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flowback
Optimizing Choke Operations in Shale Gas Horizontal Wells: A Comprehensive Study
Guo, Wei (PetroChina Research Institute of Petroleum Exploration and Development (RIPED)) | Yang, Zhanrong (Xi’an Shiyou University) | Dong, Zhenzhen (Xi’an Shiyou University) | Zhang, Xiaowei (PetroChina Research Institute of Petroleum Exploration and Development (RIPED)) | hou, Tong (Xi’an Shiyou University) | Zou, Lu (PetroChina Research Institute of Petroleum Exploration and Development (RIPED)) | Li, Weirong (Xi’an Shiyou University) | Gao, Jinliang (PetroChina Research Institute of Petroleum Exploration and Development (RIPED)) | Liu, Yuyang (PetroChina Research Institute of Petroleum Exploration and Development (RIPED)) | Kang, Lixia (PetroChina Research Institute of Petroleum Exploration and Development (RIPED)) | Lin, Keze (China University of Petroleum (Beijing))
Abstract The efficient development of shale gas reservoirs relies heavily on multistage fractured horizontal wells (MFHWs). Post-fracturing flowback is a crucial phase bridging hydraulic fracturing and production, and it significantly impacts the effectiveness of both fracturing and production. During the stage of hydraulic fracturing fluid flowback, the flowback timing and rate, whether it occurs too quickly, too slowly, too early, or too late, can result in premature fracture closure and reservoir contamination. which can significantly impact long-term production. Investigating the flow conditions of this gas-water two-phase flow in reservoir and wellbore and proppant flow is crucial for choke size optimization in the efficient development of shale gas wells. This paper takes into full consideration the dynamic flow of the choke, wellbore, and reservoir, establishing a comprehensive integrated model. Through iterative processes involving the drawdown pressure from the choke to the wellhead and then to the reservoir, this integrated model calculates the maximum flowback rate that ensures no proppant flowback. Consequently, it establishes a dynamically adjustable choke management strategy. The study area is the Da’an Block in the Sichuan Basin. Optimization of the choke operation strategy was carried out under varying conditions of fracture permeability, fracture length, and fracture water saturation, resulting in a significant increase in gas production from shale gas wells. This paper identifies key factors influencing choke management in shale gas wells, providing technical support for on-site optimization of choke sizes. This research holds practical significance for the efficient development of shale gas reservoirs. Introduction Shale gas, as an efficient unconventional hydrocarbon resource, has gained significant industrial attention. The advancements in horizontal well drilling and staged fracturing techniques have established the foundation for the successful exploitation of shale gas. Chokes are necessary in every wellhead completion for regulating flow from the reservoirs. Analysis and selection of choke size for multistage horizontal fractured wells (MHFWs) is imperative for production optimizations of shale gas wells in reservoir management. (Wijaya et al., 2020; Gidado et al., 2023)
- Asia > China (0.88)
- North America > United States > Texas (0.46)
- Asia > Middle East > UAE (0.28)
Using Foam Treatments to Control Gas-Oil Ratio in Horizontal Producing Wells at Prudhoe Bay
Davis, T. (Hilcorp Alaska LLC, Anchorage, AK, USA) | Monette, M. (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX, USA) | Nelson, J. (Hilcorp Alaska LLC, Anchorage, AK, USA) | Mayfield, C. (Hilcorp Alaska LLC, Anchorage, AK, USA) | Cunha, K. (Hilcorp Alaska LLC, Anchorage, AK, USA) | Nguyen, Q. (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX, USA)
Abstract Production at Prudhoe Bay is constrained by gas handling. The objective of this project was to develop a foam injection strategy to reduce gas mobility in producing wells and increase field oil production through reduction of producing gas-oil ratio. Aqueous foam has been extensively studied through laboratory and field experiments for gas mobility control to improve sweep efficiency in gas flooding. However, the potential of foam injection into horizontal producers for mitigating unwanted gas production has not been well understood. In this work, a unique design of laboratory experiments was developed to optimize surfactant formulation for foam generation and stability under the conditions of target gas saturated zones in the Ivishak sandstone reservoir. Gas blocking capacity for different foam placement and flowback strategies in reservoir cores were evaluated to identify important factors for optimized field process design. Based on lab results, five producing wells were selected for repeat injections of brine using varying volumes. Flowback results described the gas-blocking potential and determined optimal foam injection volume for each well. Two of the same wells were then treated with foam and flowed back. Experimental results show that oil tolerance is not a critical surfactant screening criterion for these particular reservoir conditions as the targeted treatment zones are the high permeability channels which have likely experienced a large amount of gas channeling. The threshold surfactant concentration, above which foam blocking capacity did not further improve, was significantly lower than that used in previous lab and field studies. Moreover, foams with an initial apparent viscosity above 50 cP remarkably delayed and reduced gas production rate for over a week in short cores at varying applied pressure gradients. The laboratory observations led to a new foam injection strategy that aims to place surfactant deeper into the gas zone by an optimal foam drive. Field trials demonstrated strong technical success of both brine and foam treatments to block gas production and reduce producing gas-oil-ratio (GOR). Flowback following brine injection demonstrated temporary GOR reduction for a period of about one week. Repeat brine treatments, of varying injection volumes, described the near-wellbore pore space and informed optimal foam treatment volume for each well. Both foam treatments resulted in reduced gas mobility, reduced producing GOR, and longer duration of these effects compared to brine gas blocking. Foam gas blocking effects lasted up to 70+ days, resulting in significant incremental oil production from the field. Foam provides a novel method to decrease producing GOR in horizontal wells in Prudhoe Bay and increase field oil production. Foam treatments are shown to be a cheaper alternative to well interventions, gas handling expansion, or other means of increasing production in a gas constrained system. This work has advanced our understanding of foam potential for gas shut-off in both vertical and horizonal producing wells.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.69)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (0.46)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (38 more...)
Abstract In an attempt that is considered the first in well stimulation techniques by means of Hydraulic Fracture practice in GRE lined tubing, Badr Petroleum Company, BAPETCO (A SHELL Joint Venture in Egypt) has a successful experience to report. The company performed a hydraulic fracture operation through one of its water injection well installations completed with GRE (fiberglass) lining. The need for fiberglass tubular lining raised from the fact that the injected water in Neag-1 field is saturated with 1000 ppb of oxygen content and a range between 60,000 to 80,000 of salinity which led to an active corrosion cell within the downhole injection strings. The company has been using GRE fiberglass lining for their downhole tubing since 2013 for corrosion protection. However, whenever a frac job was required in a GRE lined string, the tubing had to be pulled out of hole, a frac string had to be run allowing for flowback through the temporary frac string and then the GRE lined string to be re-run again. This sequence of processes lead to a significant downtime and increased workover costs. The concerns about the hydraulic fracture jobs with a GRE lined string came from the fear that the proppants flowing back would erode away the internal GRE lining. There was no availability of any test reports on erosion from conditions mimicking frac jobs through GRE lined tubing that could duplicate the flow back conditions. In two of the wells already completed with GRE lined tubing since 2014, the operations required hydraulic fracture job to be carried out using proppants. The injection rates were high at 20 barrels per minute (28,800 bpd flow rate) for a period of 30 minutes. The proppant injection pressure was 4000 psi. The flow back (cleaning post frac) took 24 hours to complete. 90,000 lb of proppants was injected. At the completion of the fracture job operations in 2018, no returns of GRE or flare or corrosion barrier ring pieces were collected in the surface. The paper will share the intervention jobs that have been recently run through the tubing that corroborates with the fact that the GRE lining inside the tubing is intact. This paper demonstrates the preparatory steps taken by the company to carry out hydraulic fracture jobs through a fiberglass GRE lined string and the learnings from this operation. It also sets a new limit on the erosional resistance of GRE lined tubing. The paper will also highlight the gains of Bapetco utilizing GRE within their water injection wells for corrosion protection. The injection flowrate gains will also be shared in detail, as well as the economic gains of performing the frac job through an already RIH GRE lined string instead of using the conventional frac string operation procedures.
Production Breakthrough from Channel Fracturing: A Seven-Year Journey in South Sulige Tight Gas Field
Fuyang, Wu (PetroChina Changqing Oilfield South Sulige Operation Company, Xi'an, China) | Qian, Ma (PetroChina Changqing Oilfield South Sulige Operation Company, Xi'an, China) | Libin, Dai (PetroChina Changqing Oilfield South Sulige Operation Company, Xi'an, China) | Ting, Jin (PetroChina Changqing Oilfield South Sulige Operation Company, Xi'an, China) | Tao, He (PetroChina Changqing Oilfield South Sulige Operation Company, Xi'an, China) | Shengfang, Yang (PetroChina Changqing Oilfield South Sulige Operation Company, Xi'an, China) | Yu, Lei (PetroChina Changqing Oilfield South Sulige Operation Company, Xi'an, China) | Long, Wang (PetroChina Changqing Oilfield South Sulige Operation Company, Xi'an, China) | Yifan, Dong (PetroChina Changqing Oilfield South Sulige Operation Company, Xi'an, China) | Qiang, Wang (Total E&P Chine, Beijing, China) | Na, Li (Total E&P Chine, Beijing, China) | Yin, Luo (SLB, Beijing, China) | Liang, Zhao (SLB, Beijing, China)
Abstract South Sulige Operating Company (SSOC), a joint venture company between CNPC and TotalEnergies, has been the main operator in South Sulige gas field since 2011. After years of optimization on operation parameters, the annual post-fracturing production (absolute open flow, AOF) has reached a high plateau that outperforms offset blocks. Nevertheless, because of the fast-growing domestic gas demand, utilizing proper fracturing technology to further increase production has become crucial in recent years. This paper describes the successful design evolution of channel fracturing technology in Sulige tight gas field through a 7-year trial. Unlike the homogeneous proppant pack created in a conventional fracturing job, channel fracturing makes open and highly conductive channels by forming proppant pillars in the fracture through pumping proppant-laden fluid and proppant-free fluid intermittently. These channels are beneficial for improving effective fracture length, facilitating fracturing fluid cleanup, minimizing pressure drawdown along the fracture, and thus improving post-fracturing production performance. In 2016, the first channel fracturing trial was conducted on four wells in this field, with comparable treatment size to conventional jobs. The average 600-day cumulative production of target wells was 25% higher than that of offset wells, which demonstrated the enhancement to effective fracture half-length and thus more fracture-reservoir contact. In 2021, the design strategy was upgraded by incorporating a more aggressive pumping schedule to improve near-wellbore fracture conductivity while reducing fracturing fluid usage, with superior production results achieved from wells with mid to high reservoir quality. In 2022, the fracturing design strategy was set to maximize the production potential for high-quality wells with increased treatment size and further extended effective fracture length. This achieved production record of 87 MMscf/d AOF from a 2-layer vertical well. This result is even comparable to performance of offset horizontal wells. Besides the promising results, through the design evolution in these 7 years, a channel fracturing candidate selection workflow with associated design strategy has been established for a similar tight gas field. Channel fracturing has been proved an effective tool to create extended effective fracture length and maximize single-well production in South Sulige tight gas field, with potential cost saving from needing fewer wells to deplete the same reservoir area. This technology, along with the properly designed workflow described in this paper, can also be widely adapted in other tight reservoirs.
- Asia > China > Inner Mongolia (1.00)
- North America > United States > Gulf of Mexico > Central GOM (0.24)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > China Government (0.34)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Taylakovskoye Field (0.99)
- Asia > India > Rajasthan > Cambay Basin (0.99)
- Asia > India > Gujarat > Cambay Basin (0.99)
- (8 more...)
Abstract During drilling operations, kick or influx events are threatening the safety of operating personnel and the environment; thus, early and accurate detection of the potential kick or influx becomes essential. Kicks frequently happen while making connections because when the pumps are turned off, the circulating flow rate decreases to zero, and the pressure exerted on the formations moderates to the hydrostatic pressure. Flowback fingerprinting, an analysis method for interpreting and comparing flowback patterns, has been widely used in the industry recently for early kick and loss detection during connection operations. However, the flowback fingerprinting, usually conducted manually by skilled engineers, lacks timeliness and accuracy in some scenarios. This paper presents an innovative solution to enable detecting abnormal flowbacks automatically by leveraging data-driven and machine learning based algorithm, including smart safe envelope, mud transfer filter and trip tank change detection. The new system automatically monitors the flowback volume vs. time data and compares them with a safe envelope in real time. The safe envelope is formed by a machine learning process, which performs clustering and curve-fitting based on historical normal flowbacks in the current well. Uncertainty is also included in the process to determine the upper and lower bound of the envelope. During each connection period, if the flowback curve deviates from the safe envelope, it will be identified as abnormal flowback and alarms will notify the users. During the operation, the safe envelope is automatic updated adaptively based on the characteristics of current flowback, e.g., the hole depth and the flow rate before turning off the pumps. This fully automated system greatly improves the accuracy and timeliness of abnormal flowback detection while minimizing the frequency of false alarms. Besides, the smart alarms could be sent to users by mails or mobile app which makes the reaction and decision-making more in time and convenient. The new system has been evaluated on previously drilled wells. In this paper, the capability of the new system is presented in one case studies by means of streaming actual well data, in which alarms were successfully triggered before the influx events occurred. The case studies demonstrate the capability and benefits for the entire workflow and how they can significantly reduce operation risks and non-productive time.
- Asia (0.69)
- North America > United States (0.46)
Proppant Flowback Control with High-Aspect Ratio Proppant and Advanced Modeling
Khan, Abdul Muqtadir (SLB, Sugar Land, Texas, USA) | BinZiad, Abdullah (Saudi Aramco, Eastern Province, Saudi Arabia) | Alsubaii, Abdullah (Saudi Aramco, Eastern Province, Saudi Arabia) | Kuznetsov, Dmitry (SLB, Sugar Land, Texas, USA)
Abstract Hydraulic fracturing is a common method of production enhancement for low- and mid-permeability reserves. Deep, hot gas reservoirs are usually fractured using ceramic proppant that is prone to flowback during fracture cleanup and production phases. Design techniques such as tip screenout (TSO) mode, particle size for a stable proppant arch, and choke management exist but are not foolproof. Resin-coated proppant (RCP) is a common method for proppant flowback control. However, it requires additional time and may reduce proppant pack permeability in the critical near-wellbore zone. A proppant with high aspect ratio (HARP) was trial tested as an alternative to RCP to optimize the mitigation of solids production. Multiple repeatability long-term conductivity tests were conducted on the proppant samples. HARP was implemented in two wells replacing RCP as a tail-in proppant. HARP placement was a concern due to its size and weight; the candidate well is the deepest and the hottest well so far where HARP has been pumped globally. Therefore, the HARP concentration was limited to a maximum 7 PPA at the first trial compared to 9 PPA in the offset area with 20/40-mesh proppant. The treatment execution, challenges, performance, and solids recovery of the trial wells were compared to their offset wells using the local solids-free criteria. A novel fracture flowback simulator was used to couple fracture modeling, placement, and flowback schedule design. The numerical simulator was built by digitizing flow tests to approximate the bridging and failure criteria for proppant packs. Post-fracturing shut-in time reduction by 55% was found to be an early benefit of using HARP. The trial Well-A resulted in zero solids recovery during the post-treatment well cleanup. Following this, multiple wells were trialed with similar results except in one well that showed formation sand during flowback. In no cases was HARP recovered at surface. Offset well analysis showed higher cumulative production of proppant and formation sand, even when the RCP to total proppant ratio was two-to threefold higher compared to the ratio of HARP amount to total proppant. Also, the end-of-treatment net pressure gain increased up to 50% higher compared to the offsets. The gas production for both of the trial wells exceeded the offsets due to 50% to 900% higher conductivity, which was evaluated through long-term conductivity tests input to validate the post-fracturing net pressure history match. It was also realized that perforation strategy, including gun orientation, interval length, etc., is a critical factor for solids flowback control and must be optimized together with proppant selection. Flowback tests with HARP also showed a much higher critical velocity for proppant pack failure compared to RCP. This paper presents an alternate solution for proppant flowback control material and even an alternate design strategy to integrate the flowback schedule design along with fracturing design as opposed to the silo approach. The unconventional proppant coupled with a robust flowback simulator opens high potential for unconsolidated formations. A frac-and-pack design with HARP engineering with a choke schedule has the potential to replace expensive screen completions and the complications associated with them.
- Asia > Middle East > Saudi Arabia (0.68)
- Europe (0.67)
- North America > United States > Texas (0.46)
Impact of Production Scheme on Pressure-Sensitive Reservoirs After Hydraulic Fracturing
Liu, Sen (China University of Petroleum) | Zheng, Leyi (China University of Petroleum) | Li, Wenjie (Xinjiang Oilfield Company of CNPC) | He, Jiajun (Downhole Service Company of XDEC) | Liang, Tianbo (China University of Petroleum)
ABSTRACT Tight oil reservoirs are typically pressure-sensitive, which can affect the well productivity and oil recovery rate when the reservoir pressure decays. In this paper, the pressure-sensitive of reservoir rock is studied using CT-monitored corefloods, during which the change of permeability and porosity of the rock can be determined under different effective stresses; meanwhile, numerical simulations are conducted to understand the conducted to understand the impact of flowback and production schemes on the oil recovery rate in the field scale. After the reservoir rock sample is saturated with the sample oil, different effective stresses are applied on the rock; the oil is continuously flooded through the sample, during which the porosity change is recorded through CT scans, and the pressure change across the rock is recorded to calculate the rock permeability at different time. After the numerical simulation results are history matched with the experimental results, different flowback and production schemes are studied. After fracturing, the bottom pressure was reduced to 15MPa by different steps. The change of permeability and porosity of the rock and its influence on oil recovery rate under different production schemes were observed. During production, the effective stress in the reservoir increases from about 10 MPa to 50 MPa. According to the pressure-sensitive experiment results, the permeability and porosity of the rock decreased to 22% and 89%. When the pressure sensitive effect is considered, the 10-year recovery rate is reduced from 27% to 17%, and the flowback rate is reduced by 13%.The numerical simulation results show that the rapid production scheme has the highest production and flowback rate, increasing the oil recovery rate by 6% and the flowback rate by 5.9% compared with the three or five steps. The change of production scheme has no significant effect on the relief of pressure-sensitivity and the well should be quickly flowback considering the potential effect of water-sensitivity. The change of rock permeability and porosity are firstly quantified in-situ using a CT-monitored coreflood. Combining the experimental and numerical simulation results, the production scheme can be optimized pressure-sensitive reservoirs.
- Research Report > New Finding (0.35)
- Research Report > Experimental Study (0.35)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Numerical Simulation and Field Application of Deepwater and Shallow Quick Puncture Tube Shoes
Xu, Dongsheng (China University of Petroleum (Beijing)) | Yang, Jin (China University of Petroleum (Beijing)) | Zhao, Yuhang (China University of Petroleum (Beijing)) | Ma, Kuo (China University of Petroleum (Beijing)) | Han, Zengcheng (China University of Petroleum (Beijing)) | Fan, Jianchun (China University of Petroleum (Beijing)) | Wen, Zhiliang (China University of Petroleum (Beijing)) | Lim, Frank (2H Offshore) | Zhu, Chunlin (China University of Petroleum (Beijing)) | Cai, Rao (Zhanjiang Branch of CNOOC China Ltd) | Xia, Xi (Zhanjiang Branch of CNOOC China Ltd) | Zhu, Hong (China University of Petroleum (Beijing)) | Yang, Kaidie (China University of Petroleum (Beijing))
ABSTRACT During installation of conductors, there are often obstacles in the entry. The newly developed quick puncture tube shoes can solve this problem. The results presented in this paper show that the penetration speed of the shoe and the conductor can be increased quickly for different conductor depths. The performance of the shallow quick puncture tube shoe was calculated through numerical simulation, and its layout was optimized. A conductor shoe, with swirl rib, can significantly improve the flowback capacity of rock cuttings in the conductor, which can help reduce the standing waiting time after spraying in place. The field engineering practice shows improved deep water well construction, with reduction in injection time by 1.75 hours and waiting time by 2 hours. INTRODUCTION The surface conductor is the first layer of conductor string in the drilling process. In deep-water drilling, the jet method is often used to install the surface conductor. Whether in shallow water or deep water, the conductor shoe is a very important component, which plays a key role in the safe, smooth, and efficient running of the surface conductor r. Without a properly designed conductor shoe, there will be many challenges and risks for the first basic component to be installed for offshore well construction. Shallow marine soil often contains hard interlayer and pebbles (Tan et al.,2018). In the process of jet well construction, the operation is slow, and the conductor can often be damaged. For instance, the conductor can be blocked, easy to tilt and the top of the conductor is damaged, which can result in difficulties in the conductor installation, seriously impacting the operation efficiency of well construction; The conductor cannot be sprayed to a safe and reliable depth, resulting in additional wellhead instability risks such as wellhead sinking and inclination. In fact, serious accidents such as excessive inclination of conductor installation and irreparable damage at the bottom of conductor can result in wellhead scrapping (Zhang et al., 2017).
Abstract During the initial flowback after hydraulic fracturing in unconventional wells, fluid rates (oil, gas, and water) and pressures are typically recorded on an hourly basis. Therefore, even though flowback may only take a few weeks, there are hundreds of available data points. The authors have developed an innovative approach to predict short-term cumulative oil production and long-term oil EUR using hourly flowback data, theory-based calculations, and empirical correlations. Unconventional wells produce in the linear flow regime in early time. During this period, the production depends on pressure, fracture surface area, and reservoir and fluid properties, which can be lumped into one term obtained from the slope of the RTA superposition time plot. Most wells exhibit a linear flow signature during the flowback period, so this slope is easily obtained. Hundreds of Permian wells with hourly flowback data were analyzed to obtain the slope. The initial pressures for these wells divided by this slope were plotted against their corresponding one-year cumulative oil production and EUR. From this analysis, correlations for both one-year cumulative oil production and EUR have been established. Using these correlations from historical wells, the one-year cumulative oil production and oil EUR of a new well can be estimated with just a few weeks of flowback data since the main parameters (pressure, fracture surface area, and reservoir and fluid properties) impacting production performance can be obtained. We named the EUR from this RTA linear flow-based correlation LinearFlow-EUR. The authors validated this innovative method based on hourly flowback data in new wells in different benches in both the Midland Basin and Delaware Basin. We also validated the method with dynamic reservoir simulation. The correlations can generally predict one-year cumulative oil production and oil EUR within reasonable ranges, even though the correlations are only based on linear flow regime, not considering the pseudo-steady state depletion. This new method provides an early performance indication for new wells, new benches, or new areas. The application of the method could speed up completion trials and appraisal processes tremendously while optimizing field development plans.
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (30 more...)
Abstract In past studies, changes in fluid pressure in natural fractures (planes of weakness) have been ignored for the interaction of hydraulic and natural fractures. To overcome these limitations, in this paper we develop a method to simulate the growth of hydraulic fractures as they interact with natural fractures while accounting for changes in fluid pressure in the network of natural fractures. This simulation can be very computationally expensive and so a computationally efficient, mesh-free, integrated fracturing-production simulator was developed to simulate the creation of fracture networks and simulate fluid flowback. The integrated fracturing-production simulator has several key advantages. It can: (1) capture the variation of fluid pressure in natural fractures induced by variations in stresses in the rock matrix, (2) eliminate the need to discretize the rock matrix domain by using the displacement discontinuity method for fracture propagation, and (3) use a new and general Green’s function solution for production and flowback . Information about the propagated complex fracture network can be seamlessly used by the fluid production module once the hydraulic fracturing process ends. The simulator is used to investigate the effect of changes in in-situ stress contrast, and other parameters in the discrete fracture network (DFN) on the geometry of the fracture network and fluid flowback.. The results show that (1) compared to a constant fluid condition in natural fractures, the variation of natural fracture fluid pressure can significantly change the geometry of the created fracture network and subsequent production rate; (2) a larger stress contrast more readily reactivates natural fractures and leads to a shorter fracture network and a lower production rate; and (3) an alternate fracturing sequence generates longer fractures, resulting in better well performance. The simulator presented here can be used to provide computationally efficient and effective guidance on fracture design and reservoir optimization to enlarge reservoir drainage area and increase well productivity.