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Flow-Assurance Challenges in Gas-Storage Schemes in Depleted Reservoirs...

Flow-Assurance Challenges in Gas-Storage Schemes in Depleted Reservoirs
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146239, "Flow-Assurance Challenges in Gas-Storage Schemes in Depleted Reservoirs," by Alireza Kazemi, SPE, and Bahman Tohidi, SPE, Hydrafact Ltd., and Emile Bakala Nyounary, Heriot-Watt University, prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6–8 September.

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    Gas Production Technology Gas Production Technology Document Transcript

    • TECHNOLOGY FOCUSGas ProductionTechnologyIt was not long ago that finding a natural-gas field beneath your property was Scott J. Wilson, SPE, is a Senior Viceviewed universally as a stroke of good luck. Now, local natural-gas development President of Ryder Scott Company. Heis feared by many who assume the “new technology” of “fracing” is environ- specializes in well-performance predic-mentally harmful. In reality, the first hydraulic-fracturing treatment was tested tion and optimization, reserves apprais-in a North Carolina granite quarry way back in 1903. Hydraulic fracturing hasbeen used successfully in more than a million wells since then, and, currently, als, simulation studies, software develop-hundreds of fracturing stages are pumped every day. Very impressive for a ment, and training. Wilson has worked“new” technology! in all major producing regions in his Partly because of these very successful and trouble-free wells, natural gas has 25-year career as an engineer and con-enjoyed an enviable reputation as a clean, cheap, and abundant energy source. sultant with Arco and Ryder Scott. He isHowever, we need only to look to the nuclear industry to see that a hard-won Cochairperson of the SPE Reserves andreputation can be ruined by false rumors, isolated incidents, or the worst exam-ples of safety, environmental, and reporting practices. If we always strive to be Economics Technical Interest Group andgood neighbors in the communities in which we work, we can remain proud serves on the JPT Editorial Committee.natural-gas producers for years to come. Wilson holds a BS degree in petroleum Because stimulated wells make up an increasing portion of supply with each engineering from the Colorado Schoolpassing year, we have become dependent upon wells that require additional of Mines and an MBA degree from theattention and often exhibit high decline rates. To buffer the supply/demandswings, gas-storage wells are used for both injection of dehydrated pipeline gas University of Colorado. He holds twoand production of newly saturated formation gas. Water-vapor equilibrium will patents and is a registered professionalreduce the water saturation around injection wellbores but may increase salt engineer in Alaska, Colorado, Texas,precipitation in the same region. A new study from the Middle East describes a and Wyoming.means of maximizing sand-free gas-production rates from wells in unconsolidat-ed zones, without a difficult-to-place hydraulic fracture. A third paper describes ameans of identifying well candidates that may need a second treatment becauseof deterioration of the original fracture or the need to access additional reservoir.A downloadable full-length technical paper provides a new decline-curve func-tional form that can match unconventional wells with long transient-flow peri-ods while honoring late-time interference and depletion. These papers providesome legitimately new technology. JPT Gas Production Technology additional reading available at OnePetro: www.onepetro.orgSPE 137748 • “Rate-Decline Analysis for Fracture-Dominated ShaleReservoirs” by Anh N. Duong, ConocoPhillips. (See SPE Res Eval & Eng,June 2011, page 377.)SPE 142283 • “Effect of Water-Blocking Damage on Flow Efficiency andProductivity in Tight Gas Reservoirs” by Hassan Bahrami, Curtin University,et al.SPE 139260 • “Production Allocation in Multilayer Gas-Producing Wells UsingTemperature Measurements (by Genetic Algorithm)” by Reda Rabie, SPE, CairoUniversity, et al.94 JPT • NOVEMBER 2011
    • GAS PRODUCTION TECHNOLOGYFlow-Assurance Challenges in Gas-StorageSchemes in Depleted ReservoirsInjection or production of dry gas into or surface facilities, resulting in corro- rium. Generally, producing this amountor from a depleted gas reservoir could sion, hydrate, and/or ice formation. of water from the reservoir results inresult in serious flow-assurance chal- an increase in the salt concentrationlenges. Parameters involved in water Background (hence, a reduction in water-vapor pres-evaporation/production and in salt pre- The study model was a 3D, Cartesian- sure and in water evaporation/produc-cipitation for a gas-production/-injec- grid-type block containing one well. tion). However, it is challenging totion well are described quantitatively. The model was intended to represent model this salt-deposition phenomenonThe terms of formation damage (skin) a portion of a gas field (i.e., drainage with commercial simulators.were evaluated, and some recommen- area) with its corresponding producer/ During injection/production cycles, adations for prediction and mitigation injector. A seasonal natural-gas storage/ constant water-production-rate increaseare proposed. Water in the produced production scheme was modeled. First, was observed that corresponded togas is a major flow-assurance threat production from the reservoir lasted the constant-rate-vaporization period.because of the possibility of gas-hydrate 30 months with a maximum daily gas- During this period, it is assumed thatformation in the production system. production rate of 45×106 m3/d. Then, gas is in contact with connate waterMitigation methods are presented. injection was modeled for 3 months at and that the rock surface is saturated; 10×106 m3/d, followed by 4 months of therefore, vaporization continued untilIntroduction soaking (i.e., shut-in). Then, for 5 years the falling-rate period occurred. DuringGas injected into the depleted reser- the following injection/production cycle the falling-rate period, the rock surfacevoir normally is a processed/dried gas. was used: 2 months of production, 3 was no longer saturated; therefore, theHowever, after injection, the gas is in months of soaking, 3 months of injec- evaporation rate and water-productioncontact with hydrocarbon and aqueous tion, 4 months of soaking, and 2 months rate decreased.phases in the reservoir. Therefore, the of production, for each calendar year.composition of the produced gas may The following properties were Salinity. Constant salinity was con-differ from that of the injected gas. More assumed: Reservoir temperature= sidered throughout the entire produc-importantly, the produced gas will have 104°C, initial reservoir pressure= tion period to predict the maximumsome water (mainly in the form of vapor 250 bar, average porosity=10%, hori- water production for hydrates preven-at reservoir conditions) because of the zontal permeability in x- and y-direc- tion and to determine inhibitor dosage.contact with water in the formation. tion=100 md, vertical permeability= During gas injection/production, a por-During production, the water is produced 10 md, reservoir thickness=110 m, and tion of connate water is evaporated forwith the gas. The net result is evaporation reservoir dimensions of 900×900 m. thermodynamics equilibrium, whichof water from formation brines, result- Connate-water saturation was increases with increasing gas rate anding in an increased formation-water salt assumed to be 10%, with a gas/water with pressure decline. Higher forma-concentration in the reservoir and salt contact at 1005-m depth. The reservoir tion-water salt concentration tends toformation/deposition. Also, the produced gas was assumed to comprise four slow the rate of evaporation; therefore,water may condense in the wellbore and/ main components: methane (highest less water is produced. concentration), ethane, carbon diox-This article, written by Senior Technology ide, and water. The injected dry gas Capillary Pressure. Assuming a water-Editor Dennis Denney, contains highlights was assumed to have no water (i.e., 0% wet system, if an aquifer is in contactof paper SPE 146239, “Flow-Assurance humidity). A modified Peng-Robinson with the reservoir, the capillary pres-Challenges in Gas-Storage Schemes equation of state was used in the simu- sure effect will increase the amountin Depleted Reservoirs,” by Alireza lation calculations. of liquid water produced because theKazemi, SPE, and Bahman Tohidi, water moves through small pores hav-SPE, Hydrafact Ltd., and Emile Bakala Water Production. As pressure declines ing the highest capillary pressure. TheNyounary, Heriot-Watt University, pre- during initial field production, gas higher the capillary pressure, the high-pared for the 2011 SPE Offshore Europe expands, rock is compacted, and water er the produced-water rate.Oil and Gas Conference and Exhibition, solubility in the gas increases, resultingAberdeen, 6–8 September. The paper has in more connate water being evapo- Gas Velocity (Gas Rate). An increasenot been peer reviewed. rated to satisfy thermodynamic equilib- in gas injection/production from For a limited time, the full-length paper is available free to SPE members at www.jptonline.org.JPT • NOVEMBER 2011 95
    • 10×106 to 15×106 std m3/d results in tion damage. However, if a large aquifer 200 m, the effect on gas production anda 10% increase in the total water pro- support does exist, then the produced water production was negligible.duced at the end of 91 months of the water will be water from evaporationinjection/production cycle (2550 m3 vs. plus liquid water from water influx. Dynamic Flow2315 m3). This observation indicates When considering capillary pressure Natural-Depletion Phase. As the pres-that a higher evaporation rate will occur in the model, with or without existence sure decreases while gas is producedin the vicinity of the well and near per- of an aquifer, water is produced along by natural depletion, the molar fractionforations, where the highest gas velocity with gas at each gas-production period of water in the gas phase increases.will be encountered (resulting in higher during the five injection/production Also, the increase in evaporation willpressure drops). Nevertheless, a higher cycles. The total amount of water evap- cause salt deposition in the formation,gas velocity leaves less time for equi- orated and produced, resulting in salt and the salt precipitation will partiallylibrium; thus, there will be less water transport in the near wellbore region, reduce the pore-throat cross-section-evaporation. Further, this higher evapo- will depend strongly on the magnitude al flow area, increasing the local gasration rate is likely to occur locally, in of capillary pressure. velocity and, consequently, the evapo-the pore throats, where some reduction ration rate. In radial flow toward thein permeability has happened because Near-Wellbore Effects wellbore, these phenomena combine,of salt precipitation. A realistic option is to assume that leading to a more-severe halite deposi- most of the water evaporation is likely tion near the wellbore and perforations.Salt-Induced Skin to occur in the near-wellbore region,By examining the total-water-produc- which will experience maximum for- Dry-Gas-Injection Phase. As dry gas istion graphs from previous studies, if no mation damage. As water is produced injected into the formation, it contactsor a weak aquifer exists, then most of (evaporated) the deposited salt reduces connate water. The result is evapora-the produced water could be assumed the permeability in the evaporation tion of some of the connate water. Thisto be from evaporation. This situation area. It was observed that because the process is driven mainly by the velocitycould be similar to a well completed far zone of evaporation is close to the of the gas and its relative humidity.from the aquifer or in a large gas res- wellbore (e.g., 150 m from wellbore),ervoir during the early gas-production the effect on gas productivity was more Soak Phase (Shut-In). When the wellstage during which no water influx severe (i.e., 25% less gas production is shut in for a prolonged period of timeoccurs in the reservoir. These situations for the 150-m zone). However, when after gas injection, some of the gas willcould lead to salt deposition and forma- considering a radius of approximately dissolve in the water, and the molar water West Virginia University College of Engineering and Mineral Resources - Department of Petroleum and Natural Gas Engineering The Department of Petroleum and Natural Gas Engineering (PNGE) at West Virginia University invites applications and nominations for two tenure- track faculty positions at the level of Assistant or Associate Professor. Applicants must have an earned Ph.D. in petroleum engineering and or natural gas engineering or a closely related field, and the ability to provide teaching excellence in a variety of petroleum engineering courses, both at the graduate and undergraduate levels. The department values intellectual diversity and demonstrated ability to work with diverse students and colleagues. Both positions are expected to be filled on or after January 1st 2012. Drilling and Completion The successful candidate for this position is expected to develop an active, externally sponsored research program in the area of Natural Gas Recovery from Unconventional Reservoirs, with an emphasis on drilling and completion in Marcellus shale. Enhanced Oil Recovery The successful candidate for this position is expected to develop an active, externally sponsored research program in the area of Enhanced Oil Recovery. West Virginia University is a comprehensive land grant institution with medical, law, and business schools, over 29,000 students, and has Carnegie Doctoral Research Extensive standing. The PNGE Department has 5 faculty members, approximately 200 undergraduates, and 45 graduate students. The Department offers B.S. (PNGE), M.S. (PNGE), and doctoral degrees. The College has seven departments, over 3,000 students, 120 faculty, and approximately $25 million in research expenditures per annum. The University is located within a growing high technology corridor that includes several federal research facilities as well as the West Virginia High Technology Consortium. Morgantown and the vicinity have a diverse population of about 62,000, and is ranked as one of the most livable cities in the country. The city is readily accessible and is within driving distance from Pittsburgh, PA and Washington, D.C. Candidates should submit current curriculum vitae, names and addresses of three references, a one page summary statement describing qualifications for the position, and plans for teaching and research. Review of applications for both positions will start on September 16th, 2011. These positions will remain open and applications will continue to be reviewed until appointments are made. Send inquiries and applications to: Dr. Aminian Chair, Faculty Search Committee Department of Petroleum and Natural Gas Engineering West Virginia University is the recipient of an NSF ADVANCE Award West Virginia University for gender equity. P.O. Box 6070 WEST VIRGINIA UNIVERSITY IS AN AFFIRMATIVE ACTION/EQUAL Morgantown, WV 26506-6070 OPPORTUNITY EMPLOYER96 JPT • NOVEMBER 2011
    • content in the gaseous phase will be at a Economic Implications. Assuming an a significant role with respect to watermaximum. After pressure/temperature arbitrary hydrate-inhibitor dosage of 1% production and amount of inhibitorstabilization, some of the water in the of the produced-water volume, hydrate- required to prevent hydrate formation.gas phase may recondense, increasing control-cost comparisons were carried out • Salt precipitation will reduce pore-the water saturation in the near-wellbore for different water-production scenarios. throat size, resulting in less gas andregion. This recondensation could redis- • An increase of formation salinity water being produced.solve some of the deposited salt. When from fresh water to brine resulted in Comparing systems with and with-production is resumed after the soak- 7.5% reduction in hydrate-control cost. out salt precipitation showed a 19%ing period, salt precipitation will occur • The inhibitor cost when consider- reduction in water production in thebecause of pressure drop and water evap- ing moderate capillary pressure was case with salt precipitation and, conse-oration in the near-wellbore region. 10 times that for the zero-capillary- quently, a hydrate-inhibitor-cost reduc- pressure case. Capillary pressure plays tion of 19%. JPTProduction-After-Soaking Phase.Generally, the same production phe-nomenon occurs in this stage. Butthe produced water is a combinationof water in gaseous phase from previ-ous evaporation (dry-gas injection) andwater evaporated because of pressuredrop. However, as gas is produced, thesalt saturation increases in the near-well-bore region because of evaporation. Thisprocess could result in water migrationto the near-wellbore region because ofthe concentration difference. This ten-dency is greater when a communicatingaquifer exists.Reducing Halite Deposition. To reducesalt precipitation during dry-gas injec-tion/production, freshwater stimulationon regular basis is recommended becausesalt is highly soluble in water. Regularwater washing will help dissolve salt pre-cipitates in the near-wellbore region andperforations. Also, the use of long perfo-ration intervals rather than deep perfora-tions is recommended. This method willincrease the interface between formationand wellbore and, therefore, lessen theflow restriction. Reducing the pressuredrop in the near-wellbore region by anymeans is the main objective. Formation fracturing could be used tobypass the damaged zone. The fracturewould provide wider flow paths thatwould reduce the gas velocity to the well-bore and provide a larger well/formationinterface. Consequently, the water-evap-oration rate and salt precipitation couldbe reduced in the near-wellbore region. Whatever abrasive, high-pressure, high-Natural-Gas Hydrates volume operation you have planned for your completion, you’re going toWater produced during gas withdrawal want packing that’s up to the task.may condense in the wellbore, tubing, Our well service packing solutions areand surface facilities and may cause cor- engineered to keep you up and running through it all. Count on us.rosion or formation of hydrates and/ www.TuffBreed.comor ice. The amount of hydrates formedand/or inhibitor required is a functionof the amount of water in the system.Therefore, it is important to predict theamount of water in the system for design-ing prevention techniques/facilities.JPT • NOVEMBER 2011 97
    • GAS PRODUCTION TECHNOLOGYAchieving Solids-Free Gas-Production Target Rate FromHighly-Unconsolidated-Sandstone Formation IntervalsOne of the most challenging aspects ofproducing wells drilled in the uncon-solidated pre-Khuff gas reservoirs inSaudi Arabia is to achieve solids-freeproduction while trying to achievehigh gas rates. Challenging reservoirconditions include high temperatureand pressure, high stress, heterogene-ity, and the absence of stress barriersthat together make placing fracturetreatments very difficult. Stand-alonescreens were installed in openholewell completions in the sandstone res-ervoir and achieved excellent resultsby eliminating the need for a fractur- Fig. 1—Casing and surface-equipment damage caused by formation- sand production.ing treatment. angle and increased-contact wells, and, cementation and diagenesis-controlledIntroduction more recently, sand-screen comple- cementation also play a role. TheseAchieving solids-free production from tions have been used to develop these reservoir-quality-influencing factorsunconsolidated-sandstone reservoirs is gas reserves. Among these approaches, are, in turn, subject to sedimento-an ongoing challenge. The importance the sand-screen completions, in both logical and diagenetic processes, con-of effective sand control in these wells vertical and high-angle wells, was field trolled largely by the depositional set-is the need to maintain the integrity tested in two wells, and then it was ting. Porosity and permeability of theof bottomhole and surface processing implemented in more wells after the gas-bearing intervals vary over a wideequipment and facilities, and to ensure success of the pilot. range. The well-plan metric for thethat production targets are met consis- initial gas-production rate from thetently. Fig. 1 shows examples of the Formation Geology formation is from 15 to 20 MMscf/D.potential damage that sand production The sandstone formation in which the Although this rate is achievable, givencan cause. two well pilot tests were conducted is a the permeability and pressure char- Several approaches including indirect siliciclastic formation in the pre-Khuff acteristics of the reservoir, the forma-hydraulic-fracturing stimulation, high- stratigraphic section in Saudi Arabia. tion’s unconsolidated nature increases Gas resources are in sandstones of the risk of exposing equipment toThis article, written by Senior Technology variable quality within a sequence of damaging sand production.Editor Dennis Denney, contains high- sandstones, siltstones, mudstones,lights of paper SPE 141878, “Achieving and shales. Because the formation was Screen SelectionTarget Solids-Free Gas Rate From Highly- deposited in a shallow marine tidally Optimum screen selection was achievedUnconsolidated-Sandstone Formation influenced shoreline setting, it is het- after implementing a series of tests.Intervals,” by Nahr Abulhamayel, J. erogeneous in character.Ricardo Solares, SPE, Walter Nunez, Heterogeneity imposes both verti- Sieve Analysis. Several core samplesAtaur Malik, SPE, Mustafa Basri, cal- and lateral-distribution variability were cut and dried in an oven at 185°FSPE, and Andrew McWilliams, Saudi of reservoir-quality properties over a to make sure that any water in theAramco, and Oumer Tahir, SPE, and wide range of scale and geometry. samples was removed. Each sampleMohammad Abduldayem, SPE, Reservoir quality in this sandstone was gently ground with a rubber mor-Weatherford, prepared for the 2011 formation is a function of several fac- tar to break up lumps of particles.SPE Middle East Oil and Gas Show tors, particularly grain size and sort- Approximately 100 g of the groundand Conference, Manama, Bahrain, ing and clay type and content, which material was weighed, then 12-, 14-,20–23 March. The paper has not been are controlled largely by the primary 16-, 18-, 20-, 25-, 30-, 35-, 40-, 45-, 50-,peer reviewed. sedimentological process. Sandstone 60-, 70-, 80-, 100-, 120-, 140-, 170-, For a limited time, the full-length paper is available free to SPE members at www.jptonline.org.98 JPT • NOVEMBER 2011
    • hole section. The completion string used 41/2-in. super-13Cr standalone screens similar to that shown in Fig. 2. Screen-Deployment Standalone-screen installations in pilot Well X and pilot Well Y were trouble- free operations. Predeployment torque- and-drag modeling results showed that the screens and other components of the bottomhole assembly (BHA) could be deployed without the risk of helical buckling. The modeling runs indicated that 25,000 lbm of maximum slackoff weight could be applied at any stageFig. 2—Sand-screen construction. of screen deployment if required, and that if any obstruction was found in the200-, 230-, 270-, 325-, and 400-mesh- emulated a collapsed-annulus scenario openhole wellbore, the string had to besize sieves were used to determine the with sand packed around the screen. picked up and redeployed because nodistribution of particle sizes. Most of rotation was allowed.the particle retention was in the 40- to Filter-Cake Flowback Test. A filter- Before deploying the screens, the70-mesh pans. cake flowback test ascertained whether 7-in. casing in each well was scraped the mud cake that formed in the well- and dressed to eliminate the risk ofSand-Retention Tests. Sand-retention bore during drilling operations was able tearing or damaging the screens by burstests (slurry and sandpack methods) to pass through the screens at normal or debris, and to avoid problems withwere performed after completing the flowing conditions. Test results indi- setting and sealing the packer againstsieve analysis. The slurry method cated that the optimum aperture size the casing. A check trip also was per-emulated the annular space between for the screens for the two pilot wells formed to ensure that the screens werethe wellbore wall and the outer wall was 300 µm. Both wells were completed able to reach the required depth, givenof the screen. The sandpack method with a 7-in. liner and a 57/8-in. open- that the maximum slackoff weight was Payback Comes in Months with Patented Engineered Multiphase Pumping Solution • Increases oil production on marginal wells • Decreases bottomhole pressure • Eliminates the need for flaring gas at the well • Effectively handles gas void fractions up to 95% • Payback comes in months • Field proven for nearly 20 years • Eliminates need for battery and separation equipment at well • Patented multiphase pumping action will not emulsify oil, gas and water, increasing the efficiency of downstream separation 1-877-4UMOYNO www.moyno.comJPT • NOVEMBER 2011 99
    • limited and that circulating through the depth was reached, a 13/4-in. alumi- • Upon reaching total depth, it isscreens rarely helps to wash a string num ball was dropped to plug the drill- important to circulate drill cuttingsdeeper. Therefore, the check trip was string, and the liner hanger was actu- out of the wellbore, back ream to theperformed by running a string down to ated hydraulically. Then, the pressure casing shoe, and perform a check tripa depth where the outer diameter (OD) was increased gradually to 2,500 psi before deploying the screens, to elimi-of the BHA was larger than the OD of to set the packer, and was increased to nate possible problems.the screen shoe. The string reached 4,000 psi in increments to energize the • Friction factors should be calibrat-total depth in both wells without need- packing elements as much as possible. ed with the actual loads experienceding to ream or pump, indicating that Packer integrity was confirmed with a during the reaming run.the screens could be deployed without 10,000-lbf overpull test, a 10,000-lbf • Ensure that solids-free mud is usedany problems. slackoff test, and a 2,500-psi annulus- by checking the shakers frequently to During screen deployment, wellbore pressure test. confirm that they are filtering the mudfluids were monitored constantly to properly.ensure that they were clean and free of Well Performance • Newly mixed mud sometimes isany particles that could plug the screen, Deliverability tests showed that both sheared insufficiently and has poorthereby minimizing the risk of screen wells performed above expectations. carrying capacity. The mud will havecollapse. Subsequently, fresh solids- Well X flowed at a sustainable con- to be sheared properly before deploy-free mud was spotted in the open- trolled gas rate of 22 MMscf/D with a ing the screens; because this can takehole section ahead of the deployment flowing wellhead pressure of 2,400 psi considerable time, this time must beoperation and a high-rate circulation and no skin damage. Well Y flowed factored in during the planning of thewas performed. at a sustainable controlled gas rate of drilling operation. The weight of the string was moni- 22 MMscf/D with a flowing wellhead • Proper torque-and-drag modelingtored carefully during the deployment pressure of 2,425 psi and skin damage must be performed to be fully aware ofoperation, and when the BHA reached of less than 1.0. the maximum allowable weight dur-the targeted depth, its last upward ing deployment of the screens.movement was recorded to keep it in Lessons Learned Implementing the actions listed abovetension. The setting depth of the liner • Adhering to the directional-drill- will minimize skin damage across thehanger and the liner-top packer was ing plan is critical to limit the dogleg screens, which in turn will reduce theselected taking into consideration the severity and to ensure that screens can pressure drop across the completionliner-couplings depth. Once the setting be deployed trouble free. and maximize production rate. JPT SPE Middle East Unconventional Gas Conference and Exhibition Unlocking Unconventional Gas: New Energy In the Middle East 23–25 January 2012 | Abu Dhabi, UAE www.spe.org/events/ugas Society of Petroleum Engineers100 JPT • NOVEMBER 2011
    • PRODUCTION ENHANCEMENT “Seen side by side, there’s no doubt which will be the superior producer.” The only service of its kind, the Halliburton AccessFrac™ stimulation service reliably delivers maximized propped fracture volume for improved long-term production. To do it, the AccessFrac service provides full access to complex fracture networks in unconventional formations—significantly increasing your reservoir contact. Indeed, better proppant distribution can reduce the amount of proppant required and improve efficiency. In addition, the customizable conductivity of the AccessFrac service—made possible by unique pumping and diversion technology—allows for maximum oil and gas flow to the wellbore. What’s your fracturing challenge? For solutions, go to halliburton.com/accessfrac. Solving challenges. ™ HALLIBURTON© 2011 Halliburton. All rights reserved.
    • GAS PRODUCTION TECHNOLOGYScreening Method To Select Horizontal-WellRefracturing Candidates in Shale-Gas ReservoirsA method was developed to screen total well population that represents will result in good production perfor-potential horizontal-well-refracturing high potential for restimulation suc- mance, for which the degree of depar-candidates rapidly by use of produc- cess. However, it also was determined ture from the optimum parameters istion performance and completion- that industry’s current experience with translated as a proxy for restimulationdata analysis. Integration of initial restimulation is mixed, and that con- potential. Virtual-intelligence tech-hydraulic-fracture-completion details siderable effort is required in candi- niques can be designed to mimic theaugments the process and helps date selection, problem diagnosis, and thinking process of a completion engi-screen understimulated wells in dif- treatment design/implementation for a neer who is entrusted with selectingferent production classes. To accom- program to be successful. refracturing candidates. The downsidesplish this screening, an index called a The GTI study investigated three are the data and expertise require-“completion index” was defined after main classes of candidate-selection ments. Expert judgment is required inanalysis of the completion param- methods: production-performance conditioning data to be used in the var-eters, production behavior, and their comparisons, pattern-recognition-tech- ious processes, and the outcome couldinterrelationship. nology/virtual-intelligence methods, be compromised by lack of important and production-type-curve matching. information, such as reservoir proper-Introduction The study concluded that although ties. Selection based solely on produc-Restimulation of existing wells rep- virtual-intelligence methods were rela- tion data will have the same limita-resents a vast unexploited resource tively better compared to production tions faced in tight sands, althoughin tight formations. In 1996, the type curves, no universal method exists production data are a critical input forGas Research Institute, now the Gas that enables selecting restimulation the other two methods. Hence, thereTechnology Institute (GTI), investi- candidates across different geologic set- is a need for specific methodologiesgated the potential for natural-gas-pro- tings. Use of production statistics alone for refracturing-candidate selection induction enhancement by use of restim- was the least-effective process. shale reservoirs.ulation in the USA (onshore, lower Most of the literature referencs ver-48 states). The report indicated that tical wells in layered formations of Rationale of Refracturingthe potential was substantial (more tight-sand reservoirs. Although the and Candidate Selectionthan 1 Tcf of reserves in 5 years), par- same candidate-selection methods The rationale is to attain a stimu-ticularly in the tight gas sands of the can be extended to horizontal wells in lated-reservoir volume greater thanRocky Mountain, midcontinent, and shale-gas reservoirs, limitations exist. that achieved in the initial fractur-south Texas regions. The study also The production-type-curve-matching ing treatment. When a new volumestated that 85% of the restimulation method typically is not applicable in a of shale is exposed in a refracturingpotential for a field exists in 15% of shale-gas setting because of variability treatment, the stimulated-reservoir vol-the wells. Hence, the key to any suc- in complex fracture networks from well ume is enlarged, resulting in a gain incessful restimulation program is being to well and lack of diagnostic tools for reserves. A potential refracturing can-able to identify that 15 to 20% of the quantifying fracture characteristics for didate is one that is performing below analysis. Pattern-recognition or virtual- its productive potential with respect toThis article, written by Senior Technology intelligence methods have limitations in-situ reservoir characteristics despiteEditor Dennis Denney, contains highlights mainly from the amount, type, and initial hydraulic fracturing. Therefore,of paper SPE 144032, “A Novel Screening quality of data available for robust anal- to identify potential candidates, res-Method for Selection of Horizontal- ysis. Ideally, an adequate and complete ervoir characteristics need to be sepa-Refracturing Candidates in Shale-Gas data set (including completion and rated from hydraulic-fracture charac-Reservoirs,” by Shekhar Sinha, SPE, reservoir/geology data) that quantifies teristics. Generally, underperformanceand Hariharan Ramakrishnan, SPE, successful cases of horizontal refractur- of shale-gas wells can be caused bySchlumberger, prepared for the 2011 ing in shale should be available to train inefficient initial completion, inefficientSPE North American Unconventional the virtual-intelligence tools. Pattern- well placement, gradual damage duringGas Conference and Exhibition, The recognition tools use artificial neural production, or pressure depletion.Woodlands, Texas, 14–16 June. The networks to extract a set of optimum A refracturing-candidate-identifica-paper has not been peer reviewed. completion parameters that most likely tion workflow should honor both For a limited time, the full-length paper is available free to SPE members at www.jptonline.org.102 JPT • NOVEMBER 2011
    • Fig. 1—3D Earth model produced from integrating Fig. 2—Gas-porosity log extracted from the 3D modelseismic, log, and geological data. along a horizontal lateral.production potential of the reservoir are used for comparing production in the laterals. Staging has been as closerock and major causes of underper- between wells. The production indica- as 270 ft in Barnett shale completions.formance. The method detailed in the tor should represent long-term pro- Consistent staging data are difficult tofull-length paper has two tiers. The duction behavior. Estimated ultimate find in public databases; therefore, onlyfirst tier is a purely statistical short recovery (EUR) would be the best a few operators’ data sets were con-listing of candidates by use of both production indicator, but for horizon- sistent enough to use for completion-production-performance comparisons tal wells in shale reservoirs, EURs often index calculation.and initial-completion details. The sec- are subjective and change as additional Depending on shale-reservoir char-ond tier is model based and integrates production data become available (i.e., acteristics (e.g., heterogeneity andthe first tier of statistical analysis with prolonged linear-flow behavior and presence of natural fractures), the cor-available petrophysical data and geo- absence of boundary-dominated flow relation between individual comple-logical information. in the available production history). tion variables and the production indi- Often, the first-12-month gas produc- cator varies. Therefore, the completionCandidate-Selection Workflow tion or best-12-month gas production index for a specific shale play mustData Requirements. Production and will correlate well with longer-term be defined for wells being studied incompletion data for this study were production (5- or 10-year cumulative the area of interest after studying thetaken from the public domain. The production) and can be used as a proxy correlation of individual completiondata from these sources can be import- for long-term production. and stimulation parameters vs. pro-ed into any database application or Completion Indicators. Evolution of duction indicators. The completion-spreadsheet program to perform the completion practices in shale reser- index definition and calculation usedanalysis. Monthly oil-, gas-, and water- voirs has had a significant effect on here are based on the data set used andproduction data were available from production performance. Many of the on available public completion data.these sources, as reported to regulatory early foam and gel completions in the Internal to an operating company, aagencies. Reported-completion-data Barnett shale have been restimulated more complete data set would be avail-quality in the public domain is some- with slickwater, which has become able and analyzed to formulate thetimes inconsistent and requires strin- the standard treatment. Large slick- applicable completion index.gent quality checks before proceeding water completions have been shown For the given data set, the simplestfor analysis. to develop very large and complex completion index can be computed fracture-network systems, resulting by combining three completion vari-Production, Completion, and Reser- in higher production rates compared ables—total volume pumped, numbervoir-Quality Indicators. The first tier with other fluid types. Supplementing of stages, and length of the lateral—of data analysis is statistical and uses production-data analysis with com- as follows.production indicators and completion pletion data enhances the candidate-indicators derived from initial-com- selection process and provides valu- Completion Index=pletion details. This step reduces the able insights by identifying patterns of Total volume of fluid pumpednumber of potential candidates for use completion practices and their effect .in the second-tier analysis. First-tier on production performance. (Lateral length/Total number of stages)data analysis will yield results similar to An important development in hor-those of pattern-recognition methods. izontal-well fracturing has been mul- If only one variable shows a clear Production Indicators. Time-norma- tistage fracturing. There has been an dominant correlation to production,lized production indicators often evolution to a larger number of stages then that variable alone can be rep-104 JPT • NOVEMBER 2011
    • OPTIMIZING RESERVOIR DRAINAGE / CONVEYANCEOPEN HOLE TRACTORING REDUCED RIG TIME, IMPROVED LOG QUALITYUNCONVENTIONAL ACCESS WITH TRACTORING WELLTEC® – THE WELL SOLUTIONS PROVIDERUsing a 4 1/2” Well Tractor® logging tools can be con- We develop and provide solutions based on our pio-veyed in a matter of hours compared to days using neering well intervention technology. This has madeconventional drill pipe conveyed (DPC) methods. it possible to extend deviated and horizontal wells ® Recently, a Well Tractor conveyed an OH logging and still intervene to the very end. With our clients,toolstring consisting of resistivity and porosity mea- we set new standards and will continue to do so assurements 4,000 ft. in a shale gas well. This electric the challenges increase.line solution resulted in higher quality data in approx.a third of the time required for a DPC operation.LEARN MORE! WWW.WELLTEC.COM
    • resented as the completion index. A to the hydrocarbon-in-place potential. reservoir-quality, tends to reduce andsimple completion index could be total The reservoir-rock-quality definition trends are more noticeable.volume of fluid pumped, volume of also can consist of rock-mechanical To determine whether completionfluid per unit length, or total proppant properties that define the fracturabil- or reservoir quality has more effectplaced. Once a completion indicator ity of the rock, which enables cre- on production, the production indexis defined, it is used as an indicator of ation of large fracture-surface areas in was crossplotted with the completionoverall hydraulic-fracture-completion the reservoir. index, and the reservoir-quality indexquality of the well. For an area of Most operators in different shale and correlation coefficients were com-interest with relatively uniform res- plays drill multiple pilot wells and pared. Wells that are out of zone areervoir-rock characteristics, a positive perform complete suites of logs for clustered together and have no correla-correlation between computed com- evaluation. These pilot-well logs can tion, while wells landed in the targetpletion index and production index is be integrated with available logs from zone have a much better correlation.expected with a lower degree of scat- laterals, logging-while-drilling data, For the analyzed data set, the cor-ter, but the objective of crossplots is to seismic data, and geological data to relation between production index anduse the correlation as a candidate-well build an integrated reservoir model. reservoir-quality index was strongerfiltering tool, as explained in the next The integrated reservoir model cap- than that between production indexsubsection, not to derive the correla- tures structural and reservoir-proper- and completion index. Out-of-zonetion coefficient. ty variations between the pilot wells wells showed a slight trend with res- Reservoir-Quality Indicators. One by integrating data from all sources, ervoir-quality index, but no trend withof the main factors for scatter observed as shown in Fig. 1. From the model, completion variables. Also, out-of-on correlation graphs of production synthetic logs along the horizontal zone wells had poor overall comple-and completion variables alone is the laterals, as shown in Fig. 2, can be tion quality. In general, reservoir qual-variation of reservoir-rock character- extracted and used as proxies for ity had a greater effect on productionistics in these reservoirs. Reservoir- reservoir-quality indicators. When the potential compared with the effect ofrock quality can be defined by several variability in reservoir quality is nor- completion variables. For uniform res-properties, such as hydrocarbon-filled malized, scatter in the observed rela- ervoir quality, the production indicatorporosity, pore pressure, and organic tion between production and com- would correlate better with comple-content and maturation, that relate pletion, or between production and tion variables. JPT STATEMENT OF OWNERSHIP, MANAGEMENT AND CIRCULATION (Required by 39 U.S.C. 3685). 1. Title of publication, Journal of Petroleum Technology. 2. Publication No. 0028-1960. 3. Date of filing, 26 September 2011. 4. Frequency of issue, monthly. 5. No. of issues published annually, 12. 6. Annual subscription price, $15. 7. Complete mailing address of known office of publication, SPE, 222 Palisades Creek Drive, Richardson, TX 75080-2040, Dallas County. 8. Complete mailing address of the headquarters or general business offices of the publishers, SPE, 222 Palisades Creek Drive, Richardson, TX 75080-2040. 9. Name and address of publisher, Georgeann Bilich, 222 Palisades Creek Drive, Richardson, TX 75080-2040. Name and address of editor, John Donnelly, 10777 Westheimer, Suite 1075, Houston, TX 77042-3455. 10. Owner, Society of Petroleum Engineers (SPE), 222 Palisades Creek Drive, Richardson, TX 75080-2040. 11. Known bondholders, mortgagees, and other security holders owning or holding 1 percent or more of total amount of bonds, mortgages, or other securities (none). 12. The purpose, function, and nonprofit status of this organization and the exempt status for Federal income tax purposes have not changed during preceding 12 months. 13. Publication name: Journal of Petroleum Technology. 14. Issue date for circulation data below: September 2011. 15. Extent and nature of circulation: Average Number Copies Each Number Copies of Single Issue Issue During Preceding 12 months Published Nearest to Filing Date A. Total number of copies (net press run) 66,274 68,622 B. Paid circulation (by mail and outside the mail) 1. Mailed outside-county paid subscriptions stated on Form 3541 30,481 31,292 2. Mailed in-county paid subscriptions stated on Form 3541 none none 3. Paid distribution outside the mails including sales through dealers and carriers, street vendors, counter sales, and other paid distribution outside USPS 34,465 35,967 4. Paid distribution by other classes of mail through the USPS none none C. Total paid distribution 64,946 67,259 D. Free or nominal rate distribution (by mail and outside the mail) 1. Free or nominal rate outside-county copies included on Form 3541 none none 2. Free or nominal rate in-county copies included on Form 3541 none none 3. Free or nominal rate copies mailed at other classes through the USPS none none 4. Free or nominal rate distribution outside the mail 305 175 E. Total free or nominal rate distribution 305 175 F. Total distribution 65,250 67,434 G. Copies not distributed 1,024 1,188 H. Total 66,274 68,622 I. Percent paid and/or requested circulation 99.5% 99.7% 17. I certify that the statements made by me above are correct and complete. Alex Asfar, Senior Manager Publishing Services.106 JPT • NOVEMBER 2011
    • EGPC INTERNATIONAL 2011 BID ROUND FOR PETROLEUM EXPLORATION AND EXPLOITATION- The Egyptian General Petroleum Corporation (EGPC) invites Petroleum Exploration Companies forthe International 2011 Bid Round to explore / exploit for Oil and Gas in Egypt under the ProductionSharing Agreement.- The International 2011 Bid Round includes Fifteen (15) Exploration Blocks in Gulf of Suez, EasternDesert, Western Desert & Sinai Sedimentary Basins as shown in the map. (1) (13) NE OBAYED NW ABU ZENIMA 801.266 KM2 276.3 KM2 (2) (3) NORTH MATRUH (14) 798.124 KM2 NW GINDI (11) 1351.16 KM2 E. RAS BUDRAN E. LAGIA OFFSHORE (I) 2989 KM2 45.56 KM2 (II) (5) (8) (15) (III) N.ALAM EL SHAWISH NW GHARIB NE ISSRAN 565.23 KM2 ONSHORE 343 KM2 (4) 654.98 KM2 S.GHAZALAT 1883 KM2 (9) SW GHARIB (12) (6) ONSHORE (7) EL QA’A PLAIN 195.5 KM2 S. ABU SENNAN 1823.5 KM2 2978.8 KM2 SE ABU SENNAN 3006 KM2 (10) SE GHARIB ONSHORE 508.5 KM2- Interested companies can submit their offers based on the Procedures, Main Commercial Parameters andthe applied Egyptian Production Sharing Model Agreement.- Data purchasing and data room will be available in EGPC Geological & Geophysical InformationCenter, Nasr City, upon request and according to the determined prices.- Main Information, Coordinates, Procedures, Main Commercial Parameters and the Model Agreementcan be obtained through EGPC site : www.egpc.com.egClosing Date: Monday, January 30th, 2012 at 12:00 hrs. For further information, please contact: Deputy Chief Executive Officer for Agreements Telephone : (202) 27065358 Fax : (202) 27065887