SPE Reservoir Evaluation & Engineering最新文献

{"title":"Modeling Two-Phase Flow in Tight Core Plugs with an Application for Relative Permeability Measurement","authors":"M. Yousefi, H. Dehghanpour","doi":"10.2118/214659-pa","DOIUrl":"https://doi.org/10.2118/214659-pa","url":null,"abstract":"\u0000 The two-phase flow of immiscible fluids in porous media has been studied for a long time in different disciplines of engineering. Relative permeability (kr) is one of the constitutional relationships in the general equation governing immiscible displacement that needs to be determined. Due to the complexity and nonlinear nature of governing equations of the problem, there is no unique model for relative permeability. The modified Brooks and Corey (MBC) model is the most common model for kr prediction. Here, a practical technique is presented to measure kr for low-permeability tight rocks. We use this experimental data to tune the empirical constants of the MBC model. The proposed method is based on a simple mathematical technique that uses assumptions of frontal advance theory to model the pressure drop along the core plug during two-phase immiscible displacement at constant injection flow rate. We make simplifying assumptions about the highest point on the observed pressure profile and use those assumptions to determine relative permeability of a tight rock sample. In the end, the amount of work for an immiscible displacement is calculated as the area under the pressure-profile curve. The effect of initial water saturation (Swi) and interfacial tension (IFT) is studied on the work required for an immiscible displacement. Using this concept, it is concluded that adding chemical additives such as surfactants to fracturing fluids can help the reservoir oil to remove the water blockage out of the rock matrix more easily while maintaining the flow rate at an economic level.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"1 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78642988","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Automatic Multiwell Assessment of Flow-Related Petrophysical Properties of Tight-Gas Sandstones Based on the Physics of Mud-Filtrate Invasion","authors":"M. Bennis, C. Torres‐Verdín","doi":"10.2118/214668-pa","DOIUrl":"https://doi.org/10.2118/214668-pa","url":null,"abstract":"\u0000 Petrophysical interpretation of borehole geophysical measurements in the presence of deep mud-filtrate invasion remains a challenge in formation evaluation. Traditional interpretation methods often assume a piston-like radial resistivity model to estimate the radial length of invasion, resistivities in the flushed and virgin zones, and the corresponding fluid saturations from apparent resistivity logs. Such assumptions often introduce notable inaccuracies, especially when the radial distribution of formation resistivity exhibits a deep and smooth radial front. Numerical simulation of mud-filtrate invasion and well logs combined with inversion methods can improve the estimation accuracy of petrophysical properties from borehole geophysical measurements affected by the presence of mud-filtrate invasion.\u0000 We develop a new method to quantify water saturation in the virgin zone, residual hydrocarbon saturation, and permeability from borehole geophysical measurements. This method combines the numerical simulation of well logs with the physics of mud-filtrate invasion to quantify the effect of petrophysical properties and drilling parameters on nuclear and resistivity logs. Our approach explicitly considers the different volumes of investigation associated with the borehole geophysical measurements included in the interpretation. The new method is successfully applied to a tight-gas sandstone formation invaded with water-base mud (WBM). Petrophysical properties were estimated in three closely spaced vertical wells that exhibited different invasion conditions (i.e., different times of invasion and different overbalance pressures). Available rock-core laboratory measurements were used to calibrate the petrophysical models and obtain realistic spatial distributions of petrophysical properties around the borehole. This approach assumes that initial water saturation is equal to irreducible water saturation. Based on the calibrated petrophysical models, thousands of invasion conditions were numerically simulated for a wide range of petrophysical properties, including porosity and permeability. Based on the large data set of numerical simulations, analytical and machine-learning (ML) models were combined to infer unknown rock properties in each well. Mean-absolute-percent errors (MAPE) of the analytical and ML models for the estimation of water saturation in the virgin zone are 5% and 2%, respectively, while the MAPE of the analytical models for the estimation of residual hydrocarbon saturation is 10%. Synthetic and field examples are examined to benchmark the successful application and verification of the new interpretation method. Estimates of water saturation in the virgin zone using the new method are in good agreement with core-based models.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"143 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80328579","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Evaluation of ATBS Polymers for Mangala Polymer Flood","authors":"Vivek Shankar, Robert Zagitov, S. Shekhar, A. Gupta, M. Kumar, Ritesh Kumar, Santhosh Veerbhadrappa, P. Nakutnyy","doi":"10.2118/211461-pa","DOIUrl":"https://doi.org/10.2118/211461-pa","url":null,"abstract":"\u0000 Mangala field has been under polymer flood since 2015. The polymer flood has been more successful in accelerating recovery compared to waterflood. As the flood matured, field performance indicated that part of the injected polymer was degrading in the reservoir. Laboratory studies and polymer samples collected from the reservoir suggest that the most likely reason for the degradation is increased hydrolysis due to thermal aging. This degradation compels higher dosing of polymer to make up for the lost viscosity and increases operating costs. Polymer precipitation in the reservoir may also lead to loss of reservoir permeability.\u0000 Literature surveys and preliminary laboratory studies showed that polymers with acrylamide-tertiary-butyl-sulfonic acid monomer units (referred to as ATBS polymers) could be a suitable option for Mangala. To evaluate the hypothesis, the team did a series of laboratory and coreflood studies. The studies include accelerated thermal ageing, rheology, dynamic adsorption, injectivity, waterflood with fresh and degraded samples, and compatibility studies with topside chemicals. Two hydrolyzed polyacrylamide (HPAM) polymers with different degrees of hydrolysis (DOH) and two ATBS polymers were evaluated. The selected ATBS polymer was then tested for compatibility with surface topside chemicals.\u0000 The studies show that the classic 20 to 25% DOH HPAM suffers viscosity degradation and possible precipitation in Mangala reservoir conditions. ATBS polymers and a lower DOH HPAM provide superior results to the incumbent HPAM with an acrylamide (AM) (86)-ATBS (14) copolymer providing the best results. ATBS polymers were especially resistant to cloudpoint lowering and provide some superiority in shear degradation. The ATBS monomer was resistant to hydrolysis during the period of testing. Contrary to the published literature, ATBS polymers showed higher adsorption and their propagation through cores required a higher pressure drop. ATBS polymer seemed to plug a low-permeability section of the core stack. All polymers reach their peak viscosity at 30 to 40% hydrolysis and decline sharply after 40%, but viscosity and cloudpoints measured during accelerated aging are possibly conservative. A large-scale pilot of ATBS injection in Mangala is under way to validate the laboratory test results.\u0000 ATBS polymer can be a suitable polymer for some layers of Mangala with a high residence time and permeability. The choice is driven by the economics of the incremental cost of ATBS for the benefits it offers. In some sands with shorter interwell spacing, a lower DOH HPAM may be a more cost-effective solution.\u0000 The study results in this paper provide insights to operators to understand the reservoir performance of existing polymer floods and plan for future polymer floods.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"136 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76451976","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Discrete Measurements of the Least Horizontal Principal Stress from Core Data: An Application of Viscoelastic Stress Relaxation","authors":"K. McCormack, J. McLennan, E. Jagniecki, B. McPherson","doi":"10.2118/214669-pa","DOIUrl":"https://doi.org/10.2118/214669-pa","url":null,"abstract":"\u0000 The emerging Paradox Oil Play in southeastern Utah is among the most significant unconventional plays in the western USA. The mean total undiscovered oil resources within just the Pennsylvanian Cane Creek interval of the Paradox Basin are believed to exceed 215 million barrels. However, to date, less than 5% (~9 million barrels) of the total Cane Creek resource has been produced from fewer than 40 wells, and only approximately one-half of those are horizontal wells. More than 95% of production is from the central Cane Creek Unit (CCU). Natural fractures are a key feature of many production wells, but stimulation by induced hydraulic fractures is not consistently successful. We hypothesize that more effective production in this play will rely on better fundamental characterization, especially on better quantification of the state of stress. Approximately 110 ft of core, well logs, and a diagnostic fracture injection test (DFIT) were acquired from the State 16-2 well within the CCU. With these data, we applied two methods to constrain and clarify the state of stress. The first technique, the Simpson’s coefficient method, provides lower bounds on the two horizontal principal stresses and relies on only limited data. Alternatively, the viscoelastic stress relaxation (VSR) method is used to estimate the least horizontal principal stress, building on observations that principal stresses become more isotropic as the viscous behavior of a rock is more pronounced. Results of these two methods support the hypothesis that the state of stress in the CCU of the Paradox Basin is nearly lithostatic and isotropic. Other factors consistent with this hypothesis include high formation pore pressure, which tends to reduce the possible stress states by changing the frictional failure equilibrium; lack of induced fractures in the core, which should be present in the case of stress anisotropy; and interbedded halite layers, which given their high degree of ductility, probably lead to greater VSR for the entire sedimentary package.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"83 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83808685","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Active Fault Detection by an Automatic Breakout Geometry Characterization Algorithm from Ultrasonic Borehole Imager","authors":"Hamid Heydari Gholanlo, M. Nikkhah","doi":"10.2118/214673-pa","DOIUrl":"https://doi.org/10.2118/214673-pa","url":null,"abstract":"\u0000 An underground stress state might be disturbed in an area, particularly adjusting to an active shear zone. Borehole breakouts (BOs) that appeared in a circular hole excavated in an inhomogeneous stress field might be tracked to identify the active shear zone. The present study aims to develop the breakout morphology analysis (BMA) algorithm to exploit the valuable attributes of borehole BOs including azimuth, width, and intensity (depth of elongation) of failure from wellbore ultrasonic imaging tools. In the current study, the extracted azimuthal information was surveyed to detect the active shear zone along the well. Ultrasonic data from five wells drilled in the doubly plunging Ahvaz Anticline located in Iran were collected for the purpose of algorithm verification. The multiwell correlation of the BOs’ azimuth generated by the algorithm in the Ahvaz Anticline suggests a shear plan dipping southwest-northeast direction is possibly active in the deep vertical wells. Similarly, the seismic reflection profile of the Ahvaz Anticline shows a track of detachment faulting system in the mid-Cretaceous sediments. The finding confirms that the raw ultrasonic traveling time is more applicable than other borehole image data, such as static and dynamic images of ultrasonic amplitude, in BO characterization.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"10 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90954568","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Improving Prediction of Fracture Distribution Using Microseismic Data and Acoustic Logging Measurements","authors":"Yilin Liu, Guozhong Gao","doi":"10.2118/214677-pa","DOIUrl":"https://doi.org/10.2118/214677-pa","url":null,"abstract":"\u0000 The complex fracture network from hydraulic fracturing can significantly improve oilwell productivity, so it is widely used in the field of unconventional reservoir development. However, accurate evaluation of the fracture spatial distribution remains a challenge. As a result, how to combine a variety of data to avoid data islands and identify and predict the space of fracture zone is of great importance. In this paper, we present a method and workflow based on the microseismic (MS) data combined with shear wave velocity data to estimate the physical parameters of subsurface media and improve the description and prediction accuracy for hydraulic fractures. The method analyzes MS events to construct the fracture spatial distribution and uses acoustic logging measurements to correct the magnitude of MS events and enhance the resolution. The corrected MS magnitude is mapped to the MS event space for Kriging interpolation analysis to predict the improved spatial distribution of fractures, which is available in the format of a 3D cloud image.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"53 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82699589","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Systematical Review of the Largest Polymer Flood Project in the World: From Laboratory to Pilots and Field Application","authors":"X. Lu, W. Li, Y. Wei, J. Xu.","doi":"10.2118/210298-pa","DOIUrl":"https://doi.org/10.2118/210298-pa","url":null,"abstract":"\u0000 This paper presents a systematical review of the largest polymer flood project in the world, applied to multilayered, heterogeneous sandstone reservoirs in the giant Daqing Oilfield in China. First, reservoir and fluid characteristics are highlighted to understand the heterogeneity of the reservoir. Next, the project history is summarized, including laboratory studies, pilot tests, commercial tests, and fieldwide applications. Third, typical polymer flood performance and reservoir management measures are presented. Finally, key understandings and lessons learned from more than 50 years of experience are summarized.\u0000 The La-Sa-Xing Field in the Daqing Field Complex contains three types of reservoir sands: Type I sand with high permeability, Type II sand with medium permeability, and Type III sand with low permeability. Polymer flood was studied in the laboratory in the mid 1960s, followed by small-scale pilots beginning in 1972 and industrial-scale pilots starting in 1993, all of which successfully reduced water cut and enhanced oil recovery. Fieldwide application commenced in 1996, targeting the Type I sand. With Type II sand being brought onstream in 2003, the project achieved a peak production of 253,000 BOPD in 2013. Polymer flood reduced water cut by 24.8%. Reservoir management measures, such as zonal injection, profile modification, hydraulic fracturing in low-permeability sand, and injection optimization, proved to be effective. Based on the water-cut performance, production can be divided into four stages: (1) water-cut decline, (2) low water cut, (3) rebound, and (4) water chase. Fit-for-purpose improved-oil-recovery measures were implemented for each stage to improve production performance.\u0000 Key understandings and lessons learned include the following: (1) Polymer flood improves both sweeping and displacing efficiencies; (2) high interlayer permeability contrast leads to low incremental recovery; (3) variable well spacing should be adopted for different reservoir types; (4) adoption of large molecular weight (MW) and large slug size greatly enhances recovery; and (5) salt-resistant polymer is beneficial for produced water reinjection in Type II sand; (6) zonal injection increased swept reservoir zones by 9.8% and swept pay thickness by 10.3%; (7) profile modifications helped improve vertical conformance in injection wells and led to enhanced sweeping efficiency and extended low water-cut stage; and (8) optimization-recommended well spacing for Type I, Type II, and Type III sands is 10–15.5, 5.6–7.6, and 2.5–3.6 acres, respectively.\u0000 In comparison with generally 6–8% incremental recovery by polymer flood in the industry, this project achieved an impressive incremental recovery of 12%, enhancing the oil recovery factor from 40% by primary recovery and waterflood to 52% stock tank oil initially in place (STOIIP). The progressive approach from laboratory experiments through pilots and finally to field application is a best practice for app","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"7 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79479144","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A New Workflow for Improved Resistivity-Based Water Saturation Assessment in Organic-Rich Mudrocks: Application to Haynesville, Eagle Ford, and Woodford Formations","authors":"Sabyasachi Dash, Artur Posenato Garcia, Zoya Heidari","doi":"10.2118/214656-pa","DOIUrl":"https://doi.org/10.2118/214656-pa","url":null,"abstract":"Summary Reliable fluid saturation assessment in organic-rich mudrocks has been a challenge for the oil and gas industry. The composition and spatial distribution of rock components have a significant impact on electrical resistivity and, thus, on hydrocarbon reserves estimates. Clays are typically considered, in resistivity models, to be distributed in laminated or dispersed forms. Additionally, conventional resistivity models do not incorporate conductive components other than brine. Such assumptions can lead to uncertainty in fluid saturation assessment in organic-rich mudrocks. We introduce a well-log-based workflow that quantitatively assimilates the type and spatial distribution of all conductive components to improve reserves evaluation in organic-rich mudrocks and demonstrate its field application in the Eagle Ford, the Woodford, and the Haynesville formations. The introduced workflow consists of an inversion algorithm to estimate geometry-dependent parameters (depolarization factors or geometric model parameters) and water saturation. Inputs to the inversion algorithms include volume concentrations of minerals, estimated from the multimineral analysis. Other inputs are conductivity of rock components and porosity obtained from laboratory experiments and interpretation of well logs. The petrophysical model considers that brine forms the conductive background to which conductive (e.g., clay, pyrite, and kerogen) and nonconductive (e.g., grains and hydrocarbon) components are incorporated. The assumed/estimated petrophysical properties have an impact on the effective conductivity of the rock and thereby can impact the performance of the new resistivity-based method. We applied the new method to different organic-rich mudrock formations to test the universal nature of the method and its efficacy in organic-rich mudrock reservoirs with varying volumetric concentrations of minerals within the rock. We successfully applied the workflow to four wells in the Eagle Ford, the Woodford, and the Haynesville formations. The formation-by-formation inversion showed a variation in geometric model parameters in different petrophysical zones, resulting in improved water saturation estimates. A comparison of the results obtained from the new workflow against those from the Waxman-Smits and Archie models indicated a relative improvement in saturation estimates of 9.5 and 26.3% in the Eagle Ford formation. Similar improvements were noted in the Woodford and the Haynesville formations as well. The improvement can be enhanced in formations with larger fractions of conductive components. The results confirmed that the new workflow improves the reliability of water saturation estimates in organic-rich mudrocks, which has been a challenge for the oil and gas industry. In contrast to conventional techniques, the new method does not need water saturation obtained from core measurements for calibration efforts. All the parameters in the new workflow are geometry- or p","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"122 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136175337","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Small-Scale EOR Pilot in the Eastern Eagle Ford Boosts Production","authors":"Tim Bozeman, Will Nelle, Quoc Nguyen","doi":"10.2118/209429-pa","DOIUrl":"https://doi.org/10.2118/209429-pa","url":null,"abstract":"Summary Low primary and secondary recoveries of original oil in place from modern unconventional reservoirs beg for utilization of tertiary recovery techniques. Enhanced oil recovery (EOR) via cyclic gas injection (“huff ‘n’ puff”) has indeed enhanced the oil recovery in many fields, and many of those projects have also been documented in industry technical papers/case studies. However, the need remains to document new techniques in new reservoirs. This paper documents a small-scale EOR pilot project in the eastern Eagle Ford and shows promising well results. In preparation for the pilot, full characterization of the oil and injection gas was done along with laboratory testing to identify the miscibility properties of the two fluids. Once the injection well facility design was completed, a series of progressively larger gas volumes were injected followed by correspondingly longer production times. Fluids in the returning liquid and gas streams were monitored for compositional changes, and the learnings from each cycle led to adjustments and facility changes to improve the next cycle. After completing five injection/withdrawal cycles in the pilot, a few key observations can be made. The implementation of cyclic gas injection can be both a technical and a commercial success early in its life if reasonable cost controls are implemented and the scope is kept manageable. The process has proved to be both repeatable and predictable, allowing for future economic modeling to be used to help determine timing of subsequent injection cycles. A key component of the success of this pilot has been the availability of small compressors capable of the high pressures required for these projects and learning how to implement cost saving facility designs that still meet high safety standards.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136175792","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Optimization of an Integrated Reservoir-Production System Using Polynomial Chaos Expansion and Sobol Sensitivity Analysis","authors":"J. Rezaeian, Saman Jahanbakhshi, Kaveh Shaygan, S. Jamshidi","doi":"10.2118/214329-pa","DOIUrl":"https://doi.org/10.2118/214329-pa","url":null,"abstract":"\u0000 Integrated reservoir-production modeling is a collaborative multidisciplinary tool that can facilitate optimization of oil and gas production operations during the field development planning stage of exploiting subsurface resources. The critical issue with this technique is the excessive computational burden of the large integrated model with many input variables, which has not been effectively addressed to date. This study aims to reduce the computational costs and runtimes associated with the production integration and optimization process from oil fields. To do so, the reservoir and the surface network models of an Iranian oil field were coupled to create an integrated model for the optimization of field parameters to achieve the highest oil production rate. In the first step of simplification, polynomial chaos expansion (PCE) was used to establish a surrogate model from the integrated system. Next, Sobol sensitivity analysis, which is a variance-based, global, and model-free sensitivity analysis technique, was performed to reduce the number of input variables by identifying the most influential variables. Finally, the optimization was implemented using genetic algorithm (GA) on the PCE surrogate model of the integrated system with the most important variables. The results from the case study showed that the integrated model can be replaced with the PCE surrogate model while the accuracy is maintained. Moreover, performing sensitivity analysis considerably decreased the number of input variables for optimization by revealing their significance. The proposed methodology in this study can substantially improve the computational efficiency of the optimization for the integrated reservoir-production system.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"47 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84653248","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}