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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Abstract To obtain the actual gas-water relative permeability of the coalbed methane (CBM) reservoir and further deepen the cognition of the gas-water production law of multiple coal seams, a relative permeability calculation method based on production data inversion is constructed. Based on production data, historical fitting is carried out through the multiple coal seams whole process coupling flow model, and the basic physical parameters of each layer are inversed. Based on the obtained physical parameters, the productivity prediction of the whole production cycle is carried out. By calculating the average water saturation and gas-water relative permeability in each iteration time step, the average gas-water relative permeability curve of the reservoir in the target period is finally obtained. The results show that the calculation method proposed in this paper can realize the acquisition of the relative permeability curve in the given period. Compared with the input relative permeability curve, there is a reverse point on the output relative permeability curve that can represent the continuous production of desorption gas. Gas production is affected significantly by different types of initial input relative permeability curves, and is mainly influenced by the input relative permeability curve at the initial production stage. Under ±30% deviation, the average difference in cumulative gas production is 16.92% (3 years). During the production of CBM wells, the average water saturation was maintained at a high level. At the end of the production of multiple coal seams commingled production well, the average water saturation change is less than 15%. Restricted by high water saturation, the average relative permeability of the gas is always maintained at a low level, less than 0.1 at the end of production of actual production wells. The fundamental technical difficulty in realizing the initial high production and subsequent sustained and stable production of CBM wells lies in how to reduce the reservoir water saturation effectively and improve the relative permeability of the gas, so as to promote the desorption of adsorbed gas and the sustained CBM production.
Ding, Yan (CNPC Engineering Technology R&D Company Limited, Beijing, China) | Cui, Yi (CNPC Engineering Technology R&D Company Limited, Beijing, China) | Qing Xin, Qing (Research Institute of Oil & Gas Technology, PetroChina Changqing Oilfield Company, Xi'an, Shaanxi, China) | Xie, Yong Gang (Research Institute of Oil & Gas Technology, PetroChina Changqing Oilfield Company, Xi'an, Shaanxi, China) | Gao, Re Yu (CNPC Engineering Technology R&D Company Limited, Beijing, China) | Zhao, Fei (CNPC Engineering Technology R&D Company Limited, Beijing, China)
Identification of lithology from drilling cuttings is a key step for reservoir characterization. At present, the traditional method is to collect and analyze the cuttings by manual interpretation, which is subjective and time-consuming. In order to improve the accuracy, timeliness, and automation of identification of cuttings lithology, this paper completed lithology identification and classification through batch iterative training based on Resnet-34 network. Automated rock type identification from cuttings images captured by a given camera is the goal of this work. The main challenge in cuttings recognition is the similarity of color and grain size in two or different cuttings.
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.
Zhang, Shaohui (PetroChina Research Institute of Petroleum Exploration & Development, Beijing, China) | Huang, Weihe (PetroChina Research Institute of Petroleum Exploration & Development, Beijing, China) | Bi, Guoqiang (PetroChina Research Institute of Petroleum Exploration & Development, Beijing, China) | Zhang, Jianli (PetroChina Research Institute of Petroleum Exploration & Development, Beijing, China) | Zhang, Xiaohui (PetroChina Research Institute of Petroleum Exploration & Development, Beijing, China) | Wen, Hucheng (Engineering Supervision Department of Changqing Oilfield Company, Xi'an, China) | Ma, Changjun (Qinghai Oilfield Supervision Company, Dunhuang, China) | Bai, Junqing (Xi'an Petroleum University, Xi'an, China) | Li, Haijun (PetroChina Research Institute of Petroleum Exploration & Development, Beijing, China)
Abstract The drilling operation procedures are complicated and its risks are high. The unsafe behavior of well site personnel and the unsafe state of equipment and materials are the main causes of drilling accidents. At present, these are mainly supervised by drilling supervisors. The supervisors, who's supervising means are single, cannot achieve full coverage of on-site personnel, equipment and materials. In order to realize intelligent identification and warning of drilling operation risks, the intelligent risk identification and warning model for typical drilling operation scenes and its application are carried out. First of all, considering the influence of different environmental conditions, the approach of automatically generating image dataset based on machine learning is proposed, and the typical scene sample image database is established. Meanwhile, the typical scene risk identification model based on YOLOv5 algorithm is designed and established by introducing feature aggregation, loss function and attention mechanism, and the algorithm model is trained and tested by using neural network method. In addition, based on the risk identification of drilling operation, the approach of risk warning and feedback is put forward. Finally, a set of ablation experiments are designed to test the performance of the improved algorithm models in drilling well sites. By using the approach of automatically generating image dataset based on machine learning, the foreground and background images can be automatically fused, and the standardized collection and classified storage of well site video image data are realized, saving a lot of manpower labeling costs. With the use of the risk identification model of typical scenes, typical risks can be automatically identified, with the mAP of 90.3% and the response time of less than 2 seconds. Three ways of mobile phone short message, well site speaker and screen pop-up reminder have been developed to timely send the identified risks to relevant personnel. Through intelligent risk identification and processing, the operation risk is reduced, the operation quality is guaranteed, and the supervision efficiency and effect are improved significantly. The intelligent risk identification and warning models of typical drilling operation scenes are innovatively established by using the approach of combining the drilling operation risk identification theory and artificial intelligence technology, which solves the problem of intelligent risk identification and warning of typical drilling operation scenes, and provides theoretical and practical basis for the development of digital supervision management in the drilling operation.
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.
Guo, Hu (China University of Petroleum-Beijing and Sinopec Research Institute of Petroleum Engineering Co., Ltd) | Wang, Zhengbo (CNPC Research Institue of Petroleum Exploration and Development) | Dang, Sisi (PetroChina Xinjiang Oilfield Company) | Wen, Rui (PetroChina Changqing Oilfield Company) | Lyu, Xiuqin (Sinopec Northwest Oilfield Company) | Liu, Huifeng (CNPC Engineering Technology R&D Company Limited and CNPC R&D, DIFC Company Limited) | Yang, Meng (China University of Petroleum-Beijing)
Abstract Polymer flooding is very promising chemical enhanced oil recovery technique because it has been widely field tested in many oil fields and commercially applied in several countries in onshore reservoirs. The understanding of polymer flooding mechanisms is still developing, even though the principal mechanism was sweep efficiency increase due to reduced mobility ratio of water and oil due to reduced mobility of water. The incorporation of polymer flooding mechanisms and practical challenges make some projects fail to attain economical or technical goal. For offshore reservoirs, the polymer flooding becomes more difficult because of limited space and harsh reservoirs. Although there were hundreds of polymer flooding field tests in onshore reservoirs, polymer flooding in offshore reservoirs remains limited. In this paper, the previous onshore polymer flooding lessons and findings were briefly reviewed to look into the mechanisms which can guide the design of polymer flooding in offshore reservoirs. Then, the lessons learned from previous offshore reservoirs were reviewed. Advices were given to improve the field test performance. it is conclude that low concentration polymer solution with moderately-low viscosity should be injected into offshore reservoirs to keep displacing pressure between injectors and producers. The injected polymers should have good transportation ability which avoids the formation blockage. The optimum injection timing remains to be further investigated because the evidences. The injection rate should be controlled to avoid well casing damage which has been observed in onshore reservoirs. Except for Bohai oilfield, the formation blockage was not reported in offshore reservoirs. However, the microfracture can form in injectors which improved the injectivity of polymers as long as the injected polymers have good transportation capacity.
Xiao, Wenlian (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University (Corresponding author)) | Yang, Yubin (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Bernabé, Yves (Earth, Atmospheric and Planetary Sciences Department, Massachusetts Institute of Technology) | Lei, Qihong (PetroChina Changqing Oilfield Company) | Li, Min (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Xie, Qichao (PetroChina Changqing Oilfield Company) | Zheng, Lingli (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Liu, Shuaishuai (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Huang, Chu (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Zhao, Jinzhou (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Ren, Jitian (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
Summary A significant amount of associated gas has been produced from shale oil reservoirs in the Ordos Basin, northern China, in recent years, which has provided an opportunity for using low-cost, associated gas in enhanced oil recovery (EOR) projects. However, there are few other reports of EOR projects in shale oil reservoirs using associated gas, and a quantitative evaluation of the technique is needed. Therefore, we conducted associated gas and waterflooding experiments in shale oil samples at constant and gradually increasing injection pressure while monitoring the spatial distribution of movable and residual oil by means of nuclear magnetic resonance (NMR) technology. Before the injection experiments, we performed mercury intrusion tests and measured the NMR transverse relaxation time, T2, of fully saturated samples to characterize the pore-throat size distribution of rock samples. Furthermore, we established a novel and robust mathematical model based on a fractal description of the pore space and a capillary tube model to determine the lower limit of the pore radius of movable oil, rc, during gas- and waterflooding. We observed that the oil recovery factor at a low injection pressure (i.e., 0.6 MPa) during the associated gasflooding was lower than that during waterflooding under both constant pressure injection mode and gradually increasing pressure injection mode. However, the performance of associated gasflooding was greatly improved by increasing the injection pressure. High injection pressure indeed produced a higher oil recovery factor, thinner residual oil film thickness, and smaller rc during associated gasflooding than during waterflooding under both injection modes. These differences in behavior appear to be linked to dissimilarities in flooding mechanisms at high and low injection pressures. Our main conclusion is that associated gasflooding at high injection pressure (i.e., 6 MPa) has a better potential for enhancing the oil recovery factor than waterflooding in shale oil reservoirs.
Xu, Youjie (Chongqing University of Science and Technology (Corresponding author)) | Zuping, Xiang (Chongqing University of Science and Technology / School of Petroleum Engineering, Chongqing University of Science and Technology) | Yu, Mengnan (Liaohe Oilfield Company PetroChina)
Summary Vertical hydraulic fracturing is widely used to develop low-permeability gas reservoirs. Uneven distribution of formation permeability and stress leads to multiple-wing hydraulic fractures with different lengths, which results in the wellbore not being the center of the circular stimulated reservoir volume (SRV) region. Therefore, to simulate the wellbore pressure of this phenomenon, a semianalytical model of the off-center multiwing fractured well in radial composite gas reservoirs is presented and the corresponding solution method is shown. The model is verified with the numerical solution, and eight flow regimes can be distinguished under the ideal case, which includes bilinear flow, fracture interference, linear flow, radial flow of inner region, transition flow of inner region, and radial flow of inner region. Compared with the previous model in which the well is at the center of radial composite gas reservoirs, in this paper we present an obvious “step” after the inner region radial flow regime, which is related to the off-center distance and radius of the inner region. In addition, the effects of some important parameters (such as off-center distance, permeability mobility, inner region radius, and fracture distribution) on typical curves are discussed. Finally, field well testing data are used to verify the accuracy of the model.
Summary Elemental mercury (Hg) is a common trace contaminant associated with corrosion of infrastructure impacting exploration, production, and processing of commercial hydrocarbons. Presently lacking is a model for the quantitative prediction of Hg concentration in reservoir fluids, sufficiently reliable for process engineering applications and design of mitigation strategies to ameliorate the potential risk of Hg presence. In this paper, we present a thermodynamic equilibrium mineral-based model for predicting the solubility of mercury in hydrocarbons, Hg(org), at in-situ reservoir conditions. The model is based on literature experimental data on the solubility of Hg in a mixture of alkanes, in equilibrium with Hg, H2S, O2, cinnabar (HgS), and water. As the model inputs are based on the chlorite-pyrite-H2S model, its application should primarily be limited to clastic hydrocarbon-bearing reservoirs. A global data set of Hg in hydrocarbons reveals a remarkably strong association with the presence of humic coal in subsurface formations. Assuming that pure stoichiometric cinnabar (HgS) is stable at the reducing conditions typical of hydrocarbon reservoirs (i.e., aHgS = 1) results in an overestimation of Hg(org) solubility by up to three orders of magnitude relative to globally reported concentrations of mercury in natural hydrocarbons. A statistically robust match between model and observed concentrations of Hg(org) was achieved using an aHgS of 0.003, consistent with reported concentrations of Hg from pyrite (FeS2) in coals and hydrocarbon reservoirs. The model has been validated in a case study of reservoir Hg reported in the Gorgon North-1 well, North West Shelf (NWS), Australia. The dominant process of cinnabar precipitation is by oxidation, particularly in the near-surface environment where reduced Hg-bearing hydrocarbons mix with shallow oxygenated or acidic surface waters. Such processes are typical of the environments where most downhole fluid samples are collected during drilling, sampling, and cleanup of exploration and development wells. This leads to the invariable conclusion that much of the particulate mercury species, specifically HgS, collected with hydrocarbon fluid samples, are metastable with respect to the dissolved Hg(org) in hydrocarbons at reservoir conditions and should not be included in the estimation of total Hg (i.e., THg) in hydrocarbons. This hypothesis has been confirmed by an extended well test in the Minami-Nagaoka gas condensate field, where it was observed that Hg dissolved in produced water decreased to negligible levels over time, while the Hg(org) in the condensate liquid reached a stable value like what the new Hg(org) solubility model would predict for in-situ reservoir conditions.
Wang, Kai (College of Petroleum Engineering, China University of Petroleum (East China)) | Luo, Mingliang (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum (East China)) | Li, Mingzhong (College of Petroleum Engineering, China University of Petroleum (East China)) | Kang, Shaofei (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum (East China) (Corresponding author)) | Li, Xu (College of Petroleum Engineering, China University of Petroleum (East China)) | Pu, Chunsheng (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum (East China)) | Liu, Jing (College of Petroleum Engineering, China University of Petroleum (East China))
Summary Hydrolyzed polyacrylamide/chromium III [HPAM/Cr (III)]-acetate gel treatment is an effective way for conformance control and water shutoff in various mature reservoirs around the world. However, it encounters severe challenges in the fractured extralow permeability reservoirs with the performance varying between success and failure when channeling caused by through-type fracture exists. The through-type fracture channel that connected injection to production is formed by the connection of hydraulic and natural fractures. This research takes the extralow permeability reservoir in the Ordos Basin as the background, and under the characterization of HPAM/Cr (III)-acetate gel, the effect of a preflush crosslinker on improving gel-plugging performance was studied via experiment, and the corresponding gel-plugging process was optimized. Experimental results showed that the preflush crosslinker could effectively improve the blocking strength and stability of HPAM/Cr (III)-acetate gel for through-type, large-opening fractures. Moreover, a high-quality “gel wall” was formed based on the preflush crosslinker; it worked as a barrier within the fracture and was the key to successfully blocking the millimeter-opening fracture. Under the experimental conditions, the optimized plugging process was as follows: The crosslinker was preflushed 24 hours in advance, and the gelant was injected in three slugs, with the volume of the first slug being 0.5 pore volume (PV). A field trial conducted in Ansai Oil Field demonstrated the potential of HPAM/Cr (III)-acetate gel and its plugging capability of optimized plugging method based on the preflush crosslinker to block through-type water channeling. This research provides valuable experimental data and theoretical guidance for conformance control and water shutoff of HPAM/Cr (III)-acetate gel treatment in fractured extralow permeability reservoirs.