SPE Reservoir Evaluation & Engineering最新文献

{"title":"A Practical and Innovative Workflow to Support the Numerical Simulation of CO2 Storage in Large Field-Scale Models","authors":"Marcos Vitor Barbosa Machado, M. Delshad, K. Sepehrnoori","doi":"10.2118/215838-pa","DOIUrl":"https://doi.org/10.2118/215838-pa","url":null,"abstract":"\u0000 Numerical simulation of the CO2 storage process in porous media, such as in hydrocarbon (gas or oil) depleted reservoirs and in saline aquifers, has been the most indicated tool due to its ability to represent CO2 capacity and the different trapping mechanisms that retain CO2 in the subsurface. Given the complexity of the physicochemical phenomena involved, the modeling needs to incorporate multiphase flow, complex representation of fluids, rock, and rock-fluid interaction properties. These include CO2 reactions with aqueous species and with reservoir rock minerals, in addition to the structural and stratigraphic aspects of the reservoir heterogeneity. These phenomena need to be represented on suitable temporal and spatial scales for accurate predictions of their impacts. Currently, many studies are focused on simulating submodels or sectors of the reservoir, where using finer grids is still practical. This level of grid refinement can be prohibitive, in terms of simulation times, for modeling the entire reservoir. To address this challenge, we propose a new and practical workflow to simulate CO2 storage projects in large field-scale models. When the proposed workflow is applied in both synthetic and real field cases, simulation time is reduced by up to 96% compared to that of the fine-grid model, preserving the same results in representing the aforementioned mechanisms. The workflow is based on classical and standard approaches to handle the high simulation time, but in this study, they are structured and sequenced in three steps. The first one considers the most relevant mechanisms for CO2 storage, ranked from a high-resolution sector model. With the mechanisms prioritized in the previous step, a single-phase upscaling of petrophysical properties can be applied in the field-scale model, followed by adopting a grid with dynamic sizing. The proposed methodology is applied to saline aquifer models in this study, but it can be extended for storage in depleted hydrocarbon reservoirs.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"12 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78746613","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":"Special Connections for Representing Multiscale Heterogeneities in Reservoir Simulation","authors":"Manuel Gomes Correia, Gonçalo Oliveira, Denis José Schiozer","doi":"10.2118/200572-pa","DOIUrl":"https://doi.org/10.2118/200572-pa","url":null,"abstract":"Summary The significant quantities of oil contained in fractured karst reservoirs in Brazilian presalt fields add new challenges to the development of upscaling procedures to reduce time on numerical simulations. This work aims to represent multiscale heterogeneities in reservoir simulators based on special connections between matrix, karst, and fracture mediums, both modeled in different grid domains within a single porosity flow model. The objective of this representation is to strike a good balance between accuracy and simulation time. Therefore, this work extends the approach of special connections developed by Correia et al. (2019) to integrate both karst and fracture mediums modeled in different grid domains and block scales. The transmissibility calculation between the three domains is a combination of the conventional formulation based on two-point flux approximation schemes and the matrix-fracture fluid transfer formulation. The flow inside each domain is governed by Darcy’s equation and implicitly solved by the simulator. For proper validation and numerical verification, we applied the methodology to a simple case (two-phase and three-phase flow) and a real case (two-phase flow). For the simple case, the reference model is a refined grid model with (1) an arrangement of large conduits (karsts), which are poorly connected; (2) a well-connected and orthogonal system of fractures; and (3) a background medium (matrix). The real case is a section of a Brazilian presalt field, characterized as a naturally fractured carbonate reservoir. The reference is the geological model. The simulation model consists of a structural model with different gridblock sizes according to the scale of the heterogeneities—small-scale karst geometries, medium-scale matrix properties, and larger-scale fracture features—interconnected by special connections. The results for both cases show a significant performance improvement regarding a dynamic matching response with the reference model, within a suitable simulation time and maintaining the dynamic resolution according to the representative elementary volume of heterogeneities, without using an unstructured grid. In comparison to the reference model, for the simple case and the real case, the simulation time was reduced by 42% and 87%, respectively. The proposed method contributes to a multiscale flow simulation solution to manage heterogeneous geological scenarios using structured grids while preserving the high resolution of small-scale heterogeneities and providing a good relationship between accuracy and simulation time.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"10 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-05-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135718162","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":"Proved Reserves Revisions: How Reliable Are They?","authors":"Enrique Morales, John Lee","doi":"10.2118/210476-pa","DOIUrl":"https://doi.org/10.2118/210476-pa","url":null,"abstract":"Summary This paper incorporates the findings of our previous publication (Morales and Lee 2022) and identifies, isolates, and quantifies elements in the annually disclosed proved reserves revisions that should not be considered technical or economic revisions. This has resulted in significantly different technical and economic revisions compared to those simplistically and directly derived using a common interpretation of the Financial Accounting Standards Board (FASB) Topic 932-235-50-5 (a) definition. We have assessed the reliability and comparability of the updated technical revisions when used to judge the reasonable certainty of the underlying proved reserves. We have carried out the analysis separating the proved reserves into developed and undeveloped. To derive a realistic data set to generate the updated technical and economic revisions, we reviewed more than 1,000 annual reports (10K and 20F Forms) and more than 600 comment letters from 141 companies filing annual reports to the Securities and Exchange Commission (SEC) during the period 2010–2020, extracting the information related to annual reserves changes and explicitly focusing on the disclosed revisions of previous estimates (RPE). We present evidence showing that the approach followed is robust and more reliable than the simple approach where technical revisions are estimated by simply subtracting the disclosed revisions due to price effects from the disclosed revisions in annual reports. The root causes for the significant differences between the simplistic approach and the one presented in this paper are mainly due to (1) including annual reserves changes due to nontechnical or economic factors as technical revisions, (2) using different interpretations of SEC and FASB regulations, and (3) not providing critical disaggregation information needed to estimate technical, economic, or other types of revisions correctly. Without proper consideration of these issues, the derived technical and economic revisions from disclosed data can be significantly distorted, affecting any conclusions derived. The annual average changes in technical revisions during a representative period, if correctly estimated, can provide an indication of both overstated and understated certainty of proved reserves estimates, which can impact a company’s relative valuation, asset impairment, internal depreciation, profit/loss, standardized measure, unit development costs, and other indicators based on proved reserves, making the reliability of the technical revisions and their actual upward or downward movements of paramount importance. We also highlight the significant different root causes driving the major differences between developed and undeveloped reserves in their annual technical revisions. The results indicate that for some companies that provide most of the information required for proper analysis, the certainty level of their disclosed developed and undeveloped proved reserves points toward an appar","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"19 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-05-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134989164","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":"RTA-Assisted Numerical History-Matching Workflow","authors":"H. Hamdi, C. Clarkson, A. Ghanizadeh","doi":"10.2118/210224-pa","DOIUrl":"https://doi.org/10.2118/210224-pa","url":null,"abstract":"\u0000 Due to strong nonlinearities in the governing diffusivity equation for flow in porous media, numerically assisted rate-transient analysis (RTA) techniques have been suggested for the analysis of multiphase production data from multifractured horizontal wells (MFHWs). However, these methods are based on some limiting assumptions that cannot be generalized for three-phase flow or when relative permeability is unknown. In this study, a new RTA-assisted history-matching technique is proposed to simultaneously match production data and diagnostic plots during the calibration process.\u0000 In the proposed method, the objective function is modified to include the derivative of the integral of rate-normalized pressure for the primary phases. As such, in the history-matching process using compositional numerical simulation, the flow regimes are also matched, which can increase the reliability of the calibrated numerical model. This approach is applied to a challenging data set of production data from an MFHW completed in a Canadian shale reservoir hosting a near-critical gas condensate fluid.\u0000 The results demonstrate that when the modified objective function is used, the history-matching scheme will reject models that cannot reproduce the flow regimes even if the production data are visually matched. Another benefit of this modified history-matching workflow is that, unlike other numerically assisted RTA techniques, it is not limited to any specific conceptual model or reservoir geometry. Further, interactions between parameters are accounted for during the calibration process. Including the derivative terms in the objective function can ensure a better history-matched model with improved forecast quality. However, comparing the convergence rates of the history-matching with the standard and modified objective functions indicates that adding the derivative terms comes with an additional computational cost requiring more iterations and a slower convergence rate.\u0000 In this study, a modified objective function is introduced for the first time to enhance the numerical history-matching process to ensure the resulting calibrated model can also reproduce the observed transient flow regimes. This approach is easy to implement and is not limited to a specific model geometry or any input-output relationship.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"1 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91229410","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":"Modeling Transient Flow Behavior of Off-Center Fractured Well with Multiple Fractures in Radial Composite Gas Reservoirs","authors":"You-jie Xu, Xiang Zuping, Mengnan Yu","doi":"10.2118/215808-pa","DOIUrl":"https://doi.org/10.2118/215808-pa","url":null,"abstract":"\u0000 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.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"32 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89314747","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":"Geophysical Modeling and Its Contribution on the Reservoir Characterization of Al Baraka in El Gallaba Plain, South Egypt","authors":"Mohamed Osman Ebraheem, H. Ibrahim, H. Ewida, A. H. Senosy","doi":"10.2118/214693-pa","DOIUrl":"https://doi.org/10.2118/214693-pa","url":null,"abstract":"\u0000 The early Cretaceous formations in recent years are considered significant potential hydrocarbon-bearing rocks in many rift basins such as Komombo, south Egypt. Therefore, this study is focused on the critical analysis and interpretation of well logging together with seismic reflection data on the Al Baraka petroliferous reservoir in the Komombo subbasin. The interpretation of these data was used to construct the first 3D geophysical models in this area which were subsequently interpreted in terms of their potential to be hydrocarbon-bearing or not. The 3D petrophysical models were deduced to illustrate the spatial distribution and propagation of the petrophysical properties (laterally and vertically) within the reservoir. Additionally, 3D seismic models were prepared to get a comprehensive, in-depth picture of how the productive hydrocarbon reservoir zones are structurally controlled in different depths. So, these models are crucial for explaining reservoir characteristics and providing supported geological reservoir models for precise reservoir performance prediction. This study aims to differentiate and determine hydrocarbon potential zones in terms of the petroleum system. The results of these progressive analyses showed that only two zones (C and D) in the Six Hills Formation are considered the most productive zones because they have a large thickness of sand bodies, low-water saturation values, high porosity, and high permeability. These zones are located in the northeastern and central parts of the studied area, which represent the depocenter of the subbasin. This evidence supported and confirmed the presence of petroleum accumulations in certain zones within the Six Hills Formation. Therefore, this work can give and encourage experts with adequate knowledge to understand the development of the rift basins in Komombo and other basins in middle and south Egypt.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"41 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81484767","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":"Data Assimilation of Production and Multiple 4D Seismic Acquisitions in a Deepwater Field Using Ensemble Smoother with Multiple Data Assimilation","authors":"Daiane Rossi Rosa, D. Schiozer, A. Davolio","doi":"10.2118/215812-pa","DOIUrl":"https://doi.org/10.2118/215812-pa","url":null,"abstract":"\u0000 In recent years, time-lapse (4D) seismic (4DS) data have been widely used for reservoir monitoring to provide relevant information on dynamic changes occurring during production. In complex reservoirs, multiple seismic monitor surveys are usually available. Updating reservoir models with these data can be very beneficial to improve the field’s management. In the quantitative integration of 4DS data into the data assimilation (DA) process, it is crucial to define how to deal with more than one seismic monitor. In this work, we continue a series of investigations about seismic DA procedures and expand on them by analyzing ways to assimilate more than one seismic monitor. More specifically, we evaluate different ways of using production data and two monitor surveys (M3 and M5) to calibrate the dynamic models of a real Brazilian reservoir using the ensemble smoother with multiple data assimilation (ES-MDA) method. We performed the following experiments: (1) sequential assimilation of M3 and M5 with parts of well history divided according to the seismic acquisition dates; (2) assimilation of M3 with the entire well history and subsequent assimilation of M5; (3) assimilation of well and M3 data; and (4) assimilation of well and M5 data. For comparison purposes, we also assimilated only well data. From the results, we observed that well and 4DS data misfits were reduced when assimilating both monitors, compared to the cases where only a single monitor (any of them) was used with production data. This conclusion is also true in the comparison with results obtained when only assimilating well data. This indicates that both seismic monitors are important data to be quantitatively considered in DA. In this particular field, using a previous DA run to solely assimilate the newly available monitor (Case 2) delivered better models and long-term forecasts. Therefore, this would be our recommendation. This study highlights the importance of several 4DS acquisitions for reservoir monitoring and management and shows the challenges of their application in seismic DA for better life cycle field applications.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"48 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73749989","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 Systematic Experimental Study to Understand the Performance and Efficiency of Gas Injection in Carbonate Reservoirs","authors":"Shehadeh Masalmeh, S. Amir Farzaneh, Mehran Sohrabi, M. Saeid Ataei, Muataz Alshuaibi","doi":"10.2118/200057-pa","DOIUrl":"https://doi.org/10.2118/200057-pa","url":null,"abstract":"Summary Gas injection is the most widely applied recovery method in light, condensate, and volatile oil carbonate reservoirs. Gas has high displacement efficiency and usually results in a low residual oil saturation in the part of the reservoir that is contacted with gas. The displacement efficiency increases when the injected gas is near-miscible or miscible with the oil. In addition to nitrogen and hydrocarbon gas projects, carbon dioxide (CO2) enhanced oil recovery (EOR) has been the dominant gas EOR process. Gas-based EOR has been implemented in both mature and waterflooded carbonate reservoirs. In this paper, we present the results of a detailed experimental study aimed at understanding the performance and efficiency of gas injection in carbonate reservoirs. A series of immiscible and miscible gas injection coreflood experiments were performed using limestone reservoir cores under different injection strategies. To minimize laboratory artifacts, long cores were used in the experiments, and to observe the effect of gravity, both 2 in. diameter and 4 in. diameter (whole core) were used. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by aging the core in crude oil for several weeks under reservoir temperature. Hydrocarbon gas (methane) was used as the immiscible injectant, and both CO2 and a mixture of 50% C1 and 50% CO2 were used as miscible injectant. All gas injection experiments were performed using vertically oriented cores, and the gas was injected from the top unless it is stated otherwise. The main parameters investigated in this study are as follows: The effect of miscibility on oil recovery for both continuous gas injection and water alternating gas (WAG). The effect of gravity on gas sweep efficiency compared to waterflooding. The effect of gas-oil interfacial tension (IFT) on oil recovery when using the same oil. The effect of oil type on oil recovery using the same injected gas at miscible and immiscible conditions. The effect of immiscible gas injection on subsequent miscible gas injection performance. Impact of CO2 cycle length on ultimate oil recovery. The impact of the order of fluid injection where multiple WAG injection cycles were performed in separate experiments after water or gas injection. The main conclusions of this study are as follows: As expected, miscibility has a significant impact on displacement efficiency and oil recovery where miscible gas recovered more than 20% extra oil compared to immiscible gas. A significant variation in oil recovery is observed for miscible gas injection (i.e., more than 10 saturation units difference) depending on the minimum miscibility pressure (MMP) between the injected gas and crude oil, even when both experiments are performed at miscible conditions using the same injected gas. The performance of tertiary CO2 flood was adversely affected by the slug of immiscible gas injected. Therefore, it is not recommended to ha","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"9 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135912691","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":"Smartwater Synergy with Chemical EOR: Studying the Potential Synergy with Surfactants","authors":"Abdulkareem Sofi, Jinxun Wang, Mathieu Salaün, David Rousseau, Mikel Morvan, Subhash C. Ayirala","doi":"10.2118/211475-pa","DOIUrl":"https://doi.org/10.2118/211475-pa","url":null,"abstract":"Summary The potential synergy between smartwater and various enhanced oil recovery (EOR) processes has recently attracted significant attention. In previous work, we demonstrated such favorable synergy for polymer floods not only from a viscosity standpoint but also in terms of wettability. Recent studies suggest that smartwater synergy might even extend to surfactant floods. In this work, we investigate the potential synergy between smartwater and surfactant flooding. Opposed to previous work, the potential synergy is investigated from ground zero. We concurrently developed two surfactant formulations for conventional high-salinity injection water and low-salinity smartwater. To design the optimal surfactant-polymer (SP) formulations, we followed a systematic all-inclusive laboratory workflow. Oil displacement studies were performed in preserved core samples using the two developed formulations with conventional injection water and smartwater. The results demonstrated the promising potential of binary surfactant mixtures of olefin sulfonate (OS) and alkyl glyceryl ether sulfonate (AGES) for both waters. The designed binary formulations were able to form Winsor Type III emulsions besides achieving ultralow interfacial tensions (IFTs). Most importantly, in terms of oil displacement, the developed SP formulations in both injection water and low-salinity smartwater were capable of recovering more than 60% of the remaining oil post waterflooding. A key novelty of this work is that it investigates the potential synergy between smartwater and surfactant-based processes from the initial step of surfactant formulation design. Through well-designed from-scratch evaluation, we demonstrate that surfactant-based processes exhibit limited synergies with smartwater. Comparable processes in terms of performance can be designed for both high-salinity and low-salinity waters. It is also quite possible that the synergistic benefits of smartwater on oil recovery cannot be effective in SP flooding processes, especially with specific surfactant formulations under optimal salinity conditions.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136080745","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":"Stochastic Estimation of Barrels of Oil Equivalent Conversion Factor for Natural Gas Volumes from Offshore Carbonate Fields in Ultradeep Waters","authors":"L. C. Silva, J. V. Roque, G. Oliveira, R. G. Souza, S. Paulino, C. Fonseca, D. Braga, J. Trujillo","doi":"10.2118/214683-pa","DOIUrl":"https://doi.org/10.2118/214683-pa","url":null,"abstract":"\u0000 Oil and gas production is measured in different units; therefore, there is a need to use a conversion factor of natural gas (NG) to barrels of oil equivalent (BOE). The SPE unit conversion factor, which is based on a reference oil, is often used. However, BOE conversion factors vary as a function of the high heating value (HHV) calculated for a gas, which in turn, varies as a function of the NG composition. Herein, by using Monte Carlo simulations, HHV and produced volumes of NG measured over the years were used in estimating BOE conversion factors for two offshore carbonate fields in ultradeep waters. Then, the new BOE conversion factors were used to review the production data collected in 2021. By comparing the new production data with the data obtained by using the SPE unit conversion factor, it is seen that the proposed conversion factors are more suitable for the specific assets than the standardized conversion factors.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"49 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79126092","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}