Integrated Workflow Optimizes Completion, Boosts Production in Chinese Tight Oil Well

® Originally appeared in World Oil JANUARY 2016 issue, pgs 55-58. Posted with permission. HYDRAULIC FRACTURING Integrated workflow optimizes completion, boosts production in Chinese tight oil well

ŝŝHU XIFENG and ZHANG CUNWANG, PetroChina Changqing Oil Company; PIYUSH PANKAJ, LIU PEI WU and TOBIAS JUDD, Fig. 1. Modified workflow for stage selection and hydraulic fracture design. Schlumberger Design Execution Evaluation

China’s unconventional basins hold significant quantities of Pumping schedule Perforation, Pumping optimization, in-place oil and gas, but they have been largely underdeveloped, staging design schedule geo hazard staging due to technical limitations in overcoming challenging reservoirs adjustment modification and geology. Tight oil reservoirs, featuring thin pay zones and Visualization based application Staging, perforation low permeability and porosity, have historically yielded low or and completion poor production using conventional exploration and appraisal Microseismic Completion eciency practices. Unlocking production in these plays requires tools and interpretation adjustment Modeling Future treatment, technologies that go beyond standard methodologies. based application and completion Over the past decade, technological advances have enhanced design reference the industry’s ability to tap the potential of unconventional plays, Future field Well placement both in North America and emerging markets, such as China. An Geology, development and spacing, important turning point was the realization that the heterogene- reservoir data drainage pattern and recovery ity and complexity of unconventional formations require detailed reservoir understanding. They also required the application of a disciplined and integrated workflow that can simulate or model and a treatment consisting of 100,000 lb/m to 250,000 lb/m of hydraulic fractures to optimize the completion program. proppant and a hybrid fracturing technique. China’s biggest oil production company, PetroChina, teamed In some cases, initial production (IP) rates showed marginal up with Schlumberger to successfully use the Mangrove engi- improvement, with output ranging from 30 bopd to 150 bopd. neered stimulation design in the Petrel platform software to de- However, IP rates tended to decline significantly within the first sign a completion for a multi-stage horizontal well in north-cen- three to six months. The large number of vertical wells provided tral China’s Ordos basin. This is China’s second-largest, onshore offset correlations for subsequent horizontal well development. producing basin, spanning an area of 370,000 km2 across parts of Wells typically were designed with several transverse hydraulic Shaanxi, Shanxi and Gansu provinces, and the Ningxia Hui and fracturing treatments to establish more reservoir contact and Inner Mongolia regions. The application of a real-time, microseis- achieve commercial flowrates. mic fracture monitoring tool further optimized the design and treatment execution. The integrated approach resulted in a more FIT-FOR-PURPOSE COMPLETION STRATEGY than eight-fold production increase, compared to conventionally In a pilot project aimed at optimizing production in the completed vertical wells. NP1 well, PetroChina implemented the Mangrove engineered The NP1 well is in the unconventional, oil-rich Chang 7 reser- stimulation design (MESD) software, which incorporates res- voir, underlying conventional oil layers in the Ordos basin’s Yan- ervoir characterization data and geological and geomechanical chang formation. The sandstone reservoir has stacked sand and properties to develop a fit-for-purpose completion strategy. shale deposits resulting from a series of river, delta and lake sys- The software integrates petrophysical, geomechanical, geo- tems deposited during the Triassic period. The low-porosity, low- physical and microseismic data to realistically simulate fractures permeability layers feature reservoir-quality factors that include in unconventional reservoirs, taking into account reservoir het- high quartz content, fine grain size, and depositional microfacies erogeneity and rock property variations along the lateral. The and diagenesis. The lateral extension of the formation is uniform resulting model analyzes reservoir and completion quality pa- with extensive areal distribution. It is divided into three oil layers, rameters, and automatically groups rock with similar properties with the Chang 7-1 identified as the primary target zone. and stresses into stages, to achieve the optimum distribution of Exploration and development in the Chang 7 formation be- hydraulic fractures. gan in 1996. Initial exploration and appraisal efforts involved The software’s completion advisor module uses seismic- drilling multiple vertical wells to characterize the reservoir, using to-simulation data in a range of formats, including 3D models, core data, field observations, and analysis and seismic sequence and well logs from candidate wells, offset wells or pilot wells, to interpretation. To improve production performance in the sands, characterize the reservoir and then design the completion. The operators began drilling and completing a large number of verti- software utilizes a mechanistic earth model to simulate realistic cal wells, typically with a small, single hydraulic fracturing stage, hydraulic fracture geometries for a wide range of formations.

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ing, which can be compared to simulated results to improve and Fig. 2. Selection of well stages and perforation intervals, with optimize treatments, as they are being performed. comparisons of reservoir quality with completion quality. The plan for NP1 called for landing the lateral in the Chang 7-1 section, a 20-m-thick sand layer with permeability ranging from 0.05 to 0.3 md, average porosity of 8.6% and average perme- ability of 0.1 md. A logging suite that included density neutron, resistivity, sonic dipole and spectral gamma ray sensors was de- signed to help identify the landing point for the lateral section. The 3,937-ft horizontal section was drilled along the direction of the minimum horizontal stress to ensure maximum reservoir contact with multiple transverse fractures. The MESD software integrated data from vertical wells in the field, and petrophysical and geomechanical stimulation data, into a geomechanics model to characterize the reservoir and design the completion. The model was used to simulate fracture geome- try and stage spacing, identify any high-stress intervals that could impact operations or cause a premature screen-out, and provide an understanding of reservoir variability across the lateral length to identify the sections with the best completion quality and the best production potential. To better understand the fracture geometry and lateral cover- age, the microseismic diagnostics service was integrated into the

Fig. 3. The stress gradient differential within each stage of a reservoir stimulation design to detect microseismic events trig- perforation cluster. gered by the stimulation treatment. Historically, microseismic measurements have not been processed until after the stimulation 0.06 pumping phase. The StimMAP hydraulic fracturing mapping Stress gradient dierential service monitors hydraulic fractures as they are created, acquiring 0.05 and processing data in real time, so that engineers can make im- mediate adjustments to the stimulation plan, based on interpreta- tion of the data along with the analysis of treatment parameter. 0.04 COMPARING RESERVOIR, COMPLETION QUALITY The completion strategy for the NP1 well called for multi- 0.03 stage hydraulic fracturing, a practice that has become essential for commercial production in most low-permeability unconvention- 0.02 al reservoirs. In this case, 14 stages, a normal stage count for the region, were designed for the lateral. The workflow was divided into two parts, the first involving the integration and modeling of 0.01 various data sources. The second part included the field execu- Stress gradient, psi/ft tion phase, which combined the dynamic data obtained during 0.00 fracturing and then used the data to update the treatment well model to optimize subsequent stage designs, Fig. 1. Each perforation and fracturing stage was designed, based on –0.01 reservoir quality (physical characteristics, such as porosity, satu- ration and permeability) and completion quality (stress profile). Both of these are critical for stage optimization, to ensure that the –0.02 entire horizontal section is uniformly covered, and maximum reservoir contact is achieved. Stress and rock properties also can –0.03 impact the effectiveness of the stimulation treatment. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 The combination of reservoir quality with completion quality Stage number created good-good (GG), good-bad (GB), bad-good (BG) and bad-bad (BB) flags for the well. For example, GG indicates the The fracture models in the software can estimate proppant rock has good hydrocarbon content and is also easy to fracture, placement, fracture network dimensions, and reservoir penetra- making it a good candidate for development. GB suggests the hy- tion, based on fluid rheology, leak-off pressure, friction perfor- drocarbon content is good, but is difficult to fracture, meaning mance, reservoir permeability and closure stress. Automated it may be a good target economically, but will be operationally gridding mechanism in the software honors the granularity of the difficult to complete. BG refers to rock that is easy to fracture, but fracture geometry and ties it directly to the reservoir simulation has little or no hydrocarbon content, and should be avoided. BB for production estimation. The software also facilitates the acqui- means there is no hydrocarbon content and the rock is also dif- sition of real-time data, including microseismic fracture monitor- ficult to fracture.

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The combination, referred to as composite quality flag, was then used to develop an overall quality index for staging and per- Fig. 4. Observed microseismic event distribution for all the foration placement on the NP1 well, Fig. 2. The objective was to hydraulic fractures on each stage. move from the conventional strategy of geometrically, or evenly, spaced stages that may target uneconomical parts of the reservoir, to a tailored approach that targets similar reservoir properties for each stage to achieve a more economically viable scenario. The well was completed with a 5½-in. cemented liner across the reservoir section. As is customary for most horizontal wells in China, the stage-by-stage hydraulic fracturing operation involved the use of a tubing-conveyed packer, for zonal isolation, and an abrasive perforating technique that cuts holes in the casing to pro- vide access between the wellbore and the reservoir, itself. This is in lieu of the plug-and-perf method commonly used in the U.S., whereby plugs are used for isolation and explosive guns are con- veyed downhole for perforation. Each stage consisted of two perforation clusters placed in areas of similar stress, based on the wellbore geomechanics model, Fig. 3. Sections with poor cement quality, or where there was a risk of perforating across a casing collar, were avoided. Based on field data and experience in the area, the pumping rate for each cluster 3 was increased to more than 3 m /min. to ensure that proppant Fig. 5. The pumping schedule adjustments for all 14 stages, in could be transported along the fracture length and result in ad- terms of designed versus actual values, for pad percentage and equate fracture conductivity. total fluid volumes. 30 900 Pad design OPTIMIZING JOB DESIGN, EXECUTION 3 Pad actual 750 25 Fluid volume design While optimizing the job design through the engineered Fluid volume actual stimulation process, PetroChina also was able to optimize the 20 600 job execution and the fluid package, improving the fracturing de- 15 450 sign as each stage was treated. Based on the Chang 7-1 formation Pad, % properties, the presence and quantity of natural fissures, poten- 10 300 tial risk and complications from excessive height growth and the 5 150 offset-well experience, a hybrid fracturing technique, incorporat- Pumped fracturing fluid volume, m ing the benefits of fracturing fluid cleanup, was selected for the 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 well. Good fracturing fluid clean-up is essential for maximizing Stage number well deliverability and effective fracture half-length in low-perme- ability, low-pressure reservoirs. works as they were being created, the service was able to optimize The hybrid treatment used a low-viscosity fluid for the pad the treatment. Based on the microseismic results for a particular stage, where fluid is pumped before the sand to open up the rock stage, including observations of unanticipated fracture geometry, and create a crack in the formation for the proppant. A higher- the model was updated, and the treatment for subsequent stages viscosity low-polymer, refined guar system with borate cross- was modified by changing the perforation depth, pumping sched- linked fluid was used for proppant transport and placement for ule, fluid type, treatment rate or job size. These modifications en- high fracture conductivity. After each stage, the gel was allowed sured fracture coverage of the entire lateral section. to break, and the zone was flowed back immediately for clean-up. In most cases, the actual volumes pumped were similar to the Based on local experience, the moderate depths and in-place designs. However, during the pumping of Stage 6, the microseis- stress calculations, resin-coated proppants of two mesh sizes were mic results observed during the pad stage indicated that the frac- selected to create a high-permeability pathway for the hydrocar- ture had opened only in the near-wellbore area. The fracture half- bons to flow from the formation with minimal restriction. A stage length was shorter than initially designed, due to fluid loss to the of 100-mesh sand decreased perforation and/or near-wellbore surrounding natural fractures. In an attempt to increase the frac- friction effects, and prevented excessive leakoff to the natural frac- ture half-length and the reservoir contact area, the pad stage was tures, reducing the risk of a premature screen-out or job termi- extended by 415 bbl. The fracture half-length increased, however nation. The subsequent main stage included 40/70 mesh resin- the pad volume was extended again, by 130 bbl, due to concerns coated sand to minimize the risk of early bridging and improve about placement of the main fracturing treatment. The pad vol- transport. The final proppant stages included 20/40 mesh, resin- ume, including the original design and the two contingency stage coated sand to increase near-wellbore conductivity. volumes, was pumped continuously, with the primary placement To further optimize the treatment designs, microseismic mon- of 157,500 lb/m of proppant. itoring and real-time fracture modeling updates were performed, Fig. 4. The fracture geometry for each stage was obtained by MODIFYING THE TREATMENT matching the observed net pressure of the treatment with the Real-time microseismic measurements also were used to ad- mapped fracturing dimensions. By mapping the fracture net- just the perforation distance between stages, to achieve good

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mized with integration of a broad range of subsurface informa- Fig. 6. Accumulated oil production for NP1 well. tion, which is highly beneficial in improving the understanding 70,000 of fracture behavior. By incorporating microseismic information in the design pro- 60,000 cess, the multi-discipline team could make better-informed deci- 50,000 sions and real-time adjustments to optimize the treatment. The optimized fracture design also relied on reservoir characteristics, 40,000 taking into account the injection volume and rate, proppant prop- erties and treatment size. 30,000 In this case, gathering data early in the horizontal well ap- 20,000 praisal process gave PetroChina the opportunity to positively

Accumulated oil production, bbl impact the field development, and apply the gained knowledge 10,000 about model calibration in terms of well spacing and completion 0 scenarios. Additionally, the hydraulic fracturing techniques used 0 200 400 600 800 1,000 1,200 for NP1 can be applied to future horizontal wells in other areas of Time, days the reservoir. The successful use of fracture treatments, flowback and post-fracture production in the model calibration has paved separation between each fracture treatment stage while including the way for the simulation model to be used to study production the previously acquired information on fracture azimuth and ex- sensitivities for future treatment parameters and well configura- tent. It was important to understand the stress gradient differen- tions, orientation and spacing. tial within each stage, to ensure that each cluster within each stage ACKNOWLEDGMENT was stimulated equally. This article is derived from SPE paper 167062, “An integrated disciplinary approach toward hydraulic Based on the microseismic data, 11 of 14 states were adjust- fracturing optimization of tight oil wells in the Ordos basin, China.” It was originally presented at the SPE ed during the operation, Fig. 5. After Stage 11 was pumped, Unconventional Resources Conference and Exhibition-Asia Pacific, Brisbane, Australia, Nov. 11-13, 2013. the microseismic data were reviewed and used to change the perforation locations for Stage 12, and optimize the distance HU XIFENG is the senior engineer and exploration department manager for PetroChina Changqing Oil between adjacent stages. The final microseismic events for Company. He is in charge of various operations, Stages 11 and 12 indicated that the perforation spacing avoid- including drilling, well testing and stimulation ed overlaps between fracturing treatments and ensured that technology. Mr. Hu has more than 15 years of technical experience. He holds an MS degree in structural geology the lateral section was stimulated effectively with the designed engineering from Northwest University, Xi’an, China. volume of proppant. After all the adjustments, the final microseismic results of the ZHANG CUNWANG works for the exploration department at PetroChina Changqing Oil Company. He 14 fracturing stages showed that strong and credible event loca- is in charge of various operations, and mainly focuses on tions, along with reservoir data, were critical in making real-time reservoir stimulation research and well testing intervention decisions. High-stress intervals were avoided when operations management. Mr. Zhang has more than eight years of oilfield operation experience at PetroChina. He designing the perforation stages to further minimize the risk of holds an MS degree in mineralogy engineering from operational failure. Perforation placement, regarding the stress Northwest University, Xi’an, China. profile and the microseismic results, was especially critical for TOBIAS JUDD is the reservoir and production Stages 7–11. engineering business manager for Schlumberger The integrated approach resulted in the NP1 horizontal well Integrated Solutions, based in Houston. Previously, he producing 755 bopd, an eight-fold increase in IP compared to served as stimulation domain manager for Schlumberger PetroTechnical Engineering in Beijing, China. He has vertical IP well production. The workflow helped PetroChina to more than 15 years of technical experience, focused on better determine where, when and how to deploy hydraulic frac- reservoir stimulation and production enhancement in various locations worldwide. He holds a BS degree in chemical turing in the lateral section of the well, resulting in increased, and engineering from the University of Colorado and an MBA from RSM more evenly distributed, stimulated volume along the lateral sec- Erasmus University in Rotterdam, The Netherlands. tion. Thus, production and pressure have not declined as quickly PIYUSH PANKAJ is the production solutions as they did for vertical wells completed with a single stage. technologist for Schlumberger, based in Houston. He Based on the accumulated production profile, the deliverabil- has more than nine years of experience in the ity of the NP1 well remains a constant slope, which is indicative international oil and gas industry. He was previously the Mangrove product champion, and served in various of the reservoir outflow not being exceeded by the well’s flowing engineering and technical roles in India and the U.S. Mr. condition, with the multiple hydraulic fractures being effective in Pankaj has developed expertise in unconventional draining the targeted reservoir area. At approximately 465 days, completion and hydraulic fracturing techniques. He holds a BT degree in the slope of the accumulated production changes, but this was petroleum engineering from Indian School of Mines, Dhanbad, India. due to a well intervention operation, Fig. 6. LIU PEI WU is the senior production stimulation In a mature field, where vertical well development has been engineer for Schlumberger, based in Beijing. He has more than seven years of operational and technical standard practice, application of the unique workflow for well experience in the oil and gas industry of China. Mr. Liu is design and real-time microseismic fracture monitoring in this experienced in conventional/unconventional completion initial horizontal well helped to gain valuable understanding of and hydraulic fracturing technology, and has been involved with various stimulation projects in China. He hydraulic fracturing and well production. The results showed holds an MS degree in petroleum engineering from Southwest that a hydraulic fracturing completion strategy can be opti- Petroleum University, Chengdu, China. Article copyright © 2016 by Gulf Publishing Company. All rights reserved. Printed in U.S.A. 58 JANUARY 2016 / WorldOil.comNot to be distributed in electronic or printed form, or posted on a website, without express written permission of copyright holder.