High-Pressure, High-Temperature · PDF file46 Oilﬁeld Review High-Pressure, High-Temperature Technologies Gunnar DeBruijn Craig Skeates Calgary, Alberta, Canada Robert Greenaway

46 Oilfield Review

High-Pressure, High-TemperatureTechnologies

Gunnar DeBruijnCraig SkeatesCalgary, Alberta, Canada

Robert GreenawaySouthampton, England

David HarrisonMike ParrisSugar Land, Texas, USA

Simon JamesClamart, France

Fred MuellerCorpus Christi, Texas

Shantonu RayAberdeen, Scotland

Mark RidingGatwick, England

Lee TempleHouston, Texas

Kevin WutherichHannover, Germany

For help in preparation of this article, thanks to TrevorBouchard, Calgary; Mary Jo Caliandro, Martha Dutton,Gretchen Gillis, John Still and Don Williamson, Sugar Land,Texas; and Lisa Stewart, Cambridge, Massachusetts, USA.AIT, CemCRETE, CemSTRESS, CNL, FlexSTONE, FlexSTONE HT,Litho-Density, Quicksilver Probe, REDA Hotline550, Sensa,SlimXtreme, SLT, ThermaFRAC, WellWatcher, WellWatcherBriteBlue, WellWatcher Ultra and Xtreme are marks ofSchlumberger.Chemraz is a trademark of Greene, Tweed & Co., Ltd.INCONEL and Monel are trademarks of Special MetalsCorporation. Teflon is a registered trademark of E.I. du Pontde Nemours and Company. Viton is a trademark of DuPont

E&P activity increasingly involves operations in high-pressure, high-temperature

downhole conditions. This environment introduces difficult technical concerns

throughout the life of a well. Scientists and engineers are developing advanced tools,

materials and chemical products to address these challenges.

News reports continually remind us about thecost and availability of energy from fossil fuelsand renewable sources. Despite remarkablegrowth in renewable-energy technology duringthe past 20 years, it is well accepted by thescientific and engineering community that theworld’s energy needs will continue to be satisfiedprimarily by fossil fuels during the next fewdecades. Aggressive exploration and productioncampaigns will be required to meet the coming demand.

Finding and producing new hydrocarbonreserves may be a difficult proposition, oftenrequiring oil and gas producers to contend withhostile downhole conditions. Although high-pressure, high-temperature (HPHT) wells are

fundamentally constructed, stimulated, pro ducedand monitored in a manner similar to wells withless-demanding conditions, the HPHT environ -ment limits the range of available materials andtechnologies to exploit these reservoirs.

The oil and gas industry has contended withelevated temperatures and pressures for years;however, there are no industry-wide standardsthat define HPHT conditions and the associatedinterrelationship between temperature andpressure. In an effort to clarify those definitions,Schlumberger uses guidelines that organizeHPHT wells into three categories, selectedaccording to commonly encountered technologythresholds (below).1

1. Belani A and Orr S: “A Systematic Approach to HostileEnvironments,” Journal of Petroleum Technology 60,no. 7 (July 2008): 34–39.

> HPHT classification system. The classification boundaries representstability limits of common well-service-tool components—elastomeric sealsand electronic devices.

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Autumn 2008 47


In this system, HPHT wells begin at 150°C[300°F] bottomhole temperature (BHT) or69 MPa [10,000 psi] bottomhole pressure (BHP).The rationale for this threshold is related to thebehavior of standard elastomeric seals.Engineers who run downhole equipment in thisenvironment have found it prudent to replace theseals before reusing the tools.

Ultra-HPHT wells exceed the practicaloperating limit of existing electronicstechnology—greater than 205°C [400°F] or 138 MPa [20,000 psi]. At present, operatingelectronics beyond this temperature requiresinstalling internal heat sinks or placing thedevices inside a vacuum flask to shield theelectronics from the severe temperatures.

The HPHT-hc classification defines the mostextreme environments—wells with temperaturesand pressures greater than 260°C [500°F] or241 MPa [35,000 psi].2 Such pressure conditionsare unlikely to be seen in the foreseeable future.However, bottomhole tempera tures in geothermaland thermal-recovery wells already exceed 260°C.

It is important to emphasize that theSchlumberger HPHT classification scheme is notlimited to wells that simultaneously satisfy thetemperature and pressure criteria. If eitherparameter falls within one of the three HPHTregions, the well is classified accordingly. Thus, alow-pressure, shallow steamflood project toextract heavy oil lies in the HPHT-hc regionbecause of the high steam temperature.Conversely, reservoirs associated with low-temperature, high-pressure salt zones in the Gulfof Mexico fit an HPHT classification because ofthe high pressure.

A vital HPHT-well parameter is the length oftime that tools, materials and chemical productsmust withstand the hostile environment. Forexample, logging and testing tools, drilling mudsand stimulation fluids are exposed to HPHTenvironments for a limited time, but packers,sand screens, reservoir monitoring equipmentand cement systems must survive for manyyears—even beyond the well’s productive life.

Accordingly, this time factor has a major impacton how scientists and engineers approachproduct development.

Oilfield Review last reviewed the HPHTdomain in 1998.3 Since then, the number of HPHT projects has grown, and the severity ofoperating conditions has steadily increased(above). For example, a recent proprietary survey by Welling and Company on the directionof subsea systems and services reported that 11%of wells to be drilled in the next three to fiveyears are expected to have BHTs exceeding177°C [350°F]. In addition, 26% of respondentsexpect BHPs between 69 and 103 MPa [10,000 and 15,000 psi], and 5% predict evenhigher pressures.

Today, scientists and engineers push thelimits of materials science to meet the technicalchallenges posed by HPHT wells. This articlesurveys tools, materials, chemical products andoperating methods that have been developed forsuccessful HPHT well construction, stimulation,production and surveillance. Case studiesillustrate the application of some solutions.

48 Oilfield Review

> HPHT projects around the world. During the past decade the number of HPHT projects has increased significantly; nevertheless, these projectsrepresent only about 1% of producing reservoirs worldwide. The principal HPHT areas are found in the United States (deepwater Gulf of Mexico anddeep, hot onshore wells), North Sea, Norwegian Sea, Thailand and Indonesia. In addition, thermal-recovery projects to extract heavy oil are located inCanada, California, Venezuela and eastern Europe.

HPHTUltra-HPHTHPHT-hc


Autumn 2008 49

Testing and Qualification of HPHT TechnologiesHPHT conditions amplify risks that exist inconventional wells. In HPHT wells, the marginfor error is greatly reduced, and theconsequences of failure may be more costly andfar reaching. Therefore, before field application,new products and services designed for hostileenvironments must be rigorously tested andqualified to withstand the tougher downholeconditions.4 This qualifi cation includesaccelerated degradation testing aimed atcalculating ultimate service life withoutperforming several years of testing. To meet thisneed, the industry has built state-of-the-artfacilities that allow engineers to conductrealistic evaluations (right). Many tests areperformed according to standard industrymethods; however, increasingly severe downholeconditions are rapidly approaching the limits ofdocumented testing procedures.5

Laboratory evaluations fall into three principalcategories: fluids, mechanical devices and elec -tronics. Engineers pump a plethora of fluidsystems into wells throughout their productivelives. Testing under simulated downhole condi -tions answers two basic questions. Can the fluidbe prepared and properly placed in the well? Willthe fluid be sufficiently stable to perform itsintended functions? The testing protocol is oftencomplex, involving rheology, filtration, corrosionand mechanical-properties evaluations.6

Mechanical devices include seals, screensand packers, along with rotating andreciprocating parts such as shafts, pistons, valvesand pumps. In addition to HPHT exposure,qualification testing also includes contact withhazards such as mechanical shocks, hydrogensulfide [H2S], carbon dioxide [CO2] and erosiveparticle-laden fluids.

Electronic components and sensors, the thirdelement, are particularly vulnerable to hightemperatures. The key challenge involves thestability of plastic or composite materials thatprovide modern electronics with structuralintegrity and insulation. Electronics manufac -turers do not perform extensive R&D in theHPHT domain because the size of the HPHTelectronics market is tiny compared to consumerelectronics such as mobile phones. As a result,oilfield-equipment engineers must determinethe operational time limit of existing electronicsunder simulated downhole conditions.

The availability of sophisticated test facilities,coupled with an intense R&D effort, has resultedin the development of new HPHT products andservices that span all the stages of well opera -tions. Several of these advances are highlightedin the following sections.

2. The “hc” term comes from the steepest mountain-gradeclassifications used by the Tour de France bicycle race.In the French language, “hc” stands for “horscatégorie,” essentially meaning “beyond classification.”

3. Adamson K, Birch G, Gao E, Hand S, Macdonald C, Mack D and Quadri A: “High-Pressure, High-Temperature Well Construction,” Oilfield Review 10, no. 2 (Summer 1998): 36–49.Baird T, Fields T, Drummond R, Mathison D, Langseth B,Martin A and Silipigno L: “High-Pressure, High-Temperature Well Logging, Perforating and Testing,” Oilfield Review 10, no. 2 (Summer 1998): 50–67.

4. Arena M, Dyer S, Bernard LJ, Harrison A, Luckett W,Rebler T, Srinivasan S, Borland B, Watts R, Lesso B and Warren TM: “Testing Oilfield Technologies for Wellsite Operations,” Oilfield Review 17, no. 4 (Winter 2005/2006): 58–67.

5. Organizations governing the testing and qualification ofoilfield products and services include the AmericanPetroleum Institute (API), International Organization forStandardization (ISO), NACE International (NACE) andASTM International (ASTM).

6. For more on laboratory testing of fluids:Dargaud B and Boukhelifa L: “Laboratory Testing, Evaluation and Analysis of Well Cements,” in Nelson EBand Guillot D (eds): Well Cementing–2nd Edition.Houston: Schlumberger (2006): 627–658.Gusler W, Pless M, Maxey J, Grover P, Perez J, Moon Jand Boaz T: “A New Extreme HPHT Viscometer for NewDrilling Fluid Challenges,” paper IADC/SPE 99009,presented at the IADC/SPE Drilling Conference, Miami,Florida, USA, February 21–23, 2006.“Laboratory Techniques for Fracturing-FluidCharacterization,” in Economides MJ and Nolte KG (eds):Reservoir Stimulation. Houston: SchlumbergerEducational Services (1987): C-1–C-3.

> HPHT testing. Special equipment and facilities are required to evaluate fluids, mechanical devicesand electronics at realistic downhole conditions. Logging tools and associated electronics can beoperated in an HPHT casing simulator (top left ) at temperatures and pressures up to 316°C and 207 MPa. HPHT consistometers (top center) can evaluate the thickening and setting behavior ofcement slurries up to 371°C [700°F] and 207 MPa. (Photograph courtesy of Cement Testing Equipment,Inc.) A similar device for measuring the rheological behavior of drilling fluids can operate at 316°Cand 276 MPa [40,000 psi] (top right). (Photograph courtesy of AMETEK, Inc.) For flow-assurancemeasurements, HPHT pressure-volume-temperature (PVT) cells (center) detect fluid-phase changesand bubblepoints at conditions up to 250°C and 172 MPa. For safety, engineers place the equipment inindividual reinforced testing bays (bottom left ) and control it remotely from a central facility (bottomcenter). Before shipment to the field, integrated solutions can be tested in the well at theSchlumberger Sugar Land, Texas facility (bottom right) , rated to 316°C and 241 MPa.


Drilling and Formation EvaluationWhile drilling HPHT wells, engineers frequentlyencounter overpressured formations, weak zonesand reactive shales. In addition, boreholes areoften slim and highly deviated. To maintain wellcontrol, the drilling-fluid hydrostatic pressuremust be high enough to resist the formation porepressure, yet low enough to prevent formationfracturing and lost circulation. As a conse -quence, the acceptable fluid-density range isoften small, requiring careful control of fluidcirculation to avoid pressure surges that exceedformation-fracture pressures. To prevent forma -tion damage or borehole collapse, the drillingfluid must inhibit clay-mineral swelling. Thedrilling fluid must also be chemically stable andnoncorrosive under HPHT conditions.

During the past decade, drilling fluids based onformate salts have been displacing conventionalhalide-base fluids in HPHT wells.7 Fluidscontaining halides are highly corrosive to steel atelevated temperatures and pose environmentalhazards. Corrosion rates associated with formatesolutions are low, provided the fluid pH remains inthe alkaline range. For this reason, formate mudsare usually buffered with a carbonate salt. Unlikehalides, formates are readily biodegradable andmay be used with confidence in environmentallysensitive areas.

Formates are extremely soluble in water andcan be used to create invert emulsions or solids-free brines with densities up to 2,370 kg/m3

[19.7 lbm/galUS], reducing the need forweighting agents.8 Lower solids concentrations

often improve the rate of drillbit penetration andallow better control of rheological properties.Formate brines also have low water activity;consequently, through osmotic effects, theyreduce the hydration of formation clays andpromote borehole stability.9

Statoil reported success with formate-basefluids when drilling high-angle HPHT wells in theNorth Sea.10 The wells are in the Kvitebjørn,Kristin and Huldra fields, with reservoir pres suresup to 80.7 MPa [11,700 psi] and temperatures upto 155°C [311°F]. Long sequences of interbeddedreactive shales are also present. Despite thechallenging environ ment, Statoil experienced nowell-control incidents in all 15 HPHT drillingoperations in those fields during a five-yearperiod. In addition, control of formation clays anddrilling cuttings helped maintain a low solidsconcentration, allowing the operator to routinelyrecycle and reuse the drilling fluid.

HPHT conditions present abundant chal -lenges to scientists and engineers who design andoperate formation-evaluation tools. As mentionedearlier, the most vulnerable tool compo nents areseals and electronics. Measurement physicsdictates direct exposure of most logging-toolsensors to wellbore conditions; thus, they arebuilt into a sonde. Most sonde sections are filledwith hydraulic oil and incorporate a compen -sating piston that balances the inside and outsidepressures to maintain structural integrity andprevent tool implosion. Current sondes areroutinely operated at pressures up to 207 MPa[30,000 psi].

The electronics are separated and protectedinside a specially engineered cartridge section.11

Unlike sonde sections, cartridges are not pressure-compensated because high pressures would crushthe electronics inside. During a logging trip,electronic components remain at atmosphericpressure inside the cartridge housing, which mustresist the external pressure. Housing collapse notonly would destroy the electronics, but also mightdistort the tool to an extent that fishing would benecessary. Pressure protection is provided bytitanium-alloy housings.

Leaks at seal surfaces or joints may also lead toflooding and cartridge destruction. Therefore, O-rings are strategically placed along thetoolstring to seal connections and internalcompartments. To avoid catastrophic failure of theentire toolstring, individual tools are also isolatedfrom each other by pressure-tight bulkheads in amanner similar to those in a submarine. O-ringsfor HPHT applications are composed offluoropolymeric elastomers. Viton elastomer, themost common example, is rated to 204°C [400°F].At higher temperatures, the Viton formulationbreaks down and loses elasticity. For theseextreme situations, Schlumberger engineers havequali fied O-rings fabricated from Chemrazelastomer—an advanced material that is stable toabout 316°C [600°F] but is significantly moreexpensive than its Viton counterpart.12

Current electronic systems for HPHT loggingcan operate continuously at temperatures up to177°C. The temperature inside the cartridge is afunction of the downhole temperature andinternal heat generated by the electronics. Whenhigher external temperatures are anticipated,engineers place the tool inside an insulatingDewar flask—a vacuum sleeve that delays heattransmission. Depending upon the duration ofthe logging run, Dewar flasks allow operations attemperatures up to 260°C. Recently, extendedrun times have become possible with the intro -duction of low-power electronics that generateless internal heat.

Since the mid 1990s, well depths in the Gulfof Mexico have increased rapidly, and BHTs andBHPs have followed suit (left).13 Conversely,borehole size usually decreases with depth. Inresponse to this trend, Schlumberger engineersintroduced the SlimXtreme well loggingplatform—a miniaturized version of the XtremeHPHT logging system (next page).14 This serviceoffers the same suite of measurements as itslarger counterpart, packaged in a 3-in. diametertoolstring. As a result, the system can be runinside openings as small as 31⁄2-in. drillpipe or 37⁄8-in. open hole. In addition, thanks in part to

50 Oilfield Review

> Trend of maximum well depth in the Gulf of Mexico. A significant acceleration of the trend hasoccurred since the mid 1990s. Unprecedented bottomhole conditions are expected within the nextfew years, with BHTs exceeding 260°C and BHPs approaching 241 MPa.

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Autumn 2008 51

the lower external surface area of the titaniumhousing, the SlimXtreme toolstring can operateat pressures up to 207 MPa.

Chevron applied SlimXtreme technology inthe Gulf of Mexico while logging deepwaterexploratory wells at the Tonga prospect in GreenCanyon Block 727. During logging runs to31,824 ft [9,700 m], the system experienced pres -sures up to 26,000 psi [180 MPa] and continuedto operate successfully. Another Chevronexploratory well, the Endeavour 2 in south Texas,tested SlimXtreme performance at elevatedtempera tures. The toolstring, incorpo ratingportions enclosed within a Dewar flask, was ableto provide reliable data to 21,800 ft [6,645 m] and489°F [254°C].

Deep HPHT wells present additional wireline-logging challenges. Multiple runs are usuallynecessary to acquire the information, and smallboreholes, long cables and heavy toolstringsincrease the risk of the tools becoming stuck.

7. Formate salts are based on formic acid—HCOOH.Sodium, potassium and cesium formate (and combina -tions thereof) are used in drilling-fluid applications.

8. An invert emulsion contains oil in the continuous, orexternal, phase and water in the internal phase.

9. Water activity (aw ) is the equilibrium amount of wateravailable to hydrate materials. When water interactswith solutes and surfaces, it is unavailable for otherhydration interactions. An aw value of one indicates purewater, whereas zero indicates the total absence of“free” water molecules. Addition of solutes (such asformate salts) always reduces the water activity.Byrne M, Patey I, George L, Downs J and Turner J:“Formate Brines: A Comprehensive Evaluation of TheirFormation Damage Control Properties Under RealisticReservoir Conditions,” paper SPE 73766, presented atthe SPE International Symposium and Exhibition onFormation Damage Control, Lafayette, Louisiana, USA,February 20–21, 2002.

10. Berg PC, Pedersen ES, Lauritsen A, Behjat N, Hagerup-Jenssen S, Howard S, Olsvik G, Downs JD,Harris M and Turner J: “Drilling, Completion andOpenhole Formation Evaluation of High-Angle Wells inHigh-Density Cesium Formate Brine: The KvitebjørnExperience, 2004–2006,” paper SPE/IADC 105733,presented at the SPE/IADC Drilling Conference,Amsterdam, February 20–22, 2007.

11. The sonde is the section of a logging tool that containsthe measurement sensors. The cartridge contains theelectronics and power supplies.

12. Viton elastomer is a copolymer of vinylidenfluoride andhexafluoroisopropene, (CH2CF2)n(CF(CF3)CF2)n. Chemrazelastomer is a similar compound that contains morefluorine. Both are related to the well-known Teflonfluoropolymer.

13. Sarian S: “Wireline Evaluation Technology in HPHTWells,” paper SPE 97571, presented at the SPE HighPressure/High Temperature Sour Well Design AppliedTechnology Workshop, The Woodlands, Texas, May 17–19, 2005.

14. Introduced during the late 1990s, Xtreme well-logging toolsrecord basic petrophysical measurements at conditions upto 260°C and 172 MPa [25,000 psi]. The measurementsinclude resistivity, formation density, neutron porosity,sonic logging and gamma ray spectroscopy.Henkes IJ and Prater TE: “Formation Evaluation in Ultra-Deep Wells,” paper SPE/IADC 52805, presented at the SPE/IADC Drilling Conference, Amsterdam, March 9–11, 1999.

> Equipment and software for wireline logging and sampling in HPHT wells.The SlimXtreme platform (left ), designed for slimhole drilling in HPHT andhigh-angle wells, provides a complete suite of downhole measurements inboreholes as small as 37⁄8-in. Engineers run the tools at speeds up to 1,097 m/h[3,600 ft/h], and data can be transmitted to the surface through wireline aslong as 10,970 m [36,000 ft]. Temperature planning software simulates thelogging job and predicts external (red) and internal (blue) tool temperaturesversus time (top right). In this example, the external tool temperature risesand falls as the tool is lowered into the well and then retrieved. However, theinternal tool temperature remains well below the 160°C limit (green),indicating that the electronics will be protected. These simulations are usefulfor optimizing the operation and ensuring tool survival. The applicationconsiders several job parameters, including well conditions, logging speedand the presence of Dewar flasks. The risk of stuck toolstrings increaseswhen logging and sampling from deep, slim HPHT wells. A high-tensiondeployment system (bottom right) mitigates the risk by combining a standardSchlumberger wireline unit, a high-strength dual-drum capstan and high-strength wireline cable. The capstan increases the pulling force that can beexerted on the wireline, allowing retrieval of heavy toolstrings and reducingthe risk of sticking.

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Caliper sonde

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Fishing operations to retrieve tools from deepholes are expensive, time-consuming andprecarious—possibly resulting in stuck drillpipe,tool damage or tool loss. To minimize the danger,Schlumberger engineers developed an improvedtool-deployment method using high-tension cableand a capstan. The system allows rapiddeployment of the logging string and much higherpulling capacity, reducing the risk of tool sticking.

Another important wireline operationinvolves acquiring fluid samples from hydro -carbon reservoirs and analyzing them downholeor at the surface. Test results provide oilcompanies with information necessary to decidehow to complete a well, develop a field, designsurface facilities, tie back satellite fields andcommingle production between wells.15 HPHTconditions increase the difficulty of downholesampling. In addition, pressurized live-fluidsamples must be safely transported to thesurface and then to nearby laboratories.Sampling operations in HPHT wells are costly,especially offshore; therefore, collecting high-quality samples is crucial to justify the expense.

In 2004, Chevron began drilling exploratorywells into the Lower Tertiary play in the deepwaterGulf of Mexico (see “The Prize Beneath the Salt,”page 4). These wells can be difficult to drill andcomplete, with water depths to 9,800 ft [3,000 m],total well depths exceeding 25,000 ft [7,600 m],and BHPs and BHTs often approaching 20,000 psi[138 MPa] and 392°F [200°C]. In 2006, Chevrondecided to invest considerable resources and rigtime to perform an extended well test (EWT) onthe Jack 2 well, southwest of New Orleans and

175 mi [282 km] offshore. The long-term drillstemtest (DST) was necessary to acquire vital reservoirand production information that would reduceuncertainty and risk involving reservoir compart -mentalization, fluid properties and productivity. At28,175 ft [8,588 m], the Jack 2 test would be thedeepest ever attempted in the Gulf of Mexico.

Before performing the DST, Chevron selectedthe Quicksilver Probe fluid-sampling tool toextract high-purity formation-fluid samples. Thissystem employs a unique multiple fluid-intakesystem to minimize formation-fluid samplecontamination, and it operates in conditions to350°F. Samples acquired by the QuicksilverProbe module contained less than 1% contami -nation after 4 hours of pumping. Fluid-propertiesdata provided by the samples allowed theoperator to make drilling and well-testing proce -dure adjustments that reduced the overall risk.

The Jack 2 EWT also required an HPHTperforating system. Consulting with Chevronpersonnel, Schlumberger engineers built a toolcombination that is rated to 25,000 psi [172 MPa].The Jack 2 perforating system incorporated a 7-in.gun capable of firing 18 shots per foot, as well as aperforating shock absorber and a redundantelectronic firing head. Approximately ninemonths of engineering, manufacturing and testingwere required to achieve full qualification. A final90-day performance test took place at theSchlumberger Reservoir Completions (SRC)Center in Rosharon, Texas, inside a test vesselthat simulated the anticipated downhole condi -tions. The equipment functioned properly, andChevron engineers approved deployment of theperforating equipment to the rig.

The EWT was a success, and the Jack 2 wellsustained a flow rate exceeding 6,000 bbl/d [950 m3/d] of crude oil from about 40% of thewell’s net pay. This result led Chevron and itspartners to request various sizes of HPHTperforating systems for additional appraisal wellsnearby and future field developments elsewherein the deepwater Gulf of Mexico.16

Cementing and Zonal IsolationProviding zonal isolation in deep oil and gas wellssuch as Jack 2 requires use of cement systemsthat are stable in HPHT environments. Thermallystable cements are also necessary in steamfloodwells and geothermal wells.17 The physical andchemical behavior of well cements changessignificantly at elevated temperatures andpressures. Without proper slurry design, theintegrity of set cement may deteriorate,potentially resulting in the loss of zonal isolation.Unlike many other HPHT technologies, wellcements are permanently exposed to downholeconditions and must support the casing andprovide zonal isolation for years.

Portland cement is used in nearly all well-cementing applications. The predominantbinding minerals are calcium silicate hydrates(CSH). At temperatures above about 110°C[230°F], mineralogical transformations occurthat may cause the set cement to shrink, losestrength and gain permeability. This deterio -ration can be minimized or even prevented byadding at least 35% silica by weight of cement.The compositional adjustment causes theformation of CSH minerals that preserve thedesired set-cement properties. Although silica-stabilized Portland cement systems can be usedat temperatures up to about 370°C [700°F], theyare susceptible to other challenges posed bythermal wells.

A thermally stable cement system mayinitially provide adequate zonal isolation;however, changes in downhole conditions caninduce stresses that compromise cement-sheathintegrity. Tectonic stresses and large changes inwellbore pressure or temperature may crack thesheath and can even reduce it to rubble. Radialcasing-size fluctuations induced by temperatureand pressure changes can damage the bondbetween the set cement and the casing or theformation, creating a microannulus. Theseproblems are of particular concern in deep, hotwells and thermal-recovery wells employingcyclic-steam-stimulation (CSS) or steam-assisted-gravity-drainage (SAGD) processes.18

52 Oilfield Review

> FlexSTONE HT cement properties at 200°C compared with those ofconventional cements. To ensure proper bonding between the cement/casingand cement/formation interfaces, FlexSTONE cements can be formulated toprovide significantly more expansion after setting than conventional systems(left ). FlexSTONE HT systems also offer improved zonal-isolation properties,including lower Young’s modulus and lower permeability (right).

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15


Autumn 2008 53

Until recently, the well cementing industryfocused on one mechanical parameter—unconfined uniaxial compressive strength—toqualify a cement design. The longer-term diffi -culties described above led Schlumbergerscientists to more thoroughly investigate themechanical properties of set cement, along withmodels governing the mechanical behavior ofsteel pipe and rocks. They adapted the models tothe geometry of a well and introducedCemSTRESS software—an application thatanalyzes the behavior of a cement sheath exposedto anticipated downhole conditions. This softwareanalyzes radial and tangential stresses experi -enced by the cement sheath resulting frompressure tests, formation-property changes andtemperature fluctuations. Along with compressivestrength, the CemSTRESS algorithms considerYoung’s modulus, Poisson’s ratio and tensilestrength and help engineers determine theappropriate cement mechanical properties for agiven application.19

CemSTRESS analysis usually indicates thatcement sheaths in CSS and SAGD wells should bemore flexible than in conventional systems. Thiscan be achieved by using cements with lowerYoung’s moduli (previous page).20 In addition, thecement sheath should expand slightly aftersetting to ensure firm contact with the casingand formation. These requirements led to thedevelopment of FlexSTONE HT high-temperatureflexible cement.21 This cement is part of a familythat combines the engineered particle-sizeconcept of CemCRETE technology with flexibleparticles that lower the Young’s modulus.22 Inaddition, expansion after setting can besignificantly higher than that of conventionalcement systems, promoting bonding with thecasing and formation.23 The temperature limit ofFlexSTONE HT cement is about 250°C [482°F].

An operator in the UK region of the North Seahad an ambitious goal of producing gas at asustained 6.8-million m3/d [240-MMcf/d] produc -tion rate from three wells with a BHT of 193°C

[380°F].24 Meeting this goal would requireunusually high drawdown pressures, exertingsigni ficant mechanical stress on the casing,cement sheath and formation. Using CemSTRESSsoftware, Schlumberger engineers determinedthat placing FlexSTONE HT cement across theproduction zone would provide a gasket-like sealcapable of withstanding the severe environment.After cement placement, the production stringswere subjected to pressure tests up to 69 MPa anddrawdown tests exceeding 41 MPa [6,000 psi]. Thecement sheath remained intact. After more thantwo years of production, there have been no well-integrity problems.

Heavy-oil projects involving SAGD wells alsoemploy FlexSTONE HT cement extensively. Aneastern European reservoir contained aparticularly thick crude oil—12,000-MPa-s[12,000-cP] viscosity and a 17°API gravity. Oilmining had been the standard recovery method.To reduce production costs, the operator electedto try the SAGD method in a pilot well. Thisapproach presented multiple well-constructionconcerns: 300-m [984-ft] horizontal sections at aTVD of 228 m [748 ft], temperatures approaching250°C and stresses on the cement sheathresulting from thermal production cycles and asoft formation. FlexSTONE HT cement success -fully withstood the production conditions with noloss of zonal isolation, and the operator hasplanned additional SAGD installations. CSS andSAGD wells in Canada, Venezuela, Egypt,Indonesia and California, USA, have alsobenefited from FlexSTONE HT cement.

CSS and SAGD wells require specialized, high-performance completion equipment to handlethe extreme temperature cycles. Commonelastomeric seals often fail, allowing pressure andfluids to escape up the casing, reducing steam-injection efficiency and increasing the potentialfor casing corrosion. Recently, Schlumbergerengineers began using seals fabricated from ayarn of carbon fibers contained within anINCONEL alloy jacket. These seals are capable of

operating at cycled-steam temperatures up to340°C [644°F] and pressures up to 21 MPa[3,000 psi], allowing reliable deployment ofthermal liner systems (above).

15. Akkurt R, Bowcock M, Davies J, Del Campo C, Hill B,Joshi S, Kundu D, Kumar S, O’Keefe M, Samir M,Tarvin J, Weinheber P, Williams S and Zeybek M:“Focusing on Downhole Fluid Sampling and Analysis,”Oilfield Review 18, no. 4 (Winter 2006/2007): 4–19.Betancourt S, Davies T, Kennedy R, Dong C, Elshahawi H,Mullins OC, Nighswander J and O’Keefe M: “AdvancingFluid-Property Measurements,” Oilfield Review 19, no. 3(Autumn 2007): 56–70.

16. Aghar H, Carie M, Elshahawi H, Ricardo Gomez J,Saeedi J, Young C, Pinguet B, Swainson K, Takla E andTheuveny B: “The Expanding Scope of Well Testing,”Oilfield Review 19, no. 1 (Spring 2007): 44–59.

17. Nelson EB and Barlet-Gouédard V: “Thermal Cements,”in Nelson EB and Guillot D (eds): Well Cementing–2ndEdition. Houston: Schlumberger (2006): 319–341.

18. Alboudwarej H, Felix J, Taylor S, Badry R, Bremner C,Brough B, Skeates C, Baker A, Palmer D, Pattison K,Beshry M, Krawchuk P, Brown G, Calvo R,

Stiles D: “Effects of Long-Term Exposure to UltrahighTemperature on the Mechanical Parameters of Cement,”paper IADC/SPE 98896, presented at the IADC/SPEDrilling Conference, Miami, Florida, February 21–23, 2006.

22. For more on engineered-particle-size cements:Nelson EB, Drochon B and Michaux M: “Special Cement Systems,” in Nelson EB and Guillot D (eds): Well Cementing–2nd Edition. Houston: Schlumberger(2006): 233–268.

23. Cement systems that expand slightly after setting are aproven means for sealing microannuli and improvingprimary cementing results. Improved bonding resultsfrom tightening of the cement sheath against the casingand formation.

24. Palmer IAC: “Jade North Sea HPHT Development:Innovative Well Design Generates Best in ClassPerformance,” paper SPE/IADC 92218, presented at the SPE/IADC Drilling Conference, Amsterdam, February 23–25, 2005.

Cañas Triana JA, Hathcock R, Koerner K, Hughes T,Kundu D, López de Cardenas J and West C: “Highlighting Heavy Oil,” Oilfield Review 18, no. 2(Summer 2006): 34–53.

19. Thiercelin M: “Mechanical Properties of Well Cements,”in Nelson EB and Guillot D (eds): Well Cementing–2ndEdition. Houston: Schlumberger (2006): 269–288.James S and Boukhelifa L: “Zonal Isolation Modelingand Measurements—Past Myths and Today’s Realities,”paper SPE 101310, presented at the SPE Abu DhabiInternational Petroleum Exhibition and Conference,Abu Dhabi, UAE, November 5–8, 2006.

20. Young’s modulus, also called the modulus of elasticity, isthe ratio between the stress applied to an object and theresulting deformation, or strain. Lower Young’s modulicorrespond to more flexible materials.

21. Abbas R, Cunningham E, Munk T, Bjelland B,Chukwueke V, Ferri A, Garrison G, Hollies D, Labat C andMoussa O: “Solutions for Long-Term Zonal Isolation,”Oilfield Review 14, no. 3 (Autumn 2002): 16–29.

> Schlumberger high-temperature liner hanger.Developed for steamflood applications, the linerhanger features seals made from carbon fiberand INCONEL alloy. The tool has permanent slipsand a one-piece mandrel to minimize possibleleak paths and can be rotated while running inthe hole. To date, Schlumberger engineers haveinstalled more than 150 units in Canada, with nopressure-test failures. Some of the systems havesurvived up to 10 thermal cycles to 343°C [649°F].

Upper tiebacksealbore

Permanenthold-down slip

Heavy-oil-thermal(HOT) seal

Permanenthanging slip

Liner connection


Schlumberger high-temperature thermalliner hangers have been used in the Cold Lakefield, where a major operator in Canada isconducting a horizontal-well CSS program.25 Withcustomized liners and carbon-fiber andINCONEL seals at the top of the liner, theoperator has been able to achieve good steamconformance—steam intake spread evenly overthe length of the horizontal well—verified bytime-lapse seismic surveys over the pilot area.

Reservoir Stimulation and ProductionReservoir stimulation encompasses two majortechniques: matrix acidizing and hydraulicfracturing. Both procedures bypass formationdamage incurred during drilling, cementing andperforating, and they also provide an enhancedconnec tion between the formation rock and thewellbore. The goal is to increase hydrocarbonproduction to levels far exceeding what would bepossible under natural-flow conditions.26

Matrix acidizing consists of pumping a low-pHfluid through naturally existing channels in therock, at rates that are sufficiently low to avoidcreating fractures in the formation. The aciddissolves soluble components of near-wellboreformation rock and damaging materialsdeposited by previous well-service fluids, therebycreating a more permeable path for hydrocarbonflow. Acidizing fluids are formulated to stimulatecarbonate or sandstone formations.

Most carbonate acidizing involves reactinghydrochloric acid (HCl) with formations com -posed of calcium carbonate (calcite), calciummagnesium carbonate (dolomite) or both. As theacid flows through perforations and dissolves thecarbonate rock, highly conductive channels calledwormholes are created in the formation.Wormholes radiate from the point of acid injectionand carry virtually all of the fluid flow duringproduction (left). For efficient stimulation, thewormhole network should penetrate deeply anduniformly throughout the producing interval.

HCl is an effective stimulation fluid at lowtemperatures, but it can be problematic when usedat temperatures exceeding about 93°C [200°F]. Athigher temperatures, this mineral acid attacks theformation too rapidly, mini mizing the depth anduniformity of the wormholes. These conditions alsopromote excessive tubular corrosion and requireengineers to add high concentrations of toxiccorrosion inhibitors. Recently, Schlumbergerchemists solved these problems by developingacidizing fluids based on hydroxyethylamino -carboxylic-acid (HACA) chelating agents. Commoncommercial HACA compounds such as tetra -sodium EDTA and trisodium HEDTA have beenused in the oil field for decades, mainly as scale-removal agents and scale inhibitors.27

A variety of HACA compounds underwentlaboratory testing at temperatures up to 200°C.The evaluation consisted mainly of corefloodtests in limestone and corrosion-rate measure -ments involving common tubular metals. Thebest performer was trisodium HEDTA, bufferedto a pH value of about 4. Less acidic than acarbonated beverage, this formulation is far lesscorrosive than conventional mineral acids, andvery low tubular corrosion rates can be achievedby adding small amounts of milder, environ -mentally acceptable corrosion inhibitors. Withits higher pH, trisodium HEDTA reacts moreslowly and creates an extensive, farther-reachingwormhole network rather than a short dominant

54 Oilfield Review

> Wormholes formed during a laboratory-scale matrix acidizing treatment ofa carbonate-formation sample. The length, direction and number ofwormholes depend on the formation reactivity and the rate at which acidenters the formation. Once formed, the wormholes carry virtually all of thefluid flow during production.


Autumn 2008 55

one (right). In addition, HEDTA fluid is far moreefficient than HCl at HPHT conditions. Acomparable level of stimulation may be achievedby pumping less than one-tenth the fluid volume(below right).28

Hydraulic fracturing involves pumping largevolumes of fluid through perforations and into theformation at rates and pressures sufficient to notonly create a fracture, but also propagate it farbeyond the near-wellbore region. The final fluidstage fills the fracture with proppant—silicate,ceramic or bauxite granules with high sphericity—leaving a high-permeability conduit between theproducing formation and the wellbore.29

Fracturing-fluid viscosity is a critical param -eter that governs fracture initiation andpropagation, as well as proppant transport downthe tubulars, through perforations and into thefracture. At HPHT conditions, sufficient fluidviscosity is usually achieved by preparing metal-crosslinked solutions of guar-base polymers. Themost common metal crosslinkers are boron andzirconium.30 However, viscosity attainment alone isnot sufficient to perform a successful HPHTfracturing treatment. To minimize friction-pressure losses as the fluid is pumped downhole,the crosslinking reactions should be delayed untiljust before the fluid enters the perforations. Inaddition, the viscosity should not be undulysensitive to the high-shear-rate environmentcommonly found in the tubulars and perfora tions;otherwise, the fluid will be ill equipped for fracturepropagation and proppant transport, increasingthe likelihood of a premature screenout.31

The characteristics of borate- and zirconate-crosslinked fluids are fundamentally different.Borate crosslinking arises from ionic bonds thatcan break under high-shear conditions; however,the bonds heal and fluid viscosity recovers whena low-shear environment is restored. Zirconate-crosslinked fluids are not as forgiving becausethe linkage results from covalent bonds that formonly once. If the fluid crosslinks and experienceselevated shear too early, the bonds will break

25. Smith RJ and Perepelecta KR: “Steam ConformanceAlong Horizontal Wells at Cold Lake,” paper SPE/PS-CIM/CHOA 79009, presented at the SPE InternationalThermal Operations and Heavy Oil Symposium andInternational Horizontal Well Technology Conference,Calgary, November 4–7, 2002.

26. For more on reservoir stimulation: Economides MJ andNolte KG (eds): Reservoir Stimulation, 3rd Edition. NewYork City: Wiley, 2003.

27. Chelating agents, also known as sequestering agents,are compounds used to control undesirable reactions ofmetal ions (such as Ca, Mg and Fe). For example, theyform chemical complexes that do not precipitate duringacidizing treatments, thereby preventing formation

29. For more on hydraulic fracturing: Economides and Nolte,reference 26.

30. Crosslinks are bonds that link one polymer chain toanother. Boron and zirconium interact with guar-basepolymers, forming linkages that increase the effectivepolymer molecular weight by several orders ofmagnitude and dramatically increase the fluid viscosity.

31. Screenout occurs when proppant particles bridge theperforations and block further fluid ingress. Thiscondition is accompanied by a sudden treatment-pressure increase. A premature screenout occurs when the fracture volume is insufficient, when less than the desired amount of proppant is placed in thefracture, or both.

damage. EDTA and HEDTA are acronyms for ethylene -diaminetetraacetic acid and hydroxyethylene diaminetri-acetic acid.Frenier WW, Fredd CN and Chang F: “Hydroxyamino -carboxylic Acids Produce Superior Formulations forMatrix Stimulation of Carbonates at High Temperatures,”paper SPE 71696, presented at the SPE Annual Technical Conference and Exhibition, New Orleans,September 30–October 3, 2001.

28. Frenier WW, Brady M, Al-Harthy S, Arangath R,Chan KS, Flamant N and Samuel M: “Hot Oil and GasWells Can Be Stimulated Without Acids,” paper SPE 86522, presented at the SPE InternationalSymposium and Exhibition on Formation DamageControl, Lafayette, Louisiana, February 18–20, 2004.

> Acidizing coreflood test with 20% Na3HEDTA. Technicians pumped the acid through a 2.54-cm [1-in.]diameter, 30.5-cm [12-in.] long limestone core at 177°C [350°F]. The Na3HEDTA solution creatednumerous wormholes that formed a complex network. The photograph of the core entrance (left )shows the formation of many wormholes. The CT-scan sequence (right) confirms that the wormholenetwork extends throughout the core length. The upper-left CT-scan image displays the coreentrance, and subsequent core sections continue from left to right.

> Comparing the acidizing efficiency of 15% HCl (purple) and Na3HEDTA(green) at 177°C. This graph shows the amounts of acidizing fluid (expressedin pore volumes) required to radially penetrate 30.5 cm [12 in.] into a 30.5-m[100-ft] interval of 100-mD carbonate formation with 20% porosity. The resultsindicate that, regardless of pumping rate, trisodium HEDTA is more than oneorder of magnitude more efficient than HCl.

1,000

100

10

Pore

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umes

to b

reak

thro

ugh

10 2 4 6 8 10 12

Flow rate, bbl/min

20% Na3HEDTA

15% HCI


irreversibly, fluid viscosity will decrease, and thescreenout probability will increase (below).Therefore, it is vital to control the timing and thelocation of crosslinking.

Although less forgiving, zirconate-crosslinkedfluids have been used almost exclusively in HPHTfracturing treatments, mainly because they arethermally more stable than borate fluids. Despitesteady advances in fluid design, achieving

sufficient crosslink control with zirconate fluidshas remained elusive. The crosslinking reactionsare temperature-sensitive, and predicting circu -lating temperatures inside tubulars of HPHTwells is often difficult.

Chemists solved these problems by com -bining the best features of borates andzirconates into one system—ThermaFRACfracturing fluid. The new dual-crosslinker fluid,based on carboxymethylhydroxypropyl guar(CMHPG), features two crosslinking events—anearly low-temperature reaction involving borate,and a secondary temperature-activated oneinvolving zirconate. Borate crosslinking provideslow shear sensitivity, and zirconate bondingcontributes thermal stability (next page).32 Fluidpreparation is simpler and more reliable becauseadditives previously used to stabilize and controltraditional zirconate-only fluids are no longernecessary. Laboratory tests have demonstratedsuitable performance at temperatures from 200° to 375°F [93° to 191°C].

South Texas has long been a major center ofHPHT activity, and operators there have come torely heavily on new technologies to solveproblems. Producing reservoirs are deep andmust frequently be stimulated through longtubing strings or slimhole completions. This wellgeometry is problematic for two main reasons.First, treatment pump rates must be reduced tominimize friction-pressure losses and decreasethe number of pump trucks at the wellsite.33

Lower flow rates limit the fluid pressure thatengineers may apply to initiate and propagate ahydraulic fracture. Second, fracturing fluidsexperience high amounts of shear as they flowthrough small-diameter tubulars, and zirconate-base fluids are particularly susceptible topremature deterioration. Dual-crosslinker fluidshave successfully addressed these problems.

One example involves a well that sufferedcasing collapse after a fracturing treatment.Workover operations to restore communicationand production were unsuccessful, and theoperator’s only remaining option was to sidetrackthe wellbore and install a slimhole completion.The operation involved lowering 12,200 ft[3,719 m] of 23⁄8-in. tubing from surface to theproducing interval and then cementing it inplace. Wellbore integrity was a serious concernbecause of damage resulting from the workoveroperations. In addition, the operator was worriedabout friction-pressure losses and high leakoffrates arising from fluid diversion into theexisting fracture. The thickness of the producingsandstone interval was 46 ft [14 m], and the BHTwas 310°F [154°C].

56 Oilfield Review

> Shear-history behavior of guar fluids crosslinked by borate and zirconate compounds. Rheologicaltesting of fracturing fluids involves two principal devices: a shear-history simulator and a viscometer.The shear-history simulator exposes fracturing fluids to shearing conditions they would experiencewhile traveling down the tubulars toward the perforations. The viscometer measures the fracturing-fluid viscosity at various shear rates, temperatures and pressures. Shear-history studies determinehow shearing in the tubulars would affect fluid viscosity. Technicians measure and plot the rheologicalbehavior of two identical fluids—one that has undergone pretreatment in the shear-history simulator(blue) and one that has not (pink). Test results show that, after prolonged exposure to a high-shear-rateenvironment in the shear-history simulator, the borate-crosslinked fluid recovered and achieved thesame viscosity as its counterpart that did not experience pretreatment (top). The viscosity plotseventually overlapped. On the other hand, the zirconate-crosslinked fluid permanently lost viscosityafter pretreatment in the shear-history simulator (bottom). This effect would increase the potential forscreenout. The baseline viscosities on the plots correspond to a 100-s–1 shear rate. The periodic spikesdenote shear-rate ramps in the viscometer up to about 300 s–1. Viscosity measurements at variousshear rates allow calculation of additional rheological parameters that engineers use to optimizefracturing-fluid designs.

0 40 60 80 100

Time, minUnshearedSheared at 1,350 s–1 for 5 min

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Autumn 2008 57

The operator approved a ThermaFRAC treat -ment that addressed the anticipated difficulties.The pad volume was unusually large—65% of thetotal job—and the CMHPG concentration washigh—45 lbm/1,000 galUS [5.4 kg/L]—tocompensate for the high leakoff rate.34 To mini -mize friction pressure, the maximum pump ratewas 12 bbl/min [1,908 L/min]. The proppantslurry placed 62,000 lbm [28,120 kg] of 20/40-mesh resin-coated bauxite at concentra -tions up to 8 lbm/galUS [961 kg/m3] of fracturingfluid. Following the success of this treatment, theoperator applied dual-crosslinker fluids inadditional slimhole applications, including onein which 295,000 lbm [133,810 kg] of 20/40-meshceramic and resin-coated ceramic proppant wereplaced into a 74-ft [22.6-m] interval through11,600 ft [3,536 m] of 27⁄8-in. tubing. At thiswriting, more than 60 ThermaFRAC treatmentsinvolving 11 operators have been successfullyperformed in south Texas, at bottomhole tempera -tures between 121° and 191°C [250° and 375°F].

The new fracturing fluid has also been used tostimulate a gas-bearing HPHT sandstone reservoirin northern Germany. The average formation depthis 4,550 m [14,930 ft] TVD, and the BHT isapproximately 150°C. BHPs vary from 25 to 30 MPa[3,630 to 4,350 psi], and the formation-permeability range is 0.1 to 5 mD. In this area,engineers usually perform fracturing treatmentsthrough a dedicated tubing string with the rig inplace. To save money, the operator wanted to beginstimulating wells without the rig, pumping thetreatment through the final well-completion string.

Fracturing fluids are usually prepared withambient-temperature mix water. However, pump -ing a cool fluid through a finished completionwould cause sufficient tubular contraction toexert excessive stress on packers and jeopardizezonal isolation. Therefore, to minimize thermaleffects, it would be necessary to preheat the mixwater to 50°C [122°F]. Zirconate crosslinking istemperature-dependent, and it was unlikely thatreliable rheological control would be possiblewith a traditional single-crosslinker system.

To develop a solution, engineers conductedfluid-design experiments at the SchlumbergerClient Support Laboratory in Aberdeen,Scotland. This facility has testing equipment thatcan simulate both the thermal environment andthe shear environment antici pated in theGerman well. Test results showed that the dual-crosslinker fluid would allow sufficient leeway todesign a treatment compatible with theoperator’s cost-saving goal.

Engineers performed the ThermaFRAC treat -ment in a well with a 30-m [98-ft] producing zone,pumping 184 m3 [48,600 galUS] of fluid with aCMHPG loading of 4.8 kg/m3 [40 lbm/1,000 galUS],and placing 32 metric tons [70,500 lbm] of 20/40resin-coated high-strength proppant in the frac -ture. The resulting fracture conductivity in thiswell was 250% higher than those of offset wellstreated with conventional single-crosslinkerfluids, and the production rate was 30% higherthan the operator’s prediction. Consequently, theoperator has chosen this fluid to stimulate sevenmore wells in this region.

Certain types of HPHT reservoirs would notbenefit significantly from matrix-acidizing orhydraulic-fracturing treatments. Perhaps thebest examples are heavy-oil deposits, in whichthe preferred stimulation method involves oil-

viscosity reduction by steam injection. Steamgeneration comprises approximately 75% of theSAGD operating expenses. Reducing thesteam/oil ratio (SOR) and maintaining anoptimal production rate are keys to improvingprofitability. Reducing steam input saves energycosts, decreases produced-water volume andtreatment expenses, and curtails associated CO2

emissions. A 10 to 25% SOR reduction may beachieved by using electric submersible pump(ESP) systems.

ESPs allow reservoirs to be produced atpressures that are independent of wellhead orseparator pressures, thereby increasing steam-injection efficiency and decreasing the produc tioncost by at least US $1.00 per barrel of produced oil.Numerous Canadian operators, including Encana,Suncor, ConocoPhillips, Nexen, TOTAL, Husky and

32. Guar gum, a powder consisting of the ground endospermof guar beans, is used extensively as a food thickener.Guar-gum derivatives are purified and functionalizedproducts with good thermal stability. Common derivativesfor hydraulic-fracturing applications includehydroxypropyl guar (HPG) and carboxymethyl -hydroxypropyl guar (CMHPG).

33. Friction-pressure loss is the pressure decrease arisingfrom frictional losses that occur as a fluid passes

through pipe. The pressure decrease is mainly a functionof pipe diameter, pipe length, fluid rheological propertiesand flow rate. High friction reduces the available fluidpressure at the pipe outlet.

34. Fracturing treatments consist of two fluid stages. Thefirst stage, the pad, initiates and propagates the fracture.The second stage, the proppant slurry, transportsproppant down the tubulars, through the perforationsand into the fracture.

> Shear-history behavior of ThermaFRAC fluid at 135°C [275°F]. After prolonged exposure to a highshear rate in the shear-history simulator, the viscosity of ThermaFRAC fluid does not change significantly.

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Blackrock, have installed the REDA Hotline550high-temperature ESP system in steam-injectionwells (left). Rated to operate continuously at up to288°C [550°F] internal motor temperature, or218°C [425°F] bottom hole temperature, theequipment employs high-temperature thermo -plastic motor-winding insulation and is designedto compen sate for variable expansion andcontraction rates of the different materials in thepump. Many of these installations have operatedcontinuously for more than two years.

SurveillanceMaintenance of an optimal reservoir-temperature distribution is vital to efficientheavy-oil production from SAGD or CSS wells;therefore, engineers need to acquire real-timetemperature information to make necessarysteam-injection or production-rate adjustments.For more than a decade, WellWatcher distributedtemperature sensing (DTS) systems have beencapable of transmitting data to surface by lasersignals that travel through Sensa fiber-opticcable.35 However, conventional DTS systems donot function properly in an HPHT environment.

Most optical fibers begin to degrade whenexposed to hydrogen, which occurs naturally inwellbores. This degradation accelerates at hightemperatures, detrimentally affecting signaltransmission and measurement accuracy. Attemperatures above 200°C, conventional opticalfibers exposed to a hydrogen-pressured environ -ment may become unusable within days.

Schlumberger and Sensa engineersresponded by developing WellWatcher BriteBluemultimode optical fiber from a material that ismore thermally stable and chemically resistantto hydrogen (below).36 An improved version,WellWatcher Ultra DTS system, is equipped with

58 Oilfield Review

> REDA Hotline550 ESP artificial lift system. The multicomponent toolstringcan be used in wells with BHTs up to 218°C (center). The heart of the systemis the centrifugal pump, equipped with silicon- or tungsten-carbide bearingsfor durability at extreme temperatures (left ). The number of stages can alsobe adjusted according to the completion requirements. The pump motoremploys metal-to-metal seals to provide a heat-resistant mechanical barrierto fluid entry (right). Cables that transmit power to the motor and data tosurface are protected by insulating armor composed of heavy galvanizedsteel, stainless steel and corrosion-resistant Monel alloy (inset). As ofNovember 2008, the Hotline550 system is operating in more than 100Canadian thermal wells.

Pump

Intake

Motor

> Hydrogen effects on optical-fiber performance after HPHT exposure. Accelerated testing methods determine the high-temperature performance ofWellWatcher BriteBlue multimode fiber (blue) compared with that of conventional single-mode optical fibers (red and orange). Light transmittance of themultimode fiber deteriorates at a significantly lower rate (left ), allowing the fibers to transmit data for years after installation. Unlike the single-mode fibers,the new fiber material maintains the ability to transmit light throughout the useful wavelength range (right).

Ligh

t los

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Ligh

t los

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Time, min Wavelength, nm

Standard single-mode fiberPure core single-mode fiberWellWatcher BriteBlue fiber


Autumn 2008 59

the new fiber and can measure temperatureswith ±0.01°C [±0.018°F] accuracy over distancesup to 15 km [9.3 mi] with a 1-m [3.3-ft] spatial resolution.

Since 2007, the new fiber-optic system hasbeen installed in Canadian steamflood comple -tions with BHTs up to 300°C [572°F] (above). Sofar, no discernable reduction in fiber ormeasurement performance has been observed,and the temperature data are providingoperators with reliable guidance for decidinghow to adjust steam injection and oil productionto achieve maximum efficiency (right).

35. Al-Asimi M, Butler G, Brown G, Hartog A, Clancy T,Cosad C, Fitzgerald J, Navarro J, Gabb A, Ingham J,Kimminau S, Smith J and Stephenson K: “Advances inWell and Reservoir Surveillance,” Oilfield Review 14,no. 4 (Winter 2002/2003): 14–35.

36. Multimode optical fiber is mainly used for communica -tion over relatively short distances, such as within abuilding or a campus. Typical multimode links supportdata rates up to 10 Gbits/s over distances up to a fewkilometers. Multimode fiber has a higher “light-gathering”capacity than single-mode optical fiber and allows theuse of lower-cost electronics such as light-emittingdiodes or low-power lasers that operate at the 850-nm wavelength.

> SAGD-well temperature profile acquired by the WellWatcher BriteBlue system.Optical fibers transmit temperature data to surface at a 1-m [3.3-ft] resolution. Thesharp temperature increase indicates that steam injection is effectively confined tothe horizontal interval between about 900 and 1,500 m [2,950 and 4,920 ft].

Sampling position, m

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> WellWatcher BriteBlue fiber installation in a heavy-oil well. Engineers pump the fiber through a conduit inside a coiled tubing string (inset) that is hungfrom the surface across the producing interval.

Steam injection

Oil recovery


Future HPHT Technology DevelopmentsSignificant technologies introduced during the past decade are allowing operators toconfidently address numerous challenges posedby HPHT projects (above). As HPHT activitycontinues to grow and well conditions becomemore severe, more advanced devices andmaterials will be required.

Engineers are working to translate theadvances realized with HPHT wireline logging tothe MWD/LWD environment. The measurementsystems must not only withstand elevatedtemperature and pressure, but also performreliably when exposed to shocks and vibrationsassociated with drilling operations. The goal is to

reduce drilling risk by enabling better wellplacement, improved borehole stability and adecreased number of required trips.

Current chemical research involves extendingthe useful range of additives for primary andremedial cementing, as well as stimulationfluids, into the HPHT-hc realm. This workincludes developing novel sealants for pluggingand abandoning HPHT wells at the end of theiruseful lives, and ensuring long-term isolation toprevent fluid flow between subterranean zonesor to the surface. In addition, research is under -way to develop completion equipment fabricatedfrom materials with better resistance tocorrosive fluids and gases.

Extensive operator involvement in equipmentdesign and manufacture, as well as chemical-product development, is not typical for standardwells; however, operator participation will becrucial to the success of future ultra-HPHT andHPHT-hc operations. Cooperation betweenoperators and service companies will be vital forproper quali fication testing, manufacturing,assembly, testing and installation. Schlumbergerscientists and engineers are committed toparticipating in this cooperative process, helpingthe industry at large advance the technologiesnecessary to meet the world’s growing demandfor energy. — EBN

60 Oilfield Review

> HPHT products and services summary. The range of products and services for HPHT wells spans the productive life of a well. The color codes indicatehow technologies fit into the HPHT, ultra-HPHT and HPHT-hc schemes. Products and services highlighted in this article are shown in boldface.

Drilling

Evaluation

Cementing

Stimulation

Completions

Artificial lift

RSS 150° C

155° C

MWD 175° C

Petrophysics

Reservoir

Geology

Geophysics

Additives

Upper

Lower

Perforating

Monitoring

ESP

Test

Evaluation

Testing

Wireline (SlimXtreme platform) 260° C

LWD 175° C

Wireline 260° C

LWD 150° C

Wireline 175° C

LWD 150° C

Wireline (SlimXtreme platform) 260° C

LWD 150° C

DST 215° C

Tubing conveyed perforating 200° C

Retarder 249° C

Fluid loss 249° C

Quicksilver Probe tool

Subsurface safety and isolation valves

Packers

Screens

Fluids

Tools

Thermal liner hanger

Permanent

WellWatcher Ultra system

REDA Hotline550 ESP

Production logging

Flow control

260° C

260° C

250° C

316° C

Fluids

175° C

230° C

190° C

205° C

218° C

175° C

200° C

200° C

218° C

150° C

175° C

175° C

260° C

340° C

300° C

175° C

35kpsi

30kpsi

32.5kpsi

25kpsi

27.5kpsi

22.5kpsi

20kpsi

17.5kpsi

15kpsi

12.5kpsi

10kpsi

MaximumtemperatureService Domains

Dri

lling

and

Eva

luat

ion

Dev

elop

men

tPr

oduc

tion

Formate drilling fluids

FlexSTONE HT cement

HEDTA acidizing fluid

ThermaFRAC fluid

HPHT>150°C or 10 kpsi

Ultra-HPHT HPHT-hc

Hydraulic-fracturing monitoring

>205°C or 20 kpsi >260°C or 35 kpsi


Documents

High-Pressure, High-Temperature · PDF file46 Oilﬁeld Review High-Pressure, High-Temperature Technologies Gunnar DeBruijn Craig Skeates Calgary, Alberta, Canada Robert Greenaway