Stimulation Design for Unconventional Resources

Babatunde Ajayi Seneca Resources Corporation Stimulation Design for Pittsburgh, Pennsylvania, USA Unconventional Resources Iroh Isaac Aso Ira J. “Jay” Terry, Jr. Kirby Walker Kevin Wutherich The oil and gas industry has undergone a renaissance brought on by the development Canonsburg, Pennsylvania of ultralow-permeability reservoirs, made possible through horizontal drilling and Jacob Caplan hydraulic fracturing. Recent innovations in systematic engineering design are improv- Dewey W. Gerdom PDC Mountaineer LLC ing stimulation effectiveness and well production. Completion engineers are able to Bridgeport, West Virginia, USA perform the entire design loop, from reservoir characterization to stimulation plan,

Brian D. Clark monitoring and calibration and production evaluation. Utpal Ganguly Houston, Texas, USA

Xianwen Li Yonggao Xu The ability to efficiently exploit ultralow-permea- Increasingly, directional wells are being Hua Yang bility plays has invigorated the oil and gas indus- drilled and steered based on logging-while-drill- PetroChina Changqing Oilfield Company try around the globe. The transition from vertical ing (LWD) data.1 Engineers can use these Xi’an, Shaanxi, People’s Republic of China to horizontal wells was spurred by development measurements to characterize small-scale het- Hai Liu of revolutionary techniques for drilling and com- erogeneities that horizontal wells encounter as Beijing, People’s Republic of China pletion. Eventually, completion and stimulation they penetrate stratified formations. However, design for horizontal wells evolved into a stan- even with the addition of LWD data to help in Yin Luo dard template—the geometric method, whereby planning stimulation programs, well perfor- Chengdu, Sichuan, People’s Republic of China engineers divide the horizontal wellbore length mance has been difficult to predict. evenly into the number of planned intervals, or Recently, Schlumberger engineers analyzed George Waters stages, designated for fracture treatment. To pro- production logs from more than 100 horizontal Oklahoma City, Oklahoma, USA mote fracture growth from multiple starting shale gas wells in six US shale basins to identify Oilfield Review Summer 2013: 25, no. 2. points, engineers then design stages typically factors that influence the effectiveness of hydrau- Copyright © 2013 Schlumberger. with two to eight perforation clusters distributed lic fracture completions.2 The analysis indicated For help in preparation of this article, thanks to Paul uniformly along the stage length. that perforation efficiency—the percentage of A. Babasick, Houston; John P. McGinnis and Barry L. McMahan, Seneca Resources Corporation, Houston; and The geometric approach for fracture design perforation clusters that contribute to produc- Michael Yang, Beijing. ignores the vertical and horizontal heterogeneity tion—was about 70%. Nearly a third of the clus- Mangrove, Petrel, RST, Sonic Scanner, StimMAP LIVE and UFM are marks of Schlumberger. of unconventional reservoirs. Vertical wells may ters contributed nothing to production. The INTERSECT is a joint mark of Schlumberger, Chevron penetrate a stack of highly variable sandstone and investigators looked deeper into the data to and Total. shale strata. Horizontal wells may wander through explain this inefficiency. 1. For more on current horizontal drilling technology: heterogeneous portions of a reservoir, or even The data showed that increasing the number Felczak E, Torre A, Godwin ND, Mantle K, Naganathan S, Hawkins R, Li K, Jones S and Slayden F: “The Best of completely out of a reservoir, depending on how of fracture stages and decreasing the distance Both Worlds—A Hybrid Rotary Steerable System,” closely the driller was able to follow the target between stages and between perforation clusters Oilfield Review 23, no. 4 (Winter 2011/2012): 36–44. For more on steering horizontal wells: Amer A, zone. Geologic heterogeneity along wellbores correlated with a rise in production rate from a Chinellato F, Collins S, Denichou J-M, Dubourg I, causes wide variability of rock properties that, in well. Stimulation design is a compromise between Griffiths R, Koepsell R, Lyngra S, Marza P, Murray D and Roberts I: “Structural Steering—A Path to Productivity,” turn, directly affect where fracturing stages will the extremes of a single customized fracture Oilfield Review 25, no. 1 (Spring 2013): 14–31. encounter producible reservoir rock. Consequently, stage and of multiple stages to cover a wide vari- 2. Miller C, Waters G and Rylander E: “Evaluation of the geometric placement of stages often results in ety of rocks. Increasing the number of perfora- Production Log Data from Horizontal Wells Drilled in Organic Shales,” paper SPE 144326, presented at the poor well performance, leading completion engi- tion clusters and stages is not a guarantee for SPE North American Unconventional Gas Conference neers to use manual, time-intensive methods of success. The analysis suggested that focused and Exhibition, The Woodlands, Texas, USA, June 14–16, 2011. picking stage and perforation locations based on staging is important: Fracture stages should tar- subtle well log characteristics. get rocks with similar petrophysical and geomechanical properties.

34 Oilfield Review Summer 2013 35 Engineered Stimulations Reservoir Quality (RQ) Completion Quality (CQ) While Mangrove software provides a specific Organic content Mineralogy—mainly clay, carbonate and silica engineering workflow intended for predictive Thermal maturity model building and evaluation of hydraulic frac- Mechanical properties—Young’s modulus, ture treatment in unconventional reservoirs, it Effective porosity Poisson’s ratio and tensile strength also continues to support workflows and model- Intrinsic permeability ing necessary for conventional reservoirs. The Fluid saturations—oil, gas, Natural fractures—presence, density, orientation condensate and water and condition (open, closed or cemented) Mangrove system is capable of accommodating reservoir heterogeneity, rock fabric, physical Organic shale thickness In situ stress—variations between intervals properties and geomechanical properties at a Hydrocarbons in place accounting for mechanical properties anisotropy fine level of detail without compromising compu- tational efficiency.4 > Reservoir quality and completion quality factors. Input to the workflow comes from geologic, core, well log, seismic, production log and engineering data. Geologists, geophysicists and Because it was apparent that not every stage stimulation design software for engineering, engineers compile, synthesize and interpret contributed equally to well productivity, the modeling and designing hydraulic stimulations. these data and summarize them in a common investigators also examined the contribution of The software facilitates a systematic strategy for 3D earth model. This integration and display are perforation clusters within fracture stages. They designing multistage stimulations centered on performed within the Petrel E&P software plat- determined that, like fracture stages, not every single wells embedded within the context of a 3D form. The earth model forms the basis for geo- cluster contributed equally to production, and earth model of the reservoir. Completion and logic, discrete fracture network (DFN) and they concluded that the optimal number of perfo- stimulation design is based on multidisciplinary geomechanical models that are input to the ration clusters per stage ranged from two to five. reservoir characterization that is combined with completion advisor as well as to a number of The analysis suggested that strategic placement microseismic information for model calibration hydraulic fracture models and to production of clusters within productive and fracturable geo- and integrated with production forecasting for and forecasting simulators accessible within logic units was more important than the number design evaluation.3 the Mangrove workflow. of clusters. This article describes the Mangrove software Engineers use the Mangrove completion advi- The study results led to fundamental design and outlines case studies that demonstrate how sor to assign levels of reservoir quality and com- questions: the software helps operators improve well pro- pletion quality to the reservoir rock (above left). • Is there an optimal number of treatment stages? ductivity. Two examples from the eastern US Reservoir quality (RQ) is a prediction of how • Is there an optimal location for each treatment show side by side comparisons of well produc- prone the rock is to yield hydrocarbon. stage along a wellbore? tivities that result from conventional and engi- Completion quality (CQ) is a prediction of how • Is there an optimal place for perforation clus- neered completions in the Marcellus Shale. An effectively the rock may be stimulated using ters within stages? example from the Ordos basin of China illus- hydraulic fractures. The RQ and CQ parameters To address these questions, Schlumberger com- trates improvements to production from low- typically receive binary scores of good or bad pletion engineers developed the Mangrove reservoir permeability sandstones. based on cutoff criteria for a reservoir. They are then combined into composite scores that grade 3. Cipolla C, Weng X, Onda H, Nadaraja T, Ganguly U and Suárez-Rivera R, Deenadayalu C, Chertov M, Malpani R: “New Algorithms and Integrated Workflow for Hartanto RN, Gathogo P and Kunjir R: “Improving the intervals from best to worst for placing frac- Tight Gas and Shale Completions,” paper SPE 146872, Horizontal Completions on Heterogeneous Tight Shales,” turing stages and perforation clusters within presented at the SPE Annual Technical Conference and paper CSUG/SPE 146998, presented at the Canadian Exhibition, Denver, October 30–November 2, 2011. Unconventional Resources Conference, Calgary, each stage. The best locations have good RQ and Cipolla C, Lewis R, Maxwell S and Mack M: “Appraising November 15–17, 2011. CQ grades, meaning the rock should be produc- Unconventional Resource Plays: Separating Reservoir Suárez-Rivera R, Burghardt J, Stanchits S, Edelman E and 5 Quality from Completion Effectiveness,” paper Surdi A: “Understanding the Effect of Rock Fabric on tive and fracturable (next page). The completion IPTC 14677, presented at the International Petroleum Fracture Complexity for Improving Completion Design and advisor also allows similar quality rocks to be Technology Conference, Bangkok, Thailand, Well Performance,” paper IPTC 17018, presented at the February 7–9, 2012. International Petroleum Technology Conference, Beijing, grouped in the same stage, leading to the most 4. Fabric refers to the spacing, arrangement, distribution, March 26–28, 2013. effective multistage treatment. The completion size, shape and orientation of the constituents of rocks 8. For more on the wiremesh model: Xu W, Thiercelin M, advisor is able to accommodate user-provided such as minerals, grains, porosity, layering, bed Ganguly U, Weng X, Gu H, Onda H, Sun J and Le Calvez J: boundaries, lithology contacts and fractures. “Wiremesh: A Novel Shale Fracturing Simulator,” paper operational constraints, such as the maximum 5. For more on fracture staging algorithms: Cipolla et al SPE 132218, presented at the CPS/SPE International Oil stage interval or minimum and maximum perfo- (2011), reference 3. and Gas Conference and Exhibition in China, Beijing, June 8–10, 2010. ration interval, and structural constraints such 6. For more on conventional hydraulic fracture models: Brady B, Elbel J, Mack M, Morales H, Nolte K and Poe B: 9. For more on the UFM model: Weng X, Kresse O, Cohen C, as fault locations and distances of perforation “Cracking Rock: Progress in Fracture Treatment Design,” Wu R and Gu H: “Modeling of Hydraulic Fracture- clusters from these faults. Oilfield Review 4, no. 4 (October 1992): 4–17. Network Propagation in a Naturally Fractured Formation,” SPE Production & Operations 26, no. 4 7. Jeffrey RG, Zhang X and Thiercelin M: “Hydraulic After deciding where to locate stages and per- (November 2011): 368–380. Fracture Offsetting in Naturally Fractured Reservoirs: foration clusters, engineers design the stimula- Quantifying a Long-Recognized Process,” paper SPE Kresse O, Cohen C, Weng X, Wu R and Gu H: “Numerical 119351, presented at the SPE Hydraulic Fracturing Modeling of Hydraulic Fracturing in Naturally Fractured tion treatments using hydraulic fracture (HF) Technology Conference, The Woodlands, Texas, Formations,” paper ARMA 11-363, presented at the simulators. In situations in which the geology is January 19–21, 2009. 45th US Rock Mechanics/Geomechanics Symposium, San Francisco, June 26–29, 2011.

36 Oilfield Review relatively simple, conventional HF simulators are Segments of Similar Lithology adequate. These time-tested 2D and pseudo-3D models treat HFs as planes propagating away from the well in the direction of the maximum Well segments principal compressive stress.6 Engineers have the option to use these models in the Mangrove workflow and determine which model is best suited Austin Chalk for a given reservoir. Conventional models are not comprehensive enough for heterogeneous and naturally fractured reservoirs. Hydraulic fracture growth is complex, and its characterization requires 3D Upper Eagle Ford Shale models that incorporate interactions of HFs with natural fractures while also considering the impact of HFs on local principal stresses.7 To address complex situations, the Mangrove system Lower Eagle Ford Shale provides two fracture models: the wiremesh hydraulic fracturing model and the UFM unconventional fracture modeling simulator. The wiremesh model provides a mathemati- Buda Limestone cal equivalent representation of the hydraulic fracture network.8 The wiremesh approach is relatively fast and suitable for environments that lack significant reservoir characterization data. Stages of Similar Rock Quality and Stress Gradient To improve well productivity, completion design- ers are able to iterate and parameterize the input values to obtain an optimal stimulation design for Hydraulic fracturing stages fracture length, height, surface area and proppant distribution. Austin Chalk The UFM model is the first commercially available complex hydraulic fracture model to Rock Quality incorporate fracture-to-fracture interactions.9 Good RQ and good CQ Bad RQ and bad CQ The model accounts for the effects of natural Bad RQ and good CQ fractures and geomechanical properties on Good RQ and bad CQ hydraulic fracture growth and predicts den- dritic—multiple branching—hydraulic fracture Rock quality Eagle Ford Shale propagation as well as fluid flow and proppant transport. Hydraulic fracture growth is governed Stress gradient by the rock fabric and geomechanical properties of the reservoir, the preexisting fracture network Stress gradient and prevailing in situ stress magnitudes and anisotropy. As the HF network develops, it per- Low High turbs the stress field as each fracture surface Buda Limestone becomes pressurized, opened and propped. Engineers may use the UFM simulator for HF net- > Dividing horizontal laterals into segments and stages. This horizontal well (top center) targets a work design to optimize well productivity. reservoir zone near the boundary horizon (purple) between the upper and lower Eagle Ford Shale, Regardless of the HF model engineers use to which was deposited above the Buda Limestone and below the Austin Chalk. The other horizons are the top surfaces of the Buda Limestone (blue) and the upper Eagle Ford Shale (brown). Engineers prepare their initial design, the result must be divided the lateral into segments based on location within the reservoir, the wellbore trajectory and calibrated during HF stimulations. The Mangrove rock properties. Each segment contains similar lithology along its length. Engineers further subdivided workflow is able to incorporate results obtained the segments into stages (bottom center) based on similar minimum horizontal stress gradients, reservoir quality (RQ) and completion quality (CQ) along the length of each stage. Each stage is then a from monitoring microseismicity induced by candidate for hydraulic stimulation. A color-coded rock quality index, shown above the well, combines propagating HFs to calibrate the predicted RQ and CQ and indicates the best intervals for stimulation. The relative magnitude of the far field model. Geophysicists process the microseismicity minimum horizontal stress gradient, shown along the bottom of the well, indicates the relative data to locate seismic emissions from small slip pressure levels at which the reservoir interval will fracture. [Adapted from Cipolla et al (2011), reference 3.] events associated with the development of the

Summer 2013 37 Perforation cluster

Geometric Placement of Fracture Stages and Perforation Clusters

Fracture stage Rock Quality Good RQ and good CQ Bad RQ and bad CQ Bad RQ and good CQ Good RQ and bad CQ

Rock quality

Stress gradient

Low High

Engineered Placement of Fracture Stages and Perforation Clusters

Rock quality

Stress gradient

> Comparing hydraulic fracture designs for a horizontal well in the Eagle Ford Shale. In a geometric design (top), fracture stages (inset, four disks of the same color) and perforation clusters (individual disks) were distributed uniformly along the length of the lateral. In the engineered design from the Mangrove workﬂow (bottom), engineers determined the location and length of each fracture stage and the placement of each perforation cluster from analysis of the composite rock quality scores and minimum horizontal stress gradients. The optimal design is for all perforation clusters (PCs) to break down and initiate fractures at more or less the same pressure. The composite RQ and CQ rock quality index is shown along the top of the well. The relative magnitude of the far ﬁeld minimum horizontal stress gradient is shown along the bottom of the well. [Adapted from Cipolla et al (2011), reference 3.]

HFs.10 Often, to increase the precision and accu- fracture models simulate rock deformation, the densities. Fine gridding in the vicinity of the well- racy of the event locations, geophysicists adjust creation of conductive fractures and channels in bore and HF network captures fine-scale details. their geologic and velocity models. These adjust- the reservoir and the placement of proppant into Coarse gridding is usually sufficient far from the ments, in turn, are used to update the geome- them. The reservoir simulators predict the flow of wellbore and HF network.11 chanical and the DFN models for the HF models. fluids from the reservoir into and through the The Mangrove workflow provides analysis Before and after completion of HF stimula- higher conductivity pathways created by HFs that from data entry to model updates. In this process, tions, production engineers run reservoir flow have been propped open. Within the Mangrove geologic and engineering field data are input for models to predict the resulting production per- workflow, these calculations may be performed building models of the reservoir. Engineers use formance. These models couple mechanical using the INTERSECT reservoir simulator, which the models to estimate RQ and CQ (above). deformation and pore volume changes. The allows unstructured gridding for a range of grid Engineers input the completion design into 2D or

38 Oilfield Review 3D HF simulators for evaluating the fracture A software-mediated systematic approach to divided into segments of similar lithology that did stimulations that will be pumped and then feed planning, engineering and executing stimulations not include discontinuities—primarily faults, the stimulation design into reservoir simulators has proved to be more effective than convention- fractures and highly laminated intervals. The seg- to forecast production. ally planned stimulations. PDC Mountaineer LLC ments would then be divided into stages and per- The system is able to incorporate microseis- and Schlumberger obtained favorable results with forated in rocks of similar minimum horizontal micity monitoring to calibrate steps in the engineered completions in the Marcellus Shale. stress. During each fracture stage, all perfora- Mangrove workflow. Such calibration comes from tions would initiate fractures at roughly the same locating microseismic events precisely and com- Comparing Completion Methods pumping pressure, the fractures would extend paring these locations with predicted HF growth. PDC Mountaineer LLC (PDCM) focuses primarily and propagate together, and eventually, produc- The location of microseismic events may help the on natural gas production from the Marcellus tion would flow from the fractures in proportion system estimate the effective stimulated reser- Shale formation. In the company’s efforts to to the stimulated reservoir volume they contact. voir volume, which may then be used to adjust the develop a Marcellus Shale field near Bridgeport To test this procedure, the PDCM team completion and stimulation strategies of subse- in Harrison County, West Virginia, USA, its first selected three new well locations, near the origi- quent fracture stages or make adjustments even three horizontal wells were only marginally eco- nal three wells, which had similar reservoir and while stimulation is occurring in some stages. nomic. Consequently, PDCM wanted to deter- completion quality. Except for the engineered In addition, to obtain precise microseismic mine how to improve production. design for distributing the staging and perfora- event locations, geophysicists conduct seismic The company started each of these first tion locations along the laterals, the new wells velocity inversion, and in the process, adjust the wells by drilling and logging a vertical pilot well. would be completed in the same way as the ear- starting model of the geologic and mechanical Engineers used these data to determine the tar- lier wells. properties within the reservoir zone. The adjusted get reservoir zone and the landing point for the The wells were drilled in the direction of the model may be used to update predictions of horizontal well, or lateral. PDCM then drilled regional minimum in situ principal horizontal hydraulic fracture growth and forecasts of reser- the laterals using data derived from mud logs stress to facilitate opening of hydraulic fractures voir production. and logging-while-drilling (LWD) gamma ray for emanating perpendicularly from the wells. The The Mangrove workflow centers around com- guidance to stay within the target zone. The lat- lateral wells cut across rocks of variable lithology pletion and stimulation design for single wells erals were completed using designs based on a and, consequently, mechanical properties, which within the 3D context of a larger reservoir model. geometric method—stages and perforation dictate how the regional stress field is transmit- The focus on single wells reduces model size, clusters distributed uniformly—followed by ted through the rock to the local borehole wall. enables faster calculations and gives completion slight manual adjustments to the design to move After drilling the wells and before designing engineers flexibility to make quick decisions and perforation clusters within each stage to zones the completions, the team collected the follow- adjustments to stimulation programs. that were estimated to have lower minimum ing well information: wellbore directional sur- The Mangrove software may be run on a sin- horizontal stress.12 veys, gamma ray logs, petrophysical and gle platform, which eliminates the need to PDCM and Schlumberger engineers analyzed mechanical properties for evaluating RQ and migrate data from one software application to the data from the first three wells and concluded CQ, planned fracture fluid types and properties, another and to address problems of software that the completion designs paid little attention to pumping rates, number of stages, number of interfaces and interoperability. specific conditions in each well—lithology, reser- perforation clusters per stage and perforation voir quality, mechanical properties and in situ diameter, density and phasing. The completion 10. For more on hydraulic fracture monitoring: Bennett L, Le Calvez J, Sarver DR, Tanner K, Birk WS, Waters G, Drew stresses. Furthermore, examination of stimula- design called for slickwater to be pumped at J, Michaud G, Primiero P, Eisner L, Jones R, Leslie D, tion-induced microseismicity monitored during 80 bbl/min [13 m3/min] through five perforation Williams MJ, Govenlock J, Klem RC and Tezuka K: “The Source for Hydraulic Fracture Characterization,” the treatments showed a relationship between the clusters in each stage. Oilfield Review 17, no. 4 (Winter 2005/2006): 42–57. locations of perforation clusters, predicted mini- Engineers assembled this information in the Burch DN, Daniels J, Gillard M, Underhill W, Exler VA, Favoretti L, Le Calvez J, Lecerf B, Potapenko D, mum in situ horizontal stress and microseismic Mangrove workflow software and constructed Maschio L, Morales JA, Samuelson M and Weimann MI: activity; the highest microseismic activity concen- 3D earth models of each well. Based on data “Live Hydraulic Fracture Monitoring and Diversion,” Oilfield Review 21, no. 3 (Autumn 2009): 18–31. trated near perforations in rocks of low stress, and from the 3D earth models, engineers were able 11. For more on the INTERSECT simulator: Edwards DA, lower activity occurred elsewhere. Fractures to segment the wells into lengths of similar Gunasekera D, Morris J, Shaw G, Shaw K, Walsh D, started and grew by taking paths of least resis- lithology; each segment was subdivided into Fjerstad PA, Kikani J, Franco J, Hoang V and Quettier L: “Reservoir Simulation: Keeping Pace with tance. Areas near the geometrically located perfo- stages, such that each stage length contained Oilfield Complexity,” Oilfield Review 23, no. 4 ration clusters were effectively stimulated only rock of similar reservoir quality and was capable (Winter 2011/2012): 4–15. 12. Walker K, Wutherich K, Terry J, Shreves J and Caplan J: when the clusters happened to be located in easily of accepting the planned pumping rate. The “Improving Production in the Marcellus Shale Using an fractured rock. Otherwise, areas tended to be team selected perforation locations based on Engineered Completion Design: A Case Study,” paper SPE 159666, presented at the SPE Annual Technical understimulated because the perforation clusters completion quality. The perforation locations Conference and Exhibition, San Antonio, Texas, were not strategically located. were adjusted until the models showed that October 8–10, 2012. The analysis indicated that optimal stimula- fractures initiated at each perforation cluster Gerdom D, Caplan J, Terry IJ Jr, Wutherich K, Wigger E and Walker K: “Geomechanics Key in Marcellus Wells,” tions would result if the completions were engi- within a stage at the same pressure within a tol- The American Oil & Gas Reporter 56, no. 3 neered so each stage and each perforation cluster erance of 0.01 psi/ft [0.23 kPa/m] for the (March 2013): 84–91. contributed to the overall production in proportion to their number. Horizontal wells would be

Summer 2013 39 minimum in situ stress gradient.13 When the higher production. During the first 30 days, the and New York, USA. The company sought to team was satisfied with the completion plans, engineered completions resulted in 106% higher ini- increase production by maximizing reservoir con- the wells were stimulated (below). tial cumulative production per foot of stimulated tact through hydraulic fracture stimulations from Completion engineers conducted each frac- wellbore length than the original three wells. horizontal wells. ture treatment according to the intended prop- Based on these positive results, PDC Seneca Resources had been stimulating wells pant schedule. Compared with the treatments in Mountaineer now performs engineered comple- in the Marcellus Shale but results were highly the original three horizontal wells, the engi- tion designs for all its horizontal wells. The com- variable, even from apparently identical wells. neered completions were pumped at 10.3% higher pany has determined that the time and effort However, the Marcellus Shale comprises many average pumping rates and 5.7% lower average spent on the design are more than offset by the thin laminations, each distinct from its neighbor treating pressures. In addition, the treatments savings from operational effectiveness during com- in terms of physical and mechanical properties. succeeded in placing 30% more of the designed pletions and revenue from increased production.14 As horizontal wells cut through the formation, proppant load per lateral and experienced no they intercept these varied laminations. The screenouts (next page, top left). Perforating Low-Stress Intervals company teamed with Schlumberger to conduct a The team compared the first 30 days of produc- Seneca Resources Corporation and Schlumberger controlled pilot study to test the effectiveness of tion from each well, which revealed a second mea- conducted another test of engineered completion engineered completions compared with what had sure of success. Compared with the original wells, design. Seneca Resources produces natural gas been standard practice for the company—geo- the engineered completions resulted in significantly from Marcellus Shale reservoirs in Pennsylvania metric completions.

Minimum Stimulation Measured Gamma Stress Poisson’s Young’s Calcite Quartz Kerogen Effective Stages Original 5-ft Moving Average Depth, Ray Gradient Ratio Modulus Volume Volume Volume Porosity Perforation Minimum Smoothed Minimum ft 0gAPI 460 0.67psi/ft 1.01 –0.17 0.44 2.33 MMpsi 3.93 0% 100 0%0 100 %0 25% 15Cluster Depth, ft Stress Gradient Stress Gradient Measured Stage 14 0.67psi/ft 1.01 0.67psi/ft 1.01 Segment 1 X1,000 Stage 13

Stage 12 Segment 2 X3,850 X1,500

Stage 11

X2,000 Stage 10 X3,900

Stage 9 X2,500 Segment 3 Stage 8 X3,950

X3,000 Stage 7

Stage 6 X4,000 X3,500 Stage 5

X4,000 Stage 4 X4,050 Segment 4 Stage 3 X4,500 Stress gradient Stage 2 Low High X5,000 Stage 1 > Segments, stages and clusters. Stresses typically change from one lithology to another. To prevent a fracture stage from crossing a lithology barrier, engineers divide the well into segments of similar lithology. Stimulation stages (left, Track 9, green and light blue) should be contained within a segment, and their lengths should be within prescribed minimum and maximum values. Engineers position the perforation clusters (Track 9, short horizontal lines to the left and right of the fracture stages) based on preset design criteria: the number of clusters per stage, the minimum and maximum distance between clusters and a minimum horizontal stress gradient (Track 2) tolerance of 0.01 psi/ft [0.23 kPa/m]. During completion design and modeling, these criteria may need to be relaxed to account for the minimum horizontal stress variation. A close-up of the red box (right) from Track 2 shows the stress gradient ranges from high (blue) to low (red). The original stress gradient logs were recorded every half foot (inset, Track 1) and smoothed using a 5-ft [1.5-m] moving average algorithm (inset, Track 2) to account for imprecision during the perforating operation. (Adapted from Walker et al, reference 12.)

13. The rate of these stress variations within a few borehole 15. Wutherich K, Walker K, Aso I, Ajayi B and Cannon T: 16. Waters G and Zhao R: “Measuring the Impact of diameters of the wellbore, away from the immediate “Evaluating an Engineered Completion Design in the Geomechanical Heterogeneity in Organic Shales on inﬂuence of the borehole, is the wellbore-parallel stress Marcellus Shale Using Microseismic Monitoring,” paper Hydraulic Fracture Initiation and Propagation,” gradient and, for wells drilled parallel to the minimum SPE 159681, presented at the SPE Annual Technical paper CSUG/SPE 147597, presented at the Canadian in situ principal stress direction, is equivalent to the Conference and Exhibition, San Antonio, Texas, Unconventional Resources Conference, Calgary, minimum stress gradient. October 8–10, 2012. November 15–17, 2011. 14. Walker et al, reference 12.

40 Oilﬁeld Review Design Summary

Design Design 0 m 305 Average Perforation Proppant Pumping 0 ft 1,000 Completion Lateral Stage Clusters per Lateral, Rate, Well Method Fluid Length, ft Stages Length, ft per Stage lbm/ft bbl/min N Well 1 Nonengineered Slickwater 3,37514 241 5 1,670 80 Well 2 Nonengineered Slickwater 2,3127 330 5 1,220 80 Well C Well 3 Nonengineered Slickwater 2,1407 306 5 1,320 80 Well B Average 2,6099.3 292 5 1,40080 Well 4 Engineered Slickwater 4,50012 375 5 1,080 80 Well A Well 5 Engineered Slickwater 3,95012 329 4.5 1,230 80 Well 6 Engineered Slickwater 3,92512 327 4.5 1,240 80 Average 4,12512 344 4.7 1,180 80

Monitor well Completion Summary 30-Day Cumulative Production

Normalized Average Average Placed Percentage Normalized Normalized by Number of Treating Treatment Proppant of Proppant by Lateral by Number Perforation Pressure, Rate, per Lateral, Placed Gross, Length, of Stages, Clusters, Well psi bbl/min lbm/ft Versus Design Mcf Mcf/ft Mcf/ft Mcf/cluster Well 1 7,749 78.1 1,783 107.0% 63,194 18.7 4,514 903 Well 2 7,557 76.3 672 55.0% 42,396 18.3 6,057 1,211 Well 3 7,716 66.3 855 65.0% 65,039 30.4 9,291 1,858 Average 7,674 73.6 1,103 75.7% 56,876 21.8 6,094 1,219 Well 4 7,308 79.2 1,002 92.8% 212,631 47.3 17,719 3,544 > Well plan. From a single pad, Seneca Well 5 7,105 81.9 1,251 101.7% 162,652 41.2 13,554 3,012 Resources drilled horizontal Wells A, B and C and Well 6 7,298 82.3 1,245 100.5% 180,436 46.0 15,036 3,341 drilled a vertical monitor well for recording Average 7,237 81.1 1,166 98.3% 185,240 44.9 15,437 3,308 stimulation-induced microseismicity. Well A was completed following a geometric design and Average difference –437 7.6 63 22.7% 128,363 23.1 9,343 2,089 Wells B and C were completed according to Percent average engineered completion designs. The disks on difference –5.7% 10.3% 5.7% 30.0% 226% 106% 153% 171% each well, which represent perforation clusters, are grouped into fracture stages with adjacent > Summary of completion design and results. Data from six horizontal wells drilled into the Marcellus stages differentiated by color. (Adapted from Shale illustrate the results of nonengineered and engineered completion methods (top). Wells 1 to 3 Wutherich et al, reference 15.) were drilled and completed conventionally. Wells 4 to 6, which were drilled near Wells 1 to 3, were completed using an engineered design method that speciﬁes stage and perforation cluster placement. The engineered completions were more effective than the nonengineered completions (bottom); the success of the engineered completions is measured by lower treating pressures, higher pumping rates, more efﬁcient proppant placement and higher cumulative production after 30 days compared with those in the nonengineered completions. (Adapted from Walker et al, reference 12.)

The company drilled three horizontal wells Although completion strategies were custom- zipper-fracture method, whereby plug and perfora- into the same Marcellus Shale reservoir zone ized to optimize production from each well, tion operations followed by stimulation of stages from the same drilling pad. The laterals were engineers kept a number of completion vari- were rotated from one well to the next. As Well A drilled parallel to one another, 800 ft [240 m] ables—fluid, proppant type and size and pump- was being stimulated, Well C was undergoing plug- apart and aligned to the northwest, in the direc- ing flow rate—the same and also kept the ging and perforating. Then stimulation moved to tion of the regional minimum in situ principal number of stages, number of perforation clusters Well B, while plugging and perforating moved to horizontal compressive stress (above right). per stage and amounts of proppant per length of Well A. This process continued until stimulation of Well A, the base case, was completed using the lateral similar for both wells. Nonetheless, some all stages in all the wells was complete. standard geometric method.15 variability existed across the three wells. By their The stimulation engineering team analyzed Wells B and C were completed using the engi- nature and because they are intended to account pilot study results by comparing treatment, neered approach. The RST reservoir saturation for the rock and stress heterogeneity along the microseismicity and initial flowback data from tool and Sonic Scanner acoustic scanning tool wellbore, engineered completion designs inevita- the geometrically designed completion in were run along each lateral after casing had been bly result in variable stage lengths, perforation Well A to similar data from the engineered set to determine the extent of variation between cluster spacings and pumping schedules. completions in Wells B and C. Because all of lithologic and mechanical properties and the To accommodate these variations and main- the perforation clusters were engineered to be resolved stresses in the three wells.16 These mea- tain the spirit of consistency, the company stag- located in wellbore intervals of relatively low surements were compiled and interpreted using gered the timing of the well stimulations using a minimum principal stress, the average fracture the Mangrove workflow software to produce an breakdown and treatment pressures were 7% engineered completion strategy for each well.

Summer 2013 41 Design Summary

Design Design Average Perforation Proppant Pumping Completion Proppant Lateral Stage Clusters per Lateral, Rate, WellMethod Fluid Size Length, ft Stages Length, ft per Stage lbm/ft bbl/min Well A Geometric Slickwater 40/70 5,312 18 295 3 1,650 90 Well B Engineered Slickwater 40/70 4,528 20 226 3.7 1,585 90 Well C Engineered Slickwater 40/70 4,998 20 250 3.9 1,675 90

Completion Summary Flowback Results

Average Average Average Placed Percentage Breakdown Treating Treatment Proppant of Proppant Maximum Tubing Pressure, Pressure, Rate, per Lateral, Placed Flow, Pressure, Well psi psi bbl/min lbm/ft Versus Design Mcf/d/1,000 ft psi Choke, in. Well A 5,572 7,277 69.7 1,122 68% 450 1,500 5/8 600 1,800 5/8 Well B 5,160 7,095 81.1 1,353 83% Well C 640 1,800 5/8 Difference –412 –182 11.4 231 15% 170 300 Percent difference –7% –3% 16% 21% 22% 38% 20%

> Summary of completion design and results. Of three horizontal wells drilled into the Marcellus Shale, Well A, the reference case, was completed following a geometric design (top). Wells B and C were completed according to engineered completion designs, which were more effective than the geometric completion. Their relative success is measured by lower breakdown and treating pressures, higher pumping rates, more effective proppant placement and higher ﬂowback rates than those of Well A (bottom). (Adapted from Wutherich et al, reference 15.)

and 3% lower and the average treatment rate much as 35% of the perforation clusters in Well A, Stimulation of Tight Oil Sandstone and amount of proppant placed were 16% and with the geometric completion, were not contrib- Conventional reservoirs are also candidates for 22% higher in Wells B and C, respectively, than uting to the reservoir volume targeted for stimu- the application of the systematic, engineering in Well A. The treatment comparison indicated lation. In contrast, microseismicity from the approach to reservoir stimulation. The that the engineered completions were more engineered completions and stimulations in PetroChina Changqing Oilfield Company con- effective than the geometric completion (above). Wells B and C showed improvement in the per- ducted a pilot study using the engineered Initial gas flowback rates from Wells B and C centage of perforation clusters that contributed approach for designing reservoir stimulation in a were 33% and 40% higher than the rates from to the stimulated reservoir volume—only 20% of conventional clastic reservoir. Well A on the same 5/8-in. choke size. In addition, the perforation clusters made little to no contri- The Ordos basin, in north-central China, is a fracture-water flowback recovery from Wells B bution (next page). The microseismicity compar- gentle monocline that dips stratigraphically and C was twice that from Well A. These flowback ison indicated that the engineered completions about 1° from east to west. Its fill, which consists data suggest that the wells stimulated by engi- resulted in better placement of perforation clus- of sediments deposited during the Paleozoic, neered completions were making better reservoir ters than did the geometric completion. Mesozoic and Cenozoic eras, thickens in the dip contact, leading to better production, than was The Mangrove workflow software not only pro- direction with an average thickness of 4 to 5 km the geometrically completed well. duced the designs that led to these positive [2.5 to 3.1 mi]. The Paleozoic sediments are During the pilot study, the team placed a verti- results but also reduced completion design time marine deposits that yield primarily natural gas, cal monitor well between Wells A and B; the well from several hours to about one hour per well. while the Mesozoic sediments have a continental was instrumented with geophones for monitoring Moreover, the software rationalized data han- origin and yield oil.18 microseismicity induced by the stimulations in the dling and procedural operations, which led to 17. Wutherich et al, reference 15. three wells. The StimMAP LIVE real-time micro- fewer inaccuracies and improved perforation 18. For more on the Ordos basin: Yang Y, Li W and Ma L: seismic monitoring service recorded and analyzed placement. Seneca Resources continues to use “Tectonic and Stratigraphic Controls of Hydrocarbon Systems in the Ordos Basin: A Multicycle Cratonic microseismicity. When compared with perforation computer-aided completion design and micro- Basin in Central China,” AAPG Bulletin 89, no. 2 cluster locations, microseismic event locations seismic analysis on other wells in its fields.17 (February 2005): 255–269. from the StimMAP LIVE service revealed that as

42 Oilﬁeld Review Well A

35 100 Event count Event count 0 0

A B

100 200 Event count Event count 0 0

C D

Well B

40 Stress gradient 40 Stress gradient

Low High Low High Event count Event count 0 0

A B

250 Stress gradient 40 Stress gradient

Low High Low High Event count Event count 0 0

C D

> Microseismicity comparison. Microseismicity resulting from four fracture stages in Well A (top) and Well B (bottom) indicate improved stimulations from the engineered completions in Well B over the stimulations from the geometric completions in Well A. In each panel, the data show results from a fracture stage; the disks along the colored well trace represent stimulated perforation clusters and the dots are induced microseismic event locations. To show correlation, the disks and dots have the same color. Above the well trace, the height and color of the orange-to-green bars indicate the number of microseismic events along each wellbore interval. Below the well trace on Well B, the minimum horizontal stress gradient is plotted; the amplitude and color of the pink-to-blue shading specify the closure stress gradient level. The company placed perforation clusters based on engineering design principles at locations with relatively low stress gradients. There is a better one-to-one correspondence between microseismicity and perforation locations in Well B than in Well A, indicating improved perforation performance results from an engineered completion design. (Adapted from Wutherich et al, reference 15.)

Summer 2013 43 300 m 300 m Ordos Basin

MW1 Beijing 250 m 250

C H I N A Xi’an 500 m 500 MW2 Shanghai

500 m 500 MW3

N HW2 ea

250 m 250 Basin S HW1 ina Gas field Ch 0 250 500 m th Oil field ou 0 750 1,500 ft S

> Ordos basin, north-central China. A completions team conducted a pilot study to test engineered completion designs from Mangrove software. The ﬁeld test area (white box) is in southwest Ordos basin. The well layout (inset) consists of two parallel horizontal production wells (HWs) and three vertical monitoring wells (MWs, blue circles) constucted for recording microseismicity. The Chang 7 member of the Yanchang Formation was the target horizon. (Adapted from Liu et al, reference 20.)

The Yanchang Formation is a thick sequence of in a pilot project to test the Mangrove workﬂow in Optimal stimulation design requires that lake and delta sediments deposited during the horizontal wells in a tight oil reservoir zone in the each stage and its perforation clusters be placed Late Triassic period. The formation consists of 10 southwest Ordos basin.20 in wellbore intervals that have a high likelihood lithologic members, named Chang 1 to Chang 10 The company drilled two 1,500-m [4,920-ft] of producing economic amounts of hydrocarbon from top to bottom. The members are stacks of parallel horizontal wells in the Chang 7 member and breaking down by fracturing in response to alternating mudstone, siltstone and sandstone lay- of the Yanchang Formation. The wells, 600 m increased pressure during stimulation. These ers that result in vertical heterogeneity. The reser- [1,970 ft] apart, were drilled in the N15°W direc- wellbore intervals possess good RQ and good CQ. voirs in the Yanchang Formation are naturally tion, which is parallel to the minimum in situ The team used the Mangrove completion advisor fractured, low-permeability sandstones in which principal horizontal stress direction in the Ordos to select 18 stages per well. porosity is typically about 10% and permeability is basin. The company drilled three vertical wells In conjunction with the completion advisor, generally 0.1 to 10 mD. The natural fractures occur 500 m [1,640 ft] apart between and along a line the team used the UFM simulator to predict HF in two sets that tend to dip steeply and generally parallel to the horizontal wells; these vertical propagation, growth and interaction with natural strike in the ENE and NNW directions.19 wells were added for microseismicity monitoring fractures (NFs) in the reservoir. Depending on To produce oil from these low-permeability (MSM) during the fracture stimulations of the the in situ stress direction and anisotropy in rela- reservoirs, an operator must stimulate the pro- horizontal wells (above). tion to the reservoir NF system, hydraulic frac- duction intervals through multistage hydraulic The pilot study team constructed 3D geologic, tures may take advantage of the NFs to produce fracturing. Historically, most production wells geomechanical and DFN models from the pilot 19. For more on the Yanchang Formation: Lianbo Z and have been vertical, and after HF stimulation, study well log data and from core descriptions Xiang-Yang L: “Fractures in Sandstone Reservoirs with their initial production rates have varied from and geologic studies in the surrounding area Ultra-Low Permeability: A Case Study of the Upper Triassic Yanchang Formation in the Ordos Basin, China,” 3 5 to 8 m /d [30 to 50 bbl/d]. In the few horizontal (next page). These models were calibrated using AAPG Bulletin 93, no. 4 (April 2009): 461–477. wells, the initial production rates after HF stimu- data from the three monitoring wells and inte- 20. Liu H, Luo Y, Li X, Xu Y, Yang K, Mu L, Zhao W and Zhou S: 3 “Advanced Completion and Fracturing Techniques in lation have averaged 32 m /d [200 bbl/d]. While grated using the Mangrove system to form the Tight Oil Reservoirs in Ordos Basin: A Workﬂow to still considered economic, these production rates bases for modeling reservoir quality, completion Maximize Well Potential,” paper SPE 158268, presented at the SPE Annual Technical Conference and Exhibition, are only marginally acceptable. To improve the quality, stimulation staging and perforation San Antonio, Texas, October 8–10, 2012. production outcomes from its stimulation pro- placement, hydraulic fracture stimulation design Yang H, Xu YG, Yang KW, Zhou SX, Liu H and Luo Y: grams, the company partnered with Schlumberger and production performance forecasting. “Optimized Treatment Design Shows Promise,” E&P 86, no. 2 (February 2013): 46–50. 21. Weng et al, reference 9.

44 Oilﬁeld Review MW1 MW2 MW3 MW1MW2 MW3 HW2 HW1 Neutron Neutron Neutron 7 Porosity Porosity Porosity (left) (left) (left) 0% 100 0% 100 0% 100 6 Bulk Density Bulk Density Bulk Density 5 Depth, m

Total Vertical Resistivity(right) Gamma Ray Resistivity(right) Gamma Ray Resistivity(right) Gamma Ray 4 Horizon Surface Horizon 7 ohm.m 617 1g/cm3 2.85 0gAPI 200 2ohm.m 2,2001g/cm3 2.85 0gAPI 200 3 ohm.m 1,700 1g/cm3 2.85 0gAPI 200 3 X,100 2

1 X,200

X,300

X,400 4

X,500

3 X,600 MW1

X,700 MW2 2 MW3

X,800 N HW2 1 HW1

> Model building for Ordos basin wells. Because there were no seismic or geologic data for the location, model building started after well logs were acquired from the three vertical monitor wells (left, MWs). Logs for each well display resistivity (Track 1), neutron porosity and bulk density (Track 2) and gamma ray (Track 3). Geoscientists began model building by extracting geologic horizon surfaces based on well-to-well correlations between the monitoring wells. Engineers used the surfaces for well placement guidance (top right) and for 3D model development (middle right) by upscaling petrophysical properties derived from well log data and filling in between the wells while honoring the horizon surfaces. Geologists created a simple discrete fracture network (DFN) model (bottom right) based on geologic studies and core descriptions. The DFN contained two dominant steeply dipping fracture sets, characterized by average strike orientations of N75°E (cyan) and N15°W (purple) and average fracture spacing of 15 m [49 ft]. The DFN was calibrated later and modified based on microseismicity data. (Adapted from Liu et al, reference 20.) complex HF networks and, consequently, high plane in the minimum principal stress direction the 3D models, UFM model and stimulation fracture surface area to make contact with the It alters the local stress magnitude and anisot- design. For the next stage, the engineers wanted reservoir. The production of complex HF net- ropy near the fracture and affects adjacent frac- to maximize the HF surface area and proppant- works is more likely when the in situ stress tures through mechanical interactions. To filled volume to obtain the best production from anisotropy is low.21 properly space HF stimulation staging, engineers the stimulated reservoir interval. MSM data sug- During the UFM modeling, the team was also must include such stress shadow effects when gested that the HFs being created tended to be concerned about determining how existing HFs calculating CQ. long and contained within the targeted Chang 7 affected the behavior of subsequent HFs. After an After selecting the stage and perforation loca- reservoir interval. HF is created and filled with proppant, the imme- tions, the team began to execute its design. While monitoring the first five to six stages, diate vicinity of the HF changes forever. The HF During stimulation operations, the team the team observed considerable overlap of micro- imposes a compressive stress component, or employed the StimMAP LIVE real-time microseismicity from neighboring stages, indicating stress shadow, that acts outward from the HF seismic monitoring (MSM) service. After each suboptimal stage spacing. The team decided to stage, the team used MSM results to recalibrate

Summer 2013 45 Rock Quality increase the spacing of stages and reduce the Good RQ and good CQ number of stages from 18 to 13 per well (left). Bad RQ and bad CQ After all 26 stages were stimulated in both Bad RQ and good CQ horizontal wells, the operator put the wells into Good RQ and bad CQ Stress Gradient production. Initial production rates were Initial Updated 103.2 m3/d [649.1 bbl/d] and 124.5 m3/d High Low Stimulation Stimulation Minimum Stress Good Bad Good Bad Stages Stages [783.1 bbl/d], a three- to fourfold improvement Gamma Ray Gradient Perforation Perforation over the average production rate of 32 m3/d from Measured Depth, m

RQ CQ Composite Cluster Cluster 0gAPI 250 0 psi/m 0.30 previous horizontal wells. After three months, the X,200 production rates from these wells stabilized and

GG Stage 18 Good Good were 50% higher than the previous best production Stage 13 from any horizontal well in the formation. Bad Bad BB

Stage 17 Stimulation by Design

GG Unconventional reservoirs provide special chal-

X,400 Good Good Stage 12 lenges because they are heterogeneous reservoirs Stage 16 composed of highly stratified sediments. Staying within a reservoir zone during horizontal drilling is Stage 15 difficult. Consequently, the wellbore intersects GG Good Stage 11 variable lithologies, which exhibit dissimilar pet- Stage 14 X,600 Good rophysical and mechanical properties. Unconventional reservoirs are also usually Stage 13 anisotropic and naturally fractured. Shales pos- Good GG Stage 12 Stage 10 sess layering caused by the horizontal alignment of finely laminated sediments and platy clay miner- Good GG Stage 11 X,800 als. This layering causes rock properties, such as GG Good Good Stage 10 permeability, elastic moduli and electrical resistiv- Stage 9 Good GG ity, to be anisotropic.22 These properties may vary more from layer to layer than within layers. Good Stage 9 Natural fractures may cut across this layering and superimpose additional anisotropy on the shales. Y,000 Good GG Stage 8 Stage 8 Good Both anisotropy and natural fractures complicate Good the propagation of hydraulic fractures.23 Stage 7 Stage 7 Recent advances in multistage stimulation tech- GG Good nology are making it possible to stimulate and Stage 6 Stage 6 develop unconventional hydrocarbon resources Y,200

GG more successfully (see “Multistage Stimulation in Good Stage 5 Stage 5 Liquid-Rich Unconventional Formations,” page 26). Good Parallel advances in the Mangrove stimulation design software are making it possible to design Stage 4 Stage 4 GG

Good completions that are more effective. Integration of Y,400 the two technologies promises a positive future for Stage 3 Stage 3 unconventional resource development. —RCNH Stage 2 Stage 2 22. For a discussion of permeability anisotropy: Ayan C, GG Good Good Colley N, Cowan G, Ezekwe E, Wannell M, Goode P, Stage 1 Stage 1 Halford F, Joseph J, Mongini A, Obondoko G and Pop J: “Measuring Permeability Anisotropy: The Latest Y,600 Approach,” Oilfield Review 6, no. 4 (October 1994): 24–35. BB Bad Bad For more on elastic anisotropy: Armstrong P, Ireson D, Chmela B, Dodds K, Esmeroy C, Miller D, Hornby B, > Completion advisor results. Engineers used the Mangrove completion advisor to compile and analyze Sayers C, Schoenberg M, Leaney S and Lynn H: “The Promise of Elastic Anisotropy,” Oilfield Review 6, petrophysical data to select fracture stages and perforation cluster locations for wells in the Ordos no. 4 (October 1994): 36–47. basin. Gamma ray (Track 1) and the minimum horizontal stress gradient (Track 2) were key parameters For more on the anisotropy of electrical properties: for the design. For the stress gradient profile, blue is high and red is low. Reservoir quality (Track 3), Anderson B, Bryant I, Lüling M, Spies B and Helbig K: completion quality (Track 4) and composite (RQ plus CQ) quality scores (Track 5) provide color-coded “Oilfield Anisotropy: Its Origins and Electrical quality indicators for stage and cluster selection. Initially, engineers proposed 18 stimulation stages Characteristics,” Oilfield Review 6, no. 4 (Track 6). After 5 stages were stimulated, engineers recalibrated the stimulation program using (October 1994): 48–56. microseismic monitoring data and, as a result, reduced the number of stages to 13 (Track 7). The blue 23. Wu R, Kresse O, Weng X, Cohen C and Gu H: “Modeling spikes (Tracks 6 and 7, left and right of stimulation stages) indicate proposed perforation cluster of Interaction of Hydraulic Fractures in Complex Fracture Networks,” paper SPE 152052, presented at the locations. (Adapted from Liu et al, reference 20.) SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, February 6–8, 2012.

46 Oilﬁeld Review