the right treatment for the right reservoir -...

4 Oilfield Review

The Right Treatment for the Right Reservoir

Bader Al-MatarMajdi Al-MutawaMuhammad AslamMohammad DashtiJitendra SharmaKuwait Oil CompanyAhmadi, Kuwait

Byung O. LeeJ. Ricardo SolaresSaudi AramcoUdhailiyah, Saudi Arabia

Tom S. NemecGoodrich PetroleumHouston, Texas, USA

Jason SwarenSugar Land, Texas

Loris Tealdi Eni Congo S.A.Pointe Noire, Republic of the Congo

For help in preparation of this article, thanks to MichaelDardis, Longview, Texas; Phil Duda and Donald Smith, Houston;Matt Gillard, Moscow; Shrihari Kelkar, Al-Khobar, Saudi Arabia;Hai Liu, Ahmadi, Kuwait; and Brad Malone, Pointe-Noire, Congo.AbrasiFRAC, ABRASIJET, ACTive, CoilFRAC, Contact,DeepSTIM, DivertaMAX, InterACT, PCM, POD, RapidSTIM,StageFRAC, StimMAP, SuperX, SXE, VDA (ViscoelasticDiverting Acid) and VSI (Versatile Seismic Imager) are marksof Schlumberger.PerfFRAC is a mark of Schlumberger, technology licensedfrom ExxonMobil Upstream Research Company.

Flow rates in most wells increase significantly after hydraulic fracture treatments.

In some completion configurations—notably multizone and long-reach, high-angle

wells—capital and operating expenses often negate economic gains from improved

ultimate recovery or accelerated production. This drawback is being addressed today

by combining more efficient, multizone fracturing tools and services with real-time

monitoring capabilities.

Among the strategies used today to produce alarger proportion of original reserves in place arehigh-angle, extended-reach wells, multizone wellsand recompletions aimed at capturing previouslyuneconomic or stranded oil and gas deposits.Recent improvements in geosteering technologyallow high-angle wells to be drilled to increasinglygreater distances, while preventing the well pathfrom straying beyond the upper and lowerboundaries of the pay zone. The result is an ability

to greatly increase wellbore contact with theformation and so significantly improve drainage.

Increased formation contact is essential tothe success of many of these long lateral wells.This is because most of the formations thatreadily give up hydrocarbons were discoveredand developed years ago. That leaves today’soperators the task of producing oil and gas fromunconventional or low-permeability sources suchas shale or the outer reaches of mature fields

> Improving formation contact in vertical and horizontal wells. A 100-ft [31-m], 81⁄2-in., vertical wellboreresults in about 222 ft2 [20.6 m2] of formation contact (far left ). A 2,000-ft [610-m], 81⁄2-in., horizontalwellbore drilled in the formation increases formation contact 20 times compared to the 100-ft verticalwell (middle left ). A 150-ft [45-m] fracture length in the vertical well increases formation contact 270times over that of the untreated vertical well and 13.5 times that of the 2,000-ft untreated horizontalwell (middle right ). When the 2,000-ft horizontal well is treated with ten, 75-ft [23-m] long fractures,formation contact increases to 1,013 times that of the untreated vertical well and 50 times that of theuntreated horizontal well (far right ).

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Summer 2008 5

where reservoir quality may be low.1 Whileextended-reach wells play a significant role inimproving reservoir contact, exposure to theformation can be further increased withhydraulic fractures.

In vertical wells, hydraulic fracturing canimprove reservoir contact several hundredfold.In horizontal wells, the improvement isexponential (previous page).2 While the resultsfrom fracturing high-angle, long-reach wells

have been encouraging, many of thesetreatments often fail to deliver expectedeconomic or production gains. This outcome is afunction of the original completion methods: tomaximize wellbore-formation contact, thesewells are traditionally completed open hole orwith slotted or preper forated liners across theproduction zone.

In an openhole completion, effective stimu -lation along the horizontal wellbore is almost

impossible using traditional bullheadingmethods, since it is difficult to place fracturefluids and acids precisely within the formation.Typically, with the use of standard methods, onlythe upper sections, or heel, of the wellbore aretreated, with little fluid ever reaching the middleor lower intervals (left).3

When operators choose to completehorizontal wells with cemented liners, individualzones can be more readily isolated and treated.However, as with any multizone treatment, thecosts of multiple, time-consuming trips per zoneoften outweigh the value of the resultingincreased production.

Despite these hurdles, and because hydraulicfracturing does consistently result in increasedproduction, demand continues to grow for thepractice in all types of wells. In an effort to attainbetter results—from both a cost and productionstandpoint—service companies are delivering

1. For more on production from gas shale: Boyer C,Kieschnick J, Lewis RE, Suarez-Rivera R and Waters G:“Producing Gas from Its Source,” Oilfield Review 18,no. 3 (Autumn 2006): 36–49.

2. Chariag B: “Maximize Reservoir Contact,” Hart’s E&PMagazine (January 2007): 11–12.

3. Al-Naimi KM, Lee BO, Bartko KM, Kelkar SK, Shaheen M,Al-Jalal Z and Johnston B: “Application of a Novel Open-Hole Horizontal Well Completion in Saudi Arabia,”paper SPE 113553, presented at the SPE Indian Oil andGas Technical Conference and Exhibition, Mumbai,March 4–6, 2008.

> Fracturing openhole, horizontal wells. Microseismic events were captured during the treatment of ahorizontal, openhole completion in a Barnett Shale well. The multicomponent sensors in monitoringwells (green) indicate that almost all of the bullheaded treatment was absorbed in the heel, or uppersection, of the well (blue). As a result, the majority of the lower Barnett formation remained untreated.

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fracturing systems that can access, stimulate and isolate numerous zones in cemented and openhole, extended-reach and verticalcompletions, in a single intervention.

Some of these multizone fracturing tech -niques are also designed to solve issues ofdegraded tubulars and control of fracture fluidplacement through the use of conveyance systemssuch as coiled tubing (CT) or jointed pipe.4

This article describes fracturing and comple -tion systems that allow operators to overcomethe economic and technological barriers tohydraulic fracturing in certain, increasinglyprevalent well types. Examples from NorthAmerica, Africa, Saudi Arabia and Kuwaitdemonstrate how these innovative approacheshave resulted in efficient, economically viablefracturing and acidizing treatments in reservoirsonce deemed poor candidates for such proce -dures. We will also examine recent innovationsthat allow operators to model and then monitorand refine their fracture treatments in real time.

An Eye on GrowthAs in many oil and gas operations, integrationwith real-time monitoring has greatly enhancedthe effectiveness of hydraulic fracturing. In thepast, downhole pressures were derived frommeasurements taken at the surface and extrap -olated to bottomhole conditions. Today, thesemeasurements are acquired directly at thesandface in real time using coiled tubing with an installed fiber-optic line (left). Themeasurements are obtained successfully despitethe extremely harsh downhole environmentcreated during hydraulic fracturing operations.

Fiber-optic-equipped coiled tubing (FOCT)systems feature a downhole sensor package thatsends real-time downhole depth, temperatureand pressure data to the surface. In addition, theoptical fiber can obtain distributed temperaturereadings at 3-ft [1-m] intervals. Data aretransmitted from the toolstring through thefiber-optic line to an electronics package thatconverts the fiber-optic signal to a wirelesssignal. This, in turn, allows transmission of thedata to a control cab where the information canbe viewed remotely through a command-and-acquisition software program.5

Operators also can gain considerable valuefrom accurate definition of the fracture systemgeometry as it is being created. Equipped withsuch knowledge, engineers can design successivefracturing operations within a field to avoidundesired results. In the past, fracture mappingwas performed through postfracture analysismeasurements such as temperature logs, radio -active tracers and tiltmeter surveys. However,these tools have shortcomings. Temperature logsor radioactive tracers can provide only near-wellbore fracture height and width. And whileinformation about the azimuth and symmetry ofthe fracture may be gained from surface anddownhole tiltmeter mapping, these methods

do not accurately assess the fracture’s height,length and width.6

More recently, service companies havedeveloped the ability to describe fracturegeometry using borehole seismic methods.7 TheStimMAP hydraulic fracture stimulation diag -nostics service uses multicomponent receivers inan offset well to record the microseismic activitycaused by the creation of hydraulic fractures inthe treated well. To create the velocity modelneeded for microseismic data analysis andprocessing, a seismically calibrated velocitymodel survey is performed in a nearby moni -toring wellbore. This borehole seismic survey isperformed before fracturing.

The map of these microseismic events allowsengineers to better understand the developmentof induced fractures in time and space. Mappingalso provides valuable geological insight into thetreated formation.8

Engineers at the monitoring or treatmentwell can communicate with other locations usingthe InterACT connectivity, collaboration, andinformation system. Remote office locations canbe included in the communications loop forinstant processing and interpretation of the data.

The StimMAP system uses real-time data tolocate microseismic events automatically in 3D space (next page).9 Comparing the fracturemapped by the StimMAP service with a fracturingdesign and evaluation software model providesuseful information for improving future treat -ments. The lessons learned enable operators tooptimize well-stimulation costs and gain insightfor new in-field drilling opportunities.

The StimMAP system was recently applied ina multizone fracturing operation in an east Texashorizontal well. During stimulation aimed at thethird zone, engineers observed unintendedmicro seismic activity in the region of what was to be a fifth zone. Following unsuccessfulattempts to redirect the fracture, the companyhalted operations.

Engineers coupled StimMAP Live services—aspecific application of the StimMAP system thatpermits engineers to monitor and, if necessary,alter fracture treatments as they are beingperformed—with pumping data to diagnose themechanical problems that were causing thefracture to veer from its planned direction. Thejob was then resumed and three more zonestreated. Without the insight afforded engineersby real-time feedback, six fracture treatmentswould have been pumped into the same zone.Instead, the operator was able to salvage three of

6 Oilfield Review

> Real-time data. Fiber-optic cable inside coiledtubing delivers a distributed temperature profilethroughout the wellbore. Temperature variationsprovide information that shows where fracturefluids are entering the reservoir. In relatively low-rate applications, ACTive in-well live performancemeasurements can be made as the fracturetreatment is pumped directly down the coiledtubing. During what are termed high-rate jobs—more than 450,000 lbm [204,117 kg] of sandpumped at 10 bbl/min [1.6 m3/min]—the fiberbundle, known as the tether, begins to moveforward and buckle, causing it to fail. For thosejobs, the system monitors conditions as the sandis pumped down the CT-casing annulus. Thesensor package shown here includes a battery(white), a circuit board with temperature sensor(green) and pressure transducers (light blue).


Summer 2008 7

the remaining five treatments while avoiding theweeks of diagnostic workover costs thatotherwise would have been necessary.

Making Multizone PayIn times of high commodity prices, operators arenaturally anxious to make the most of theirassets by producing as much hydrocarbon as is economically feasible. To do so, they often complete numerous zones with a singlewellbore or expose long intervals of formationthrough horizontal or high-angle drilling. Asdiscussed above, results from traditionalapproaches to fracturing these wells may fallshort of operator expectations for economic ortechnological reasons.

Multizone fracturing, as opposed to tradi -tional methods that include multiple trips perzone, targets both economic and techno logicalconcerns. Through efficient practices and newtechniques, these services may reduce weeks ofrig costs to a few days or even entirely eliminatethe need for a workover or drilling rig. Multizonefracturing practices also are able to deliver moreeffective treatments that optimize formationcontact because they can more accurately placetreatments without adding risk.

Service companies have customized systemsto address the varied types of multizone wellsoperators seek to treat. Schlumberger hascreated a four-category package of hydraulicfracturing services based on well type andoperator philosophy. Called Contact staged frac -turing and completion services, the categoriesinclude the following: • conventional systems that require separate

trips into the well to perforate a zone in onetrip, then stimulate and isolate it in a secondtrip, repeating that process for each zone

• intervention systems that perforate, fracture-stimulate and isolate numerous zones in asingle trip

• permanent systems that fracture-stimulateand isolate multiple zones in one pumpingoperation using assemblies that remain in thewell as part of the completion

• dynamic systems that use a degradable divert-ing material to successively plug and isolatetreated perforations and divert stimulations toother intervals in a continuous operation.

Conventional fracturing—pumping thefracture fluid and proppant or acid down thecasing or fracture workstring—is most effectivefor massive hydraulic fracture treatments inwhich hundreds of thousands of pounds of sandare pumped downhole at high rates. In cased

holes, the reservoir is accessed throughperforations created by wireline, abrasive jettingor shifting sleeves in the workstring.

4. For more on coiled tubing stimulation: Degenhardt KF,Stevenson J, Gale B, Gonzalez D, Hall S, Marsh J andZemlak W: “Isolate and Stimulate Individual Pay Zones,”Oilfield Review 13, no. 3 (Autumn 2001): 60–77.

5. Julian JY, West TL, Yeager KE, Mielke RL, Allely JN, Jenkins CN, Perius PD, Bucher RL, Foinquinos CI, Forcade KC, Fagnant JA, Montgomery DB, McInnis JGand Sack JK: “State-of-the-Art Coiled Tubing Operationsat Prudhoe Bay, Alaska,” paper IPTC 11533, presented atthe International Petroleum Technology Conference,Dubai, UAE, December 4–6, 2007.

6. Le Calvez JH, Klem RC, Bennett L, Erwemi A, Craven Mand Palacio JC: “Real-Time Microseismic Monitoring of Hydraulic Fracture Treatment: A Tool To Improve Completion and Reservoir Management,” paper SPE 106159, presented at the SPE Hydraulic FracturingTechnology Conference, College Station, Texas, January 29–31, 2007.

7. For more on borehole seismic applications: Blackburn J,Daniels J, Dingwall S, Hampden-Smith G, Leaney S,Le Calvez J, Nutt L, Minkiti H, Sanchez A and Schinelli M:“Borehole Seismic Surveys: Beyond the Vertical Profile,”Oilfield Review 19, no. 3 (Autumn 2007): 20–35.

8. Le Calvez et al, reference 6.9. For more on microseismic mapping: Blackburn et al,

reference 7.Bennett L, Le Calvez J, Sarver DR, Tanner K, Birk WS,Waters G, Drew J, Michaud G, Primiero P, Eisner L, Jones R, Leslie D, Williams MJ, Govenlock J, Klem RCand Tezuka K: “The Source for Hydraulic Fracture Characterization,” Oilfield Review 17, no. 4 (Winter 2005/2006): 42–57.

> Mapping the fracture. Shown here are a map view (left ) and a transverse view (right ) of microseismic locations from a four-stage slickwater stimulationtreatment in the Barnett Shale. StimMAP services were chosen to create an optimal fracture design using accurate image geometry of the hydraulicfracture as it developed. Microseismic data were acquired with the multishuttle VSI Versatile Seismic Imager and processed on location to generate a 3Dcomputer image of the fracture system. This allowed the stimulation treatment of subsequent stages to be reengineered.

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When multiple intervals are open within asingle zone, diverting fluid from one to another inorder to treat each of them may be accomplishedthrough such practices as limited entry, ballsealers, chemical diversion, composite bridgeplugs and sand plugs. Limited entry is created byplacing fewer perforations across certainsections to increase friction at the openperforations. This diverts the fluids from a zone

that, because of high permeability or otherfactors, may have absorbed the bulk of thetreatment at the expense of other intervals orzones (left).10

Composite bridge plugs are isolation barriersset in the casing above the treated zone anddrilled out later, usually in a separate workstringdrilling operation. This incurs a time penalty andadds operational risk. Additionally, the timebetween treating the lowest formation andflowing it back can sometimes be measured inweeks; in some cases, that may be enough timefor the fluids to leave residue in pore spaces,causing significant damage to the formation.

In wells with openhole completions andunconsolidated formations, conventional frac -turing may include deploying a completionstring—typically a slotted or perforated liner—to ensure wellbore integrity. The entire well maybe fracture-stimulated by pumping treatmentfluid down the casing or fracturing string andinto the formation in a practice known asbullheading. As in cemented completions, once acompletion string is in place, diversion may beattempted by using limited entry, ball sealers ortraditional chemical diversion.

Staging an InterventionThe intervention category of hydraulic fracturingcomprises three services: AbrasiFRAC abrasiveperforating and fracturing service, PerfFRACselective perforating, fracturing, and stageisolation with ball sealers, and CoilFRACstimulation through coiled tubing.

The AbrasiFRAC technique enables accurateplacement of fracturing treatments down thecasing or the workstring-casing annulus. It also

reduces near-wellbore pressure drop from thewellbore to the reservoir, which decreases thefrequency of near-wellbore screenouts whenproppant stops entering the formation and buildsup inside the casing. The technique isparticularly well-suited to treating formationswith high fracture-initiation pressure and areasin which precise placement is critical to thesuccess of the stimulation.

The system is based on a well-established oil industry technique for cutting casing andtubulars downhole: a slurry containing abrasivesolids is pumped at high differential pressuresthrough an ABRASIJET hydraulic pipe-cuttingand perforating service gun conveyed on a workstring. The resulting high-velocity fluid stream cuts through tubulars andsurrounding cement, then penetrates deep intothe formation (below).

The cutting tool is used to perforate thecasing and formation. The abrasive material isusually 20/40- or 100-mesh fracturing sand,which is compatible with the speciallyengineered jet guns. Sand plugs may be used toprovide zonal isolation between the fracturingtreatment zones. The jet guns, which areavailable in various size and phase config -urations, also can be used with retrievable ormillable bridge plugs for isolation.

One example of the use of the AbrasiFRACservice was in the highly laminated Hosston sandsof the Sligo field in northern Louisiana, USA. TheHosston sands contain many thin, gas-bearingsands alternating with water-bearing sands, withvarying levels of depletion. Typically, wells in thisarea are completed with multistage stimulation

8 Oilfield Review

> Conventional fracture fluid diversion throughball sealers. Once the calculated amount oftreatment fluids is pumped into a targeted zone(tan), the flow is diverted to another (blackarrows). The most common method of diversioninvolves ball sealers (black), made of nylon, hard rubber, biodegradable collagen, or acombination of these, introduced into the slurryso that they reach the perforations at the end ofthe treatment. The balls create a seal across theperforations, causing the treatment to divert tothe next open set of perforations. By repeatingthis procedure, numerous intervals per stagecan be treated without shutting down pumps orsetting plugs.

> High-pressure perforating and treatment. The AbrasiFRAC service uses a high-performance abrasive jetting tool to operate continuously under harshdownhole conditions. After depth correlation, abrasive sand slurry is pumped through the nozzles. The resulting high-velocity fluid stream perforatestubulars and surrounding cement, then penetrates deep into the formation (far left). The zone is then treated (middle left) and the cutting tool is pulled upthe hole to the next zone. Once the first treatment is complete, a sand plug may be set for isolation and the next zone perforated (middle right). Thissequence can be repeated as often as necessary in a single operation. When all zones are treated (far right), the sand plugs are reverse-circulated out.

Cutting perforations Pumping fracture treatmentdown the annulus

Cutting next set of perforationsafter placing sand plug for isolation

Reversing out sand plugafter fracturing treatment


Summer 2008 9

treatments using energized fracturing fluids andbridge plugs for isolation between zones.

In an effort to improve cost and timeefficiencies, EOG Resources field-tested theAbrasiFRAC service. The technology allowed theoperator to stimulate multiple intervals within awell in a single field operation and to moreeffectively and efficiently stimulate theindividual sands. Treatments varied from four tonine stages using CO2-energized fracturingfluids. The result was to cut water production by85% while doubling gas production.

Another approach to efficiency is to treatzones immediately after perforation without firstpulling the guns out of the hole. This step alonesaves one running and one pulling trip per zone.The PerfFRAC service is designed to performhigh-rate treatments down the casing while theperforating gun assembly remains in the well -bore. First, the guns for each zone are run in thehole and the first zone is perforated. Then, as thefirst zone is being treated, the unfired guns aremoved up the borehole and positioned to shootthe holes for the second zone.

At the end of the first zone’s treatment, ballsealers in a fiber diverting fluid are pumped intothe well. A rise in pump pressure indicates thatthe ball sealers and slurry have sealed againstthe perforations of the treated zones. At thatpoint, the guns for the second zone are fired, andthe second treatment, again tailed in with ballsealers and fiber-infused diverting fluid, ispumped. This process is repeated for multiplezones. To date, as many as eight sets of guns havebeen run and six separate zones treated in asingle intervention (below).

The PerfFRAC service often results in betterproduction rates than other, less efficienttreatments because it allows precise targeting oftreatments, ensuring that no zones are under -served. The method also allows the well to beflowed back immediately and so avoids the risksassociated with milling out composite bridgeplugs and leaving potentially damaging fluids inthe formation for an extended time period.

Goodrich Petroleum was seeking to bring justsuch efficiencies to its Cotton Valley field in eastTexas. Engineers had been treating these wells

using traditional practices: perforate the firstzone, fracture-stimulate it, flow the well to cleanit up, and finally set a composite bridge plug for isolation.

This process was repeated for each zone ofinterest. Once the last zone was treated, a coiledtubing unit was brought on location to drill outthe composite bridge plugs. This sequence costthe company US $250,000 and took five days tocomplete. Goodrich opted to use the PerfFRACservice to complete 23 of its wells and in doing soreduced the five-day operation to one day, whileeliminating the need for bridge plugs and coiledtubing milling.

But the break with past practices paid a moreimportant dividend than just lower operatingcosts and shorter time to production. In the first

> Multizone treatments in vertical wells. Multiple stacked zones in vertical wells may be stimulated using limited entry. The PerfFRAC technique shownhere uses high-rate fracture stimulation treatments down the casing with a perforating assembly in the wellbore. Once the lower zone is perforated (left ),the guns are moved up the hole and positioned for the next set of perforations; then the perforated zone is fractured (middle). Ball sealers (green) isolatethe treated zone and the next zone is perforated (right ).

10. For more on diversion techniques: Samuel M and Sengul M: “Stimulate the Flow,” Middle East & AsiaReservoir Review no. 4 (2003): 42–55.


10 Oilfield Review

> Multistage versus traditional fracturing practices. In the Cotton Valley field of Texas, Goodrich Petroleum used multistage fracturing to reduce treatmenttime (blue) from five days to one and costs (green) from US $255,000 to US $155,000 per well (left ). In a 23-well program in the same field, the operatorproduced 25 MMcf more gas compared with what would be expected following traditional treatment methods that often sacrifice treatment efficiency tomeet economic goals (right, horizontal scale not linear).

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> Workstring-conveyed selectivity. By combining a workstring with selective fracturing technology, operators can treat multiple zones in a single trip. In newwells, each zone is perforated conventionally in one wellsite visit. Coiled tubing or jointed pipe is then deployed into the wellbore with an openhole packerbottomhole assembly (right ). The bottom zone is isolated by packers above and below the target formation, and the fracture stimulation is pumped throughthe workstring (left ). Residual proppant is reverse-circulated out of the wellbore and the packer is moved to the next zone, where the process is repeated.The insets represent real-time monitoring of each treatment.

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Summer 2008 11

180 days of production, the 23 wells recovered anadditional 25 MMcf [708,000 m3] of gas—a 22%increase over wells completed using conven -tional methods. This gain allowed the operator toincrease its estimated ultimate recovery per wellby 10% (previous page, top).

In all, using the PerfFRAC system savedGoodrich Petroleum 92 completion days on23 wells. Additionally, reduction in equipment onlocation saved another 25% on total completioncosts per well. Gas-to-market time was reducedby four days per well, netting the operator anadditional 6 MMcf [169,900 m3] of initial gas.

Diversionary TacticsWith the adoption of ball sealers and limitedentry, treated zones can be isolated and thefracture treatment diverted to untreated zones.While these isolation and diversion techniqueshave the advantage of significantly reducing thenumber of trips and the costs required tofracture wells with multiple zones, because ofdifferences in fracture gradients between sandswithin a well, these methods leave some zonesineffectively treated.

One solution to this shortcoming is to isolateand stimulate each zone individually with atreatment designed specifically for its param -eters. The trick is to do so without sacrificing theefficiencies gained from other practices such aslimited entry and ball sealing. To that end,

engineers have developed systems that isolatezones between sealing elements by usingopenhole packers that may be set, unset andreset numerous times.

The CoilFRAC coiled tubing stimulationservice uses an openhole packer assemblydeployed on a workstring across the bottom zoneafter the entire well has been perforatedconventionally (previous page, bottom). Thestimulation fluid is then pumped down thetubing string, through the treatment sub of thepacker tool and into the isolated interval.Residual proppant is then reverse-circulated outand the packer moved to the next zone. Thismethod not only permits stimulation of all zonesin a single intervention but, like other Contactservices, increases treatment efficacy byallowing the operator to customize eachtreatment to suit each zone.

In older wells, this type of service is especiallysuited for accessing bypassed reserves and forrefracturing previously completed zones.11 In thisapplication, the goal is not only to minimize thecost of fracturing mature assets, but to do so whileprotecting downgraded casing from high treat -ment pressures and abrasive, proppant-ladenfluids. Using a workstring as a conduit offers theadded advantage of allowing the operator to treattargeted zones without first having to kill thewell—a procedure from which older, pressure-depleted formations may not recover.

The value of customizing discrete treatmentsto suit the needs of each interval in a multizonewell was clearly demonstrated in a RockyMountain oil field of the USA. The field containsmultiple vertical sand layers that are from 5 to60 ft [1.5 to 18.3 m] thick and distributed from adepth of 2,000 ft to 5,000 ft [609 to 1,524 m]. Theoperator had been completing wells in this fieldprimarily with limited entry, but had used bridgeplugs when the distance between layers wassignificant. However, because of the variedfracture gradients exhibited in each sand layer,many zones were not being effectively stimu -lated. In addition, some marginal sand layerswere left untreated for economic reasons.

In its search for an effective way to stimulateeach zone without increasing completion costs,the field’s operator chose to use the CoilFRACsystem. The decision paid off. For example, onewell in the field had been producing 1.9 MMcf/d[53,800 m3/d] from one limited-entry fracturestimulation of multiple layers. With the packerassembly, bypassed layers were perforated andthe entire well was restimulated. Eight fracturestimulations were performed in one day, and thestabilized production rate from the well wasrecorded at 5.3 MMcf/d [150,100 m3/d].

In addition to a more effective stimulation ofeach layer, the treatments took only one to twodays, compared with the several weeks requiredto do the jobs using conventional techniques. Inthe four-well test, average production rates of thewells with the CoilFRAC system were more thantwice those of standard completions (above left).As a consequence, recoverable reserves per wellwere increased by more than 75%.

In another example, this time in southeasternAlberta, Canada, engineers were experiencingsimilar setbacks in their stimulation efforts in ashallow gas field. The wells in the area areusually completed in four zones, ranging from820 to 1,480 ft [250 to 451 m] deep. The forma -tions are composed of layered, silty sands thatfracture easily.

Historically, operators in this area have usedvarious fracturing techniques, including com -posite bridge-plug isolation. On a four-zonecompletion, such conventional practices requireeight trips into the wellbore and an additional16 days to complete the well with flowbackrequired between each treatment.

11. For more on refracturing operations: Dozier G, Elbel J,Fielder E, Hoover R, Lemp S, Reeves S, Siebrits E, Wisler D and Wolhart H: “Refracturing Works,” Oilfield Review 15, no. 3 (Autumn 2003): 38–53.

> Increased production rates. In one Rocky Mountain gas field, the average production rate fromwells treated with the CoilFRAC system was more than twice that of wells in the same field treatedconventionally.

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One-year average production of 4 wells receiving CoilFRAC treatmentFour-year average production of 14 wells receiving conventional treatment


The more efficient, commingled multizonestimulations that rely on limited entry or ballsealers for diversion gain time compared withtraditional practices but, as discussed earlier,sacrifice production to do so. In addition, wells inthe area are generally stimulated in groups to makethe most efficient use of fracturing equipment.

The operator determined that, to optimizestimulation and production, each zone should befractured individually at reduced pump rates.That decision made CT-conveyed fracturingtreatments an obvious choice and resulted inreducing operation time to the point that crewswere treating two wells per day (left). This was acritical advantage because for environ mental andeconomical reasons, summer access is restrictedto 10- to 14-day operational win dows. In all, usingthe CoilFRAC service saved the company US$110,000 while increasing production by morethan 190% in one field.

Permanent SolutionsMotivated by a desire to minimize the number ofinterventions or tools introduced into horizontaland high-angle wells, some operators prefer totreat zones using equipment that will becomepart of the permanent completion design. Oneway to do so is to complete the well usingconventional casing with sliding sleeves. Inopenhole completions, such a system includeshydraulically operated openhole packers tocreate a seal against the wellbore wall.

In either cemented or openhole wells, eachzone is treated through the sliding sleeves. Thepurposes of the cement and openhole packersare the same: to provide isolation between zonesof different treating pressures and to ensuretreatment along the entire length of the well.

Like other multizone services, permanentsolutions also reduce risk by limiting trips in thehole to set and remove bridge plugs andincrease treatment efficiency by allowing theoperator to design each treatment for a specificzone. This strategy also increases the number ofzones that can be treated because operators

12 Oilfield Review

12. Seale R, Donaldson J and Athans J: “Multistage Fracturing System: Improving Operational Efficiency and Production,” paper SPE 104557, presented at the SPE Eastern Regional Meeting, Canton, Ohio, USA, October 11–13, 2006.

13. Skin is a dimensionless factor calculated to determinethe production efficiency of a well by comparing actualconditions with theoretical or ideal conditions. A positiveskin value indicates some damage or influences that are impairing well productivity. These are the result ofcompletion or drilling fluid residue left on or in the formation. A negative skin value indicates enhanced productivity, typically resulting from stimulation.

> Cost, time and production. In shallow wells in southeastern Alberta, theefficiency gains of workstring-conveyed fracturing over traditionaltechniques are evident by all measures. Standard methods (blue) consumedUS $400,000 and 16 days per well, resulting in a 16% production gain. In thesame field, the CoilFRAC system (pink) cost US $290,000 and took 4 days,resulting in a 192% increase in production.


CoilFRAC service

$400,000

$290,000

16 days

Increased production

4 days

16%

192%

Cost Time

> Permanent service. Multiple fracture stages can be completed in a single trip by isolating the targetformation between openhole packers. The treatment fluid is delivered through frac ports in the tubularsection between the packers (top). During StageFRAC service operations (bottom), a ball (red),pumped down the wellbore with the tail end of the treatment fluid, lands in a seat inside a slidingsleeve. The resulting pressure buildup forces the sleeve to the open position. Fluid is then forced toenter the interval above the landed ball and the seat. At the same time, the ball and seat form a sealthat acts as a plug to isolate the lower, previously treated zone. By using progressively larger seat andball diameters from the deepest zone to the shallowest, the entire formation may be treated uniformlyin a single intervention.

Frac ports Openhole packers


Summer 2008 13

often address risk by reducing the number ofplug pulling and running trips. This inevitablyleads to limiting the number of zones that maybe isolated and treated.

If engineers choose at some point torefracture a conventionally completed well inwhich all perforations are left open, they must doso through the workstring. In addition to the costof the rig required to do that and the riskinvolved, fracturing through a workstringintroduces added frictional forces that limit theflow rate during fracturing, so the optimal designcannot be accomplished.12

StageFRAC and RapidSTIM multizonefracturing and completion services incorporatePackers Plus technology—openhole packers thatare run on conventional casing to segment thereservoir with ball-activated sleeves placedbetween each set of openhole packers. The twosystems are nearly identical except that theStageFRAC service treats the isolated zonesthrough frac ports, and the RapidSTIM servicedoes so through jets. Both frac ports and jets arelocated between the packers and behind ball-activated sliding sleeves (previous page, bottom).This mechanical diversion allows for precise fluidplacement, complete zonal coverage and greatereffective fracture conductivity.

Eni Congo turned to this solution when facedwith a significant challenge in its offshoreoperations near the Republic of the Congo coastin West Africa. These aging fields still containlarge quantities of reserves in low-permeability(10 mD), consolidated formations that are barelyeconomic to produce using conventional stimu -lation methods. Formerly, stimulation consistedof matrix acidizing to eliminate or reach slightlynegative skin.13

Eni chose the StageFRAC service for threeexisting cased and perforated wells in theKitina field where eight hydraulic, proppedfractures were placed in three recompleted,cased-hole wells. These jobs were being pumpedfrom a support barge to an offshore platformwith limited deck space. As a result, only twozones could be pumped before the vessel had tobe restocked.

The first well pumped was the KTM W6 ST(right). Two of the three zones treated down astimulation liner were pumped without shuttingdown the pumps. Once the bottom interval hadbeen treated, a ball was pumped, the zone wasisolated, and the next zone was opened. Thethird zone was treated separately.

> Offshore permanent solution. The KTM W6 ST wellbore has a 7-in.cemented liner run from 1,600 to 3,110 m [5,250 to 10,204 ft]. The well wasoriginally produced from a deeper interval and recompleted as shown. TheStageFRAC service was used to perforate the well in three intervals: 2,785 to2,810 m [9,138 to 9,220 ft], 2,820 to 2,865 m [9,252 to 9,400 ft] and 2,870 to2,910 m [9,416 to 9,548 ft]. New perforations were added in 2-m [6-ft] groupsto each of the existing perforation sets to reduce risk of screenout caused bytortuosity. The packer assembly, run on 41⁄2-in. tubing as a production liner,straddles the three perforated intervals.

7-in. x 4 1⁄2-in. cased-holehydraulic packer


4 1⁄2-in. hydraulic frac port

4 1⁄2-in. toe circulating sub

7-in. permanent packer

Perforations at2,785 m2,810 m

Frac port at2,801 m


Frac port at2,861 m


Frac port at2,909 m

Circulating subat 2,913 m

Tubing bottomat 2,916 m


3-in. ball

3 1⁄4-in. ball


Three zones were also treated in the secondof the three-well series. In the final well, it wasdetermined that the lowest zone was too close toa water contact and this zone was left untreated.Stabilized production from the three wellsincreased 230% over their previous performance.Production prior to fracturing was around590 bbl/d [94 m3/d]; after treatment, steady-stateproduction was 1,950 bbl/d [310 m3/d] (left).

This sequential approach holds specialpromise for the offshore arena wherecompleting a single fracture using conventionaltechniques can take a week and must be donefrom an offshore rig that costs several hundredthousand US dollars per day. By using openholepackers and sliding sleeves for isolation andfracturing the whole well in a single pumpoperation, each zone can receive extensivestimulation during a single mobilization of astimulation vessel (left).

On land, it is the ability of sequentialtreatments to effectively treat an entire wellcontaining numerous zones of differing qualitythat attracts operators to the technique. In SaudiArabia, operator Saudi Aramco had completed awell with a 5,000-ft openhole, hori zontal sectionthrough eight different zones of varyingpermeability. Because of its higher permeability,engineers expected most of the oil contributionto come from Zone 1.

Because of the length and trajectory of thehorizontal section, coiled tubing could not reachthe lower sections and so the plan was tobullhead an acid treatment. However, because ofits high permeability, Zone 1 at the heel of thewell took all the acid, and the other seven zoneswere left untreated. As predicted and because ithad received all the acid treatment, allproduction improvement came from Zone 1.

14 Oilfield Review

< Offshore capacity. The Schlumberger DeepSTIMgroup of stimulation vessels are specificallydesigned for fracturing and other fluid treatments.Their onsite quality control and mixing capacities(top), pump capacity (middle), and storagecapacity (bottom), and their dynamic positioningcapabilities render them self-sufficient. This elim-inates deck and storage space concerns onplatforms and the need for a costly offshore rig.Since these vessels are equipped to treat six ormore zones sequentially, they can do in six hourswhat requires six weeks by conventional means—a significant savings of time in view of offshorerig day rates.

Environmental wasteProppant to silo

12,000 lbm/min

(10,000 lbm/min

for DeepSTIM III)

Completion fluidto pumps To PCM gel hydration system

Three-compartmentmixer

Acid blender

0 to 30 bbl/min

0 to 70 bbl/min transfer rate

POD blender

Dual silo: 2,000 ft3

Acid lineLow-pressure line

High-pressure pumps

16,850 hydraulic horsepower (DeepSTIM)

21,450 hydraulic horsepower (DeepSTIM II)12,850 hydraulic horsepower (DeepSTIM III)

Dry bulk storage:

14,200 ft3 (DeepSTIM)

16,700 ft3 (DeepSTIM II)8,400 ft3 (DeepSTIM III)

Gel fluid capacity:

4,800 bbl (DeepSTIM)

6,600 bbl (DeepSTIM II)4,140 bbl (DeepSTIM III)

Completion fluid:

870 bbl (DeepSTIM)

860 bbl (DeepSTIM II)810 bbl (DeepSTIM III)

To wellhead0 to 50 bbl/min0 to 15,000 psi

High-pressure line

Bulk liquid additives Pressure-relief valve

Two 300-ft coflexip reels(1 for DeepSTIM III)

Raw acid capacity of 8,400 galUS(12,600 galUS for DeepSTIM III)

PCM gelhydration system

Acid tanks

Coflexip reels

Loading deckCrane

Silo

Liquid additives

Control room and laboratory

Satellite system

Wheel house

Iron racks

> Treatment results offshore Congo. Compared with production before stimulation, stabilizedproduction following the Kitina three-well fracturing campaign was increased by about 230%.

Well name Prefracturingoil rate, bbl/d

Initial postfracturingoil rate, bbl/d

Steady-statepostfracturingoil rate, bbl/d

Improved stabilizedproduction rate,

bbl/d

KTM-W6 (3 fracs)

160 2,100 600 + 440 bbl/d

KTM-111

(3 fracs)

300 900 650 + 350 bbl/d

KTM-107

(2 fracs)

130 1,000 700 + 570 bbl/d


Summer 2008 15

To remedy the problem, Saudi Aramcoengineers chose to use the StageFRAC service fora staged acid fracturing of all the zones. AlthoughZone 1 had been treated, it was decided to notopen it until the other seven were stimulated,cleaned up and tested. All zones were individ -ually stimulated in one pumping opera tion andimmediately flowed back. The seven previouslyuntreated zones were tested and the resultscompared with those in an offset well that hadbeen stimulated using coiled tubing and testedwith all zones open. The well that received theStageFRAC treatment had twice the productionof the offset well and triple its productivity index.

Saudi Aramco repeated this strategy in a field trial to hydraulically fracture longhorizontal, openhole wells in a deep, high-pressure, high-temperature Khuff carbonateformation. These wells, company officialsbelieved, were falling short of their productionpotential because of formation damage incurredduring drilling operations.

Engineers were also interested in thefeasibility of replacing unstimulated dual-lateralwells with hydraulically fractured single laterals.To that end it was imperative to employ a methodthat ensured stimulation of the entire length ofthe well—an impossible task in these long,complex completions using standard coiledtubing techniques.

The target of the field trial was the 3,835-ft[1,169-m] single lateral Well H-1 in the Khuffcarbonate. Three fracturing stages were planned.The first frac port was opened ahead of thetreatment by pressuring up on the workstring,and a step-rate injection test was performed toestablish fracture parameters. The first fracturestage was then bullheaded down the tubing at amaximum rate of 94 bbl/min [15 m3/min] and atreating pressure of 11,700 psi [80.66 MPa]. Atotal of 16,700 galUS [63.2 m3] of treatmentfluids, including acid and pad, were pumped.

A 2.5-in. ball was dropped, the second fracport was opened, and the second treatment of194,000 galUS [734.4 m3] of treatment fluid was pumped at 100 bbl/min [15.9 m3/min] and11,580 psi [79.84 MPa]. The final 243,222-bbl[38,648-m3] stage was pumped after a 2.75-in.ball was dropped and frac ports opened.

The well was cleaned up over a 54-hour flowperiod. Its performance was compared with thatof Wells H-2 and H-3, two offset nonstimulatedhorizontal gas producers that showed similarresults to the H-1 during their flowback periods.They were also picked because they were amongthe highest performers in the field when first puton production. Moreover, feet of net pay open toflow is six times higher in H-2 and three timeshigher in H-3 than in H-1. Additionally, both H-2and H-3 have higher permeability and porositythan H-1.

Nevertheless, the performance comparisonfor the three during the initial flowback periodshows that H-1 and H-2 were the highestproducers with a similar rate of 65 MMcf/d[1.84 million m3/d]. However, Well H-2 achievedthe same rate with a higher flowing wellheadpressure, indicating that it was a betterperformer than H-1. The stimulated Well H-1produced at a higher rate than H-3 with similarflowing wellhead pressures.

Mixing It UpThe mechanical diversion and isolationafforded by this type of system can also be supplemented by chemical diversion. TheKuwait Oil Company (KOC) used a combinationof openhole packers, frac ports and chemicalsto revive a horizontal oil producer in theSabriyah field where production had droppedto zero shortly after the well was completed in2004 (above).14

KOC also chose the StageFRAC servicebecause its mechanical isolation system remainsactive during the life of the well and could beused later to shut off certain zones that wereexpected to eventually experience waterbreakthrough. SXE SuperX concentratedhydrochloric acid [HCl] was used to achievedeep penetration and better etched fractureconductivity. This emulsion fluid is a viscous,highly retarded HCl system designed toovercome acid penetration problems when

14. Al Mutawa M, Al Matar B, Rahman YA, Liu H, Kelkouli Rand Razouqi M: “Application of a Highly Efficient Multistage Stimulation Technique for Horizontal Wells,” paper SPE 112171, presented at the SPE InternationalSymposium and Exhibition on Formation Damage Control,Lafayette, Louisiana, February 13–15, 2008.

> Mauddud well treatment. Based on the reservoir petrophysical model and interpretation, fourintervals in Mauddud C2 and Mauddud D formations (red) in the Sabriyah field were selected forstimulation (inset ). Formation permeability through these zones ranges between 5 and 100 mD acrossthe section. With StageFRAC technology and openhole packer assemblies, the four intervals (red) ofthe 2,562-ft [781-m] openhole horizontal well were compartmentalized into six zones (blue) based onpermeability contrast. The permanent completion resulted in production rates more than five timesthe field average.

8,000

7,000

6,000

5,000

4,000

0 500 1,000

Zone 1

TD 10,520 ft

1,500 2,000

Radial placement, ft

2,500 3,000 3,500 4,000

TVD,

ft

Kickoff point, 6,254 ft MD

7-in. liner point, 8,162 ft MD, 7,601 ft TVD

Zone 5 Zone 4 Zone 2Zone 6 Zone 3

Mauddud C Mauddud C2 Mauddud D

Mauddud B

9,950 to 10,450 ft9,640 to 9,050 ft

9,460 to 9,550 ft9,000 to 9,330 ft


stimulating reservoirs with temperatures higherthan 250°F [121°C]. Standard hydro chloric acidreacts so rapidly at high temperatures that it isimpossible for acid to penetrate, or wormhole,more than a few inches into the formationbefore the acid is rendered ineffective. Deep,live-acid penetration can be achieved only if theacid reaction rate is retarded.

VDA Viscoelastic Diverting Acid was used toensure full coverage across each zone.15 Uponspending, this acid rapidly develops highviscosity in situ and becomes self-diverting. Theviscosity buildup serves as a barrier to reduce thedevelopment of dominating wormholes in theformation and allows movement of the fluids tostimulate other untreated zones. By doing so, itassures treatment throughout the target zone.

Six zones were stimulated within three hours,and the well was flowed back immediately afterthe treatment was complete. The combination oftechnologies allowed successful stimulation of awell that had a 20 to 1 permeability contrastbetween layers using a workover rig instead of amore costly drilling unit. The entire well wasimmediately flowed back and cleaned up to 100%crude oil within two hours. Stabilized

measurement indicates sustained naturalproduction of more than 10,000 bbl/d [1,590 m3/d]of oil—five times the field average and threetimes greater than the best well in the field.

Real-Time ControlChemical diversion is also being used in hydraulicfracturing operations. Through the use ofdiverting fluids that degrade completely after thetreatment, it is possible to stimulate numerouszones in a continuous operation without usingdiverting tools. Recent experience has shown thatthis method of diversion is particularly well-suited to fracture treatment of shale-gasformations. In almost every case, shale-gas wellsmust be hydraulically fractured before they canproduce significant amounts of gas (above). Manyof the new, deeper shale-gas wells are horizontal,and fracturing them can represent a considerableportion of completion costs.

Typically, because of the high cost oftraditional multistage fracturing practices,horizontal shale-gas wells have been limited totwo to four perforation clusters for every 500 ft[152 m] of lateral section. That means that a2,000-ft lateral well, for example, would be

treated in only four stages through 8 to 16 zonesof entry, leaving about 90% of the wellboreuntouched. The optimum approach to shale-gasfracturing would instead be 40 or more smallerstages, clustering the fractures as close togetheras possible.16

When combined with real-time fracturemonitoring, chemical diversion can be used tocontrol fracture propagation as it occurs. Withthe Contact service dynamic category oftreatment systems, engineers use the StimMAPservice to track fracture or refracture creation asthe job is being pumped and then compare theresults with the expected outcome. Then, if thefracture is deviating from its desired course—forinstance, threatening to enter a water zone—engineers can deploy the chemical divertingagent, DivertaMAX effective diversion service formultistage hydraulic fracturing, to redirect it.Slurries containing the DivertaMAX fluid are ablend of degradable materials that cantemporarily block fractures, divert fluid flow andinduce the creation of additional fractures in situand at the wellbore.

This strategy is especially useful in shale-gasplays in which refracturing would seem to be anobvious solution to quickly falling productionprofiles. Perhaps the most active of thesereservoirs, the Barnett Shale in the Fort Worthbasin in north Texas, is a complex reservoir inwhich first-year average production decline ismore than 50%. As a result, many of thesewells—usually horizontal wells with multipletransverse fracture treatments placed acrossthe reservoir—need to be refractured withinfive years of the initial completion. Buteconomics dictate that this must be done moreefficiently than is possible with traditionalmultistage, rig-based fracturing.

16 Oilfield Review

15. For more on viscoelastic acid stimulation: Al-Anzi E, Al-Mutawa M, Al-Habib N, Al-Mumen A, Nasr-El-Din H,Alvarado O, Brady M, Davies S, Fredd C, Fu D, Lungwitz B,Chang F, Huidobro E, Jemmali M, Samuel M and Sandhu D: “Positive Reactions in Carbonate Reservoir Stimulation,” Oilfield Review 15, no. 4 (Winter 2003/2004): 28–45.

16. “Unconventional Gas: Shale Gas,” www.unbridledenergy.com/assets/pdf/About_Shale_Gas.pdf (accessed June 2, 2008).

17. Seale R: “An Efficient Horizontal Open Hole Multi-StageFracturing and Completion System,” paper SPE 108712,presented at the SPE International Oil Conference andExhibition, Veracruz, Mexico, June 27–30, 2007.

18. http://www.slb.com/content/services/solutions/reservoir/unconventional_gas_4.asp (accessed June 12, 2008).

19. http://www.gfz-potsdam.de/portal/-?$part=CmsPart&$event=display&docId=2022464&cP=sec43.quicksearch(accessed June 30, 2008).

> Enhancing production from shale-gas wells. Creating transverse fracturesin horizontal wells greatly increases contact with the shale-gas formation.Transverse fractures (purple) are those in which the direction of the fractureruns perpendicular to the wellbore. They are created by drilling the well inthe direction of minimum horizontal stresses. Longitudinal fractures (green)are parallel to the wellbore and result from fracturing wells drilled in thedirection of maximum horizontal stresses.

TransverseLongitudinal

Vertical stress

Surface

Minimum horizontal stressσh, minMaximum horizontal

stress, σH, max


Summer 2008 17

One operator was faced with this scenario ona Barnett Shale well that initially producedabout 2.2 MMcf/d [62,300 m3/d]. In less than fouryears, production had fallen to less than500 Mcf/d [14,200 m3/d]. Then microseismicmonitoring of the original stimulationtreatments revealed considerable opportunity toincrease formation contact.

The operator employed the DivertaMAXservice in concert with the StimMAP system asan alternative to the prohibitively costlytraditional methods using bridge plugs andpackers on a workstring for isolation. Based onmeasured posttreatment decline rates, theoperator estimates the combination strategy willbe paid out within six months of the stimulation.More importantly, recoverable reserves areexpected to increase by 20% over 20 years.

Another Barnett Shale well was completed in January 2005, and one year later had seenproduction fall from about 2 MMcf/d[56,640 m3/d] to half that amount. Microseismicdata indicated a less than optimal stimulationhad been performed during the third and fourthstages of the well’s original treatment.Production logs run in May 2006 and September2007 also showed that a significant portion of theheel section of the reservoir was not producing,reducing the production rate by half again to500 Mcf/d.

Company engineers decided to perform asingle-stage fracture to stimulate the heelsection of the wellbore. DivertaMAX diversionstages were pumped to allow for movement of thefracture entry point along the lateral. Duringtreatment, diversion plugs were pumped basedon feedback from StimMAP Live monitoring(above). After the treatment, productionincreased immediately from 500 to 1.2 MMcf/d[34,000 m3/d] and payout is expected in ninemonths. The treatment is also estimated to havethe potential to increase recoverable reserves by0.8 Bcf [22 million m3].

Shale Gas: The Next ChallengeSpurred by the low oil prices of the 1980s, the oiland gas industry rapidly developed newtechnology that enabled it to drill longer, moreconvoluted, directional and extended-reachwells. Initially, this effort was aimed atincreasing wellbore contact through naturallyfractured reservoirs that could flow on theirown.17 Today, most of those opportunities havebeen, or are being, exploited, and operators mustlook increasingly to combining the benefits ofextensive formation contact and hydraulicfracturing to attain economic production ratesfrom their horizontal wells.

While that strategy is being applied to manytypes of low-permeability reservoirs, both newand mature, perhaps the most tempting targetfor its application today is in shale-gas reservoirs. Once ignored by operators seeking easier plays and quicker returns oninvestments, these tight-gas formations arecurrently boosting US natural gas reserves. In2007, according to the US Energy InformationAdministration, 3.6 x 1012 m3 [1.3 x1011 Mcf] ofshale gas are technically recoverable from USreservoirs. The challenge is to release it.18

In addition, because of the technology beingdeveloped and proved in the USA, shale-gasreservoirs may soon add significant reservesworldwide. While no commercial shale-gas enterprises are currently known outside ofNorth America, worldwide reserves have been estimated at more than 16,000 Tcf[453 trillion m3] of gas.19

The key to harvesting this potential iscompleting long, high-angle wells efficiently.Technologically, that means placing treatmentsoptimally and accurately in each target zonealong the entire length of wellbore, monitoringand altering the operation in real time and achieving all this at minimum cost and time. —RvF

> Monitoring diversion. Typically, the rapid production decline in the Barnett Shale is attributed to poor stimulation in the heel section (lower right infigures) of the lateral as captured by this StimMAP microseismic monitoring profile (left ). In this case, a later treatment that incorporated DivertaMAXfracture and diversion technology ensured full coverage of all zones. StimMAP Live real-time fracture monitoring of microseismic data indicated that alarge section of the original fracture had been restimulated plus about 25% of new lateral treated (right ).

Dist

ance

, ft

Distance, ft

–1,500 –750 0–3,000 –2,250

–2,250

–1,500

–750

0

Dist

ance

, ft

Distance, ft

–1,500 –750 0–3,000 –2,250

–2,250

–1,500

–750

0


the right treatment for the right reservoir -...

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