Day 3 Wed, May 24, 2023最新文献

{"title":"An Answer to Ever-Challenging Question of Selecting the Right Test Method (Dispersion or Deposition) for Asphaltene Stability Determination","authors":"A. Punase, W. Burnett, J. Wylde","doi":"10.2118/213012-ms","DOIUrl":"https://doi.org/10.2118/213012-ms","url":null,"abstract":"\u0000 Changing thermodynamic and compositional conditions of producing fields can cause decreased asphaltene stability and initiate aggregation, subsequent precipitation, and eventual deposition within flowlines. Usage of asphaltene inhibitors that prevent aggregation and tackle the problem right at the inception is widely preferred. However, such chemistries were observed to be counter-productive and led to higher asphaltene deposition in many cases. Thus, raising the question of what approach works best for assessing asphaltene stability: Dispersion or Deposition?\u0000 The focus of this study is to explore the relationship between the underlying working mechanism of dispersion and deposition-based test methods. Multiple crude oil samples produced from different regions of the world were evaluated using asphaltene inhibitor chemistries with optical transmittance, thermoelectric, and flow loop methods. Optical transmittance method evaluates sedimentation rate and cluster size distribution of asphaltene cluster within the test fluid medium. Thermoelectric method describes the dispersion state of asphaltenes within native crude oil. Flow loop setup assesses total mass deposited when the oil (blank or dosed) and precipitant mixture is flown through capillary tubes.\u0000 The results from these tests indicated that a fine balance between the dispersion and deposition mechanisms must be maintained as these may not respond linearly or in direct relationship at all conditions. It was seen that dispersing the asphaltene clusters too small may lead to high diffusional rate within the low flow shear regime and build up more deposit in depositional dominant test methods. Variation in treatment concentration (especially overtreatment) of an effective asphaltene inhibitor can result in lowering of cluster size to a range which in effect can cause more deposition. The overall assessment suggests that not having a holistic overlook at these test methods and following the standard process of giving specific focus on a singular approach, can mislead the asphaltene stability and inhibitor performance evaluation.\u0000 The key role of asphaltene cluster size as a bridge relating the dispersion and deposition-based test method is revealed in this paper. It is seen that there exists an effective range of cluster size within which the results from different test methods correlate well. Therefore, it is imperative that the asphaltene inhibitor development philosophy must include test screening methods focusing on each instability stage (precipitation, aggregation, and deposition) individually and combine the learnings to come up with the best recommendation.","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"11 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":"121737096","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":"Hybrid Multiphase Rate Forecasting Model in Liquid Wells for Unconventional Reservoirs","authors":"Utkarsh Sinha, Hardikkumar Zalavadia, P. Chauhan, S. Sankaran","doi":"10.2118/212981-ms","DOIUrl":"https://doi.org/10.2118/212981-ms","url":null,"abstract":"\u0000 The development of shale plays requires accurate forecasting of production rates and expected ultimate recoveries, which is challenging due to the complexities associated with production from hydraulically fractured horizontal wells in unconventional reservoirs. Traditional empirical models like Arps decline are inadequate in capturing these complexities, and long-term forecasting is hindered by the challenges posed by 3 phase flow. In response, a new physics-augmented, data-driven forecasting method has been proposed that efficiently captures these complexities.\u0000 The proposed PI-based forecasting (PIBF) method combines data-driven techniques with the physics of propagation of dynamic drainage volume under transient flow conditions observed by unconventional wells for a prolonged period. The model requires only routinely measured inputs such as production rates and wellhead pressure, and efficiently captures the trend shift in gas-to-oil ratio caused by free gas liberation in the near-wellbore region. By using material balance and productivity index models, the proposed approach can forecast well performance and handle changing operational conditions during the well's lifecycle.\u0000 Compared to existing empirical or analytical methods like Arps decline and RTA, the proposed method yields more accurate forecasting results, while still using easily available inputs. Empirical methods like Arps decline have low input requirements but lack physical insights, leading to inaccuracies and inability to handle changing operational conditions. Pure physics-based methods like RTA and reservoir simulation require more input properties that are often difficult to obtain, resulting in a low range of applicability.\u0000 Overall, the proposed method offers a promising alternative to existing methods, effectively combining data-driven techniques with physics-based insights to accurately forecast well performance and handle changing operational conditions in unconventional reservoirs.","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"77 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":"129244747","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":"Improved Evaluation Methodology of Fractured Horizontal Well Performance: New Method to Measure the Effect of Gel Damage and Cyclic Stress on Fracture Conductivity","authors":"Junjing Zhang, M. Nozaki, N. Zwarich, P. Carman, E. Davis, Sandeep Pedam, B. Buck, Leigh A Childs, P. Perfetta","doi":"10.2118/212977-ms","DOIUrl":"https://doi.org/10.2118/212977-ms","url":null,"abstract":"\u0000 In thinly bedded sandstone reservoirs, hydraulic fractures are required in horizontal wells to connect isolated pay intervals and to improve the volumetric sweep efficiency during waterflooding. This study presents a new, more robust way to evaluate gel damage and cyclic stress in the laboratory. Results from the laboratory evaluation are validated with field production data.\u0000 Standard ISO/API tests are adequate at comparing proppant types but do not accurately predict resultant conductivity in a well as they do not account for several in-situ damage mechanisms. With a limited number of cores available it is important to clearly define the scope of the laboratory testing and decide which damage mechanisms to investigate. Testing all variables in the laboratory is not practical. For this study, the primary objectives were to 1) compare ceramic proppant to the natural sand, 2) investigate the impact of thinly-bedded sandstone on the fracture conductivity, and 3) determine the minimum required proppant concentration (the cutoff concentration for interpreting the effective fracture half-length in numerical hydraulic fracture model results). The laboratory testing was designed to simulate as realistic the in-situ condition by 1) using actual formation core, 2) performing cyclic stress cycles to mimic multiple shut-in and production periods, and 3) placing the gel and allowing it to cross-link and break in the fracture.\u0000 During the conductivity experiments, the following steps were taken: 1) oil injection with cyclic stress applied, 2) dynamic cross-linked gel injection and shut-in for gel breaking, and 3) oil injection with cyclic stress applied. Variables investigated include fluid-rock interaction, gel residual, cyclic stress, proppant type, concentration, and size distribution and time dependency of conductivity. Discount factors are derived from the test results which provide a more realistic and repeatable conductivity prediction. This study discovered that for hydraulic fracturing of weak rocks in the shallow formation, the baseline fracture conductivity from API tests should be reduced by 22% first to account for the proppant-rock interaction. After applying the aggressive cyclic stresses, the cumulative conductivity loss increases to 38%. After the cross-linked gel cleanup, a total of 72% fracture conductivity is lost for a proppant pack at 2 lbm/ft2 and 91% conductivity loss for proppant pack at 1 lbm/ft2. It is also found in this study that each large-scale stress cycle reduces an approximate 1% fracture conductivity of the loosely packed proppant until a tighter and stable proppant pack is formed. The cyclic stress effect becomes insignificant when the proppant pack porosity decreases to ∼0.2.\u0000 Well production history was matched by varying fracture properties in the transient inflow performance analysis. For two wells under the same fracture design, the matched fracture conductivities resulted in less than 25% error compared with the ret","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"8 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":"114343970","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":"Beneficial Advantages of Nanoparticle-Enhanced Surfactant-Assisted Low Salinity Waterflooding Process","authors":"S. H. Fakir, A. Belhaj, N. Singh, H. Sarma","doi":"10.2118/213020-ms","DOIUrl":"https://doi.org/10.2118/213020-ms","url":null,"abstract":"\u0000 The application of nanoparticles (NPs) to improve oil recovery is gaining wide acceptance in the petroleum industry in recent times. Due to their size and set chemical characteristics, NPs can be used to enhance oil recovery in carbonate reservoirs by altering the rock wettability and reducing oil–brine interfacial tension (IFT). Also, when used with surface-active agents like surfactant (cationic, anionic or non–ionic) in low–salinity waterflooding (LSWF), NPs can enhance the performance of surfactant. This study focuses on the implications of combining green NPs with surfactant and low–salinity water for EOR applications in carbonate reservoirs. A NP was synthesized from a green source, rice husk, and then characterized using XRD, FTIR, TGA and SEM analyses. A cationic surfactant, Aspiro S 6420, was added in the nanoemulsion of silica nanoparticle (SNP) and 1% diluted seawater (dSW). The SNP-Surfactant-1%dSW nanoemulsion was investigated for its beneficial effects for EOR applications. Zeta potential measurements were carried out for various brine dilutions, then for 1% dSW and surfactant, and finally 1%dSW–Surfactant–SNP nanoemulsions. The measurements showed that the zeta potentials are highly positive, confirming the stability of the nanoemulsions and alteration of rock wettability. Interfacial tension (IFT) between oil and brine were measured at a temperature of 86°C. The addition of surfactant (Aspiro S 6420) led to significant drop in IFT between oil and brine. Finally, when SNPs were added to the 1%dSW–Surfactant emulsions, the IFT reduced significantly, confirming that the combination of low salinity brine–cationic surfactant (Aspiro S 6420)–SNP can be used as a promising injection fluid to recover oil from carbonate reservoirs.","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"27 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":"125889013","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":"Gas-Flaring Solution Enhances Oil Recovery and Electric Power Reliability","authors":"Luis Alberto Gracian, Ivan Miguel Arguello, I. Diyashev","doi":"10.2118/213002-ms","DOIUrl":"https://doi.org/10.2118/213002-ms","url":null,"abstract":"\u0000 Excess gas produced in reservoirs has traditionally been flared into the atmosphere as it is a byproduct of oil and gas recovery operations. Large volumes of gas are still flared in areas where there is a lack of infrastructure to collect and transport the gas.\u0000 Gas injection into reservoirs has been shown to increase hydrocarbon production and is a method of Enhanced Oil Recovery (EOR). The proposed method for EOR would be to capture the gas that would otherwise be flared and re-inject it into the reservoir. This would further reduce overall gas flaring and increase production simultaneously. Re-injections sites are carefully chosen to ensure the gas injection yields the best production and is also economically viable. As the world increases the amount of variable renewable energy sources, solutions developed in the traditional energy industry can provide stability to the power grid and reduce the prices for consumers.\u0000 In Texas, there is a large contribution to total energy production coming from both wind and solar, which have both daily and seasonal variability. A secondary objective is utilizing the potentially flared gas to generate electricity during the high-demand months of summer and winter. Since one of the main reasons for flaring gas is the lack of infrastructure to transport the gas, the ability to use the gas to generate electricity on-site has the potential to be an invaluable asset. Generators are built and connected to the already-in-place electrical grid, bypassing the need to build new pipelines to transport the gas. This solution provides for seasonal storage for associated gas and enhanced oil recovery at the same time.\u0000 A model of an unconventional reservoir found in West Texas was built to study the feasibility of this project. Using reservoir simulation software, a single horizontal well with 50 fractures along the horizontal was placed in the reservoir model. The model has a porosity of 3.7% and a permeability of 7 nD in the horizontal direction and 0.7 nD in the vertical. The fractures have a half-length of 200 ft and a fracture zone permeability of 300 mD. The fluid properties and historical production were taken from a PVT report and production data provided. The model was then history-matched to get an accurate forecast.\u0000 Three cases were tested with this model. The base case consisted of 30 years of normal depletion with no injection (Fig. 1) The second case consisted of cyclic injection for 30 years (Fig. 2). Fig. 3a and Fig. 3b show the reservoir pressure in relation to gas injection. In the third case, the injection after depletion consisted of 15 years of normal depletion and 15 years of cyclic injection. The injection cycle consisted of 3 months of production, 2 months of injection, and 1 month of soaking for both the second and third case. Naturally, this cycle would allow for excess electricity generation to meet the demand peaks in summer and winter.\u0000 The base case produced a total of 205 MSTB, the second ","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"42 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":"134063861","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":"Modeling Two-Phase Flow Behaviour in a Shale Gas Reservoir with Complex Fracture Networks and Flow Dynamics","authors":"Yunhao Zhang, Daoyong Yang","doi":"10.2118/213001-ms","DOIUrl":"https://doi.org/10.2118/213001-ms","url":null,"abstract":"\u0000 In this work, a robust and pragmatic method has been developed, validated, and applied to describe two-phase flow behaviour of a multifractured horizontal well (MFHW) in a shale gas formation. As for a fracture subsystem, its permeability modulus, non-Darcy flow coefficient, and slippage factor have been defined and embedded into the governing equation, while an iterative method is applied to update the gas/water saturation in each fracture segment within discrete fracture networks. For a matrix subsystem, a skin factor on a fracture face is defined and introduced to represent the change in relative permeability in the matrix domain at each timestep, while the adsorption/desorption term is incorporated into the diffusivity equation to accurately calculate the shale gas production by taking the adsorbed gas in nanoscale porous media into account. Then, the theoretical model can be applied to accurately capture the two-phase flow behaviour in different subdomains. The accuracy of this newly developed model has been confirmed by the numerical simulation and then it is extended to field applications with excellent performance. The stress-sensitivity, non-Darcy flow, and slippage effect in a hydraulic fracture (HF) are found to be obvious during the production, while the initial gas saturation in a matrix and HFs imposes an evident influence on the production profile. As for an HF with a high gas saturation, the dewatering stage is missing and water from the matrix can be neglected during a short production time. For the matrix subsystem, a high-water saturation in the matrix near an HF can affect gas production during the entire stage as long as gas relative permeability in the HF remains low. In addition, the adsorption/desorption in the matrix subsystem can increase gas production but decrease water production. Compared to the observed gas/water production rates for field applications, the solutions obtained from the method in this work are found to be well matched, confirming its reliability and robustness.","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"27 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":"125471214","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":"Alaska CCUS Workgroup and a Roadmap to Commercial Deployment","authors":"F. Paskvan, Haley Paine, Christine A. Resler, B. Sheets, T. Mcguire, Kevin Connors, Esther Tempel","doi":"10.2118/213051-ms","DOIUrl":"https://doi.org/10.2118/213051-ms","url":null,"abstract":"\u0000 A group of Alaskans formed a Workgroup in July 2022 to accelerate commercial carbon capture, use, and storage (CCUS) projects in the State of Alaska (State). The Workgroup’s mission is to attract new investments and create options that enable continued operation of carbon intensive activities vital to the State’s economy including power generation, refineries, and oil and gas production.\u0000 To meet the dual challenge of increasing global energy demand and a growing population, there is a need to provide affordable and reliable energy while addressing the risks of climate change. Policies are being created and refined to incentivize carbon dioxide removal from the atmosphere including capture at the point of generation and direct air capture. Since 2008, US Federal tax credits have been established, increased, extended, and expanded for CCUS projects. Energy policy in the US and globally is evolving, moving from exclusive focus on renewable energy towards supporting low-emission energy systems, including those employing CCUS [COP 26].\u0000 This shift recognizes utility-scale renewable energy generation generally depends on fossil fuel for back-up power. The intermittent nature of renewable power generation gives rise to energy generation gaps. Coal, natural gas, and oil generation fill these gaps to provide stability to an energy system, and CCUS is increasingly viewed as a critical part of a complete clean energy portfolio. Costs to establish clean energy security would be more than twice as expensive without CCUS [IPCC].\u0000 Interest in CCUS is growing rapidly. As of 2020, 21 large-scale CCUS facilities operate globally [IEA CCUS], with 80% of capacity based in the USA. Operations began as far back as 1972 for enhanced oil recovery and more recently for geologic sequestration. As of 2022, over 190 CCUS facilities are in the project pipeline globally. Assuming one million tonnes carbon dioxide captured per year per project, over 2,500 facilities are needed by 2040 to reach the objective of 2.52 gigatonnes captured per year [IEA 2020].\u0000 This paper addresses three important topics:The importance, value, and cost of CCUS. Costs increase rapidly as the carbon dioxide (CO2) concentration decreases within the capture inlet gas stream. Herein, costs are compared with the value of capture especially 45Q tax credits. Other revenue and value drivers are also discussed. Costs typical of the contiguous 48 states of the US were used in this screening.The Alaska CCUS Workgroup’s mission, leadership, and participating organizations are discussed. Results, future plans, and approaches to ensure participant value are shared for four focus areas:Develop a State legal and regulatory framework,Track and respond to government funding opportunities,Perform public education and outreach, andDevelop a roadmap to accelerate commercial CCUS deployment in Alaska.The North Slope, Interior, and Cook Inlet regions are reviewed for CO2 storage potential, stationary emission sources, ","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"55 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":"130295250","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":"Insights on Gas and Water Coning/Channeling Processes in a Fractured Carbonate Reservoir from Embedded Discrete Fracture Modeling","authors":"H. Vo, E. Flodin, R. Hui, E. Earnest, Marcia Trindade","doi":"10.2118/213025-ms","DOIUrl":"https://doi.org/10.2118/213025-ms","url":null,"abstract":"\u0000 Coning is the mechanism describing movement of water from an aquifer and/or gas from gas-cap into the perforations of a producing well. The interface between the fluid phases deforms into a cone shape if the reservoirs are relatively homogeneous. In fractured reservoirs, water/gas incursions can take the form of discrete channels through fractures that connect the water/gas zone to the wellbore. Coning/channeling tends to increase the cost of production operations and influences the overall recovery efficiency of oil reservoirs. The coning/channeling processes constitute one of the most complex problems pertaining to oil production. This study investigates coning/channeling in an Atlantic margin pre-salt fractured carbonate reservoir using Embedded Discrete Fracture Modeling (EDFM) to gain a better understanding of the processes in fractured reservoirs.\u0000 This study focused on a sector Discrete Fracture Network (DFN) that was used to create a full-field Dual Porosity-Dual Permeability (DPDK) model. The DFN was used to generate end member models that capture the range of connectivity, geometry, and heterogeneity of fracture systems thought to exist in the field based on well log and core analysis. The sector area of interest also included existing producers and injectors and future infill wells. The coning/channeling phenomena were modeled using the EDFM method. The models were flow simulated using representative initialization, field management logic, and well producing rules, based on the history-matched full-field DPDK model. Mitigation methods to reduce coning impacts were also investigated.\u0000 EDFM, which represents the fracture network explicitly, provides insight on gas and water coning/channeling processes in a fractured carbonate reservoir. We find that fractures can lead to local channeling and coning. The degree of channeling and coning is a function of flow rates, fracture properties, and matrix-fracture exchange which in turn depends on rock property contrast between matrix and fractures. If matrix permeability is sufficiently high, matrix-fracture exchange is significant and fractures can act like leaky pipes. The effect of local gas coning/channeling is stronger in cases of isolated fractures surrounded by lower permeability rock. Water and gas coning can occur at the same time and interact with each other. Mitigation methods such as reducing well rates and use of selective completions can be applied to manage the gas and water coning/channeling.","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"45 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":"121625618","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 Two Novel Enhanced Oil Recovery Processes in the Bakken Shale","authors":"R. Downey, K. Venepalli","doi":"10.2118/212984-ms","DOIUrl":"https://doi.org/10.2118/212984-ms","url":null,"abstract":"\u0000 Oil production via horizontal wells with multistage fracture stimulation treatment completions in the Bakken shale of North Dakota and Montana began in 2003. Since then, over 19,000 Bakken shale horizontal wells have been completed and placed into production. Oil production from horizontal Bakken shale oil wells peaked in November 2019 at 1.5 million barrels/day, and is at about 1.2 million barrels/day as of September, 2022 (EIA). There have been several shale oil EOR tests conducted over the last several years, involving the injection of water, CO2 and natural gas.\u0000 This paper builds upon shale EOR modeling work described in a 2019 NETL report. In that report, a compositional simulation model of the Bakken was constructed, and a production history match on primary oil, gas and water production from a group of wells was obtained. The match model was then used to evaluate the enhanced oil recovery via cyclic injection of CO2, dry gas, and wet gas. This paper utilizes some data from that report to assess two novel, proprietary shale oil EOR processes in the Bakken, in the same area of the Williston Basin. The paper illustrates how these proprietary shale oil EOR processes may be implemented at lower BHP to mitigate interwell communication, while enabling greater oil recovery than via injection of water, CO2 or natural gas.\u0000 Compositional reservoir simulation modeling of the two novel EOR processes in the modeled Bakken shale wells indicates potential incremental oil recoveries of 200% and 300% of primary EUR may be achieved.\u0000 The two novel shale oil EOR methods utilize a triplex pump to inject a liquid solvent having a specific composition into the shale oil reservoir, and a method to recover the injectant at the surface, for storage and reinjection. One of the processes enables further enhanced oil recovery via cyclic fracture stimulation at the start of the EOR process. The processes are fully integrated with compositional reservoir simulation to optimize the recovery of residual oil during each injection and production cycle.\u0000 The patent pending shale oil EOR processes have numerous advantages over cyclic gas injection - shorter injection time, longer production time, smaller, lower cost injection volumes, no gas containment issue - much lower risk of interwell communication, elimination of the need to buy and sell injectant during each cycle, much better economics, scalability, faster implementation, optimization via integration with compositional reservoir simulation modeling, and lower emissions. If implemented early in the well life, their application may preclude the need for artificial lift, to produce more oil sooner, resulting in a shallower decline rate and higher reserves.","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"57 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":"126104767","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":"Operational Theory and Qualification of a Unique Autonomous Inflow Control Device for First Use in a Heavy Oil Layered Reservoir","authors":"Xiutian Yao, Lei Xu, Chao Wang, Floyd Simonds, Bing Ding, Liang Zhao","doi":"10.2118/214513-ms","DOIUrl":"https://doi.org/10.2118/214513-ms","url":null,"abstract":"\u0000 As Operators face challenges due to increased water production worldwide the application of Passive and Autonomous Inflow Control Devices has proven effective at both delaying water production onset (passive functionality) and reducing water production at the surface (autonomous functionality). Passive technology has been deployed very effectively in hundreds of wells while autonomous devices are showing great promise to reduce costs, environmental risk, and potentially a significant reduction in topside infrastructure.\u0000 Passive devices only delay the onset of unwanted fluid breakthrough. Once breakthrough occurs, these tools do not restrict production. This led to the development of AICD technology which provides passive functionality initially but restricts water production at breakthrough. This functionality is greatly enhanced when compartments are created downhole to enable a \"network\" of devices to function independently at breakthrough, allowing other compartments to produce oil relatively unrestricted. The design proposed in this paper uses no moving parts, significantly restricts water production in a wide range of crude viscosities, is easily configured for a variety of downhole conditions, and delivers passive ICD performance with AICD benefits using a simple, reliable, and unique design.\u0000 The tool functions to restrict water production progressively as either oil viscosity or water cut increase without ever completely or nearly completely closing to production, which makes it an excellent solution for marginal production wells, younger reservoirs, and wells with lower overall production rates compared to other technologies.\u0000 The paper will discuss the theory of the device's functionality to differentiate between fluids present. Laboratory test results will be shown to demonstrate flow performance as well as API 19ICD[1] testing for erosion, plugging resistance, and mud flow initiation testing. The completion modeling process will be discussed in detail for an upcoming completion in Sinopec's Shengli Field.","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"65 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":"124852381","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}