|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Suarez-Rivera, Roberto (W. D. Von Gonten Laboratories) | Panse, Rohit (W. D. Von Gonten Laboratories) | Sovizi, Javad (Baker Hughes) | Dontsov, Egor (ResFrac Corporation) | LaReau, Heather (BP America Production Company, BPx Energy Inc.) | Suter, Kirke (BP America Production Company, BPx Energy Inc.) | Blose, Matthew (BP America Production Company, BPx Energy Inc.) | Hailu, Thomas (BP America Production Company, BPx Energy Inc.) | Koontz, Kyle (BP America Production Company, BPx Energy Inc.)
Abstract Predicting fracture behavior is important for well placement design and for optimizing multi-well development production. This requires the use of fracturing models that are calibrated to represent field measurements. However, because hydraulic fracture models include complex physics and uncertainties and have many variables defining these, the problem of calibrating modeling results with field responses is ill-posed. There are more model variables than can be changed than field observations to constrain these. It is always possible to find a calibrated model that reproduces the field data. However, the model is not unique and multiple matching solutions exist. The objective and scope of this work is to define a workflow for constraining these solutions and obtaining a more representative model for forecasting and optimization. We used field data from a multi-pad project in the Delaware play, with actual pump schedules, frac sequence, and time delays as used in the field, for all stages and all wells. We constructed a hydraulic fracturing model using high-confidence rock properties data and calibrated the model to field stimulation treatment data varying the two model variables with highest uncertainty: tectonic strain and average leak-off coefficient, while keeping all other model variables fixed. By reducing the number of adjusting model variables for calibration, we significantly lower the potential for over-fitting. Using an ultra-fast hydraulic fracturing simulator, we solved a global optimization problem to minimize the mismatch between the ISIPs and treatment pressures measured in the field and simulated by the model, for all the stages and all wells. This workflow helps us match the dominant ISIP trends in the field data and delivers higher confidence predictions in the regional stress. However, the uncertainty in the fracture geometry is still large. We also compared these results with traditional workflows that rely on selecting representative stages for calibration to field data. Results show that our workflow defines a better global optimum that best represents the behavior of all stages on all wells, and allows us to provide higher-confidence predictions of fracturing results for subsequent pads. We then used this higher confidence model to conduct sensitivity analysis for improving the well placement in subsequent pads and compared the results of the model predictions with the actual pad results.
Abstract The application of high viscosity friction reducers (HVFRs) in unconventional plays has steadily increased over the past years, not only as alternatives to conventional friction reducers (FRs) but also as a direct replacement for the use of guar-based fluids. HVFRs demonstrate more efficient proppant transport, due to their unique rheological properties, concurrently with a high friction reduction effect allowing higher pumping rates. However, all these benefits come with few critical limitations related to frac water quality, compatibility with other additives, and static proppant suspension, which makes them very similar to conventional crosslinked gels regarding their Quality Assurance and Quality Control (QAQC) requirements at a well location during the field implementation. This paper illustrates the comprehensive laboratory efforts undertaken to evaluate different HVFR and crosslinked gel products, their successful field application supported by a robust and effective field QAQC process, and the critical importance of maintaining effective field-laboratory-field interaction/cycle to optimize the fluid design and maximize the results. Experimental studies on different products were conducted to measure the effect of frac water quality, HVFR loading, breaker loading, and compatibility with other additives used in the fluid recipe such as surfactants, scale inhibitors, and biocides. The ability of HVFR to suspend and transport proppant is not only a function of polymer loading but also highly influenced by fluid velocity as static and semi-dynamic proppant suspension tests demonstrate. Additionally, a full dynamic proppant transport test was also conducted using a multi-branched slot apparatus to simulate the flow inside a complex fracture network. Field execution followed a strict QAQC protocol including water analysis, field laboratory tests, water filtration, mixing procedure, product storage, and transport allowing direct onsite replication of the results that had been previously obtained in the laboratory. Constant communication between the field and the laboratory allowed a successful execution of several treatments in a challenging shale play in the Sichuan Region, China. These treatments achieved record proppant placements and, just as importantly, they demonstrated repeatability and consistency over time; which had not previously been attained. Laboratory testing proved critical in confirming that product segregation was occurring, even if there was no visual observation of this phenomenon, which had resulted in initial difficulties in fluid quality and reliability. The presence of constant QAQC engineering support on location was instrumental in rapidly identifying the potential root cause(s) and efficiently and correctly applying the necessary corrective actions. This paper will highlight the importance of laboratory testing, in order to design and optimize the fluid system. The paper will also demonstrate how critical the onsite QAQC is through actual examples of fluid optimization and field implementation. These two activities, although requiring a substantial resource commitment and effort, are both required to achieve successful execution.
Xie, Jun (Petrochina Southwest Oil and Gas Field Company) | Tang, Jizhou (Harvard University) | Sun, Sijie (Harvard University) | Li, Yuwei (Northeast Petroleum University) | Song, Yi (Petrochina Southwest Oil and Gas Field Company) | Huang, Haoyong (Petrochina Southwest Oil and Gas Field Company) | Pei, Hao (Harvard University) | Zhang, Fengshou (Tongji University)
Abstract Slurry, as a proppant-laden fluid for hydraulic fracturing, is pumped into initial perforated cracks to generate a conductive pathway for hydrocarbon movement. Recently, numerous studies have been done to investigate mechanisms of proppant transport within vertical fractures. However, the distribution of proppant during stimulation becomes much more complicated if bedding planes (BPs), natural fractures (NFs) or other discontinuities pervasively distributed throughout the formation. Thus, how to capture the transport and placement mechanisms of proppant particles in the opened BPs becomes a significant issue. In this paper, we propose a closed-form continuous proppant transport model based on the conservation of total proppant volume and sedimentation of proppant particles. This model enables to integrate with the fluid flow section of a 3-D hydro-mechanical coupled fracture propagation model and then predict the distribution of proppant velocity and slurry volume fraction within a dynamic fracture network. Stokes’ law is applied to determine the sedimentation velocity. In the fracture propagation model, rock deformation is governed by the analytical solution of penny-shaped crack to determine fracture width. Fluid flow is characterized by finite differentiation scheme and then the fluid velocity is obtained. These two parameters above are inputs for the proppant transport model and both slurry viscosity and density are updated in this step. Afterwards, both fracture width and fluid velocity would be altered in the fracture model. Analysis of the proppant distribution within crossing-shaped fracture is conducted to study mechanisms of proppant transport along opened BPs. From our numerical analysis, we find that the distribution of proppant concentration is independent with the fluid viscosity, but highly dependent on the volume fraction of pumping slurry, under a given pumping pressure. Due to the difference of viscosity and proppant volume fraction at locations of upper and lower BPs, we observe that two symmetric BPs are unevenly opened, with different channel length along BP. Moreover, the width of opened upper BP is much smaller than that of opened lower BP as a result of discrepancy of proppant sedimentation. Last but not the least, a criterion of flow bed mobilization is established for dynamically tracking the sedimentation along the BP. Then the effect of different parameters (such as proppant size, proppant density, fluid viscosity, injection rate) on proppant distribution along opened BPs is also studied. Our model fully considers the proppant transport and settlement, proppant bed formation and interaction between fracture and proppant, which helps to predict the influence of proppant during fracturing treatment. Additionally, our model is also capable of dynamically tracking the settlement of proppant along opened BPs.
Ju, Yang (China University of Mining and Technology (Corresponding author) | Wu, Guangjie (emails: email@example.com or firstname.lastname@example.org)) | Wang, Yongliang (China University of Mining and Technology) | Liu, Peng (China University of Mining and Technology) | Yang, Yongming (China University of Mining and Technology)
Summary In this paper, we introduce the entropy weight method (EWM) to establish a comprehensive evaluation model able to quantify the brittleness of reservoir rocks. Based on the evaluation model and using the adaptive finite element-discrete element (FE-DE) method, a 3D model is established to simulate and compare the propagation behavior of hydraulic fractures in different brittle and ductile reservoirs. A failure criterion combining the Mohr-Coulomb strength criterion and the Rankine tensile criterion is used to characterize the softening and yielding behavior of the fracture tip and the shear plastic failure behavior away from the crack tip during the propagation of a fracture. To understand the effects of rock brittleness and ductility on hydraulic fracture propagation more intuitively, two groups of ideal cases with a single failure mode are designed, and the fracture propagation characteristics are compared and analyzed. By combining natural rock core scenarios with single failure mode cases, a comprehensive evaluation index BIf for reservoir brittleness and ductility is constructed. The simulation experiment results indicate that fractures in brittle reservoirs tended to form a complex network. With enhanced ductility, the yielding and softening of reservoirs hamper fracture propagation, leading to the formation of a simple network, smaller fracture area (FA), larger fracture volume, and the need for higher initiation pressure. The comprehensive index BIf can be used to define brittleness or ductility as the dominant factor of fracturing behavior. That is, 0 < BIf ≤ 0.46 indicates that the reservoir has enhanced ductility and ductile fracturing prevails; 0.72 < BIf < 1 indicates that the reservoir has enhanced brittleness and brittle fracturing prevails; and 0.46 < BIf ≤ 0.72 means a transition from brittle to ductile fracturing. Based on fitting analysis results, the relationship between the calculated FAr and BIf is constructed to quantify the influence of reservoir brittleness and ductility on fracturing. The study provides new perspectives for designing, predicting, and optimizing the fracturing stimulation of tight reservoirs with various brittleness and ductility.
Wu, Jiwei (East China University of Science and Technology, Harvard University, Yangtze University) | Pan, Jiake (East China University of Science and Technology) | Wang, Hualin (East China University of Science and Technology (Corresponding author) | Wang, Lixiang (email: email@example.com)) | Liu, Wenjin (PetroChina Southwest Oil & Gas Field Company, Chengdu Natural Gas Chemical General Plant) | Zhang, Le (Sinopec, SJ Petroleum Machinery)
Summary With the flourishing shale gas exploitation producing more oil-based mud (OBM) cuttings, the hard-to-treat hazardous wastes heavily burden the local environment. However, the problems of treating OBM cuttings, such as huge energy consumption, tremendous treatment costs, and high risk of secondary contamination, still remain unsolved with the current treatment technologies, such as thermal desorption, incineration, and chemical extraction. In this study, we introduce a new method and equipment based on cyclone desorption to recover oil from OBM cuttings. The technological process includes viscosity reduction in heated gas, cyclone deoiling, condensation and recycling of the exhaust, and separation of oil and water in the coalescer. Based on the analysis of the physicochemical properties and the oil distribution inside the OBM cuttings samples collected from the Chongqing shale gas field, we designed this cyclone oil desorption technology and built the pilot-scale equipment to conduct the deoiling experiments. The results showed that the deoiling efficiency of OBM cuttings improved as the processing time increased. To be precise, after 2.7 seconds of treatment, the oil content of the cuttings samples fell sharply from 17.9 to 0.16%, which is about one-half of the maximum allowable oil content in pollutants of 0.3%, specified in the national standard (GB 4284-84 1985) promulgated by the People’s Republic of China. The foundation of the technology is that the particles have a high-speedself-rotation (more than 30,000 rad/s) coupled with a revolution in the cyclone in which a generated centrifugal force removes the oil from the pores of the particles. This process is purely physical and involves no phase change of the oil, so it is free of chemical addition and high heating temperature. The application of this newly developed cyclone oil desorption technology is expected to lower the treatment costs, enhance the processing efficiency, contribute to the energy development, and eventually benefit the local environment where the shale gas exploitations take place.
Zhang, Jianping (Research Institute of Natural Gas Economy, PetroChina Southwest Southwest Oil and Gas Field Company) | Wang, Fuping (Research Institute of Natural Gas Economy, PetroChina Southwest Southwest Oil and Gas Field Company) | Pu, Yongsong (CNPC Chuanqing Drilling Engineering Well Test And Wokover Company Limited) | Li, Pu (Gas Company of Southwest Oil & Gasfield Company Petrochina) | Ma, Yingkai (Research Institute of Natural Gas Economy, PetroChina Southwest Southwest Oil and Gas Field Company) | Li, Zizi (Research Institute of Natural Gas Economy, PetroChina Southwest Southwest Oil and Gas Field Company)
Abstract After China's supply chain finance business has gradually matured in the consumer finance field, it has begun to extend to the industrial finance field. As a branch of industrial finance, the natural gas industry supply chain finance business has gradually developed, and the number of participants has gradually increased. The article mainly introduces the development status of natural gas supply chain financial services in China. Research has found that there are still many problems in the current industry development, such as the inability of effective collaboration among participants, and the inability to unify logistics, information flow, capital flow and energy flow in the industry. On this basis, the article studies the methods of blockchain technology to solve corresponding problems, and proposes the application ideas of blockchain technology in the field of natural gas supply chain finance, hoping to promote development by constructing a business model business architecture and technical architecture, This model can produce significant economic and social benefits, has a high theoretical feasibility, but there is no concrete examples at present. Finally, suggestions are made in five aspects, including strengthening the design of top-level systems, incorporating energy flows into the supply chain financial framework system, creating an open innovation atmosphere, enhancing technological progress, strengthening core corporate social responsibility, and promoting core corporate organizational innovation.
Shi, Xuewen (PetroChina Southwest Oil & Gas Field Company) | Tong, Yanming (Schlumberger China) | Liu, Wenping (PetroChina Southwest Oil & Gas Field Company) | Zhao, Chunduan (Schlumberger China) | Liu, Jia (PetroChina Southwest Oil & Gas Field Company) | Fang, Jian (CCDC Geological E&D Research Institute)
Abstract Ascertaining the characteristics of fracture system at different scales integratedly is very important for performing efficient exploration and development activities of specific shale gas reservoirs. In this paper, an area around 250 square kilometers in Changning Block of Sichuan Basin is taken as an example, which belongs to Chinese Shale Gas Development Demonstration Plot. Seismic structural interpretation was performed detailedly based on original seismic amplitude cube and derived edge-detection cubes, and then the technologies of finite element horizon flattening, orthogonal decomposition principal component analysis, seismic discontinuity patch auto-extraction and paleo-stress field inversion were applied, together with the existing regional geological understanding and fracture information in wells, to figure out the staging and grouping of fracture system at seismic scale (i.e., at large and middle scales), at the same time to clarify the regional tectonic evolution and its genetic relationship with fractures at different scales such as the ones revealed by seismic data and cores or image logs. The following conclusions were reached. (a) The tectonic movements affecting the development of fracture system in study interval mainly happened during Yanshanian-Himalayan periods, i.e., 3 compressional tectonic episodes which were nearly in S-N direction in Late Yanshanian period, in NNE-SSW direction in Early Himalayan period, and in NWW-SEE direction in Middle Himalayan period respectively. (b) The Late Yanshanian tectonic event primarily formed long-axis anticlines and synclines, thrust faults and fault-related fractures, all of which were nearly in E-W trending, and fold-related fractures in different directions. (c) The Early Himalayan tectonic event mainly formed genetically related conjugate fracture sets including strike-slip faults and shear fractures both in NNW and NE directions, and transverse extensional fractures. (d) The Middle Himalayan tectonic event chiefly formed thrust faults, and related fractures and folds in NNE~NE direction, and transverse extensional fractures. (e) Furtherly our work demonstrated that such kind of fracture system analysis was of great significance in building discrete fracture network, providing precautionary advice for drilling engineering, and optimizing completion program and field development plan, etc. Hence, integrated fracture system analysis at full scales to reach more meaningful and robust conclusions is essential work for unconventional resources evaluation and characterization.
Chen, Chi (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Wang, Shouxin (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Lu, Cong (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Wang, Kun (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Lai, Jie (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Liu, Yuxuan (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
Abstract Hydraulic fracturing technology provides a guarantee for effective production increase and economic exploitation of shale gas wells reservoirs. Propped fractures formed in the formation after fracturing are the key channels for shale gas production. Accurate evaluation of local propped fracture conductivity is of great significance to the effective development of shale gas. Due to the complex lithology and well-developed bedding of shale, the fracture surface morphology after fracturing is rougher than that of sandstone. This roughness will affect the placement of the proppant in the fracture and thus affect the conductivity. At present, fracture conductivity tests in laboratories are generally based on the standard/modified API/ISO method, ignoring the influence of fracture surface roughness. The inability to obtain the rock samples with the same rough morphology to carry out conductivity testing has always been a predicament in the experimental study on propped fracture conductivity. Herein, we propose a new method to reproduce the original fracture surface, and conductivity test samples with uniform surface morphology, consistent mechanical properties were produced. Then, we have carried out experimental research on shale-propped fracture conductivity. The results show that the fracture surfaces produced by the new method are basically the same as the original fracture surfaces, which fully meet the requirements of the conductivity test. The propped fracture conductivity is affected by proppant properties and fracture surface, especially at low proppant concentration. And increasing proppant concentration will help increase the predictability of conductivity. Due to the influence of the roughness of the fracture surface, there may be an optimal proppant concentration under a certain closure pressure.
Wang, Jianhua (CNPC Engineering Technology R&D Company Limited) | Zhang, Jiaqi (CNPC Engineering Technology R&D Company Limited) | Yan, Lili (CNPC Engineering Technology R&D Company Limited) | Cheng, Rongchao (CNPC Engineering Technology R&D Company Limited) | Ni, Xiaoxiao (CNPC Engineering Technology R&D Company Limited) | Yang, Haijun (CNPC Engineering Technology R&D Company Limited)
Abstract Oil-based mud (OBM) is the first choice for complex deep wells due to its advantages of high-temperature resistance, good lubrication and borehole stability. But barite sagging under ultra-high temperature during the long-time stationary completion operation may lead to serious problems in ultra-deep wells, for instance, pipe sticking, density variation and well control problems. In this paper, the influence of high-temperature and high-pressure (HTHP) on the performance of oil-based completion fluid was studied, and a model of rheological parameters was established with HTHP static sag law. The barite sagging stability was evaluated by a high temperature (220°C) and high pressure (100MPa) sag instrument. The results indicated that RM6 value and static shearing force were the main factors of affecting the settlement stability. The viscosity of the completion fluid significantly decreased with the increase of temperature, but increased with the increase of pressure. In addition, the relationship was also studied between HTHP rheology and atmospheric pressure rheology at 50°C. The results showed that when RM6 value was kept above 10, the sag stability factor (SF) of oil-based completion fluid was less than 0.52 at 190°C for 10 days, which proved a good high-temperature sag stability. Furthermore, the anti-high temperature property of oil-based completion fluid was improved through enhancing the temperature-resistance of the additives. And the high-temperature-resistant organic soil was introduced to raise the RM6 value and the static shearing force. Based on these solutions, the barite sag under high temperature of the oil-based completion fluid was prevented during drilling and completion operation in ultra-high temperature wells. The oil-based completion fluid was successfully used in Well Keshen 17 (175°C,7475 m) in Kuche piedmont structure and TT 1 well (210°C,6500 m) in Sichuan basin. The casing run smoothly, the oil-test operation was completed smoothly for 15 days, and no barite sag happened. It testified that the oil-based completion fluid had excellent of high-temperature sag stability. Therefore, this oil-based completion fluid is expected to be used widely in ultra-deep wells.
Xie, Bing (PetroChina Southwest Oil and Gas Company, Chengdu) | Lai, Qiang (PetroChina Southwest Oil and Gas Company, Chengdu) | Mo, Jing (Schlumberger, Chengdu) | Bai, Li (PetroChina Southwest Oil and Gas Company, Chengdu) | Luo, Wenjun (PetroChina Southwest Oil and Gas Company, Chengdu) | Wang, Dali (Schlumberger, Chengdu) | Wang, Yue (Schlumberger, Chengdu) | Li, Kaixuan (Schlumberger, Chengdu)
Abstract Predicted reservoir results from conventional methods didn’t match the production performance in GS B well block in the Lower Sinian Dengying dolomite formation. The predicted gas production of vertical well is around 500k m/day, but the real gas production is below 100k m/day. In GS A well block, the predicted gas production of vertical well is consistent with the real gas production around 500k m/day, and when meter cavie develops, test gas production can reach 1000k m/day. It suggests the biggest challenge is to clarify reservoir characterization in GS B well block. However, due to the limited resolution of conventional logs and strong heterogeneity of carbonate reservoir, conventional open hole logs and seismic data has limitation to provide the details of secondary pore and fractures to clarify reservoir characterization. The electrical image logs provide high resolution images with high borehole coverage. It can provide abundant information about secondary pore and fracture to identify dominant dissolution facies window. Through electrical image logs, secondary pore and fracture classification in 50 vertical wells were performed in the Lower Sinian Dengying dolomite formation. Five facies were detected based on electrical image logs, including vug facies (honeycomb vug facies, algal stromatolite vug facies and bedding vug facies), cave facies, fracture-vug facies, massive dense facies and dark thin layer dense facies. With the five facies and top interface constraints from seismic data, 3D dissolution facies model was created, which can show different dissolution facies window of GS A and GS B well block. The method in this paper reveals the reason of confliction and agree test gas production. The case study presents how to identify five dissolution facies based on high-resolution electrical image logs with core data calibration. Besides, 3D dissolution facies model is created to show dissolution facies window of GS B well block to optimize well trajectory deployment during the development stage. Better understanding of reservoir characterization was instructive for acid fracturing design of Dengying dolomite gas reservoir as well.