Gas Production Technology

It was not long ago that finding a natural-gas field beneath your property was viewed universally as a stroke of good luck. Now, local natural-gas development is feared by many who assume the “new technology” of “fracing” is environ-mentally harmful. In reality, the first hydraulic-fracturing treatment was tested in a North Carolina granite quarry way back in 1903. Hydraulic fracturing has been used successfully in more than a million wells since then, and, currently, hundreds of fracturing stages are pumped every day. Very impressive for a “new” technology!

Partly because of these very successful and trouble-free wells, natural gas has enjoyed an enviable reputation as a clean, cheap, and abundant energy source. However, we need only to look to the nuclear industry to see that a hard-won reputation 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 good neighbors in the communities in which we work, we can remain proud natural-gas producers for years to come.

Because stimulated wells make up an increasing portion of supply with each passing year, we have become dependent upon wells that require additional attention and often exhibit high decline rates. To buffer the supply/demand swings, gas-storage wells are used for both injection of dehydrated pipeline gas and production of newly saturated formation gas. Water-vapor equilibrium will reduce the water saturation around injection wellbores but may increase salt precipitation in the same region. A new study from the Middle East describes a 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 a means of identifying well candidates that may need a second treatment because of 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 provide some legitimately new technology.

Gas Production Technology additional reading availableat OnePetro: www.onepetro.org

SPE 137748 • “Rate-Decline Analysis for Fracture-Dominated Shale Reservoirs” by Anh N. Duong, ConocoPhillips. (See SPE Res Eval & Eng, June 2011, page 377.)

SPE 142283 • “Effect of Water-Blocking Damage on Flow Efficiency and Productivity in Tight Gas Reservoirs” by Hassan Bahrami, Curtin University, et al.

SPE 139260 • “Production Allocation in Multilayer Gas-Producing Wells Using Temperature Measurements (by Genetic Algorithm)” by Reda Rabie, SPE, Cairo University, et al.

Gas Production Technology

TECHNOLOGY FOCUS

94 JPT • NOVEMBER 2011

JPT

Scott J. Wilson, SPE, is a Senior Vice President of Ryder Scott Company. He specializes in well-performance predic-tion and optimization, reserves apprais-als, simulation studies, software develop-ment, and training. Wilson has worked in all major producing regions in his 25-year career as an engineer and con-sultant with Arco and Ryder Scott. He is Cochairperson of the SPE Reserves and Economics Technical Interest Group and serves on the JPT Editorial Committee. Wilson holds a BS degree in petroleum engineering from the Colorado School of Mines and an MBA degree from the University of Colorado. He holds two patents and is a registered professional engineer in Alaska, Colorado, Texas, and Wyoming.

JPT • NOVEMBER 2011 95

Injection or production of dry gas into or from a depleted gas reservoir could result in serious flow-assurance chal-lenges. Parameters involved in water evaporation/production and in salt pre-cipitation for a gas-production/-injec-tion well are described quantitatively. The terms of formation damage (skin) were evaluated, and some recommen-dations for prediction and mitigation are proposed. Water in the produced gas is a major flow-assurance threat because of the possibility of gas-hydrate formation in the production system. Mitigation methods are presented.

IntroductionGas injected into the depleted reser-voir normally is a processed/dried gas. However, after injection, the gas is in contact with hydrocarbon and aqueous phases in the reservoir. Therefore, the composition of the produced gas may differ from that of the injected gas. More importantly, the produced gas will have some water (mainly in the form of vapor at reservoir conditions) because of the contact with water in the formation. During production, the water is produced with the gas. The net result is evaporation of water from formation brines, result-ing in an increased formation-water salt concentration in the reservoir and salt formation/deposition. Also, the produced water may condense in the wellbore and/

or surface facilities, resulting in corro-sion, hydrate, and/or ice formation.

BackgroundThe study model was a 3D, Cartesian-grid-type block containing one well. The model was intended to represent a portion of a gas field (i.e., drainage area) with its corresponding producer/injector. A seasonal natural-gas storage/production scheme was modeled. First, production from the reservoir lasted 30 months with a maximum daily gas-production rate of 45×106 m3/d. Then, injection was modeled for 3 months at 10×106 m3/d, followed by 4 months of soaking (i.e., shut-in). Then, for 5 years the following injection/production cycle was used: 2 months of production, 3 months of soaking, 3 months of injec-tion, 4 months of soaking, and 2 months of production, for each calendar year.

The following properties were assumed: Reservoir tempera ture=104°C, initial reservoir pressure=250 bar, average porosity=10%, hori-zontal permeability in x- and y-direc-tion=100 md, vertical permeability=10 md, reservoir thickness=110 m, and reservoir dimensions of 900×900 m.

Connate-water saturation was assumed to be 10%, with a gas/water contact at 1005-m depth. The reservoir gas was assumed to comprise four main components: methane (highest concentration), ethane, carbon diox-ide, and water. The injected dry gas was assumed to have no water (i.e., 0% humidity). A modified Peng-Robinson equation of state was used in the simu-lation calculations.

Water Production. As pressure declines during initial field production, gas expands, rock is compacted, and water solubility in the gas increases, resulting in more connate water being evapo-rated to satisfy thermodynamic equilib-

rium. Generally, producing this amount of water from the reservoir results in an increase in the salt concentration (hence, a reduction in water-vapor pres-sure and in water evaporation/produc-tion). However, it is challenging to model this salt-deposition phenomenon with commercial simulators.

During injection/production cycles, a constant water-production-rate increase was observed that corresponded to the constant-rate-vaporization period. During this period, it is assumed that gas is in contact with connate water and that the rock surface is saturated; therefore, vaporization continued until the falling-rate period occurred. During the falling-rate period, the rock surface was no longer saturated; therefore, the evaporation rate and water-production rate decreased.

Salinity. Constant salinity was con-sidered throughout the entire produc-tion period to predict the maximum water production for hydrates preven-tion and to determine inhibitor dosage. During gas injection/production, a por-tion of connate water is evaporated for thermodynamics equilibrium, which increases with increasing gas rate and with pressure decline. Higher forma-tion-water salt concentration tends to slow the rate of evaporation; therefore, less water is produced.

Capillary Pressure. Assuming a water-wet system, if an aquifer is in contact with the reservoir, the capillary pres-sure effect will increase the amount of liquid water produced because the water moves through small pores hav-ing the highest capillary pressure. The higher the capillary pressure, the high-er the produced-water rate.

Gas Velocity (Gas Rate). An increase in gas injection/production from

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, pre-pared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6–8 September. The paper has not been peer reviewed.

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

GAS PRODUCTION TECHNOLOGY

For a limited time, the full-length paper is available free to SPE members at www.jptonline.org.


10×106 to 15×106 std m3/d results in a 10% increase in the total water pro-duced at the end of 91 months of the injection/production cycle (2550 m3 vs. 2315 m3). This observation indicates that a higher evaporation rate will occur in the vicinity of the well and near per-forations, where the highest gas velocity will be encountered (resulting in higher pressure drops). Nevertheless, a higher gas velocity leaves less time for equi-librium; thus, there will be less water evaporation. Further, this higher evapo-ration rate is likely to occur locally, in the pore throats, where some reduction in permeability has happened because of salt precipitation.

Salt-Induced Skin By examining the total-water-produc-tion graphs from previous studies, if no or a weak aquifer exists, then most of the produced water could be assumed to be from evaporation. This situation could be similar to a well completed far from the aquifer or in a large gas res-ervoir during the early gas-production stage during which no water influx occurs in the reservoir. These situations could lead to salt deposition and forma-

tion damage. However, if a large aquifer support does exist, then the produced water will be water from evaporation plus liquid water from water influx.

When considering capillary pressure in the model, with or without existence of an aquifer, water is produced along with gas at each gas-production period during the five injection/production cycles. The total amount of water evap-orated and produced, resulting in salt transport in the near wellbore region, will depend strongly on the magnitude of capillary pressure.

Near-Wellbore Effects A realistic option is to assume that most of the water evaporation is likely to occur in the near-wellbore region, which will experience maximum for-mation damage. As water is produced (evaporated) the deposited salt reduces the permeability in the evaporation area. It was observed that because the zone of evaporation is close to the wellbore (e.g., 150 m from wellbore), the effect on gas productivity was more severe (i.e., 25% less gas production for the 150-m zone). However, when considering a radius of approximately

200 m, the effect on gas production and water production was negligible.

Dynamic FlowNatural-Depletion Phase. As the pres-sure decreases while gas is produced by natural depletion, the molar fraction of water in the gas phase increases. Also, the increase in evaporation will cause salt deposition in the formation, and the salt precipitation will partially reduce the pore-throat cross-section-al flow area, increasing the local gas velocity and, consequently, the evapo-ration rate. In radial flow toward the wellbore, these phenomena combine, leading to a more-severe halite deposi-tion near the wellbore and perforations.

Dry-Gas-Injection Phase. As dry gas is injected into the formation, it contacts connate water. The result is evapora-tion of some of the connate water. This process is driven mainly by the velocity of the gas and its relative humidity.

Soak Phase (Shut-In). When the well is shut in for a prolonged period of time after gas injection, some of the gas will dissolve in the water, and the molar water

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content in the gaseous phase will be at a maximum. After pressure/temperature stabilization, some of the water in the gas phase may recondense, increasing the water saturation in the near-wellbore region. This recondensation could redis-solve some of the deposited salt. When production is resumed after the soak-ing period, salt precipitation will occur because of pressure drop and water evap-oration in the near-wellbore region.

Production-After-Soaking Phase. Generally, the same production phe-nomenon occurs in this stage. But the produced water is a combination of water in gaseous phase from previ-ous evaporation (dry-gas injection) and water evaporated because of pressure drop. However, as gas is produced, the salt saturation increases in the near-well-bore region because of evaporation. This process could result in water migration to the near-wellbore region because of the concentration difference. This ten-dency is greater when a communicating aquifer exists.

Reducing Halite Deposition. To reduce salt precipitation during dry-gas injec-tion/production, freshwater stimulation on regular basis is recommended because salt is highly soluble in water. Regular water washing will help dissolve salt pre-cipitates in the near-wellbore region and perforations. Also, the use of long perfo-ration intervals rather than deep perfora-tions is recommended. This method will increase the interface between formation and wellbore and, therefore, lessen the flow restriction. Reducing the pressure drop in the near-wellbore region by any means is the main objective.

Formation fracturing could be used to bypass the damaged zone. The fracture would provide wider flow paths that would reduce the gas velocity to the well-bore and provide a larger well/formation interface. Consequently, the water-evap-oration rate and salt precipitation could be reduced in the near-wellbore region.

Natural-Gas HydratesWater produced during gas withdrawal may condense in the wellbore, tubing, and surface facilities and may cause cor-rosion or formation of hydrates and/or ice. The amount of hydrates formed and/or inhibitor required is a function of the amount of water in the system. Therefore, it is important to predict the amount of water in the system for design-ing prevention techniques/facilities.

Economic Implications. Assuming an arbitrary hydrate-inhibitor dosage of 1% of the produced-water volume, hydrate-control-cost comparisons were carried out for different water-production scenarios.

• An increase of formation salinity from fresh water to brine resulted in 7.5% reduction in hydrate-control cost.

• The inhibitor cost when consider-ing moderate capillary pressure was 10 times that for the zero-capillary-pressure case. Capillary pressure plays

a significant role with respect to water production and amount of inhibitor required to prevent hydrate formation.

• Salt precipitation will reduce pore-throat size, resulting in less gas and water being produced.

Comparing systems with and with-out salt precipitation showed a 19% reduction in water production in the case with salt precipitation and, conse-quently, a hydrate-inhibitor-cost reduc-tion of 19%. JPT

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One of the most challenging aspects of producing wells drilled in the uncon-solidated pre-Khuff gas reservoirs in Saudi Arabia is to achieve solids-free production while trying to achieve high gas rates. Challenging reservoir conditions include high temperature and pressure, high stress, heterogene-ity, and the absence of stress barriers that together make placing fracture treatments very difficult. Stand-alone screens were installed in openhole well completions in the sandstone res-ervoir and achieved excellent results by eliminating the need for a fractur-ing treatment.

IntroductionAchieving solids-free production from unconsolidated-sandstone reservoirs is an ongoing challenge. The importance of effective sand control in these wells is the need to maintain the integrity of bottomhole and surface processing equipment and facilities, and to ensure that production targets are met consis-tently. Fig. 1 shows examples of the potential damage that sand production can cause.

Several approaches including indirect hydraulic-fracturing stimulation, high-

angle and increased-contact wells, and, more recently, sand-screen comple-tions have been used to develop these gas reserves. Among these approaches, the sand-screen completions, in both vertical and high-angle wells, was field tested in two wells, and then it was implemented in more wells after the success of the pilot.

Formation Geology The sandstone formation in which the two well pilot tests were conducted is a siliciclastic formation in the pre-Khuff stratigraphic section in Saudi Arabia. Gas resources are in sandstones of variable quality within a sequence of sandstones, siltstones, mudstones, and shales. Because the formation was deposited in a shallow marine tidally influenced shoreline setting, it is het-erogeneous in character.

Heterogeneity imposes both verti-cal- and lateral-distribution variability of reservoir-quality properties over a wide range of scale and geometry. Reservoir quality in this sandstone formation is a function of several fac-tors, particularly grain size and sort-ing and clay type and content, which are controlled largely by the primary sedimentological process. Sandstone

cementation and diagenesis-controlled cementation also play a role. These reservoir-quality-influencing factors are, in turn, subject to sedimento-logical and diagenetic processes, con-trolled largely by the depositional set-ting. Porosity and permeability of the gas-bearing intervals vary over a wide range. The well-plan metric for the initial gas-production rate from the formation is from 15 to 20 MMscf/D. Although this rate is achievable, given the permeability and pressure char-acteristics of the reservoir, the forma-tion’s unconsolidated nature increases the risk of exposing equipment to damaging sand production.

Screen Selection Optimum screen selection was achieved after implementing a series of tests.

Sieve Analysis. Several core samples were cut and dried in an oven at 185°F to make sure that any water in the samples was removed. Each sample was gently ground with a rubber mor-tar to break up lumps of particles. Approximately 100 g of the ground material was weighed, then 12-, 14-, 16-, 18-, 20-, 25-, 30-, 35-, 40-, 45-, 50-, 60-, 70-, 80-, 100-, 120-, 140-, 170-,

This article, written by Senior Technology Editor Dennis Denney, contains high-lights of paper SPE 141878, “Achieving Target Solids-Free Gas Rate From Highly-Unconsolidated-Sandstone Formation Intervals,” by Nahr Abulhamayel, J. Ricardo Solares, SPE, Walter Nunez, Ataur Malik, SPE, Mustafa Basri, SPE, and Andrew McWilliams, Saudi Aramco, and Oumer Tahir, SPE, and Mohammad Abduldayem, SPE, Weatherford, prepared for the 2011 SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 20–23 March. The paper has not been peer reviewed.

Achieving Solids-Free Gas-Production Target Rate From Highly-Unconsolidated-Sandstone Formation Intervals



Fig. 1—Casing and surface-equipment damage caused by formation-sand production.


200-, 230-, 270-, 325-, and 400-mesh-size sieves were used to determine the distribution of particle sizes. Most of the particle retention was in the 40- to 70-mesh pans.

Sand-Retention Tests. Sand-retention tests (slurry and sandpack methods) were performed after completing the sieve analysis. The slurry method emulated the annular space between the wellbore wall and the outer wall of the screen. The sandpack method

emulated a collapsed-annulus scenario with sand packed around the screen.

Filter-Cake Flowback Test. A filter-cake flowback test ascertained whether the mud cake that formed in the well-bore during drilling operations was able to pass through the screens at normal flowing conditions. Test results indi-cated that the optimum aperture size for the screens for the two pilot wells was 300 µm. Both wells were completed with a 7-in. liner and a 57/8-in. open-

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 stage of screen deployment if required, and that if any obstruction was found in the openhole wellbore, the string had to be picked up and redeployed because no rotation was allowed.

Before deploying the screens, the 7-in. casing in each well was scraped and dressed to eliminate the risk of tearing or damaging the screens by burs or debris, and to avoid problems with setting and sealing the packer against the casing. A check trip also was per-formed to ensure that the screens were able to reach the required depth, given that the maximum slackoff weight was

Fig. 2—Sand-screen construction.

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limited and that circulating through the screens rarely helps to wash a string deeper. Therefore, the check trip was performed by running a string down to a depth where the outer diameter (OD) of the BHA was larger than the OD of the screen shoe. The string reached total depth in both wells without need-ing to ream or pump, indicating that the screens could be deployed without any problems.

During screen deployment, wellbore fluids were monitored constantly to ensure that they were clean and free of any particles that could plug the screen, thereby minimizing the risk of screen collapse. Subsequently, fresh solids-free mud was spotted in the open-hole section ahead of the deployment operation and a high-rate circulation was performed.

The weight of the string was moni-tored carefully during the deployment operation, and when the BHA reached the targeted depth, its last upward movement was recorded to keep it in tension. The setting depth of the liner hanger and the liner-top packer was selected taking into consideration the liner-couplings depth. Once the setting

depth was reached, a 13/4-in. alumi-num ball was dropped to plug the drill-string, and the liner hanger was actu-ated hydraulically. Then, the pressure was increased gradually to 2,500 psi to set the packer, and was increased to 4,000 psi in increments to energize the packing elements as much as possible. Packer integrity was confirmed with a 10,000-lbf overpull test, a 10,000-lbf slackoff test, and a 2,500-psi annulus-pressure test.

Well PerformanceDeliverability tests showed that both wells performed above expectations. Well X flowed at a sustainable con-trolled gas rate of 22 MMscf/D with a flowing wellhead pressure of 2,400 psi and no skin damage. Well Y flowed at a sustainable controlled gas rate of 22 MMscf/D with a flowing wellhead pressure of 2,425 psi and skin damage of less than 1.0.

Lessons Learned• Adhering to the directional-drill-

ing plan is critical to limit the dogleg severity and to ensure that screens can be deployed trouble free.

• Upon reaching total depth, it is important to circulate drill cuttings out of the wellbore, back ream to the casing shoe, and perform a check trip before deploying the screens, to elimi-nate possible problems.

• Friction factors should be calibrat-ed with the actual loads experienced during the reaming run.

• Ensure that solids-free mud is used by checking the shakers frequently to confirm that they are filtering the mud properly.

• Newly mixed mud sometimes is sheared insufficiently and has poor carrying capacity. The mud will have to be sheared properly before deploy-ing the screens; because this can take considerable time, this time must be factored in during the planning of the drilling operation.

• Proper torque-and-drag modeling must be performed to be fully aware of the maximum allowable weight dur-ing deployment of the screens.

Implementing the actions listed above will minimize skin damage across the screens, which in turn will reduce the pressure drop across the completion and maximize production rate.

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A method was developed to screen potential horizontal-well-refracturing candidates rapidly by use of produc-tion performance and completion-data analysis. Integration of initial hydraulic-fracture-completion details augments the process and helps screen understimulated wells in dif-ferent production classes. To accom-plish this screening, an index called a “completion index” was defined after analysis of the completion param-eters, production behavior, and their interrelationship.

IntroductionRestimulation of existing wells rep-resents a vast unexploited resource in tight formations. In 1996, the Gas Research Institute, now the Gas Technology Institute (GTI), investi-gated the potential for natural-gas-pro-duction enhancement by use of restim-ulation in the USA (onshore, lower 48 states). The report indicated that the potential was substantial (more than 1 Tcf of reserves in 5 years), par-ticularly in the tight gas sands of the Rocky Mountain, midcontinent, and south Texas regions. The study also stated that 85% of the restimulation potential for a field exists in 15% of the wells. Hence, the key to any suc-cessful restimulation program is being able to identify that 15 to 20% of the

total well population that represents high potential for restimulation suc-cess. However, it also was determined that industry’s current experience with restimulation is mixed, and that con-siderable effort is required in candi-date selection, problem diagnosis, and treatment design/implementation for a program to be successful.

The GTI study investigated three main classes of candidate-selection methods: production-performance comparisons, pattern-recognition-tech-nology/virtual-intelligence methods, and production-type-curve matching. The study concluded that although virtual-intelligence methods were rela-tively better compared to production type curves, no universal method exists that enables selecting restimulation candidates across different geologic set-tings. Use of production statistics alone was the least-effective process.

Most of the literature referencs ver-tical wells in layered formations of tight-sand reservoirs. Although the same candidate-selection methods can be extended to horizontal wells in shale-gas reservoirs, limitations exist. The production-type-curve-matching method typically is not applicable in a shale-gas setting because of variability in complex fracture networks from well to well and lack of diagnostic tools for quantifying fracture characteristics for analysis. Pattern-recognition or virtual-intelligence methods have limitations mainly from the amount, type, and quality of data available for robust anal-ysis. Ideally, an adequate and complete data set (including completion and reservoir/geology data) that quantifies successful cases of horizontal refractur-ing in shale should be available to train the virtual-intelligence tools. Pattern-recognition tools use artificial neural networks to extract a set of optimum completion parameters that most likely

will result in good production perfor-mance, for which the degree of depar-ture from the optimum parameters is translated as a proxy for restimulation potential. Virtual-intelligence tech-niques can be designed to mimic the thinking process of a completion engi-neer who is entrusted with selecting refracturing candidates. The downsides are the data and expertise require-ments. Expert judgment is required in conditioning data to be used in the var-ious processes, and the outcome could be compromised by lack of important information, such as reservoir proper-ties. Selection based solely on produc-tion data will have the same limita-tions faced in tight sands, although production data are a critical input for the other two methods. Hence, there is a need for specific methodologies for refracturing-candidate selection in shale reservoirs.

Rationale of Refracturing and Candidate SelectionThe rationale is to attain a stimu-lated-reservoir volume greater than that achieved in the initial fractur-ing treatment. When a new volume of shale is exposed in a refracturing treatment, the stimulated-reservoir vol-ume is enlarged, resulting in a gain in reserves. A potential refracturing can-didate is one that is performing below its productive potential with respect to in-situ reservoir characteristics despite initial hydraulic fracturing. Therefore, to identify potential candidates, res-ervoir characteristics need to be sepa-rated from hydraulic-fracture charac-teristics. Generally, underperformance of shale-gas wells can be caused by inefficient initial completion, inefficient well placement, gradual damage during production, or pressure depletion.

A refracturing-candidate-identifica-tion workflow should honor both

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 144032, “A Novel Screening Method for Selection of Horizontal-Refracturing Candidates in Shale-Gas Reservoirs,” by Shekhar Sinha, SPE, and Hariharan Ramakrishnan, SPE, Schlumberger, prepared for the 2011 SPE North American Unconventional Gas Conference and Exhibition, The Woodlands, Texas, 14–16 June. The paper has not been peer reviewed.

Screening Method To Select Horizontal-Well Refracturing Candidates in Shale-Gas Reservoirs




production potential of the reservoir rock and major causes of underper-formance. The method detailed in the full-length paper has two tiers. The first tier is a purely statistical short listing of candidates by use of both production-performance comparisons and initial-completion details. The sec-ond tier is model based and integrates the first tier of statistical analysis with available petrophysical data and geo-logical information.

Candidate-Selection WorkflowData Requirements. Production and completion data for this study were taken from the public domain. The data from these sources can be import-ed into any database application or spreadsheet program to perform the analysis. Monthly oil-, gas-, and water-production data were available from these sources, as reported to regulatory agencies. Reported-completion-data quality in the public domain is some-times inconsistent and requires strin-gent quality checks before proceeding for analysis.

Production, Completion, and Reser-voir-Quality Indicators. The first tier of data analysis is statistical and uses production indicators and completion indicators derived from initial-com-pletion details. This step reduces the number of potential candidates for use in the second-tier analysis. First-tier data analysis will yield results similar to those of pattern-recognition methods.

Production Indicators. Time-norma-lized production indicators often

are used for comparing production between wells. The production indica-tor should represent long-term pro-duction behavior. Estimated ultimate recovery (EUR) would be the best production indicator, but for horizon-tal wells in shale reservoirs, EURs often are subjective and change as additional production data become available (i.e., prolonged linear-flow behavior and absence of boundary-dominated flow in the available production history). Often, the first-12-month gas produc-tion or best-12-month gas production will correlate well with longer-term production (5- or 10-year cumulative production) and can be used as a proxy for long-term production.

Completion Indicators. Evolution of completion practices in shale reser-voirs has had a significant effect on production performance. Many of the early foam and gel completions in the Barnett shale have been restimulated with slickwater, which has become the standard treatment. Large slick-water completions have been shown to develop very large and complex fracture-network systems, resulting in higher production rates compared with other fluid types. Supplementing production-data analysis with com-pletion data enhances the candidate-selection process and provides valu-able insights by identifying patterns of completion practices and their effect on production performance.

An important development in hor-izontal-well fracturing has been mul-tistage fracturing. There has been an evolution to a larger number of stages

in the laterals. Staging has been as close as 270 ft in Barnett shale completions. Consistent staging data are difficult to find in public databases; therefore, only a few operators’ data sets were con-sistent enough to use for completion-index calculation.

Depending on shale-reservoir char-acteristics (e.g., heterogeneity and presence of natural fractures), the cor-relation between individual comple-tion variables and the production indi-cator varies. Therefore, the completion index for a specific shale play must be defined for wells being studied in the area of interest after studying the correlation of individual completion and stimulation parameters vs. pro-duction indicators. The completion-index definition and calculation used here are based on the data set used and on available public completion data. Internal to an operating company, a more complete data set would be avail-able and analyzed to formulate the applicable completion index.

For the given data set, the simplest completion index can be computed by combining three completion vari-ables—total volume pumped, number of stages, and length of the lateral—as follows.

Completion Index=

Total volume of fluid pumped

(Lateral length/Total number of stages).

If only one variable shows a clear dominant correlation to production, then that variable alone can be rep-

Fig. 1—3D Earth model produced from integrating seismic, log, and geological data.

Fig. 2—Gas-porosity log extracted from the 3D model along a horizontal lateral.

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resented as the completion index. A simple completion index could be total volume of fluid pumped, volume of fluid per unit length, or total proppant placed. Once a completion indicator is defined, it is used as an indicator of overall hydraulic-fracture-completion quality of the well. For an area of interest with relatively uniform res-ervoir-rock characteristics, a positive correlation between computed com-pletion index and production index is expected with a lower degree of scat-ter, but the objective of crossplots is to use the correlation as a candidate-well filtering tool, as explained in the next subsection, not to derive the correla-tion coefficient.

Reservoir-Quality Indicators. One of the main factors for scatter observed on correlation graphs of production and completion variables alone is the variation of reservoir-rock character-istics in these reservoirs. Reservoir-rock quality can be defined by several properties, such as hydrocarbon-filled porosity, pore pressure, and organic content and maturation, that relate

to the hydrocarbon-in-place potential. The reservoir-rock-quality definition also can consist of rock-mechanical properties that define the fracturabil-ity of the rock, which enables cre-ation of large fracture-surface areas in the reservoir.

Most operators in different shale plays drill multiple pilot wells and perform complete suites of logs for evaluation. These pilot-well logs can be integrated with available logs from laterals, logging-while-drilling data, seismic data, and geological data to build an integrated reservoir model. The integrated reservoir model cap-tures structural and reservoir-proper-ty variations between the pilot wells by integrating data from all sources, as shown in Fig. 1. From the model, synthetic logs along the horizontal laterals, as shown in Fig. 2, can be extracted and used as proxies for reservoir-quality indicators. When the variability in reservoir quality is nor-malized, scatter in the observed rela-tion between production and com-pletion, or between production and

reservoir-quality, tends to reduce and trends are more noticeable.

To determine whether completion or reservoir quality has more effect on production, the production index was crossplotted with the completion index, and the reservoir-quality index and correlation coefficients were com-pared. Wells that are out of zone are clustered together and have no correla-tion, while wells landed in the target zone have a much better correlation.

For the analyzed data set, the cor-relation between production index and reservoir-quality index was stronger than that between production index and completion index. Out-of-zone wells showed a slight trend with res-ervoir-quality index, but no trend with completion variables. Also, out-of-zone wells had poor overall comple-tion quality. In general, reservoir qual-ity had a greater effect on production potential compared with the effect of completion variables. For uniform res-ervoir quality, the production indicator would correlate better with comple-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.

INTERNATIONAL 2011 BID ROUND FOR PETROLEUM EXPLORATION AND EXPLOITATION

- The Egyptian General Petroleum Corporation (EGPC) invites Petroleum Exploration Companies for

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Sharing Agreement.

- The International 2011 Bid Round includes Fifteen (15) Exploration Blocks in Gulf of Suez, Eastern

Desert, Western Desert & Sinai Sedimentary Basins as shown in the map.

- Interested companies can submit their offers based on the Procedures, Main Commercial Parameters and

the applied Egyptian Production Sharing Model Agreement.

- Data purchasing and data room will be available in EGPC Geological & Geophysical Information

Center, Nasr City, upon request and according to the determined prices.

- Main Information, Coordinates, Procedures, Main Commercial Parameters and the Model Agreement

can be obtained through EGPC site : www.egpc.com.eg

Closing 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

EGPC

NE OBAYED801.266 KM2

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NORTH MATRUH798.124 KM2 NW GINDI

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S.GHAZALAT1883 KM2

N.ALAM EL SHAWISH565.23 KM2

NW GHARIBONSHORE654.98 KM2

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