Lei, Zhengdong (Research Institute of Petroleum Exploration and Development, PetroChina) | Xie, Qichao (Exploration and Development Research Institute of ChangQing Oilfield Company) | Tao, Zhen (Research Institute of Petroleum Exploration and Development, PetroChina) | He, YouAn (Exploration and Development Research Institute of ChangQing Oilfield Company) | Zhu, Zhouyuan (China university of Petroleum) | Peng, Yan (China university of Petroleum) | Liu, Canhua (China university of Petroleum)
Waterflooding of fractured low permeability reservoirs are often associated with poor sweep and high water cut due to existence of natural fractures, hydraulic fractures, and artificially induced fractures. Therefore, reservoir simulation with coupled geomechanics and dynamic fractures is required for this application. In this work, we present the use of streamline-derived flux information to improve overall waterflooding performance in such complex simulation problems.
This work shows the waterflooding optimization workflow of a fractured low-permeability reservoir in ChangQing Oilfield, China. First, the finite difference simulator considering stress field and geomechanical properties is used to simulate the growth of dynamic fractures. Then, the newly formed fracture properties are included into the dual porosity/permeability reservoir simulation model. Afterwards, streamlines can be traced based on the velocity field of this model, which represent a snapshot of the inter-well fluxes. Finally, with the goal of minimizing field water production, we implement linear programming algorithms to optimize the waterflooding operation by considering the inter-well connectivity and well allocation factors.
Through reservoir simulation coupled with geomechanics, we have found that induced fracture growth rate is relatively limited at reasonable injection rate, which is also validated by field empirical observations. This can avoid fracture propagation and reduce the risk of rapid water breakthrough. We deploy our streamline tracing and linear programming based optimization program to work together with this simulation model. A controlled and cautious increase in injection rate has resulted in a positive production response in 28 producers in the pilot area. Reallocation of water to high-efficiency injectors improves sweep efficiency in the reservoir. Finally, the optimized scenario has resulted in more than 15% incremental swept volume as compared to the basic development case.
This work provides a comprehensive case study for better understanding the impact fracture growth on waterflooding performance in fractured low-permeability reservoirs. It further establishes the workflow of using streamline-based flux information for oil production optimizations in these complex simulation problems.
The basic objective of this course is to introduce the overview and concept of production optimisation, using nodal analysis as a tool in production optimisation and enhancement. The participants are exposed to the analysis of various elements that help in production system starting from reservoir to surface processing facilities and their effect on the performance of the total production system. Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Next, appropriate depth methods will be presented. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process.
Achieving zero harm has been the talk of the industrial sector to reduce harm to as low as possible. The management of health, safety, security and environment (HSSE) should not be stagnant. It is time to rethink and reassess how the industry can prepare, mitigate and respond to stay ahead of emerging technical, regulatory and societal challenges. This session will engage leaders to discuss opportunities and challenges, share experiences and lessons learnt, and on how technology and digitalisation may affect the quality and productivity of the work sites - all of which are critical in shaping the future of HSSE in the region. The current presentation date and time shown is a TENTATIVE schedule.
He, Youwei (China University of Petroleum, Beijing and Texas A&M University) | Chai, Zhi (Texas A&M University) | Huang, Jingwei (Texas A&M University) | Li, Peng (China University of Petroleum) | Cheng, Shiqing (China University of Petroleum) | Killough, John (Texas A&M University)
Although hydraulic fracturing enables economic production from tight formations, production rates usually decline quickly and result in low hydrocarbon recovery. Moreover, it is difficult for conventional flooding methods to provide enough energy supplement in the tight formations. This paper develops an innovative approach to enhance oil recovery from tight oil reservoirs through inter-fracture injection and production, including synchronous inter-fracture injection-production (SiFIP) and asynchronous inter-fracture injection-production (AiFIP). This improves flooding performance by transforming fluid injection between different wells to between adjacent fracture stages from the same horizontal well.
The multi-stage fractured horizontal well (MFHW) comprises of recovery fractures (RFs), injection fractures (IFs) and natural fractures. In all the cases demonstrated in this work, the odd fractures and even fractures are defined as RFs and IFs respectively. Fluid is injected into IFs from injection tubing, and hydrocarbon is recovered synchronously or asynchronously through oil tubing connecting to the RFs. To quantitatively evaluate the performance of SiFIP and AiFIP in tight oil reservoirs, reservoirs are simulated based on the compartmental embedded discrete fracture model (cEDFM). The production performance of different recovery methods is compared, including primary depletion, water flooding, CO2 flooding, water Huff-n-Puff, CO2 Huff-n-Puff, SiFIP (water), SiFIP (CO2), AiFIP (water), AiFIP (CO2). The AiFIP and SiFIP achieve higher cumulative oil production than other methods. AiFIP obtained the highest cumulative oil production, which is more than two times that of primary depletion. The AiFIP (CO2) obtained almost the same cumulative oil production with SiFIP (CO2) with only 50% of CO2 injection rates, and AiFIP (water) obtained 19.3% higher cumulative oil production than SiFIP (water) with only 50% of water injection rates. Therefore, AiFIP is also a better choice when CO2 or water resource is not abundant. Sensitivity analysis is carried out to discuss the impacts of fracture and injection parameters on cumulative oil production. The fracture spacing, fracture networks, and injection rates influence the production significantly, followed by injection-production schedule and fracture length. The recommended well completion schemes of AiFIP and SiFIP methods are also provided, which is significant for the potential application of the proposed methods. This work illustrates the feasibility of SiFIP and AiFIP to enhance hydrocarbon recovery in tight reservoirs.
Ding, Shuaiwei (National & Local Joint Engineering Research Center for Carbon Capture and Sequestration Technology, State Key Laboratory for Continental Dynamics, Northwest University) | Liu, Guangwei (CNOOC Research Institute) | Li, Peng (National Engineering Laboratory for Exploration and Development of Low-Permeability Oil & Gas Fields) | Xi, Yi (Exploration and Development Research Institute, Petro-China Changqing Oil Field Company Ltd) | Ma, Jinfeng (National Engineering Laboratory for Exploration and Development of Low-Permeability Oil & Gas Fields)
Oil reservoirs are considered good storage structures for CO2 geological storage. With the right selection of candidate reservoir, injection of CO2 into tertiary and depleted oil reservoirs can result in enhanced oil recovery (EOR) and permanent sequestration of CO2 underground. The selection of candidate reservoirs for future CO2-EOR and storage projects mainly depends on storage potential evaluation. The aim of this work is to estimate the storage potential of CO2 stored in tertiary (CO2-EOR) and depleted oil reservoirs. In tertiary oil reservoirs, a method to estimate the geological CO2 storage capacity (CO2SC) in the reservoir during well open operations (EOR operations), which is a function of reservoir parameters, original geological reserves and oil volume factor is first built. In depleted oil reservoirs, a method to calculate the CO2SC in the reservoir during well shut down operations, which is based on the material balance method is proposed. In both cases, the methodology of storage capacity of CO2 dissolved in remaining oil, formation water and by mineral trapping is presented based on the model established by
Yu, Haiyang (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Chen, Zhewei (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Yang, Zhonglin (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Cheng, Shiqing (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | He, Youan (Research Institute of Exploration and Development, Petro China Changqing Oilfield Company) | Xian, Bo (Development Department, Tarim Oilfield Company, PetroChina)
Poor energy supplement and low hydrocarbon recovery are the two main shortcomings for water or gas injection in tight oil reservoir development. Horizontal well flooding can improve oil recovery and sweep efficiency of water flooding. However, the economic benefits need to be considered for long horizonal well injection. Based on a case of Changqing Oil filed, this paper presents a novel development approach, Allied In-Situ Injection and Production (AIIP), for fractured horizontal wells to increase hydrocarbon recovery, and explores its feasibility with simulation work, compared with traditional water flooding method. The impact for the existence of natural fractures in tight oil reservoir is also studied in this work. Although requiring costly special equipment, a series of simulations prove that AIIP is a more reliable and efficient approach to increase the performance of fractured horizontal wells compared to conventional methods, oil recovery and oil rate were improved significantly after AIIP was conducted. Water injectivity increased sharply than traditional water flooding with a lower injection pressure. The existence of natural fracture in tight oil formation improved the water flow inside the formation, leading better sweep efficiency and higher oil recovery factor. However, water cut in producers increased faster in natural facture enriched model than that of basic model. Thereforem it is essential to evaluate the performance of AIIP process before application.
Luo, Le (China University of Petroleum Beijing) | Cheng, Shiqing (China University of Petroleum Beijing) | Dai, Li (China University of Petroleum Beijing) | Wang, Yang (China University of Petroleum Beijing) | Zhang, Jiaosheng (Research Institute of Exploration and Development, Changqing Oilfield Company, CNPC) | Ma, Changlin (Research Institute of Exploration and Development, Changqing Oilfield Company, CNPC) | Yu, Haiyang (China University of Petroleum Beijing)
Propping agents inside hydraulic fractures perform significant role in constructing high-speed flow channel to deliver fluids into wellbore. However, proppant transport in fracture is always influenced by many factors, resulting unpropped fracture. Under such situation, this paper proposes a novel pressure-transient analysis method to better interpreted created fracture properties. The application of signal amplification technology is conducted on pressure transient analysis to deal with non-uniqueness problems. Aiming at transient linear flow, trilinear flow model in fractured wells is further modified and upgraded to characterize unpropped segments. Based on the solutions, this study applied signal amplification technology to extract weak-signals to assist early-time pressure transient analysis. The new type curves regarding with pressure response in partially unpropped fracture is then generated to capture the characteristics of this phenomenon. Subsequently, sensitivity analyses make clear the effects of key parameters on pressure response, which shows the superiorities of the new type curves in pressure transient analysis. The approaches proposed by this paper undoubtly will help solve inverse problems of wells exhibiting long-period linear flow in tight reservoirs.
Liu, Guoqiang (PetroChina Exploration and Production Company) | Hou, Yuting (PetroChina Changqing Oilfield Company) | He, Junling (PetroChina Jilin Oilfield Company) | Zhang, Hao (PetroChina Xinjiang Oilfield Company) | Wu, Jinlong (Schlumberger) | Zhao, Xianran (Schlumberger) | Li, Huayang (Schlumberger) | Wu, Fangfang (Schlumberger) | Li, Shenzhuan (Schlumberger) | Wang, Yuxi (Schlumberger)
Most shale oil resources in China are lacustrine deposit. The reservoirs are usually characterized by complex lithology and high heterogeneity with various mineral compositions (quartz, carbonates, feldspars, pyrites and volcanic ash), total organic carbon and pore structure. How to delineate the shale oil reservoir, how to identify the ‘sweet spots’ and its distribution are the two major challenges and objectives for this study.
To answer the question, a systematic workflow was proposed by integrating the advanced logging technologies (such as nuclear magnetic resonance, micro-resistivity imager, spectroscopy data, array dielectric tool) with special core measurement data. Firstly, the shale oil reservoir was classified into different types according to the logging responses. Secondly, core samples were chosen from each type and sent out to lab for a series of core special experiments to test the microscopic properties. Finally, the advanced core analysis results and logging technologies were integrated to depict the characters of the different types of shale oil reservoirs from microscopic to macroscopic scale. And by comparing with testing data, the features of best shale oil reservoir type can be identified, and the distribution and potential of shale oil reservoir can be unraveled.
The new approach helped to get a thorough understanding of the shale oil reservoirs characteristics, such as lithology, mineral composition, pore types, pore size distribution, oil content, kerogen type and maturity of organic matter, organic carbon content and distribution. Six different kinds of shale oil reservoir facies were classfied from loging responses, inculding super high gamma ray siliceous shale, high gamma ray siliceous shale, high gamma ray argillaceous shale, high gamma ray tuffaceous shale, medium gamma ray siliceous shale and medium gamma ray argillaceous shale. High gamma ray siliceous shale and medium gamma ray siliceous shale are proved to be the best shale oil reserovir, which contains 2~8% of TOC, 2~12% of effective porosity, more than 50% of quartz content and high propotion of macropores.
The method proposed in this project has been implemented in many unconventional reservoirs in china to evaluate the resource potential and get a comprehensive understanding of the shale oil reservoir.
The wells tested based on the recommendation has got promising production after fracturing, which brought client big confidence for future exploration.
Wu, Zengzhi (CNPC Chuanqing Drilling Engineering Co. Ltd., Drilling & Production Engineering Technology Research Institute) | Zou, Hongjiang (CNPC Chuanqing Drilling Engineering Co. Ltd., Drilling & Production Engineering Technology Research Institute) | Wang, Yugong (CNPC Chuanqing Drilling Engineering Co. Ltd., Drilling & Production Engineering Technology Research Institute) | Wu, Long (CNPC Chuanqing Drilling Engineering Co. Ltd., Drilling & Production Engineering Technology Research Institute) | Li, Yong (CNPC Chuanqing Drilling Engineering Co. Ltd., Drilling & Production Engineering Technology Research Institute) | Xu, Yang (CNPC Chuanqing Drilling Engineering Co. Ltd., Drilling & Production Engineering Technology Research Institute) | Wang, Renfeng (CNPC Chuanqing Drilling Engineering Co. Ltd., Drilling & Production Engineering Technology Research Institute) | Meng, QingCong (CNPC Chuanqing Drilling Engineering Co. Ltd., Drilling & Production Engineering Technology Research Institute) | Jiang, Wenxue (CNPC Chuanqing Drilling Engineering Co. Ltd., Drilling & Production Engineering Technology Research Institute) | Wang, Suoliang (CNPC Chuanqing Drilling Engineering Co. Ltd., Drilling & Production Engineering Technology Research Institute) | Li, Shan (CNPC Chuanqing Drilling Engineering Co. Ltd., Drilling & Production Engineering Technology Research Institute) | Li, Dan (CNPC Chuanqing Drilling Engineering Co. Ltd., Drilling & Production Engineering Technology Research Institute)
With the development of Chang Qing Oilfield, the following technical problems are faced: the increasing proportion of the low-production and low-efficiency wells, the worse production of pertinence and effectiveness in conventional retreatments and a large amount of remaining oil between wells and layers. In this case, the technique of radial fracture network fracturing and deep plugging has been proposed. Meanwhile, the matching products which include variable viscosity diverting acid, micro expansion high strength plugging agent and temporary plugging agent (oil soluble, water soluble and anti-scale) have been developed as well. Nowadays, the retreatment technology has been successfully tested and popularized in Chang Qing oilfield. Compared with the conventional retreatments, these two technologies have remarkable effect on increasing production and prospective application.
Tang, Jizhou (Harvard University) | Zuo, Lihua (Texas A&M University) | Xiao, Lizhi (China University of Petroleum - Beijing) | Wu, Kan (Texas A&M University) | Qian, Bin (CNPC Chuanqing Drilling Engineering Co. Ltd) | Yin, Congbin (CNPC Chuanqing Drilling Engineering Co. Ltd) | Ehlig-Economides, Christine (University of Houston) | You, Xiangyu (The Chinese University of Hong Kong)
Rock layering, a critical factor in determining fracture height growth, is pervasive in the Silurian Longmaxi shale formation in the southwest of China. From field studies, engineers found that the created fracture height is lower than the required height even after they enhanced the pumping rate to a very high value. This paper introduces a coupled three-dimensional hydraulic fracture propagation model considering the effect of bedding layers and investigate the effect of shear displacements along the bedding planes on fracture height growth. Our fracture propagation models address rock deformation and fluid flow. Rock deformation is governed by a fully three-dimensional displacement discontinuity method (3D DDM). The fluid flow model employs a finite difference method able to capture fluid movement along vertical fractures and bedding planes. Additionally, a propagation criteria determines whether the fracture would penetrate bedding planes. The Longmaxi shale formation has characteristics of large burial depth, low porosity and multiple bedding layers that hamper reaching the target fracture height even after increasing the pumping rate and treatment size. Hence, our fracture propagation model is applied to study the effect of bedding layers on fracture height growth. In this paper, we selected two different fracture geometries and analyzed profiles of fracture width, pressure and two types of shear displacement discontinuities. From numerical investigations, we found that the maximum width can be obtained at the junction after the vertical fracture penetrates the bedding planes as a result of the decrement of the compressive stress acting on the bedding planes. As the fracture penetrates the bedding planes, a certain amount of fluid would leak into the planes, which leads to fracture height containment. Moreover, the slope utilized for characterizing the correlation between leak-off volume and fracture height, is regarded as a tool to identify the number of BPs that fracture penetrates through. This paper illustrates the extensive application of our coupled hydraulic fracture propagation model for the Silurian Longmaxi shale formation with multiple bedding layers. Shear displacements along the bedding planes are regarded as a primary mechanism of fracture height containment.