SPE Journal最新文献

{"title":"Experimental Investigation of a Modified Enzyme-Induced Carbonate Precipitation Solution for Sand Production Control Applications","authors":"A. Baig, Sulaiman A. Alarifi, Mohamed Mahmoud, M. Kamal, Mobeen Murtaza, Manar M. AlAhmari, Abdulmohsen Alhumam","doi":"10.2118/219447-pa","DOIUrl":"https://doi.org/10.2118/219447-pa","url":null,"abstract":"\u0000 Sand production is one of the major problems that can occur in an oil or gas well. Enzyme-induced carbonate precipitation (EICP) methods have recently emerged as possible environment-friendly solutions for enhancing loose sand consolidation and preventing it from being produced with the fluids to the surface. This work explores increasing the consolidated sand strength and its treatment procedure using a modified EICP. The study also examines the characterization of precipitation generated by microorganisms using a computed tomography (CT) scan. To consolidate the sand specimen, nine different solutions were prepared. The solutions were a mixture of urea, urease, CaCl2, MgCl2, and xanthan gum in varying quantities. X-ray diffraction (XRD) analysis was conducted to determine the type of calcium carbonate (or CaCO3) polymorph. The morphology of calcium carbonate precipitation in the sand sample was visualized through scanning electron microscopy (SEM) imaging. The strength of consolidated samples was determined by the scratch test. The baseline EICP solution was exposed to different curing temperatures, namely, 25°C, 70°C, and 90°C. Out of these temperatures, the sample cured at 70°C showed the maximum strength, while the ones cured at 25°C demonstrated the weakest strength. This outcome emphasizes how crucial temperature control is in determining the strength development of the samples. The results highlight the importance of evaluating how varying curing temperatures affect specimen performance as well as emphasizing the need for accurate temperature control during experimental setups. Interestingly, samples made with a combination of CaCl2 and MgCl2 salts exhibited more strength when compared with EICP solutions formulated with only one type of salt. The consolidated sample that was prepared with xanthan gum with a concentration of 3 g/L showed high strength at 70°C. Notably, this technique offers a cost-effective solution compared with other methods developed to address sand production-related failures in production equipment. Furthermore, CT scans prove to be a valuable tool for investigating the characterization of microbially induced precipitation, including calcite, dolomite, and other minerals. This research underscores the professional approach in evaluating the efficacy of xanthan gum and CT scans in the context of EICP applications.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139821747","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Liquid Flow Patterns and Particle Settling Velocity in a Taylor-Couette Cell Using Particle Image Velocimetry and Particle Tracking Velocimetry","authors":"Andres F. Velez, D. Kalaga, Masahiro Kawaji","doi":"10.2118/219459-pa","DOIUrl":"https://doi.org/10.2118/219459-pa","url":null,"abstract":"\u0000 Controlling the downhole pressure is an important parameter for successful and safe drilling operations. Several types of weighting agents (i.e., high-density particles), traditionally barite particles, are added to maintain the desired density of the drilling fluid (DF). The DF density is an important design parameter for preventing multiple drilling complications. These issues are caused by the settling of the dense particles, an undesired phenomenon also referred to as sagging. Therefore, there is a need to understand the settling characteristics of heavy particles in such scenarios. To this end, simultaneous measurements of liquid phase flow patterns and particle settling velocities have been conducted in a Taylor-Couette (TC) cell with a rotating inner cylinder and stationary outer cylinder separated by an annular gap of 9.0 mm. Liquid flow patterns and particle settling velocities have been measured using particle image velocimetry (PIV) and particle tracking velocimetry (PTV) techniques, respectively. Experiments have been performed by varying the rotational speed of the inner cylinder up to 200 rev/min, which is used in normal drilling operations. Spherical particles with diameters of 3.0 mm or 4.0 mm and densities between 1.2 g/cm3 and 3.95 g/cm3 were used. The liquid phases studied included deionized (DI) water and mineral oil, which are the basic components of a non-Newtonian DF with a shear-thinning viscosity. The DF is a mud-like emulsion of opaque appearance, which impedes the ability to observe the liquid flow field and particle settling in the TC cell. To address this issue, a solution of carboxymethyl cellulose (CMC) with a 6% weight concentration in DI water was used. This non-Newtonian solution displays shear-thinning rheological behavior and was used as a transparent alternative to the opaque DF. For water, PIV results have shown wavy vortex flow (WVF) to turbulent Taylor vortex flow (TTVF), which agrees with the flow patterns reported in the literature. For mineral oil, circular Couette flow (CCF) was observed at up to 100 rev/min and vortex formation at 200 rev/min. For CMC, no vortex formation was observed up to 200 rev/min, only CCF. The settling velocities for all particles in water matched with the particle settling velocities predicted using the Basset-Boussinesq-Oseen (BBO) equation of motion. For mineral oil and CMC, the results did not match well with the predicted settling velocities, especially for heavy particles due possibly to the radial particle migration and interactions with the outer cylinder wall.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"3 S4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139817239","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Application of Mode Superposition Method in the Recoil Response of Deepwater Drilling Risers after Emergency Disconnection","authors":"Yanbin Wang, Tian Luan, Deli Gao, Rui Li","doi":"10.2118/219455-pa","DOIUrl":"https://doi.org/10.2118/219455-pa","url":null,"abstract":"\u0000 How to effectively control the recoil response after an emergency disconnection is one of the core technical problems in ensuring the safe and reliable operation of a deepwater drilling riser. Currently, the theoretical analysis is based on a discretization model or numerical simulation, which ignores the continuity of the riser system and the coupling effects of load acting on the riser. To address this problem further, in this paper, we establish a mechanical model and control equation with infinite degree of freedom for riser recoil response, where the heave motion of the floating drilling platform, seawater damping, and the viscous resistance of drilling fluid discharge were taken into account. In addition, the correctness of the model and solving approach are verified against the Orcaflex software. On this basis, the influence of wave period, wave height, initial phase angle, and tension coefficient on the recoil characteristics are discussed. The success of riser emergency disconnection is related to the clearance between the lower marine riser package (LMRP) and the blowout preventer (BOP) and the axial force distribution of the riser. The influence of the above-mentioned factors on the riser recoil response is also complicated. On the basis of the assumptions put forward and the model established, some quantitative conclusions are drawn. This study is of reference significance for safety control of riser emergency disconnection operation.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"19 10","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139813542","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Quantitative Prediction of the Development and Opening Sequence of Fractures in an Ultradeep Carbonate Reservoir: A Case Study of the Middle Ordovician in the Shunnan Area, Tarim Basin, China","authors":"Yuntao Li, Wenlong Ding, Jun Han, Xuyun Chen, Cheng Huang, Jingtian Li, Shihao Ding","doi":"10.2118/219453-pa","DOIUrl":"https://doi.org/10.2118/219453-pa","url":null,"abstract":"\u0000 Quantitative prediction of reservoir tectonic fracture development characteristics, opening pressures, and opening sequences is critical in the exploration and development of oil- and gas-bearing reservoirs and thus has received widespread attention. Using numerical simulations of the paleostress field during the formation of tectonic fractures and the rock fracture criterion, we predict the development and occurrence of fractures in the Middle Ordovician Yijianfang Formation in the Shunnan region of the Tarim Basin, China. The local paleostress fields reflected by the mechanical properties and occurrence of tectonic fractures obtained from core descriptions, acoustic emission (AE) experiments, paleomagnetic experiments, sound velocity measurements, and borehole breakouts were used to determine the regional paleostress and in-situ stress. We established a geomechanical model by combining the mechanical parameters of the rocks with the finite element method (FEM), optimizing the boundary conditions with a self-adaptive constraint algorithm, and conducting numerical simulations of the in-situ stresses. Fracture occurrence and numerical simulation results of the in-situ stress field were used to determine the opening pressure (Pk) and opening sequence of the fractures. The level of fracture development decreases away from the strike-slip fault in the study area. Fracture development is positively correlated with the Young’s modulus, paleostress difference, and paleostress difference coefficient of the rock. The direction of the maximum horizontal principal stress is from north-northeast (NNE) to northeast (NE). Initially, shear fractures and tensional fractures oriented NNE 30°–35° and NE 40°–45°, respectively, open during the water injection process. Pk is positively correlated with the horizontal stress difference coefficient and the angle between the fracture strike and the maximum horizontal principal stress. At the structural highs (burial depths shallower than 6450 m) and the structural lows (burial depths deeper than 6450 m), the burial depth correlates negatively and positively with Pk, respectively. This investigation of the development, occurrence, Pk, and opening sequence of tectonic fractures and their principal controlling factors will have a positive impact on the future exploration and production opportunities of similar fractured reservoirs.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"44 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139878317","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Fractal and Multifractal Characteristics on Pore Structure of Coal-Based Sedimentary Rocks Using Nuclear Magnetic Resonance","authors":"Na Zhang, Shuhui Guo, Shuaidong Wang, Yizhuo Tong, Zheng Li, Jiaqi Wu","doi":"10.2118/219457-pa","DOIUrl":"https://doi.org/10.2118/219457-pa","url":null,"abstract":"\u0000 Unconventional reservoirs have nanoscale pores, complex pore structures, and heterogeneity that directly affect reservoir storage performance and fluid transport capacity. In this study, shale, mudstone, and sandstone, three typical coal sedimentary rocks from the Daqiang coal mine in the Tifa Basin, were selected for nuclear magnetic resonance (NMR) and scanning electron microscopy (SEM) investigation, with the aim to investigate the pore structure and multifractal characteristics of the coal sedimentary reservoirs and to qualitatively analyze the effects of the physical property parameters and the mineralogical compositions on the multifractal parameters. The distribution data of the NMR T2 spectra were analyzed. The results showed that (1) SEM analysis concluded that the pore system of the three different lithological samples (mudstone, shale, and sandstone) was dominated by mineral matrix pores (i.e., intergranular and intragranular pores) and in the sandstone samples, there were only a few biological pores found. (2) The distribution of the NMR T2 spectrum peaks indicates that the sandstone and shale T2 spectra are bimodal, dominated by micropores, and contain a small number of transitional pores; most of the T2 spectra of mudstone are single peaks in distribution, mainly dominated by micropores. (3) Multifractal parameters are positively correlated with porosity and significantly negatively correlated with permeability; multifractal parameters are significantly positively correlated with the content of clay minerals and kaolinite, which suggests that the increase in clay minerals and kaolinite content enhances the heterogeneity of the pore space. The negative correlation with the content of quartz suggests that the enrichment of quartz reduces the irregularity of the pore space.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"25 12","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139887095","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Computational Fluid Dynamics Modeling and Analysis of Axial and Radial Temperature of Wellbore during Injection and Production Process","authors":"Jie Zheng, Zhihao Hu, Weixiao Wang, Yihua Dou, Jiahui Li, Xu Yang, Yarong Zhang, Yinping Cao","doi":"10.2118/219467-pa","DOIUrl":"https://doi.org/10.2118/219467-pa","url":null,"abstract":"\u0000 To solve problems such as additional tubing/casing load, casing deformation, and packer failure caused by changes in annular temperature during oil and gas reservoir fracturing and production, based on the well structure of oil and gas reservoirs and transition transient heat transfer mechanism, a four-field coupling simulation model of the temperature field in the main fluid domain of the tubing, the temperature field in the solid domain of the tubing, the temperature field in the annular fluid domain, and the temperature field in the solid domain of the casing is proposed. Considering the coupling of fluid temperature, pressure, and physical parameters, boundary conditions are established based on reservoir characteristics, wellbore heat transfer characteristics, and fracturing and production conditions, and are compiled into Fluent software for simulation through the user-defined function (UDF) method. The effects of the temperature and flow rate of injected fracturing fluid and produced oil and gas on the distribution of the wellbore temperature field and temperature gradient are studied. The research results show that by applying D14-1 and D5-5 gas wells to the model, the simulated temperature is in good agreement with the measured wellbore temperature, and the maximum errors of the simulated values of the two different wells are 6.4% and 4.3%, respectively. As the injection and production operation time increase, the heat transfer between the wellbore and the formation gradually stabilizes. At this time, the injection and production flow rate have little impact on the wellbore temperature field, while the injection and production temperature have a greater impact on the wellbore temperature field. The injection and production temperature will cause changes in annular temperature and temperature gradient, leading to an increase or decrease in pressure within a limited annular volume, resulting in local stress on the tubing and casing. The research results can provide a theoretical basis for the analysis of the temperature field and pressure field of the wellbore during fracturing and oil and gas production, ensuring the safety and stability of fracturing and production.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"28 9","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139891588","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"On the Evaluation of Coal Strength Alteration Induced by CO2 Injection Using Advanced Black-Box and White-Box Machine Learning Algorithms","authors":"Qichao Lv, Haimin Zheng, Xiaochen Li, Mohammad-Reza Mohammadi, Fahimeh Hadavimoghaddam, Tongke Zhou, Atena Mahmoudzadeh, A. Hemmati-Sarapardeh","doi":"10.2118/218403-pa","DOIUrl":"https://doi.org/10.2118/218403-pa","url":null,"abstract":"\u0000 The injection of carbon dioxide (CO2) into coal seams is a prominent technique that can provide carbon sequestration in addition to enhancing coalbed methane extraction. However, CO2 injection into the coal seams can alter the coal strength properties and their long-term integrity. In this work, the strength alteration of coals induced by CO2 exposure was modeled using 147 laboratory-measured unconfined compressive strength (UCS) data points and considering CO2 saturation pressure, CO2 interaction temperature, CO2 interaction time, and coal rank as input variables. Advanced white-box and black-box machine learning algorithms including Gaussian process regression (GPR) with rational quadratic kernel, extreme gradient boosting (XGBoost), categorical boosting (CatBoost), adaptive boosting decision tree (AdaBoost-DT), multivariate adaptive regression splines (MARS), K-nearest neighbor (KNN), gene expression programming (GEP), and group method of data handling (GMDH) were used in the modeling process. The results demonstrated that GPR-Rational Quadratic provided the most accurate estimates of UCS of coals having 3.53%, 3.62%, and 3.55% for the average absolute percent relative error (AAPRE) values of the train, test, and total data sets, respectively. Also, the overall determination coefficient (R2) value of 0.9979 was additional proof of the excellent accuracy of this model compared with other models. Moreover, the first mathematical correlations to estimate the change in coal strength induced by CO2 exposure were established in this work by the GMDH and GEP algorithms with acceptable accuracy. Sensitivity analysis revealed that the Spearman correlation coefficient shows the relative importance of the input parameters on the coal strength better than the Pearson correlation coefficient. Among the inputs, coal rank had the greatest influence on the coal strength (strong nonlinear relationship) based on the Spearman correlation coefficient. After that, CO2 interaction time and CO2 saturation pressure have shown relatively strong nonlinear relationships with model output, respectively. The CO2 interaction temperature had the smallest impact on coal strength alteration induced by CO2 exposure based on both Pearson and Spearman correlation coefficients. Finally, the leverage technique revealed that the laboratory database used for modeling CO2-induced strength alteration of coals was highly reliable, and the suggested GPR-Rational Quadratic model and GMDH correlation could be applied for predicting the UCS of coals exposed to CO2 with high statistical accuracy and reliability.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":" 10","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139391651","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Simple Normalized Analytical Model for Oil Production of SAGD Process and Its Applications in Athabasca Oil Sands","authors":"Shengdong Wang","doi":"10.2118/218410-pa","DOIUrl":"https://doi.org/10.2118/218410-pa","url":null,"abstract":"\u0000 Since the late 1980s, when the Alberta Oil Sands Technology and Research Authority Underground Test Facility project first demonstrated the feasibility of the steam-assisted gravity drainage (SAGD) technology, many commercial SAGD projects were brought online in Western Canada. Now, many of these projects have late-life SAGD wells approaching their ultimate SAGD recovery factors. Although these projects have demonstrated highly variable production performance, there is an opportunity to use the industry production data to find what they have in common and develop a normalized SAGD model.\u0000 For this paper, we collected oil production history from several leading SAGD projects with late-life production in the Athabasca oil sands area and confirmed the three stages in an SAGD project lifespan: chamber rising, chamber spreading, and chamber falling stages. By normalizing the field data, all SAGD projects converged to one type curve, regardless of reservoir quality and operating conditions. Based on this observation, a new simple normalized model is derived to model the bitumen production in a typical SAGD process for Athabasca oil sands.\u0000 The new model bridges the gap between the existing SAGD analytical model and conventional decline analysis and provides oil production forecasts based on the inputs for the five-component recovery factor method defined in the Canadian Oil and Gas Evaluation Handbook(Society of Petroleum Evaluation Engineers 2018). The model has been applied to one of the thermal projects to history match the field production. By running a Monte Carlo simulation, this model further demonstrates its capability to capture the uncertainty of the production forecast for the project at different stages of SAGD operation. In addition, by properly modifying the type curve of the analytical model, a similar workflow can be used to model cases with special reservoir quality or different operational limitations.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":" 33","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139393065","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Effects of Drilling Number and Distribution on Fracture Using the Pulse Plasma on Tight Sand Reservoir","authors":"Zhaoxuan Li, Shuo Wang, Yi Pan, Rongqi Zhang, Jiajun Chen","doi":"10.2118/218413-pa","DOIUrl":"https://doi.org/10.2118/218413-pa","url":null,"abstract":"\u0000 The permeability of unconventional reservoirs is extremely low, resulting in their drainage area being limited to tens of feet. Therefore, researchers have developed an effective stimulation technology that can be used in combination with conventional hydraulic fracturing, namely, pulsed plasma fracturing technology. Pulsed plasma fracturing technology is an efficient and environmentally friendly auxiliary hydraulic fracturing stimulation technology. However, most existing studies have focused only on the effect of pulsed plasma fracturing on single wells, ignoring the effect of the number and distribution of wells drilled on pulsed plasma fracturing. In this paper, pulsed plasma fracturing is studied by a self-built pulsed plasma experimental platform and nonlinear finite element software. First, the generation and propagation mechanism of shock wave, fracture type, and stress field analysis of rock mass in pulsed plasma fracturing technology are discussed. The double-well experiment was carried out by using the experimental platform, and the fracture law of fractures under different wellhead distribution conditions was obtained. In addition, a multiwell mathematical model is established by using the combination of the Euler method and Lagrange method to simulate the interaction between fluid and solid, that is, arbitrary Lagrangian Eulerian (ALE) multimaterial fluid-solid coupling method and the influence of drilling times and wellhead distribution on pulsed plasma fracturing is discussed. Stress analysis shows that the rock is mainly affected by ground stress, liquid column pressure, and shock wave pressure. The experimental results show that the discharge voltage is positively correlated with the shock wave pressure on the rock. The distribution of different wellheads affects the distribution and length of fractures. The double-well experiment makes the fractures easier to fracture. The simulation results show that the fracture length in the connection direction of the two wells is longer, and the fracture length in the vertical direction is shorter. This shows that the number and distribution of drilling affect the initiation and propagation of fractures.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":" 8","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139391655","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"The Impact of Autonomous Inflow Control Valve on Improved Oil Recovery in a Thin-Oil-Rim Reservoir","authors":"S. Taghavi, H. Aakre, Seyed Amin Tahami, Britt M. E. Moldestad","doi":"10.2118/218393-pa","DOIUrl":"https://doi.org/10.2118/218393-pa","url":null,"abstract":"\u0000 Oil production from thin-oil-rim fields can be challenging as such fields are prone to gas coning. Excessive gas production from these fields results in poor production and recovery. Hence, these resources require advanced recovery methods to improve the oil recovery. One of the recovery methods that is widely used today is advanced inflow control technology such as autonomous inflow control valve (AICV). AICV restricts the inflow of gas in the zones where breakthrough occurs and may consequently improve the recovery from thin-oil-rim fields. This paper presents a performance analysis of AICVs, passive inflow control devices (ICDs), and sand screens based on the results from experiments and simulations. Single- and multiphase-flow experiments are performed with light oil, gas, and water at typical Troll field reservoir conditions (RCs). The obtained data from the experiments are the differential pressure across the device vs. the volume flow rate for the different phases. The results from the experiments confirm the significantly better ability of the AICV to restrict the production of gas, especially at higher gas volume fractions (GVFs). Near-well oil production from a thin-oil-rim field considering sand screens, AICV, and ICD completion is modeled. In this study, the simulation model is developed using the CMG simulator/STARS module. Completion of the well with AICVs reduces the cumulative gas production by 22.5% and 26.7% compared with ICDs and sand screens, respectively. The results also show that AICVs increase the cumulative oil production by 48.7% compared with using ICDs and sand screens. The simulation results confirm that the well completed with AICVs produces at a beneficial gas/oil ratio (GOR) for a longer time compared with the cases with ICDs and sand screens. The novelty of this work is the multiphase experiments of a new AICV and the implementation of the data in the simulator. A workflow for the simulation of AICV/ICD is proposed. The simulated results, which are based on the proposed workflow, agree with the experimental AICV performance results. As it is demonstrated in this work, deploying AICV in the most challenging light oil reservoirs with high GOR can be beneficial with respect to increased production and recovery.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"14 7","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139395603","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}