The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Guan, Xu (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Zhu, Deyu (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Tang, Qingsong (PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Wang, Xiaojuan (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Wang, Haixia (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Zhang, Shaomin (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Deng, Qingyuan (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Yu, Peng (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Yu, Kai (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Huang, Xingning (Downhole service company of Xibu Drilling Engineering Company Limited, Karamay, China) | Xu, Hanbing (CNPC, International HK LTD Abu Dhabi, Abu Dhabi, UAE)
Abstract In recent years, tight sandstone gas as one of the important types of unconventional resources, has been rapid explored and developed. There are large-scale tight sandstone gas production in Sichuan Basin, Ordos Basin, Bohai Bay Basin, Songliao Basin and other basins, and it has become a key part in the area of increasing gas reserves and production in China. Due to the influence of the reservoir characteristics, tight gas reservoirs have low porosity and permeability, and the tight gas can only be effectively developed by improving the conductivity around the wellbore. Therefore, it is required to perform hydraulic fracturing after the completion of horizontal well drilling to improve the permeability of reservoir. It can be seen that hydraulic fracturing is the core technology for efficient development of tight gas resources. The implementation of hydraulic fracturing scheme directly determines the horizontal well production and EUR. This paper describes the workflow of 3D geomechanical modeling, technical application for Well YQ 3-3-H4 reservoir stimulation treatment, and carries out hydraulic fracture propagation simulation research based on 3D geomechanical model. This paper also compares the micro-seismic data with the simulation results, and the comparison results show that the propagation model is consistent with the micro-seismic monitoring data, which verifies the accuracy of the model. This paper clarifies the distribution law of hydraulic fractures in the three-dimensional space of horizontal wells in YQ 3 block, and the research results can be used to provide guidance and suggestions for the optimization of fracturing design of horizontal wells in tight gas of Sichuan Basin.
Zhu, Jun (Vertechs Energy Group) | Zhang, Wei (Vertechs Energy Group) | Zeng, Qijun (Vertechs Energy Group) | Liu, Zhenxing (Vertechs Energy Group) | Liu, Jiayi (PetroChina Southwest Oil & Gas Field Company) | Liu, Junchen (PetroChina Southwest Oil & Gas Field Company) | Zhang, Fengxia (PetroChina Southwest Oil & Gas Field Company) | He, Yu (PetroChina Southwest Oil & Gas Field Company) | Xia, Ruochen (PetroChina Southwest Oil & Gas Field Company)
Abstract In the past decade, the operators and service companies are seeking an integration solution which combines engineering and geology. Since our drilling wells are becoming much more challenging than ever before, it requires the office engineer not only understanding well construction knowledge but also need learn more about geology to help them address the unexpected scenarios may happen to the wells. Then a novel solution should be provided to help engineers understanding their wells better and easier in engineering and geology aspects. The digital twin technology is used to generate a suppositional subsurface world which contains downhole schematic and nearby formation characteristics. This world is described in 3D modelling engineers could read all the information they need after dealt with a unique algorithm engine. In this digital twin subsurface world, the engineering information like well trajectory, casing program, BHA (bottom hole assembly) status, are combined with geology data like formation lithology, layer distribution and coring samples. Both drilling or completion engineers and geologist could get an intuitive awareness of current downhole scenarios and discuss in a more efficient way. The system has been deployed in a major operator in China this year and received lot of valuable feedback from end user. First of all, the system brings solid benefits to operator's supervisors and engineers to help them relate the engineering challenges with according geology information, in this way the judgement and decision are made more reliable and efficiently, also the solution or proposal could be provided more targeted and available. Beyond, the geology information from nearby wells in digital twin modelling could also provide an intuitional navigation or guidance to under-constructed wells avoid any possible tough layers via adjusting drilling parameters. This digital twin system breaks the barrier between well construction engineers and geologists, revealing a fictive downhole world which is based on the knowledge and insight of our industry, providing the engineers necessary information to support their judgement and assumption at very first time when they meet downhole problems. For example, drilling engineers would pay extra attention to control the ROP (rate of penetration) while drilling ahead to fault layer at the first time it is displayed in digital twin system, which prevent potential downhole accident and avoid related NPT (non-production time). The integration of engineering and geology is a must-do task for operators and service companies to improve their performance and reduce downhole risks. Also, it provides an interdisciplinary information to end user for their better awareness and understanding of their downhole asset. Not only help to avoid some possible downhole risks but also benefit on preventing damage reservoir by optimizing the well construction parameters.
Abstract The deep shale gas reservoir are high formation temperature and pore pressure in Sichuan Basin. Due to the unclear geomechanical characteristics of the reservoir, a large number of accidents occurred during the drilling operation. At the same time, the wellbore instability and frequent adjustment trajectory cause long drilling cycle, low drilling efficiency, and high drilling operation cost. To solve the above problems, the drilling mud weight is optimized based on the three-dimensional geomechanical research and by establishing the pore pressure, collapse pressure and fracture pressure (leakage pressure) models. The key technology of reducing drilling mud weight are used to significantly reduce the drilling mud loss. Field application shows that the mud weight is reduced from 2.15 g/cm to 1.87 g/cm, the average ROP increased by 44.1% from 8.4 m/h to 12.1 m/h, the average drilling operation cycle decreased by 40.7% from 54.2 days to 32.1 days, and the drilling performance and efficiency are significantly improved. The fine 3D geomechanical modeling technology has great promotion and reference significance for the performance and efficiency improvement of the deep shale gas horizontal well drilling operation in China.
Abstract Nowadays, the only economic and effective way to exploit shale reservoirs is multi-stage fracturing of horizontal wells. The backflow after fracturing affects the damage degree of a fracturing fluid to a formation and fracture conductivity, and directly influences a fracturing outcome. At present, the backflow control of the fracturing fluid mostly adopts empirical methods, lacking a reliable theoretical basis. Therefore, it is of positively practical significance to reasonably optimize a flowback process and control the flowback velocity and flowback process of a fracturing fluid. On the other hand, the previous research on the productivity of multi-stage fracturing horizontal wells after fracturing is limited, and an equation derivation process has been simplified and approximated to a certain extent, so its accuracy is significantly affected. Based on previous studies, this paper established a new mathematical model. This model optimizes the flowback velocity after fracturing by dynamically adjusting a choke size and analyzes and predicts the production performance after fracturing. To maximize fracture clean-up efficiency, this work builds the model for a dynamic adjustment of choke sizes as wellhead pressure changes over time. It uses a two-phase (gas and liquid) flow model along the horizontal, slanted and vertical sections. The forces acting on proppant particles, filtration loss of water, the compressibility of a fracturing fluid, wellbore friction, a gas slippage effect, water absorption and adsorption are simultaneously considered. With the theories of mass conservation, we build a mathematical model for predicting production performance from multi-fractured horizontal wells with a dynamic two-phase model considering dual-porosity, stress-sensitivity, wellbore friction, gas adsorption and desorption. In this model, the gas production mechanisms from stimulated reservoir volume and gas and water relative permeabilities are employed. Based on shale reservoir parameters, wellhead pressure, a choke size, a gas/liquid rate, cumulative gas/liquid production, cumulative filtration loss and a flowback rate are simulated. In the simulations, the influential factors, such as shut-in soak time of the fracturing fluid, forced flowback velocity, fracturing stages and fracture half-length after fracturing, are studied. It is found by comparison that in the block studied, when a well is shut in four days after fracturing, the dynamic choke size is adjusted with wellhead pressure changing over time, the fracturing stage is 11, and the fracture half-length is 350 meters, the fracture conductivity after flowback is the largest, and the productivity of the horizontal well is the highest.
Dong, K. (China National Petroleum Corporation) | Ding, J. (Department of Geology & Geophysics, Texas A&M University (Corresponding author)) | Hou, B. (College of Petroleum Engineering, China University of Petroleum-Beijing) | Wang, X. (China National Petroleum Corporation) | Kou, R. (Harold Vance Department of Petroleum Engineering, Texas A&M University)
Summary The Wufeng and Longmaxi shales of Sichuan Basin, Southwest China have been the primary targets for shale gas development. Because hydraulic fracturing and seismic interpretation require detailed characterization of formation mechanical properties, a sufficient understanding of anisotropy and elastic behavior in Wufeng and Longmaxi shales is necessary. In this study, we conducted Brazilian and triaxial tests and ultrasonic velocity measurements to characterize tensile and compressive strengths and P- and S-wave velocities, respectively. Shale samples were cored at a range of orientations relative to bedding and tested at multiple confining pressures, which allowed a detailed study of mechanical and velocity anisotropy, static and dynamic moduli. Our experimental work shows that Wufeng and Longmaxi shales possess similar compressive strength and associated anisotropy with other shale formations but apparently weaker tensile strength anisotropy and velocity anisotropy. These two shales also exhibit much lower static moduli than dynamic values, which are interpreted to be caused by compliant pores such as microcracks and fractures. Comparison between Wufeng and Longmaxi shales reveals distinct levels of heterogeneity. Wufeng shale shows more pronounced heterogeneity regarding measured tensile and compressive strengths as well as elastic moduli. These general characteristics of Wufeng and Longmaxi shales provide valuable first-order understanding regarding anisotropy, heterogeneity, and elastic behavior. Utilizing this understanding could help improve hydraulic fracture design and seismic data interpretation.
Hui, Gang (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing) | Gu, Fei (Department of Chemical and Petroleum Engineering, University of Calgary (Corresponding author))
Summary In recent decades, a remarkable increase in induced seismicity in the Western Canada Sedimentary Basin (WCSB) has been largely attributed to hydraulic fracturing (HF) operations in unconventional plays. However, a mitigation strategy concerning geological, geomechanical, and operational susceptibilities to HF-induced seismicity has not been well understood. This work proposes an integrated method to mitigate potential risks from HF-induced seismicity in the Duvernay play near Crooked Lake. The geological susceptibility to induced seismicity is evaluated first from site-specific formation pressure and a distance to the Precambrian basement. The regional in-situ stress and rock mechanical properties are then assessed to determine the geomechanical susceptibility to induced seismicity. Next, the operational factors are determined by comparing induced seismicity with operational parameters such as total injection fluids and proppant mass. It is found that regions with a low formation pressure (<60 MPa), a great distance from the base Duvernay to the Precambrian basement (>260 m), a low minimum principal stress (<70 MPa), and a low brittleness index (<0.45) tend to be induced-seismicity-quiescent regions. Finally, a multiple linear regression (MLR)-based approach is proposed by considering the relative importance of different parameters. The MLR analysis indicates that brittleness index, formation pressure, and total injection volume are the top three controlling factors. Three new horizontal wells are drilled and the MLR analysis of these wells using the three most important parameters is conducted. High-resolution monitoring results indicated that 95% of the induced events had a local magnitude of less than 2.0 during and after the HF operations (3-month time window and 5-km well-event distance), among which the maximum magnitude reached ML3.05 (
Qian, Cheng (China University of Petroleum, Beijing) | Rui, Zhenhua (China University of Petroleum, Beijing) | Liu, Yueliang (China University of Petroleum, Beijing) | Zhao, Yang (China University of Petroleum, Beijing) | Li, Huazhou Andy (University of Alberta) | Ma, An (Moscow State University) | Afanasyev, Andrey (Moscow State University) | Torabi, Farshid (University of Regina)
Abstract Injecting CO2 into reservoirs for storage and enhanced oil recovery (EOR) is a practical and cost-effective strategy for achieving carbon neutrality. Commonly, CO2-rich industrial waste gas is employed as the CO2 source, whereas contaminants such as H2S may severely impact carbon storage and EOR via competitive adsorption. Hence, the adsorption behavior of CH4, CO2, and H2S in calcite (CaCO3) micropores and the impact of H2S on CO2 sequestration and methane recovery are specifically investigated using molecular simulation. The Grand Canonical Monte Carlo (GCMC) simulations were applied to study the adsorption characteristics of pure CO2, CH4, and H2S, and their multi-component mixtures are also investigated in calcite nanopores to reveal the impact of H2S on CO2 storage. The effect of pressure (0-20 MPa), temperature (293.15-383.15 K), pore width, buried depth and gas mole fraction on the adsorption behaviors are simulated. Molecular dynamics simulations (MD) were performed to explore the diffusion characteristics of the three gases and their mixes. The amount of adsorbed CH4, CO2, and H2S enhances with rising pressure and declines with rising temperature. The order of adsorption quantity in calcite nanopores is H2S>CO2>CH4, whereas the order of adsorption strength between the three gases and calcite is CO2>H2S>CH4 based on the interaction energy analysis. At 10 MPa and 3215 K, the interaction energies of calcite with CO2, H2S, and CH4 are -2166.40, -2076.93, and -174.57 kcal/mol, respectively. The CH4-calcite and H2S-calcite interaction energies are dominated by van der Waals energy, whereas electrostatic energy predominates in the CO2-calcite system. The adsorption loading of CH4 and CO2 are lowered by approximately 59.47% and 24.82% when the mole fraction of H2S is 20% at 323.15 K, reflecting the weakening of CH4 and CO2 adsorption by H2S due to competitive adsorption. The diffusivities of three pure gases in calcite nanopore are listed in the following order: CO2 > H2S > CH4. The presence of H2S in the ternary mixtures will limit diffusion and outflow of the system and each component gas, with CH4 being the gas most affected by H2S. The CO2/CH4 mixture can be buried in formations as shallow as 1000-1500 m, but the ternary mixture should be stored in deeper formations. The effects of H2S on CO2 sequestration and CH4 recovery in calcite nanopores are clarified, which provides theoretical assistance for CO2 storage and EOR projects in carbonate formation.
Zhang, Fengyuan (China University of Petroleum, Beijing) | Zhang, Qiang (China University of Petroleum, Beijing) | Zhang, Zhengxin (China University of Petroleum, Beijing) | Rui, Zhenhua (China University of Petroleum, Beijing) | Liu, Yueliang (China University of Petroleum, Beijing) | Zhang, Wei (University of Calgary) | Zheng, Xiaojin (Princeton University) | Torabi, Farshid (University of Regina) | Afanasyev, Andrey (Moscow State University)
Abstract Experimental methods for core plug analysis are widely used to measure formation permeability under steady-state flow or unsteady state flow conditions, which provides important geoscience information on formation properties. However, typical laboratory techniques hardly reproduce the two-phase water and hydrocarbon storage and transport conditions that formation is subject to in reality. Accordingly, we presented an integrated experimental core analysis method for permeability measurement, which better reproduces these two-phase conditions. The proposed experimental method consists of two-phase fluid initialization and production test, during which the gas rate, liquid rate, and inlet/outlet pressure of the core plug are recorded simultaneously. After constructing with uniform distribution of gas and liquid, the core sample is transformed into a two-phase production process under the conditions of variable rate and sealed boundary. Rate transient analysis is performed to estimate formation permeability with the gathered two-phase rate decline and pressure data. A two-phase diagnostic plot and specialty plot are introduced to identify flow regimes and extract permeability from the slope of a straight line during the experimental data analysis. In this paper, commercial software is used to generate synthetic data for the production test of a core plug. The simulation of two-phase fluid initialization and production tests were conducted on core plugs. The simulation results show a unit-slope straight line on the generated diagnostic plot, which indicates a clear boundary-dominated flow (BDF) regime. By performing a straight-line analysis, we calculated the permeability of the core plug with the slope of straight-line period on specialty plot. The good match of the calculated permeability with the reference value confirms the accuracy of the proposed experimental method with the relative error less than 10%. In addition, the proposed two-phase core analysis method can enormously accelerate test-time, as the permeability of selected rock sample can be estimated in less than 10 minutes. Instead of measuring permeability only under the condition of single phase flow, this paper presents a laboratory technique that combines the experiment of small-diameter core production test under two-phase flow with rate transient analysis method. Unlike prior experimental techniques, the proposed method reproduces the more realistic condition of two-phase flow in the formation during permeability measurement. The two-phase core analysis method achieves the objective of accurate and fast characterization of formation permeability, which is a more "apples to apples" comparison between the fluid flow in the actual reservoir and the core plug.
Yunpeng, Wang (School of Petroleum Engineering, China University of Petroleum (East China)) | Tiankui, Guo (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum (East China)) | Ming, Chen (School of Petroleum Engineering, China University of Petroleum (East China)) | Zhanqing, Qu (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum (East China) (Corresponding author)) | Zunpeng, Hu (School of Petroleum Engineering, China University of Petroleum (East China)) | Jinhao, Cao (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum (East China)) | Dingwei, Weng (School of Petroleum Engineering, China University of Petroleum (East China))
Summary The uneven propagation of multifractures is a key factor restricting production growth due to stress shadow and heterogeneity. To date, limited-entry fracturing techniques, nonuniform perforation, and in-stage diversion have been commonly used to promote even multifracture growth. In this study, a fully coupled multiple pseudo-3D (P3D) fracture simulator has been developed to examine the competitive propagation of multifractures during multicluster fracturing in a horizontal well. The present model considers stress interaction among multiple fractures, perforation erosion, fluid distribution among clusters, and in-stage diversion. The results of the model are validated against the reference data. Using the model, a series of numerical simulations are performed to investigate multifracture propagation with nonuniform perforation and in-stage diversion fracturing. We estimate the value of stress interaction for different fractures and time based on the approximate solution of Perkins-Kern-Nordgren (PKN) fracture in the viscosity-dominated regime and improve the dimensionless parameter that characterizes the competition between stress interaction and perforation friction. The fluid distributes evenly when the dimensionless parameter is less than unity (perforation friction is larger than stress interference). Based on this dimensionless parameter, a method to design nonuniform perforation and in-stage diversion is proposed. Results show that in the case of homogeneous in-stage stress, the perforation parameters should be selected under the condition that the dimensionless parameter is less than unity. In the case of heterogeneous in-stage stress and based on the perforation parameters selected under homogeneous stress conditions, the perforation holes in the high-stress cluster should be increased, making the reduction of perforation friction equal to the value of the in-stage stress heterogeneity. The stress heterogeneity can be balanced by decreasing the perforation friction of the high-stress clusters. In this way, nonuniform perforation under heterogeneous in-stage stress conditions can be designed quantitatively without numerical simulation. For in-stage diversion treatment, a method to design the number of ball sealers is proposed based on the results of nonuniform perforation, and only several or even zero groups of simulation are necessary to find the optimal number of ball sealers. A series of numerical simulations shows that the proposed design method is reliable and achieves a satisfactory result in an actual field case. The results can be helpful for nonuniform perforation and in-stage diversion design for multicluster fracturing in a horizontal well.
Bachi, Hana (The University of Texas at Austin) | Wu, Jianfa (PetroChina Southwest Oil & Gas Field Company) | Liu, Chuxi (The University of Texas at Austin) | Yang, Xuefeng (PetroChina Southwest Oil & Gas Field Company) | Chang, Cheng (PetroChina Southwest Oil & Gas Field Company) | Yu, Wei (SimTech LLC) | Sepehrnoori, Kamy (The University of Texas at Austin)
Abstract Microseismic technology has proven its efficiency to monitor hydraulic fracturing effectiveness. The objective of this study is to develop a novel method to calibrate and generate the hydraulic fracture cluster-based model of a multi-stage horizontal shale well using the microseismic data. We use microcosmic numerical model known as Microseismic EDFM software feature (MSE-Frac) with the embedded discrete fracture model to simulate the hydraulic and natural fractures and the discrete fracture network. The MSE-Frac can handle the grouping of the clustered microcosmic events around the wellbore and generate a cluster-based model of the complex fractures network. Afterwards, we apply different factors on the hydraulic fractures, natural fractures, and the discrete fracture network to calibrate the fracture's geometry to match the historical data. This method allows us to determine the best parameters to be applied on this model to calibrate the hydraulic fracture geometry, and to find the fractures' characteristics for optimal production. Finally, we perform a production forecasting study for the next twenty years. Through this study, we develop a novel method to calibrate the complex hydraulic fracture geometry starting from the microseismic data. Four main parameters are investigated, namely, height and length cutoff, water saturation, compaction coefficient, and conductivity of the complex hydraulic fracture network. Multiple studies have been conducted to calibrate the geometry of the hydraulic fractures, but relatively less work is focused on utilizing the microseismic events even though they are largely available to most operators. Heretofore, there are no thorough studies on innovating a workflow to calibrate and position the fracture geometry starting from the microseismic events. Our models use more precise methodical approaches to simulate and calibrate the complex hydraulic fracture geometry based on microseismic events.