Wu, Xiaye (The University of Oklahoma) | Han, Lihong (Tubular Goods Research Institute of CNPC) | Yang, Shangyu (Tubular Goods Research Institute of CNPC) | Yin, Fei (Chengdu University of Technology) | Teodoriu, Catalin (The University of Oklahoma) | Wu, Xingru (The University of Oklahoma)
Due to the layered texture and sedimentation environment, shale formations usually characterized as high heterogeneity and anisotropy in in-situ stresses. During the hydraulic fracturing process, fracturing fluid is injected at a pressure above the formation pressure. This injection process changes the local in-situ stresses in a quick and significant manner while generating fracture systems. In the regions of existing geo-features such as natural fractures and faults, local stress changes could lead to the activation of formation movement, which in return impacts the casing going through the locale. Casing deformations during hydraulic fracturing have been observed in Southwest China Sichuan basin, and it have impeded completion operations in certain regions. In order to ensure further exploring, we analyszed this phenomenon and propose practical solutions for fault reactivation prevention.
To study the mechanism of local slippage and the impact on casing integrity, we set up a 2D finite element model with considerations of in-situ stresses acquired from fields, natural fracture orientation from available seismic data, and we simulated water injection process in order to quantify potential slippage and displacement. The finite element model features an integration of casing, cementing, and formation under the hydraulic fracturing conditions. For particular parameters such as permeability and leak-off coefficeint, we conducted sensitivity studies to quantify their impacts on displacement amount.
The theoretical geomechanics studies indicate water induced slippage existence in shale due to its fracture reactivation. Using the finite element model, this paper interpreted and quantified the impact of fracturing fluid injection on casing from strike-slip fault regiems. Simulation results revealed that water injection into natural fractured shale formation can induce finite displacement characterized as fault slippage along discontinues surfaces. This study could help engineers to have a better prediction as how hydraulic fracture intereact with subsurface structures and potential risks that comes along with it. This type of casing damage can be reduced by improving well trajectory design, completion operation, and higher strength level of casing-cement system.
The findings from this study not only can be applied to naturally fractured formations, but also to other pre-existing geo-features such as discountinues surfaces. It also provides fundamental basis for more practical solution to find the measures and overcome the casing deformation problems in hydraulic fracturing.
Lu, Cong (Southwest Petroleum University) | Li, Junfeng (Southwest Petroleum University) | Luo, Yang (SINOPEC Southwest Oil & Gas field Company) | Chen, Chi (Southwest Petroleum University) | Xiao, Yongjun (Sichuan Changning Gas Development Co. Ltd) | Liu, Wang (Sichuan Changning Gas Development Co. Ltd) | Lu, Hongguang (Huayou Group Company Oilfied Chemistry Company of Southwest) | Guo, Jianchun (Southwest Petroleum University)
Temporary plugging during fracturing operation has become an efficient method to create complex fracture network in tight reservoirs with natural fractures. Accurate prediction of network propagation process plays a critical role in the plugging and fracturing parameters optimization. In this paper, the interaction between one single hydraulic fracture within temporary plugging segment and multiple natural fractures was simulated using a complex fracture development model. A new opening criterion for NF penetrated by non-orthogonal HF already was implemented to identify the dominate propagation direction of HF under plugging condition. Fracture displacements and induced stress field were determined by the three dimensional displacement discontinuity method, and the Gauss-Jordan and Levenberg-Marquardt methods were combined to handle the coupling between rock mechanics and fluid flow numerically. Numerical results demonstrate that the opening and development of NF are mainly dominated by its approaching angle and relative location. For a certain NF crossed by HF within plugging segment, HF tends to propagate along the relative upper part when the approaching angle is less than 90°, otherwise the lower part will be easier to open. The farther interaction position is away from HF tip, the easier NF with approaching angle less than 30° or larger than 150° can be open, and the outcome will be opposite if the approaching angle is larger than 45° or less than 135°. Higher approaching angle and plugging strength is necessary for expanding the position scope of NF that can be opened around HF. Under the impact of plugging, fluid pressure in HF plummets at the beginning of NF opening and keeps decreasing until NF extending for a certain distance or encountering secondary NFs. Fluid pressure drop occurs mainly in the unturned NF, together with the width of unturned NF is significantly lower than that of turned NF and HF. Sensitivity analysis shows that the main factors, such as geometry, aperture profile, and fluid pressure distribution, affecting the network progress under temporary plugging condition are the horizontal differential stress, NF position, approaching angle, plugging time, and plugging segment length. The simulation results provide critical insight into complex fracture propagation progress under temporary plugging condition, which should serve as guidelines for welling choosing and plugging optimization in temporary plugging fracturing.
Liu, Wei (BGP, CNPC, Chengdu University of technology) | He, Zhenhua (Chengdu University of technology) | Cao, Junxing (Chengdu University of technology) | Zhang, Jianjun (BGP, CNPC) | Xu, Gang (BGP, CNPC) | Wan, Xiaoping (BGP, CNPC) | Yu, Gang (BGP, CNPC)
Shale play, as one kind of non-conventional natural gas resource, has become the focus of domestic and overseas research in recent years. shale is pertained to be a reservoir with an ultralow porosity and permeability, its occurrence mode, accumulation pattern of natural gas, as well as development model are remarkably different conventional oil gas reservoirs, its development must be implemented by some special technique, e.g. horizontal drilling, drilling geologic steering, hydraulic fracturing, microseismic monitor, etc. Research shows, shale gas production depends on two factors, one is geological sweet spot factor, e.g. Total organic carbon, brittleness, core fluid pressure, micro-fractures, high quality shale thickness etc., the other is engineer technique factors, e.g. horizontal drilling, drilling geologic steering, hydraulic fracturing, microseismic monitor, fracturing schemes, etc. Single factor, sweet spots or engineering technique factor often not guarantee shale gas highly production, only when the most optimal combination of both, can achieve shale gas production maximization. How to integrate sweet spots and engineering technique to guide shale gas exploration and development? This is a serious question. This question involves to many fields, including geology and engineer sweet spots, horizontal well location deployment, drilling geologic steering, pre-fracturing warning and design, hydraulic fracturing design real-time adjustment, microseismic monitoring, etc., sweet spots results runs through the entire shale exploration and development. In this article, we will pay more attention to demonstrate that how to adjust the fracturing scheme and optimize the reservoir stimulation in real time by integrated geological sweet Spot and microseismic monitor.
Chen, Xin (BGP) | Wang, Guihai (CNODC) | Wang, Zhaofeng (CNODC) | Liu, Zundou (CNODC) | Liu, Zhaowei (CNODC) | Cui, Yi (CNODC) | Tian, Wenyuan (CNODC) | Wei, Xiaodong (BGP) | Hou, Liugen (BGP) | Yang, Ke (BGP) | Chen, Gang (BGP) | Xia, Yaliang (BGP) | Yan, Xiaohuan (BGP) | Zhang, Zeren (BGP) | Liu, Jingluan (BGP)
To improve the accuracy of permeability prediction, seismic constraint and sedimentary facies has often been adopted in conventional methods. However, it is porosity that both of them constrain, rather than permeability, and different pore structure with different permeability, the accuracy of permeability prediction cannot be radically improved. To address the problem of permeability prediction in carbonate reservoir, new permeability prediction technique workflow were summarized based on pore structure analysis and multi-parameters seismic inversion: division reservoir types based on the pore structure, construction of the rock types identification curve, carry out a rock type inversion and a porosity inversion constrained by seismic impedance respectively, and then get a final permeability prediction volume according to the porosity-permeability relationship and pore structure of core samples. It breaks the bottleneck that is difficult for seismic impedance (continuous variable) to constrain rock type (discrete variable), then constrains pore structure (continuous variable) related to rock type instead, and converts it into rock type using multi-parameters seismic inversion. According to the certification of new wells, this workflow have been applied successfully in carbonate reservoir of H oilfield in Middle East, it not only improves the prediction of rock type in space, but also permeability prediction accuracy.
Xue, Heng (China Zhenhua Oil Co., Ltd, State Key Laboratory of Oil & Gas Reservoir Geology and Exploitation Engineering, Southwest Petroleum University) | Huang, Zuxi (China Zhenhua Oil Co., Ltd) | Liu, Fei (Engineering Technology Research Institute, PetroChina Southwest Oil & Gas Field Company) | Liu, Pingli (State Key Laboratory of Oil & Gas Reservoir Geology and Exploitation Engineering, Southwest Petroleum University) | Wang, Hehua (China Zhenhua Oil Co., Ltd) | Zhang, Bo (China Zhenhua Oil Co., Ltd) | Cheng, Yi (China Zhenhua Oil Co., Ltd) | He, Bing (China Zhenhua Oil Co., Ltd) | Chen, Xiang (State Key Laboratory of Oil & Gas Reservoir Geology and Exploitation Engineering, Southwest Petroleum University)
Leakoff has been regarded as the key factor affecting live acid penetration distance and fracture etching patterns. The current leakoff coefficient model is insufficient to describe dynamic acid leakoff in the comprehensive matrix-vug-fracture medium. Furthermore, the carbonate reservoir medium is normally complex because of physical and mineral heterogeneity, which makes the acid leakoff process much more complicated. In order to increase the prediction accuracy of acid fracturing, the leakoff behavior of the matrix, wormhole & fracture and its’ related heterogenous etching patterns must be highlighted clearly.
In this paper, the leakoff experiments were performed under high temperature and high pressure (HTHP) to study the leakoff behavior for the matrix, wormhole & fracture respectively. Integrated with the experimental results, the wormhole leakoff model was developed considering the matrix and fracture medium. Based on the split rock, the conductivity of the acid etched fracture was studied to understand the effects of acid type, acid fracturing technique, closure stress, fracture roughness, mineral composition and structure on the conductivity. the integrated acid fracturing equation was developed through coupling the pseudo 3D fracture propagation model, wormhole leakoff model and the fracture heterogenous etching model. The solution was used to optimize technique parameters and predict acid fracturing effects in the carbonate reservoir.
According to the studies, the acid leakoff in the matrix agrees with Carter leakoff theory, while leakoff in the wormhole do not. The acid leakoff increases sharply with the wormhole propagation, and it has the quadratic relation with t^1/2 in the fracture. The mineral heterogeneity highly affects fracture etching patterns. Closed acidizing is an efficient method to enhance etching depth, therefore increasing fracture conductivity. The simulation results show that acid leakoff rates along the fracture length change locally and dynamically because of reservoir heterogeneity and the reaction between acid and rocks. The average leakoff rate on the fracture surface ranges in the magnitude of 10-4~10-3m/min, which tends to generate face-dissolution on the fracture surface. When the acid connects the natural fractures, the leakoff rate is sharply increased.
More than 10 wells’ acid fracturing proposals were designed based on the above works in the Upper Sinian Dengying Fm gas reservoirs in the Sichuan Basin of China. The simulated acid fracture length ranges from 23.4~42.6m, which is close to the well test results of 18.4~45.3m.
Tian, Hua (Research Inst Petr Expl & Dev, Petrochina) | Zou, Caineng (Research Inst Petr Expl & Dev, Petrochina) | Liu, Shaobo (Research Inst Petr Expl & Dev, Petrochina) | Zhang, Shuichang (Research Inst Petr Expl & Dev, Petrochina) | Lu, Xuesong (Research Inst Petr Expl & Dev, Petrochina) | Ma, Xingzhi (Research Inst Petr Expl & Dev, Petrochina) | Bi, Lina (Research Inst Petr Expl & Dev, Petrochina) | Yuan, Miao (Research Inst Petr Expl & Dev, Petrochina)
A series of petrohysical experiments have been conducted to obtain the gas physical properties (e.g., gas-water interfacial tension). The capillary pressures of pore throats were obtained through numerical calculation. Furthermore, residue water was used to calculate gas/water saturation in the reservoirs. The gas saturation variation under lower interfacial tension and the amount of gas lost during the uplift in burial history need an in-depth examination (Tian et al., 2017). In addition to the geological studies in the field, various laboratory methods were used to tackle the problems mentioned above, including Nlear nuclear magnetic resonance (NMR) and fluid inclusion analysis with optical and Laser Raman spectroscopy. During the charging history, hydrcarbon saturations at different temperature and pressure was calculated using the model established in this paper, which is mainly determined by the pore size distribution obtained by the NMR analysis. The charging pressure is measured by fluid inclusion study with optical and Laser Raman spectroscopy test. Furthermore, the leakage content of gas during the burial history was calculated using a diffusion model (Krooss& Leythaeuser., 1988; Krooss et al., 1992).
Chen, Changzhao (State Key Laboratory of Petroleum Pollution Control, CNPC Research Institute of Safety and Environmental Technology) | Li, Xingchun (China University of Petroleum) | Wu, Baichun (State Key Laboratory of Petroleum Pollution Control, CNPC Research Institute of Safety and Environmental Technology) | Zhang, Kunfeng (State Key Laboratory of Petroleum Pollution Control, CNPC Research Institute of Safety and Environmental Technology) | Song, Quanwei (State Key Laboratory of Petroleum Pollution Control, CNPC Research Institute of Safety and Environmental Technology)
The world has seen a peak in unconventional gas development in recent years. Based on the practice of unconventional gas field development domestic in China and abroad, it is risky that the reinjection water may contaminate groundwater in local or adjacent areas during reinjected fluid migration. Ensuring environmental safety of the reinjection is a multi-disciplinary system project. This paper carries out the analysis and shares the experience of China's practice based on the actual cases from the following aspects. 1) The screening of the well location and the formation of the reinjection. 2) The drilling and cementing construction of the reinjection well, which considers the factors such as cementing quality and cement height and casing material. 3) The estimation of the total reinjection capacity, and the factors such as porosity and permeability of the geologic trap and reservoir fracture pressure is considered. 4) The monitoring of well and migration of reinjection fluids. Further environmental risk study of produced water reinjection is presented in this paper, on both sandstone formation of tight sand gas field and carbonate karst formation of shale gas field in China's typical unconventional gas development areas, using laboratory geochemistry experiments and large area geophysical test to obtain seismic data.
Zheng, Xinquan (E&P Company, PetroChina) | Moh, Thomas (K&M Technology, Schlumberger) | Huang, Nan (Schlumberger) | Ke, Ning (Schlumberger) | Geng, Gan (Schlumberger) | Chin, Jer Huh (Schlumberger) | Zhang, Cheng (Schlumberger) | Wang, Xiong Fei (Schlumberger) | Liu, Dong (Schlumberger) | Yang, Lei (Schlumberger)
Being the world's third largest shale gas producer after the US and Canada, China delivered an output of 9 billion cubic meters (bcm) in 2017. China has the world's largest technically recoverable reserves of shale gas, of which US Energy Information Administration (EIA) estimates at 31.6 tcm, 68% higher than shale reserves in the US. Unlike the US who started to explore shale gas in the 1980s, China only completed the first shale gas well in 2011.
Development of shale gas resources is expected to play a vital role in China's enthusiastically planned transition to a low-carbon energy future. On September 14th, 2016, Chinese National Energy Board released Shale Gas Development Plan 2016-2020. In the plan, shale gas production goal was set at 30 bcm for 2020. With an average shale gas production of 20MCM per well per year, it is estimated that a minimum of 1500 horizontal wells with 1000m lateral length are needed by the year of 2020. The question arises whether what kind of drilling performance is needed to meet the aggressive development target.
In less than a decade, Petro China, its subsidiaries and contractors have made significant breakthroughs in shale gas exploration, not only in capacity, but also drilling techniques. The paper captures the success and lessons that the drillers had gained in the last 7 years in terms of drilling performance. It is well known that China shale gas reserves are in geologically challenging areas. The challenges consisted of hard formations with kicks, losses, frequent stuck pipe and over pressure formation. The problems were amplified by high geological formation dip, faults, and stratigraphic uncertainties. In this harsh drilling environment, rate of penetration was slow, trajectory control is difficult, mud weight and circulating pressure are high, downhole torsional vibration, drilling torque and stick&slip are high, rig equipment and downhole tools fail prematurely, and non-productive time is excessive. Over the years, the team had demonstrated that with systematic, scientific and engineering drilling approaches, a considerable improvement in drilling performance can be achieved. To deliver and execute the optimized drilling approaches, high intregration and synergy between each drilling segment are required. These approaches are nothing new in the drilling world, these are optimization in Well Plan, Mud Properties, Rig Capacity & Drilling Parameters, Bottome Hole Aseembly (BHA) selection and design, best Drilling Practice and Drilling Operation Efficiency. These are all part of a formula to success; the key is to rightly balance each one of them. The team sucessfully reduce average well days from 120 to 30 in one particular field. Along the way, the team also identify a few more components to the formula of success, with that, the short-term goal shall be further reducing the well days to 25 days, and less than 20 days in long term.
Tang, Xuanhe (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Zhu, Haiyan (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University & State Key Laboratory for Geomechanics and Deep Underground Engineering, China University of Mining & Technology) | Liu, Qingyou (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Song, Yujia (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
To investigate the time-lapse, three-dimensional (so-called four dimensional/4D) stress during production/injection, a 4D multi-physical modeling method is proposed. A finite difference method (FDM) reservoir simulator is used to couple thermal-hydrological-chemical (THC) processes, while a finite element method (FEM) geomechanical simulator takes on the role of a thermal-hydrological-mechanical (THM) coupling calculator. Heterogeneity and anisotropy of the reservoir flow and geomechanical properties as well as the permeability stress-sensitivity can be considered in modelling based on field and experimental data. In order to couple the flow model with the geomechanical model, an improved interface (coupling) Python code is provided to communicate data between the finite difference (FD) and finite element (FE) grids. Ultimately, this method is applied to analyze the stress and poro-elastic parameters evolution of hydraulic fractured Sichuan Basin shale gas reservoir and Qinshui Basin coalbed methane (CBM) reservoir in production.
Xu, Chengyuan (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Yan, Xiaopeng (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Kang, Yili (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | You, Lijun (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Zhang, Jingyi (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Lin, Chong (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Jing, Haoran (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
Plugging natural fractures with lost control materials (LCMs) is the common method to prevent foramtion damage and control fluids loss in In naturally fractured reservoir. The plugging zone strenfth stability is critically important for maintaining long-term plugging quality. Surface friction coefficient (SFC) is proposed as an important parameter for the selection of LCMs based on based on granular matter mechanics and the instability of plugging zone. The force chain network with specific geometry is the basis of the plugging zone strength and supporting external load. The likelihood of shear failure can be increased by decline of SFC. And high strength of force chain can not be formed and it can relatively easy to be broken even if a small shear is applied. Effects of LCMs particle size distribution, circulation abrasion, LCMs combination, working fluids infiltration, and high temperature aging on friction behaviors are analyzed for LCMs with high SFC selection. Results show that the average SFC shows a decreasing trend with the particle size reduction and the difficulty of particle dislocation decreases with the particle size reduction. For deep naturally fractured reservoirs, particle size will degradate due to long-term drilling fluid circulation in the wellbore, thus affecting the plugging effect of drill-in fluid. The mixture of elastic material and fiber into rigid material increases the SFC and elastic material contributes most to the increasing the SFC. The SFC decreases under the condition of fluids infiltration, and the SFC show a higher decline in oil-based condition. The high-temperature aging makes the edge of the organic rigid material more smooth, which reduces its SFC.