Flow-Channel Fracturing Raises Production in the Eagle Ford

September 2015 SHALETECH REPORT New technologies and best practices for shale refracturing

On a warm summer evening in South Texas, a Schlumberger hydraulic fracturing fleet works at an Eagle Ford shale wellsite south of San Antonio. Image: Schlumberger.

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PUBLISHED IN SEPTEMBER 2015 ® Originally appeared in World Oil SEPTEMBER 2015 issue, pg 4-7. Used with permission. SHALETECH REPORT

Flow-channel fracturing raises production in the Eagle Ford

Deck over a multi-year period. Findings document that wells stimu- lated with this technique perform better than those stimulated with conventional treatments short-term, and, more significant- ŝŝByline ly, over an extended period of time. The incremental produc- tion, and the savings realized by the reduced use of water and proppant, have translated into billions of dollars of enhanced Body Copy value for Eagle Ford operators. Hydraulic fracturing relies on filling a fracture with prop- pant, to create a continuous proppant pack. The proppant pack stabilizes and holds the fracture open, providing a porous medi- um through which hydrocarbons can flow, from the formation to the well. The technique, which has been used by the industry for decades, emerged from its niche about 20 years ago, when it was adapted for multistage horizontal fracturing operations in low-permeability reservoirs, such as shales and tight sandstone and carbonate fields across North America. Over the years, the industry has improved hydraulic fractur- ing technology through the development of sophisticated, ro- bust proppant materials and water-based fracturing fluids, from Studies in the Eagle Ford shale show that low-viscosity (slickwater) to highly viscous, polymer-laden flow-channel fracturing delivers gains in cross-linked fluids and hybrid formulas. Fluid formulations are oil and gas production and recovery while tailored to promote proppant transport and placement through- reducing water and proppant usage. out the fractures that are induced hydraulically to render them conductive for oil and gas. The introduction of chemical break- ers further improved conductivity by decomposing molecular ŝŝJOHN THOMPSON and ALEJANDRO PEÑA, Schlumberger structures that thicken the fluids and reduce the amount of resi- due left in the fracture. Despite these developments, significant technical opportu- nities remain for stimulation treatments being pumped today, In the five years since the industry first set its sights on the for unconventional hydraulic fracturing operations. It has been Eagle Ford shale, the play has emerged as one of the world’s understood, and agreed by the industry, that only the effective most prolific oil- and gas-producing regions, with thousands portion of the fracture (or stimulated reservoir volume) mat- of horizontal wells now operating across a wide swath of South ters to production and well performance. Rigorous production Texas. Advances in hydraulic fracturing methods have been piv- modeling exercises indicate that only 30% to 40% of the aver- otal to this success. Among the most important innovations is age hydraulic fracture length that is created contributes to pro- a hydraulic channel-fracturing technique that creates a network duction, in most cases. Conventional fracturing treatments and of open channels, or pathways, inside the fracture, optimizing techniques have limited capacity to transport proppant across connectivity to the reservoir and significantly improving frac- the fractured networks. Most proppant accumulates near the ture conductivity while using less proppant and water. wellbore region. Many fractures that are open initially, beyond The HiWAY flow-channel fracturing technique has proved the near-wellbore area, eventually close, due to lack of proppant to be highly effective in unlocking the Eagle Ford, starting with placed within. Also, as hydrocarbons are drained, closure pres- a single well in 2010 that is still producing today. That initial sure on the fractures increases, and the effective conductivity of success has since been repeated in more than 1,000 liquid- and the fractures diminishes as the proppant packs are compressed. gas-producing wells in the Eagle Ford, which have provided well Recognition of those limitations led to the application in un- production data for a unique and far-reaching study, conducted conventional reservoirs of flow-channel fracturing, which is based on the concept that proppant can be: a) transported more effec- More than 90% of fracturing operations currently performed by tively across the fractured network with the use of fibers; and b) Schlumberger in the Eagle Ford shale apply the HiWAY flow- placed discontinuously, or intermittently, to engineer a network channel fracturing technique with the goal of increasing well production, making more effective use of proppant and water. of open channels within the proppant pack, itself. This technique Image: Schlumberger. provides a highly conductive pathway for the flow of fluids, which

S–4 SEPTEMBER 2015 / ShaleTech Report SHALETECH REPORT renders higher residual effective fracture conductivity over time. ers. The predominantly calcareous formation has a carbonate The approach had been used previously to stimulate vertical wells rock content greater than 70%, and clay content of about 10%. in conventional sandstone reservoirs, and to improve production in vertical wells, in heterogeneous tight gas reservoirs. FROM SLICKWATER TO FLOW-CHANNEL FRACTURING ENHANCED TRANSPORT/NON-UNIFORM One of the earliest, and most active, production areas in the PLACEMENT Eagle Ford is Hawkville field, a predominantly limestone sec- In 2010, Schlumberger introduced the HiWAY flow-channel tion with 100 to 600 nanodarcy permeability and 7% to 10% fracturing technique, after five years of laboratory and field test- total porosity. Nearly all of the initial stimulation treatments ing for its qualification. Job execution and well performance in the field were done with slickwater, with an average of 12 data, from thousands of wells worldwide, show that the ap- stages pumped per well. Each stage involved pumping at high proach results in average initial and long-term well productivity, rates, typically 60 bbl-to-100 bbl/min., between 13,000 bbl and and flowing pressures that consistently meet or exceed those of 18,000 bbl of low-viscosity fracturing fluid, and 200,000 lb to wells stimulated with conventional treatments. Experience also 400,000 lb of natural sands at concentrations of 0.5 lb to 3 lb of shows that this technique contributes to a low occurrence of proppant added per gal (ppa). near-wellbore screen-outs, or early job terminations, as it miti- As laterals in the Eagle Ford became longer, operators began gates excessive accumulation of proppant in the near-wellbore implementing hybrid treatments, which delivered modest produc- area, and enhances transport of proppant within the formation. tion enhancement, but reduced fluid volumes per well significant- The flow-channel fracturing treatment fundamentally ly over slickwater treatments. An average 16 stages per well were changes the way proppant fractures generate conductivity by stimulated, each stage requiring 6,500 bbl to 8,500 bbl of fluid, and promoting the formation of stable voids within the proppant 200,000 lb to 400,000 lb of natural sands at 0.5 ppa to 4 ppa. pack. These voids serve as highly conductive channels, for The first application of the flow-channel fracturing technique transporting oil and gas throughout the fracture. Instead of in the Eagle Ford shale was in October 2010, on a horizontal dry flowing through the proppant pack, the hydrocarbons move gas well in Hawkville field, in LaSalle County near Cotulla, Texas through the channels, between pillars of proppant that are cre- (well Heim 2H, API # 42-283-32314). In a comparison study, ated, resulting in an infinite degree of flow capacity. with three offset wells stimulated with slickwater that were identi- The key to the technique’s effectiveness is the use of non- fied prior to the treatment of this well, as a reference for perfor- uniform proppant placement, achieved by implementing a mance, the flow-channel fractured well has demonstrated mark- pumping protocol whereby proppant-laden fluid, or slugs, and edly better production performance over a 4.5-year period, Fig. 1. proppant-free fluid are delivered in alternating, short pulses. The subject well has rendered over 4 Bcf, whereas the refer- Throughout the operation, degradable fibers are added to miti- ential offsets have rendered about 2.5 Bcf over such period. A gate the dispersion of the proppant-filled pulses, as they move modeling study normalizing results from these wells over their throughout the surface equipment and casing, along the lateral first six months of production rendered a 51% average increase and throughout the fractures. in output.1 Importantly, this well was treated with the lowest The fibers also strengthen the system’s proppant-moving ca- amount of water, and with less proppant than one of the offsets. pacity, by transporting the proppant farther into the formation and reducing its settling within the fracture, a phenomenon that 50-WELL STUDY can result in narrow fracture width, and a reduction in the num- Based on the success of the initial trials, a subsequent 50-well ber and quality of the channels. This capability maintains the comparative field study was launched, between October 2010 heterogeneous placement of proppant and optimizes vertical and February 2011, over a broader section of Hawkville field coverage of the fracture. Intermittent pumping of the proppant- encompassing LaSalle and McMullen counties. In this case, 30 free and proppant-filled slugs also provides the dual benefit of reducing the amount of proppant, and preventing proppant from accumulating in the near-wellbore area, mitigating the risk Fig. 1. Cumulative gas production after a 4½-year period of the first horizontal flow-channel fractured well in the Eagle Ford of screen-outs. shale, compared with Offsets A, B and C. Image: Schlumberger, The introduction of the flow-channel fracturing technique data source Ref. 1 and IHS Enerdeq. occurred at the same time as the Eagle Ford shale was starting First horizontal well using HiWAY flow-channel fracturing to be developed. The play sits in an Upper Cretaceous forma- technique, Heim 2H, La Salle County, Texas, October 2010 tion, which extends about 50 mi wide and 400 mi long, from the 4.5 Maverick basin and San Marcos Arch to the East Texas basin. 4.0 ■ Heim 2H 3.5 ■ Oset A The region is geologically heterogeneous, with the northern ■ Oset B 3.0 regions rich in liquids, while the section to the south features ■ Oset C predominantly gas reservoirs. The play is situated between the 2.5 Austin Chalk and the Buda limestone, and is the source rock for 2.0 the Austin Chalk, and East Texas oil and gas fields. 1.5

Shale depths range between 2,500 ft and 14,000 ft, with Cumulative production, Bcf 1.0 thicknesses from 20 ft to 500 ft. The thickest section, in the 0.5 Maverick basin toward the U.S.-Mexico border, is defined by a 0.0 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 lower layer with a higher organic content, and an upper layer Time, years that is not as porous and features higher calcite content sub-lay-

World Oil® / SEPTEMBER 2015 S–5 SHALETECH REPORT wells had been treated with a slickwater fracturing method, eight with a Gaussian log-normal distribution, as evidenced by rela- had been completed with a hybrid method, and 12 wells were tively good linear correlations in the log-probability plot shown stimulated, using the flow-channel fracturing technique. The in Fig. 2 for one-year cumulative production. The progression of wells, a mix of dry gas and gas condensate, provided a statistically datasets from left (slickwater) to middle (hybrid) to right (flow- significant representation of early production rates over a 90-day channel fracturing) indicates improved overall performance period, and were later assessed over a one-year period, Fig. 2. by completion technique from worst to best, in that order. The In both cases, the ratios of cumulative production per unit of same trends were observed at 90 days.1 Importantly, the average lateral length, fracturing fluid volume and proppant usage were cumulative production at 90 days, for the wells completed with included, to take into account the relative effects of the comple- the flow-channel fracturing technique, was 32% and 67% higher tion and stimulation techniques. Throughout the study, average than those of the datasets for hybrid and slickwater completions, production was consistently higher for the flow-channel frac- respectively. After one year, such differences had increased to tured wells, both when looking at overall production, and also 34% and 91%, respectively. Therefore, the flow-channel fractur- when the numbers are normalized by lateral length, and by the ing technique mitigated production decline more effectively than amount of water and proppant usage. conventional techniques, leading to higher oil and gas recovery. For all completion techniques, a distribution of cumulative On average, the wells completed with the flow-channel frac- production results was observed, for which the data were ana- turing technique required the least amount of proppant and wa- lyzed probabilistically. All samples exhibited good correlation ter, with respect to wells completed with conventional hybrid or slickwater methods. The technique enabled more efficient utilization of re- Fig. 2. Cumulative hydrocarbon production for 50 wells stimulated in Hawkville field. sources for these hydraulic fracturing Image: Schlumberger, data source Ref. 1 and IHS Enerdeq. operations. 1.8 2 Rigorous single-well modeling studies ■ 34% 91% 5 HiWAY technique 1.6 ■ HiWAY technique performed on Eagle Ford wells, includ- ■ Hybrid ■ Hybrid 10 ■ Slickwater 1.4 ■ Slickwater ing several wells from the studies referred 20 1.2 30 to above, show that enhanced effective

40 production, Bcfe 1.0 50 fracture half-length increases by more 60 0.8 70 32% 67% than 30%, and fracture conductivity in- 80 0.6 creases by more than 40% with the use of Cumulative probability 90 0.4 the flow-channel fracturing technique.2 95

Average cumulative 0.2 98 These benefits are consistent with im- 0.0 0.1 0.5 1.0 2.0 3.0 90 days 1 year proved proppant transport, due to the 1-year cumulative production, Bcfe use of fibers and heterogeneous proppant placement, enabling a secondary, but dominant, conductivity mechanism— Fig. 3. Plot showing widespread utilization of the HiWAY flow-channel fracturing technique in the Eagle Ford. The amount of wells completed with the HiWAY technique in this flow through open channels within the 3,4 shale play now numbers over 1,000 and shows increased production, with more efficient hydraulic fracture. With better prop- utilization of water and proppant. Image: Schlumberger, data source IHS Enerdeq. pant distribution within the reservoir and Eagle Ford Shale: Basin case study for HiWAY flow-channel fracturing technique much higher initial average conductivity, Direct production comparison for HiWAY flow-channel fracturing technique and with the same percentage of conduc- wells with 12 months of production required 32% less water volume and tivity reduction during the production 1,000 37% less proppant volume ■HiWAY technique (621 wells) 10 period, output from wells fractured with ■Conventional (6,074 wells) 800 9 ■HiWAY technique (621 wells) 33% 8 ■Conventional (6,074 wells) the flow-channel fracturing technique 600 716 7 holds up longer, which generates better 6 –37% 38% –32% Guadalupe 537 5 5.4 Gonzales long-term well performance, and oil and 400 460 4

Average boed 4.9 Bexar Lavaca gas recovery. Kinney Uvalde 334 3 Medina 200 2 3.3 3.4 per well, MMgal and MMlb 1 Wilson 0 0 EXPANDING THE ANALYSIS 3 months 12 months Average fluid and proppant volumes Fluid volume Proppant volume The evaluation of the flow-channel DeWitt Zavala Frio Atascosa fracturing method has expanded into a field-wide study, to include production Maverick Karnes Goliad performance and treatment size from LaSalle a public database that comprises more than 11,000 horizontal wells between Dimmit October 2010 and December 2014. Live Oak McMullen One study involved a direct compari- son of the best three-month barrels of oil

Webb equivalent per day (B3 boed) and the best HiWAY technique5.3 12-month (B12 boed) production per- Conventional 4.1 formance, on 621 flow-channel fractured wells and 6,074 conventional wells, to

S–6 SEPTEMBER 2015 / ShaleTech Report SHALETECH REPORT assess both the short-term and long-term effectiveness of the flow- Fig. 4. Estimated 40% incremental production realized by pumping HiWAY technique versus conventional treatments on channel fracturing method, compared to conventional treatments. 1,024 wells. Image: Schlumberger, data source IHS Enerdeq. These are all the wells listed in the database with at least 12 months of production. 50 MMboe incremental production in 3.75 years, due to implementation of flow-channel fracturing on 1,024 EFS wells The flow-channel fractured wells outperformed the conven- 200 tional wells, short-term, by 33%, with an average 716 B3 boed, 180 160 ■ HiWAY technique as compared to an average 537 B3 boed. The flow-channel frac- 140 ■ Conventional tured wells also outperformed conventional wells in the long 120 term, averaging 460 B12 boed, 38% more than the conventional 100 80 wells, which averaged 334 B12 boed. In regard to water and 60 proppant utilization for the same sample, wells completed with Production, MMboe 40 20 the flow-channel fracturing technique utilized 32% less water 0 and 37% less proppant than those completed using convention- Oct 2010 Feb 2011 Jun 2011 Oct 2011 Feb 2012 Jun 2012 Oct 2012 Feb 2013 Jun 2013 Oct 2013 Feb 2014 Jun 2014 al fracturing methods, Fig. 3. Dec 2010 Apr 2011 Aug 2011 Dec 2011 Apr 2012 Aug 2012 Dec 2012 Apr 2013 Aug 2013 Dec 2013 Apr 2014 A different type of analysis was conducted to highlight the Time, months overall incremental impact that the flow-channel fracturing method has on production and revenue. This study involved Fig. 5. Estimated water and proppant volumes saved on 1,146 1,024 HiWAY wells and 8,566 conventional wells over a 3¾-year HiWAY wells in 4¼-years would allow for an additional 564 to 730 HiWAY wells to be completed (based on water and proppant period (October 2010 to June 2014). These included oil, gas con- saved, respectively). Image: Schlumberger, data source IHS densate and dry gas wells. The year-on-year average production Enerdeq. difference shows the flow-channel fracturing method performed 2.68 billion lb of proppant saved by implementing 40% better than conventional treatments. During this period, the flow-channel fracturing over the past 4.25 years 1,024 flow-channel fractured wells produced 176 MMboe. 8 Had these wells been treated conventionally, the estimated 7 ■HiWAY technique cumulative production would have been 126 MMboe. This 6 ■Conventional equates to an incremental 50 MMboe, due to the implementa- 5 tion of flow-channel fracturing. The incremental production 4 generated an additional $2.9 billion, or 37%, increase in gross 3 revenue—$10.6 billion for flow-channel fractured treatments Proppant, billion lb 2 versus $7.8 billion for conventional treatments, Fig. 4. 1 In a more extensive evaluation to assess water and proppant us- 0 age, Schlumberger looked at well data over a 4¼-year period, from Oct 2010 Apr 2011 Oct 2011 Apr 2012 Oct 2012 Apr 2013 Oct 2013 Apr 2014 Oct 2014 October 2010 through December 2014. Overall, flow-channel Jan 2011 Jul 2011 Jan 2012 Jul 2012 Jan 2013 Jul 2013 Jan 2014 Jul 2014 Dec 2014 Time, months fractured wells used 39% less proppant and 33% less water com- pared to conventionally-treated wells. This led to savings of 2.7 2.06 billion gal of water saved by implementing flow-channel fracturing over the past 4.25 years billion lb of proppant and 2.1 billion gal of water on 1,146 flow- 7 channel fractured wells. The savings in fluid and proppant use al- 6 ■HiWAY technique lowed completion of 564 to 730 additional flow-channel fractured ■Conventional 5 wells from water and proppant savings, respectively, Fig. 5. These Eagle Ford studies comparing the performance of flow- 4 channel fracturing with conventional stimulation methods pro- 3 vide a comprehensive and long-term analysis that goes far beyond 2 the scope of typical production performance studies. The in- Water, billion gal 1 depth analysis paints a compelling picture, demonstrating the ef- 0 fectiveness of the flow-channel fracturing technique to optimize Oct 2010 Apr 2011 Oct 2011 Apr 2012 Oct 2012 Apr 2013 Oct 2013 Apr 2014 Oct 2014 reservoir connectivity and enhance both short- and long-term Jan 2011 Jul 2011 Jan 2012 Jul 2012 Jan 2013 Jul 2013 Jan 2014 Jul 2014 Dec 2014 production while reducing environmental footprint through re- Time, months duction of proppant and water requirements. The flow-channel fracturing method has expanded to other 3. Gillard, M., O. Medvedev, A. Peña, A. Medvedev, F. Peñacorada, and E. d’Huteau, “A unconventional U.S. and international shale plays, enabling the new approach to generating fracture conductivity,” SPE paper 135034, SPE Annual use of local sands instead of more costly proppants for effective Technical Conference and Exhibition, Sept. 20–22, 2010. 4. Medvedev, A., K. Yudina, M.K. Panga, C. Kraemer, and A. Peña, “On the mechanisms well stimulation. The technique has also expanded to comprise of channel fracturing,” SPE paper 163836, SPE Hydraulic Fracturing Conference, Feb. use of low and high viscous fluids that can be formulated with all 4–6, 2013. practical water sources. ACKNOWLEDGEMENTS REFERENCES The authors thank Schlumberger and IHS Enerdeq for permission to publish this work. 1. Rhein, T., et al, “Channel fracturing in horizontal wellbores: The new edge of stimula- They would also like to thank Chelsea Higgins, Rohann Jose, Andrew Acock, Li Fan, tion techniques in the Eagle Ford formation,” SPE paper 145403, SPE Annual Techni- Sijuola Odumabo, Garrett Lindsay, Anup Viswanathan, Raphael Altman, Chad Kraemer cal Conference and Exhibition, Oct. 30–Nov. 2, 2011. and Dmitry Oussoltsev for their significant technical contributions to the Eagle Ford 2. Altman, R., et al, “Understanding the impact of channel fracturing in the Eagle Ford case study referenced in this article. shale through reservoir simulation,” SPE paper 153728, SPE Latin American and Caribbean Petroleum Engineering Conference, April 16–18, 2012.

World Oil® / SEPTEMBER 2015 S–7 JOHN THOMPSON is a technical advisor for Schlumberger PetroTechnical Geoscience & Petroleum Engineering Services in North America, based in College Station, Texas. He has 30 years of industry experience with production, completion, and stimulation optimization in conventional and unconventional reservoirs. Mr. Thompson has authored/ co-authored more than 20 technical publications in his career. His focus in recent years has been on integrated reservoir projects in shale basins, encompassing single-well to field-wide studies, to optimize field development and maximize the value of the operations. Mr. Thompson holds a BA degree in marketing and management from Southwest Texas State University and a BS degree in petroleum engineering from Texas A&M University.

DR. ALEJANDRO PEÑA is the integrated completion services manager for Schlumberger, overseeing the global development, integration and implementation of well stimulation technologies. These include breakthrough hydraulic fracturing technologies for efficient and responsible recovery of hydrocarbons from unconventional reservoirs. He previously held operational, engineering and technology management positions with Schlumberger in South and North America. Dr. Peña is an inventor with nine granted patents, and he has authored 30 publications on interfacial phenomena and reservoir stimulation technologies. He holds a BS degree in chemical engineering from Universidad de Los Andes, and earned his PhD in chemical engineering from Rice University in Houston, Texas, where he attended as a J. W. Fulbright scholar.

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