 90,000-psi [621-MPa] yield strength coiledtubing has a burst-pressure rating of 20,700 psi[143 MPa] and can withstand collapse pressuresof 18,700 psi [129 MPa]. Coiled tubing is hydro-statically tested to about 80% of its burst-pressurerating, 16,700 psi [115 MPa] for this 13⁄4-in. stringprior to pumping operations, and maximum pumppressure is set at 60% of the design burst pressure, or about 12,500 psi [86 MPa], forthis example.

Because the entire coiled tubing string con-tributes to friction pressure, regardless of howmuch is inserted in a well, the length of coiledtubing on a reel should be minimized relative tothe deepest interval. There has been concernthat centrifugal forces on the proppant woulderode the inner wall of spooled coiled tubing.However, visual and ultrasonic inspection beforeand after fracturing found no erosion inside thecoiled tubing and detected only minor erosion atcoiled tubing connectors after pumping as manyas nine treatments.

Operational safety is critical at the high pres-sures required for hydraulic fracturing treat-ments. For example, personnel should not bepermitted near wellheads or coiled tubing equip-ment during pumping operations. Coiled tubing-conveyed fracturing requires specialized surfaceequipment and innovative modifications to

ensure safe operations and to deal with contin-gencies in the event of a screenout.9 On the surface, coiled tubing equipment, such as quick-response, gas-operated relief valves, remotelyoperated fracturing manifolds and modificationsto coiled tubing reels and manifolds, allow high-rate pumping of abrasive slurries.

Precise depth control also is important forselective stimulations. Inaccurate positioning ofcoiled tubing results in serious and costly prob-lems—perforating off-depth, placing a sand plugin the wrong place, problems positioning straddle-isolation tools or stimulating the wrong zone.Straddle-isolation tools must be positioned accu-rately across perforated intervals. Five types ofdepth measurements are used: standard level-wind pipe measurements as coiled tubing comesoff the reel, a depth-monitoring system in the injector head, mechanical casing-collar locatorsand two new independent systems used by Schlumberger—the Universal Tubing-LengthMonitor (UTLM) surface measurement and theDepthLOG downhole casing-collar locator.

7. Olejniczak SJ, Swaren JA, Gulrajani SN and OlmsteadCC: “Fracturing Bypassed Pay in TubinglessCompletions,” paper SPE 56467, presented at the SPEAnnual Technical Conference and Exhibition, Houston,Texas, USA, October 3-6, 1999.Gulrajani SN and Olmstead CC: “Coiled Tubing ConveyedFracture Treatments: Evolution, Methodology and FieldApplication,” paper SPE 57432, presented at the SPEEastern Regional Meeting, Charleston, West Virginia,USA, October 20-22, 1999.

8. Chase B, Chmilowski W, Marcinew R, Mitchell C, Dang Y,Krauss K, Nelson E, Lantz T, Parham C and Plummer J:“Clear Fracturing Fluids for Increased Well Productivity,”Oilfield Review 9, no. 3 (Autumn 1997): 20-33.

9. A screenout is caused by proppant bridging in the frac-ture, which halts fluid entry and fracture propagation. Ifa screenout occurs early in a treatment, pumping pres-sure may become too high and the job may be termi-nated before an optimal fracture can be created.

> Effect of friction-reducing fluids. As CoilFRAC applications expand to includedeeper wells, low-friction fluids will be a key to future success. This plot com-pares surface-treating pressure versus depth for 2-in. coiled tubing using apolymer-based fracturing fluid and a ClearFRAC viscoelastic surfactant (VES)fluid, both with 4 ppa proppant concentrations.

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In the past, the accuracy of standard coiledtubing depth measurements was about 30 ft[9.1 m] per 10,000 ft [3048 m] under the best con-ditions and as much as 200 ft [61 m] per 10,000ft in the worst cases. The dual-wheel UTLM sur-face measurement is self-aligning on the coiledtubing, minimizes slippage, offers improved wearresistance and measures unstretched pipe(below).10 Two measuring wheels constructed ofwear-resistant materials, on-site data processingand routine calibration eliminate the effects ofwheel wear on surface measurement repeatabil-ity and provide automatic redundancy in additionto slippage detection.

The remaining factors that affect measure-ment accuracy and reliability are contaminantsand buildup on wheel surfaces, and thermaleffects that change wheel dimensions. An anti-buildup system prevents contamination of wheelsurfaces. Downhole coiled tubing pipe deforma-tion is evaluated using computer simulation. For thermal pipe deformation modeling, a well-bore simulator provides a temperature profile.The total deformation can be estimated with anaccuracy of about 5 ft [1.5 m] per 10,000 ft. Thecombination of more accurate surface measure-ments with modeling and improved operationalprocedures result in about a 11 ft [3.4 m] per10,000 ft accuracy, and a repeatability of about 4 ft [1.2 m]. In most cases, a value of less than 2 ft[0.6 m] is achieved.

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> The UTLM dual-wheel surface depth-measurement device.

> Hiawatha field producing horizons. In the Hiawatha field of northwest Colorado (insert), pay zones historically were grouped in intervals, or stages,of 150 to 200 ft [46 to 61 m] and stimulated with a single fracture treatment.Thin sands were grouped with thick sands, and occasionally thin sandswere bypassed to avoid less effective stimulation of more prolific sands.Multiple hydraulic fracture stages were still required to treat the entire wellbore. Each fracture stage was isolated with a sand plug or mechanicalbridge plug. Justifying completion of thin sands capable of 100 to 200 Mcf/D[2832 to 5663 m3/d] was difficult.

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Previously, depth correction with wirelineinside coiled tubing or memory gamma ray log-ging tools, “flags” painted directly on the coiledtubing and mechanical casing-collar locatorsoften were inaccurate, costly and time-consum-ing. Schlumberger now uses a wirelessDepthLOG tool, which detects magnetic varia-tions at joint casing collars as tools are run into awell and sends a signal to surface throughchanges in hydraulic pressure. Subsurfacedepths are determined quickly and accurately bycomparison with baseline gamma ray correlationlogs. The use of wireless technology decreasesthe number of coiled tubing trips into a well andsaves up to 12 hours per operation on typicalcoiled tubing-conveyed perforating and stimula-tion operations.

In the past, separate coiled tubing services, ifrequired, followed fracturing operations to cleanout excess proppant. Coiled tubing-conveyedfracturing, however, requires the combinedefforts of fracturing and coiled tubing personnel.Initially, service crews faced a steep learningcurve as they began working together to reducethe time required for various operations.Subsequent CoilFRAC projects increased opera-tional efficiency and reduced completion time. Tofurther increase efficiency, Schlumberger hasformed dedicated CoilFRAC teams to integratecoiled tubing and fracturing expertise.

Revitalizing a Mature FieldTexaco Exploration and Production Inc. (TEPI),now a ChevronTexaco company, extended the productive life of West Hiawatha field inMoffat county, Colorado, USA, with CoilFRACtechniques.11 Discovered in the 1930s, this field has 18 pay sands over 3500 ft [1067 m] of gross interval. Gas production comes from the Wasatch, Fort Union, Fox Hills, Lewis andMesaverde formations (previous page, right).Previously, wells were completed with 41⁄2-, 5- or7-in. casing and stimulated using conventionalstaged fracturing treatments.

A common practice was to stimulate zonesfrom the bottom upward until production rateswere satisfactory. As a result, thin zones oftenwere ignored and undeveloped uphole potentialexisted throughout the field. In 1999, TEPI evalu-ated bypassed pay in the field to identify and rankworkover potential based on reservoir quality,cement integrity, completion age and wellboreintegrity. New drilling locations were identifiedafter a successful workover on Duncan Unit 1Well 3, but the challenge was to develop a strat-egy that could effectively stimulate all of the payzones during initial completion operations.

The operator chose CoilFRAC services toselectively stimulate Wasatch and Fort Unionsands, which comprise multiple sands from 5 to60 ft [1.5 to 18 m] thick from 2000 to 4000 ft [600to 1200 m] deep. This approach provided flexibil-ity to design optimal fracture treatments for eachzone rather than large jobs to intersect multiplezones over longer intervals.

In the first drill well, individual CoilFRACtreatments were performed on 13 zones in threedays. Seven zones were treated in a single day.This well’s average first month production was2.3 MMcf/D [65,900 m3/d]. The second drill wellinvolved eight treatments in one day. Averageproduction from the second well during the firstmonth was 2 MMcf/D. Treating pressures rangedfrom 3200 psi [22 MPa] to the maximum allow-able 7000 psi [48 MPa].

Zones separated by 10 to 15 ft [3 to 4.6 m]were fractured with no communication betweenstages. Pump-in tests verified that fracture gradi-ents between zones varied from 0.73 to 1 psi/ft[16.5 to 22.6 kPa/m]. The variation in fracturegradient for each zone confirmed the difficulty ofstimulating multiple zones with conventionalstage treatments (above). In addition to eightworkovers with mixed success, nine successful

10. Pessin JL and Boyle BW: “Accuracy and Reliability ofCoiled Tubing Depth Measurement,” paper SPE 38422,presented at the 2nd North American Coiled TubingRoundtable, Montgomery, Texas, USA, April 1-3, 1997.

11. DeWitt M, Peonio J, Hall S and Dickinson R:“Revitalization of West Hiawatha Field Using Coiled-Tubing Technology,” paper SPE 71656, presented at theSPE Annual Technical Conference and Exhibition, NewOrleans, Louisiana, USA, September 30-October 3, 2001.

> Evaluating single-stage Hiawatha field fracture stimulations. Without selective isolation of individualsands, variations in fracture gradients make it difficult to optimize fracture lengths with a single con-ventional treatment and limited-entry perforating. For two Wasatch zones that would be grouped whenstimulating multiple intervals with a single treatment, StimCADE hydraulic fracturing simulator plotsindicate that about two-thirds of the proppant is placed in the upper interval (top). This results in awider, more conductive fracture and a half-length almost 50% greater than in the lower interval (bottom). If there are more than two zones, this problem is further compounded by variations in dis-continuous sands from wellbore to wellbore.

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wells were drilled in Hiawatha field from May2000 through July 2001. These new wells werecompleted with CoilFRAC stimulations in theWasatch and Fort Union formations, and conven-tional fracture treatments for the more continu-ous Fox Hills, Lewis and Mesaverde intervalsbelow 4000 ft [1220 m].

To quantify coiled tubing stimulation results,the CoilFRAC completions were compared withwells fractured conventionally between 1992 and1996 (right). Average production from CoilFRACcompletions increased 787 Mcf/D [22,500 m3/d],or 114%, above historical rates. However, pro-duction from individual wells may be misleadingif reserves are drained from offset wells. Fieldoutput will not increase as expected when thereis interference between wells; natural pressuredepletion should result in new wells producingless, not more.

From 1993 to 1996, Hiawatha field outputincreased from 7 to 16 MMcf/D [200,500 to460,000 m3/d] as a result of the 12-well drillingprogram. Production doubled again from 11 to 22 MMcf/D [315,000 to 630,000 m3/d] as a resultof workovers and new wells completed mostlywith coiled tubing-conveyed stimulations. Fieldproduction is at the highest level in 80 years.Stimulating each zone individually during initialcompletion operations is believed to be the keyto improving production and increasing reserverecovery in this mature field.

State-of-the-Art Downhole ToolsIsolation tools have evolved along with CoilFRACtreatments and specific requirements generatedby various stimulation applications. Coiled tubing-conveyed fracturing operations are performedunder the most dynamic reservoir stimulationconditions. Treatments take place in live wells atformation temperatures and pressures, and withthe completion of each selective stimulation,these conditions change. As a result, increasinglydemanding applications in deeper wells requiremore reliable, multiple-set isolation tools.

Driven by a need to minimize operational andfinancial risks and reduce the impact ofunplanned events, like proppant screenout,Schlumberger developed the CoilFRAC Mojaveline of downhole tools (next page). This improvedstraddle system consists of three technologies—the pressure-balanced disconnect, the modularstraddle assembly with ported sub, and the slurrydump valve. In combination, these componentsprovide selective placement of sequential acid orproppant fracture stimulations, and matrix acid,

screenless sand-control or scale-inhibitor treat-ments in a single trip with coiled tubing.

The pressure-balanced disconnect features amechanical shear disconnect that is pressure-balanced to coiled tubing treating pressure. Onlymechanical coiled tubing loads are transferred tothe shear-release pins; treating pressure doesnot affect the shear-pin release function. Thisreduces the likelihood of leaving the tool in awell as a result of unexpectedly high downholetreating pressures during CoilFRAC stimulations,such as a screenout. The pressure-balanced dis-connect allows coiled tubing to be run deepbecause the disconnect does not require extrashear pins to account for pressure loads duringtreatments. If the tool becomes stuck, it can befished by overshot or internal fishing neck.

The CoilFRAC Mojave isolation tool hasopposing elastomer cups for 41⁄2- to 7-in. casing.The tool functions in vertical or horizontal wellsand has no mechanical slips and no moving parts.An internal fluid bypass in the tool body permitsrunning to deeper depth—10,000 ft instead ofless than 4000 ft. This feature lightens coiledtubing loads during trips in and out of wells toreduce elastomer wear, minimize swab and surgeforces on formations and decrease the risk of atool sticking between zones. A modular designand special 2-ft [0.6-m] ported fracturing suballow 4-ft sections to be assembled for spacingelastomer cups up to 30 ft apart.

The CoilFRAC fracturing sub also includes afluid bypass and resists erosion when pumpingup to 300,000 lbm [136,100 kg] of sand. It is pos-sible to pump up to 500,000 lbm [226,800 kg] ofless erosive resin-coated and man-made ceramic proppants. Reverse circulation isrequired to clean the coiled tubing and CoilFRACMojave isolation tool when run without a slurrydump valve. A lower reversed bottom cup seals during reverse circulation to improve post-treatment cleanup. A gauge port is built into the tool for downhole pressure and temper-ature measurements.

Since the slurry dump valve (SDV) is flow-operated, no coiled tubing movement is required.One SDV design in two sizes is compatible withstandard 41⁄2- to 7-in. CoilFRAC Mojave tools and functions in vertical or horizontal wells.Incorporating a SDV allows slurry to be dumpedfrom the coiled tubing between zones and facili-tates stimulations in low-pressure reservoirs andformations with fracture gradients of less than afull water gradient, or 0.4 psi/ft [9 kPa/m].

The SDV is closed and acts as a fill valvewhen running in a well. It also reduces formationdamage during multizone well treatments.Reverse circulation is not required for coiled tub-ing cleanup, which reduces total stimulation fluidrequirements, eliminates the environmentalimpact of slurry returned to surface, reduceselastomer wear by equalizing pressure acrosselastomer seal cups, and reduces abrasive wearon coiled tubing and surface equipment.

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> Analyzing Hiawatha field coiled tubing fracturing results. Production fromwells completed with CoilFRAC selective isolation and simulation treatments(red) was compared with production from wells that were previously frac-tured conventionally (black). Average daily well rates for each month wasnormalized to time zero and plotted for the first six months. Initial productionfrom the CoilFRAC completions was about 787 Mcf/D [22,500 m3/d], or 114%,more than historical rates.

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Optimizing Recovery in South TexasSamedan Oil Corporation operates North Rinconfield in south Texas, producing gas from variouszones of the Vicksburg formation at 6000 to7000 ft [1800 to 2100 m]. The Martinez B54 well,completed in a single 25-ft [7.6-m] zone, had aninitial production rate of 4.5 MMcf/D beforedeclining to 1 MMcf/D. In December 2000,Samedan evaluated fracturing this zone for thefirst time as well as completing deeper pay in theMartinez B54 well. Openhole logs had identifiedseveral other productive zones that had beenintentionally bypassed because of marginal eco-nomics. In February 2001, Schlumberger assem-bled a multidisciplinary team to integratepetrophysical and reservoir knowledge with completion design, execution and evaluation services using the PowerSTIM stimulation opti-mization initiative.12

Samedan and the PowerSTIM team analyzedwell data to determine reservoir size and remain-ing reserves for the current producing zone.These calculations indicated a 19-acre [7700-m2]drainage area and confirmed that a nearby geo-logic unconformity acted as a seal. Productionand NODAL analyses matched the 1-MMcf/Dproduction and indicated that, based on a limiteddrainage area and low formation damage,remaining reserves could be recovered in a few months.13 This interval was not a candidatefor stimulation.

Samedan decided to deplete the existingzone before completing the most attractivebypassed zones. Reinterpreted logs indicated77 ft [23 m] of high-quality net pay with signifi-cant recoverable reserves in five deeper zonesover 700 ft [213 m] of gross interval.Conventional stimulation techniques requiredlimited-entry perforating for diversion of largefluid and proppant volumes pumped at high ratesto cover and fracture this entire interval.

The operator considered setting productiontubing and a packer below existing perforationsand completing only one or two of the uppermostbypassed zones. This approach, however, wouldleave a significant volume of additional reservesuntapped behind pipe. The PowerSTIM team rec-ommended CoilFRAC selective isolation serviceswith optimized fracture designs to complete andindividually stimulate all five bypassed zones. A2-in. coiled tubing string was selected to conveyfracturing fluids and proppant at the requiredrates. An SCMT Slim Cement Mapping Tool logconfirmed cement integrity and adequate zonalisolation behind pipe across the proposed completion intervals. The existing perforationswere sealed with a cement squeeze prior toCoilFRAC operations.

12. Al-Qarni AO, Ault B, Heckman R, McClure S, Denoo S,Rowe W, Fairhurst D, Kaiser B, Logan D, McNally AC,Norville MA, Seim MR and Ramsey L: “From ReservoirSpecifics to Stimulation Solutions,” Oilfield Review 12,no. 4 (Winter 2000/2001): 42-60.

13. NODAL analysis couples the capability of a reservoir toproduce fluids into a wellbore with tubular capacity toconduct flow to surface. The technique name reflectsdiscrete locations—nodes—where independent equa-tions describe inflow and outflow by relating pressure

> CoilFRAC Mojave isolation tools. From single mechanical packers to elas-tomer cup and packer combinations and the earliest versions of opposingelastomer-cup straddle tools, the suite of CoilFRAC tools has expanded toinclude specially designed straddle assemblies. The effectiveness of CoilFRACstraddle assemblies for zonal isolation has been aided by more reliable seal-ing technologies. An annular flow path within the assembly allows for easydeployment and retrieval.

losses and fluid rates from outer reservoir boundariesacross the completion face, up production tubing andthrough surface facility piping to stock tanks. Thismethod allows calculation of rates that wells are capa-ble of delivering and helps determine the effects of dam-age, or skin, perforations, stimulations, wellhead orseparator pressure and tubular or choke sizes. Futureproduction also can be estimated based on anticipatedreservoir and well parameters.

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In May 2001, Samedan and Schlumbergerperformed a five-stage CoilFRAC selective stimulation (next page, top). On the first day, thefive zones were perforated with deep-penetrat-ing PowerJet premium charges to maximize perforation entry-hole size and reservoir penetra-tion. After perforating, the commingled zonesproduced 1.1 MMcf/D [31,500 m3/d] during aprestimulation test.

On the second day, each zone was isolatedsequentially with a 5-in. CoilFRAC Mojave straddle tool and fracture-stimulated with a non-damaging ClearFRAC fluid and 136,000 lbm[61,700 kg] of man-made ceramic proppant. Allfive zones were treated within a 24-hour period.Pump rates ranged from 8 to 10 bbl/min [1.3 to1.6 m3/min] with treating pressures up to11,000 psi [76 MPa]. Because of potentially highgas production rates, PropNET fiber additiveswere incorporated at the end of the pumpingschedules to prevent proppant flowback.14

When all the zones were commingled andtested, the well flowed more than 5.1 MMcf/D[146,000 m3/d] and 120 B/D [19 m3/d] of conden-sate, which closely matched production predic-tions. A production log spinner survey indicatedthat four of the five Vicksburg zones had beenstimulated successfully (above and left). One monthlater, the well was still producing about 5 Mcf/D,which did not follow the expected decline.Estimated payout was three months. Samedanengineers evaluated the next three drill wells, butnone of these new wells were viable candidatesfor coiled tubing-conveyed fracture stimulation.

Completing five zones in a single trip miti-gated the risk of formation damage from multiplewell interventions, and risk of fluid swabbingassociated with conventional fracturing opera-tions, jointed tubing and standard downholetools. This CoilFRAC treatment took only twodays, while a conventional five-stage fracturingjob might have taken up to two weeks.

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< Martinez B54 well CoilFRAC treatment stimulation results for five zones.

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Additional ApplicationsThe combination of reservoir-stimulation andwell-treatment technologies with coiled tubingconveyance is expanding selective CoilFRACtechniques to include applications, like acid frac-turing, and specialized completion techniquessuch as scale inhibition, controlling proppantflowback and screenless sand control (above).

With advances in friction-reducing fluids,injection rates are sufficient for coiled tubing and CoilFRAC tools to be used as mechanical

diversion during acid fracturing. This capability isincreasingly important in mature carbonatereservoirs when small zones within larger pro-ducing intervals require stimulation. CoilFRACstimulations help operators deplete reserves uni-formly across an entire hydrocarbon-bearinginterval and facilitate reservoir management.

The downhole buildup of scales, asphaltenesor migrating fines and the plugging of perforationsand completion equipment impair permeabilityand can restrict or prevent production altogether.

Accurate CoilFRAC selective placement allowsscale inhibitors to be conveyed deeper into the for-mation during fracturing or acidizing stimulationtreatments. Integrating scale inhibitors and stimu-lation treatment fluids into a single step ensuresthat the entire productive interval—including theproppant pack—is treated.

Performing multiple, smaller fracture treat-ments is another approach to reduce scalebuildup and sand production. This methodreduces the pressure drop across the formationface, which decreases or, in some cases, pre-vents scale and asphaltene formation. Duringproduction, pressure drawdown increases thevertical stress on producing intervals and exacer-bates sand production. An alternative is to treatsmaller intervals and reduce the pressure dropacross the formation face.

Screenless Sand-Control CompletionsInnovative screenless completions provide sandcontrol without the need for downhole mechani-cal screens and gravel packing by using tech-nologies such as resin-coated proppants andPropNET fibers to control proppant flowback andsand production. The primary challenge of apply-ing screenless technology is ensuring coverageof all perforated pay zones. In general, intervallength is the controlling factor. Thicker intervalstypically reduce treatment success rates. Coiledtubing-conveyed fracturing, with the capability oftreating numerous zones, increases screenlesscompletion effectiveness and reduces overallcosts while increasing net pay potential.Treatments in North America have reduced prop-pant flowback by five-fold.

PT. Caltex Pacific Indonesia, a ChevronTexacoaffiliate, operates the Duri field in the CentralSumatra basin.15 Primary recovery is low, sosteam injection is used to achieve higher recov-ery factors. This multibillion-barrel steamflood cov-ers 35,000 acres [14 million m2] and produces280,000 B/D [44,500 m3/d] of high-viscositycrude oil. Oil-bearing sands are highly unconsoli-dated, Miocene-age formations with permeability

14. Armstrong K, Card R, Navarrete R, Nelson E, Nimerick K,Samuelson M, Collins J, Dumont G, Priaro M, Wasylycia Nand Slusher G: “Advanced Fracturing Fluids ImproveWell Economics,” Oilfield Review 7, no. 3 (Autumn 1995):34-51.

15. Kesumah S, Lee W and Marmin N: “Startup of ScreenlessSand Control Coiled Tubing Fracturing in Shallow,Unconsolidated Steamflooded Reservoir,” paper SPE74848, prepared for presentation at the SPE/ICOTACoiled Tubing Conference and Exhibition, Houston,Texas, USA, April 9-10, 2002.

> Martinez B54 well in the North Rincon field, south Texas (Courtesy of Samedan Oil Corporation).

> Unconventional coiled tubing-conveyed treatments. CoilFRAC treatments also are applicable forchemical scale inhibition and sand-control methods. Coiled tubing places scale inhibitors included in apreflush before fracturing or proppant impregnated with scale inhibitors more effectively than conven-tional treatment techniques (left). Novel screenless completions provide sand control without down-hole mechanical screens and gravel packing by using technology like resin-coated proppants andPropNET fibers to control proppant flowback and sand production (right). The primary challenge ofapplying these techniques is ensuring coverage of all perforated pay zones.

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as high as 4000 mD (right). Combined pay thick-ness is about 140 ft [43 m] over an interval fromX430 to X700 ft. In addition to 3600 producingwells, the operator maintains about 1600 steam-injection and temperature-observation wells.

Heat requirements are lower in temperature-mature areas where the steamflood has been inoperation for an extended period of time. Steaminjection can be reduced, allowing the operatorto convert injectors and observation wells intoproducers. Low reservoir pressure causesdrilling, completion and production problemsincluding lost circulation, hole collapse and sandproduction. Severe sanding leads to frequentwell servicing to replace worn or stuck artificial-lift equipment. The marginal nature of thesewells, initially completed with 4-, 7-, or 95⁄8-in. ODmonobore casing, limits conventional gravel-packed screens for sand control. In most wells,screens are not installed because of restrictedwellbore access, smaller pump sizes and, conse-quently, unfavorable production rates.

In a recent field test on several wells, theoperator in Duri field used CoilFRAC techniquesto perform screenless completions using curableresin-coated sand and tip-screenout fracturedesigns to prevent proppant flowback and migra-tion of formation grains.16 After resin-coated sandis placed and cured, proppant packs are locked in place to create a stable filter against the formation in perforation tunnels and near-wellbore regions.

Using resin-coated proppant to control sandwithout mechanical screens is not new. In 1995, aDuri field pilot project used conventional fractur-ing with resin-coated sand to complete Rindusands at about X450 ft. Single-stage tip-scree-nout treatments attempted to place resin-coatedproppant in multiple zones across 50 to 100 ft [15to 30 m] of gross interval. This technique failed toachieve acceptable results because the grossintervals were too long and not all perforationsreceived resin-coated sand. In addition, producedformation sand covered some lower zones andsteam injection did not cure the resin-coated sandacross the entire section.

The primary objectives of the most recentfield test were to ensure complete treatment coverage of all perforations and achieve tip-screenout fractures for proper proppant packing.Grain-to-grain contact and closure stress improvethe curing process and ensure a strong com-pacted filter medium. Heat or alcohol-base fluidscure phenolic resins. The operator uses bothmethods to ensure a complete resin set.CoilFRAC selective isolation and treatmentplacement provided accurate and complete per-foration coverage, which made screenless completions a viable alternative to gravel

packing or frac packing with screens, and previous screenless completions that wereattempted conventionally.

Fracture treatments and pumping scheduleswere designed to achieve required fracture half-length and conductivity. Relatively low pumpingrates control vertical coverage, while higherproppant concentrations are needed to ensurefracture conductivity and achieve tip screenout.The maximum rate is usually about 6 bbl/min[1 m3/min] with proppant concentrations of8 pounds of proppant added (ppa). The number oftreatment stages in a given well was determinedby evaluating perforated interval length andspacing between zones.

Interval length needed to be less than 25 ft toensure complete coverage with a minimum of 7 ft[2 m] between intervals to allow the isolationtool to set properly. The operator verified cementbond and quality to ensure isolation behind thepipe and avoid proppant channeling. Extra resin-coated sand deposited after each treatment iso-lated that interval from subsequent treatmentintervals. After all zones were treated, the oper-

ator left the well undisturbed for about 12 hoursto allow the resin to set and obtain adequatestrength. Partially cured resin-coated sand in thewellbore was drilled out prior to production.

With the exception of one well, screenlesscompletions significantly increased cumulativeoil production during nine months of evaluation(next page, left). Average failure frequencybefore CoilFRAC screenless completions was 0.5per well per month. The operator allocated 36 rigdays and 32,000 bbl [5080 m3] of deferred oil pro-duction for all four wells to clean out sand. AfterCoilFRAC screenless treatments were performed,failure frequency dropped to 0.14 per well permonth, resulting in an extra five months of oilproduction per well per year. Screenless

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16. In standard fracturing, the fracture tip is the final area to be packed with proppant. A tip-screenout designcauses proppant to pack, or bridge, near the end of thefractures in early stages of a treatment. As additionalproppant-laden fluid is pumped, the fractures can nolonger propagate deeper into a formation and begin towiden or balloon. This technique creates a wider, moreconductive pathway as proppant is packed back towardthe wellbore.

> Duri field, Indonesia, producing horizons and typical well completion.

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CoilFRAC treatments paid out in 35 to 59 days.However, the use of resin-coated sand inextremely hot steamflood conditions was foundto have limitations.

Early in the application of screenless comple-tions, the operator recognized a need to use inertproppant flowback control. The resin coating usedinitially in CoilFRAC screenless completions wasthermally stable to 375°F [191°C], but could fail insteam environments of 400°F [204°C]. As a result,periodic steam injection and flowback to stimu-late oil output could cause stress cycling andproppant-pack failure that resulted in sand pro-duction. Proppant flowback control using PropNETfibers rated to 450°F [232°C] is proving to be asolution to this problem.

The operator selected a local sand combinedwith PropNET fibers in place of resin-coated sandfor eight recent screenless completions in Durifield. The PropNET fibers were added throughout

sand-laden treatment stages to ensure completeinterval coverage. Optimized perforating tech-niques also has been introduced for screenlesssand control. These wells have minimal productiondata, but early production results are encouraging.

Milestones in Selective StimulationsSelective coiled tubing-conveyed isolation andstimulation have established a template forfuture workovers on existing wells and new wellcompletions. The CoilFRAC methodology allowscontrolled delivery and accurate placement oftreatment fluids and proppant in existing orbypassed pay intervals at little or no additionalcost because decreased fluid volumes and elimi-nation of redundant operations reduce mobiliza-tion, equipment and material charges.

CoilFRAC treatments are useful for fracturingbypassed single or multiple zones, protection ofcasing and completion equipment, and for

development of coalbed methane reserves. Thistechnique is also valuable in settings wherechemical inhibition, reservoir flow-conformancemodifications, water-control or sand-controlmethods may be required. Schlumberger haspumped more than 12,000 CoilFRAC fracturestimulations in more than 2000 wells. Coiled tub-ing-conveyed treatments can now be performedin vertical, high-angle and horizontal wells withmeasured vertical depths up to 12,200 ft [3720 m].Pumping rates can range from 8 to 25 bbl/min[1.3 to 4 m3/min] with 5 to 12 ppa of proppant.

Coiled tubing-conveyed fracturing was origi-nally developed for multilayered shallow-gasreservoirs in Canada and further developed in theUSA (above). These CoilFRAC treatments, how-ever, are being refined in applications around theworld, from Indonesia, Argentina and Venezuelato Mexico and now Algeria.

The largest total volume of proppant placed ina single wellbore was 850,000 lbm [385,555 kg]for a well treatment in northern Mexico. A well insoutheast New Mexico, USA, was the first hori-zontal well to be fracture stimulated using aCoilFRAC Mojave tool. Two separate zones at9123 and 9464 ft [2781 and 2885 m] measureddepth were treated. The deepest CoilFRAC job todate was recently performed at 10,990 ft [3350 m]for Sonatrach in Algeria. The progress to date inselective stimulations has been impressive.Continued research and field experience areexpected to further extend the range of applicationsand reach of this innovative technique. —MET

> CoilFRAC screenless completion results in Duri field, Indonesia.

> Ongoing CoilFRAC operations in Medicine Hat,Alberta, Canada.

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