Day 2 Tue, April 26, 2022最新文献

{"title":"An Investigation of In-Situ Upgrading the Shale Oil By Air Injection","authors":"Jianhua Qin, T. Wan, Jing Zhang, Sheng James","doi":"10.2118/209396-ms","DOIUrl":"https://doi.org/10.2118/209396-ms","url":null,"abstract":"\u0000 Conventional in-situ upgrading techniques use electric heaters to heat oil shale. However, the efficiency of electrical heating method is very slow which requires preheating more than a year. Most conventional heating technologies focused on converting the oil shale, not shale oil reservoirs. The shale oil matrix is very tight and the pore scale is in micro to nano-meter. In this paper, it has been attempted to inject air into hydraulically fractured horizontal wells to create in-situ combustion of shale oil in ultra-low permeability formations. Heat is introduced into the formation through multistage fractured horizontal wells, which enhances the contact area of exposed kerogen.\u0000 The main focus of this paper is to evaluate the technical feasibility of recovering shale oil resources by air injection. It involves the application of hydraulic fracturing technology to enhance the kerogen exposure to oxygen. Heat flows from the fracture into shale oil formation, gradually converting the solid kerogen into mobile oil and gas, which can be produced via fractures to the production wells.","PeriodicalId":385693,"journal":{"name":"Day 2 Tue, April 26, 2022","volume":"52 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134583753","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Visualization Study of Low-Tension Polymer Flood for Viscous Oil Reservoirs","authors":"Yujia Guo, Haofeng Song, K. Mohanty","doi":"10.2118/209466-ms","DOIUrl":"https://doi.org/10.2118/209466-ms","url":null,"abstract":"\u0000 Polymer flood improves the sweep efficiency of viscous oil recovery over water flood. The low-tension polymer (LTP) flood has the potential to improve the displacement efficiency due to low interfacial tension without sacrificing sweep efficiency. The objective of this research is to evaluate the performance of LTP floods as a function of IFT for a viscous oil in a 2D sand pack. Over 20 non-ionic surfactants/co-solvents were tested. A series of sandpack flooding experiments were conducted in a custom-designed 2D visualization cell. The results show that short-hydrophobic surfactants 2EH-xPO-yEO can reduce the IFT to as low as 0.05 dynes/cm. Flooding experiments were performed in sandpacks with and without connate water saturation. For the experiments with connate water saturation, the sandpack was water-wet/intermediate-wet. A base-case polymer flood (without any surfactant) with a viscosity ratio of 10 showed a stable displacement and 82% OOIP oil recovery at the first pore volume injected (PVI).LTP flood with an IFT of 0.1 dynes/cm also showed stable displacement front, but ahigher oil recovery at 1 PVI (90% OOIP).Further reduction in IFT to 0.05 dynes/cm resulted in an unstable displacement and a lower recovery of 65% OOIP. For the experiments without connate water saturation, sandpack was oil-wet, the base-case polymer flood at a viscosity ratio of 10 showed severe fingering and a low oil recovery at 1 PVI (58% OOIP). Adding the nonionic surfactants did not improve displacement efficiency nor oil recovery in oil-wet sandpacks.","PeriodicalId":385693,"journal":{"name":"Day 2 Tue, April 26, 2022","volume":"41 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116026614","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":"Rapid Estimation of Carbon Dioxide Stored in CO2 EOR Operations for Screening Purposes","authors":"A. Carlino, A. Muggeridge, P. Smalley","doi":"10.2118/209432-ms","DOIUrl":"https://doi.org/10.2118/209432-ms","url":null,"abstract":"\u0000 We describe the development, testing, and first application of a rapid method for estimating the CO2 storage potential associated with CO2 enhanced oil recovery in both secondary and tertiary modes. The new method builds on various published empirical models for predicting incremental oil recovery (and hence CO2 storage) in solvent floods. It improves the representation of reservoir heterogeneity caused by depositional layering and fracturing. This is then combined with material balance to make site-specific estimates of the CO2 storage potential.\u0000 We cross-checked predictions from the new method against historical field data for major onshore CO2 floods with satisfactory results considering the very approximate nature of the estimation. We then applied the method to a selection of offshore oil reservoirs and found that, generally, the larger the remaining oil, which is a function of initial size and current recovery factor, the greater the CO2 storage potential. We also modelled the case of continued injection after ceasing oil production at, or after, CO2 breakthrough and observed that, as expected, the amount of CO2 stored at breakthrough depends on how early this occurs, which is affected by reservoir heterogeneity, whereas continued injection is limited by the headroom between current reservoir pressure and fracture pressure. The overall storage is the result of the interplay between these two mechanisms. In the studied fields/reservoirs, we demonstrated that large amounts of CO2 can be stored in terms of absolute mass and that storage of these quantities would represent significant abatement of the emissions generated by burning the incremental oil.\u0000 The new method can be used as a screening tool to identify and rank candidate oil fields for combined CO2 enhanced oil recovery and storage in regional, national, or corporate portfolios.","PeriodicalId":385693,"journal":{"name":"Day 2 Tue, April 26, 2022","volume":"8 3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123524693","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":"Lab and Pilot-Scale Evaluation of Stable Foam for Drilling in High Temperature Environment","authors":"C. Griffith, Harold C. Linnemeyer, Do Hoon Kim, Ruth Hahn, Jimin Zhou, E. Upchurch, Taimur Malik, Angel Wileman, Griffin C. Beck, S. Bhagwat, Luis Gutierrez","doi":"10.2118/209379-ms","DOIUrl":"https://doi.org/10.2118/209379-ms","url":null,"abstract":"\u0000 Using foams to drill in low pore pressure reservoirs is attractive because of their low density, high viscosity, and ability to transport cuttings. However, in high temperature reservoirs (240 °F) with H2S gas present, there are concerns with the long-term stability of a foam drilling fluid. In this work, we highlight a lab program to develop a stable drilling foam for drilling in a low pore pressure, high temperature reservoir. The work also includes pilot-scale experiments to evaluate foam performance.\u0000 Aqueous nitrogen-in-water foams were stabilized with a preferred foaming surfactant formulation, and the rheology and stability of the foams were measured at representative drilling conditions (temperature and pressure) at the lab and pilot-scale. The foams were also evaluated for their compatibility with current drilling fluids used on site and for stability in the presence of H2S gas (at 1900 psi and 140 °F). The drilling foam was also evaluated using a pilot-scale flow loop comprised of a rheology flow loop and a model drilling wellbore. The experiments included measuring the foam rheology, foam stability in the model wellbore, and gas migration tests to understand how the foam suppresses upwardly migrating gas bubbles.\u0000 We successfully developed a surfactant stabilized foam designed for a high-temperature reservoir with H2S gas present. We found that H2S can negatively impact foam stability if proper surfactants are not selected. Our foam showed less than 10% liquid drainage after 12 hours at 240 °F and showed no significant degradation upon contact with 17 mol% H2S gas. Additionally, the foam was compatible with all drilling fluids (both water-based and oil-based) currently used at the drill site and demonstrated good stability in a model pilot-scale drilling wellbore. Interestingly, when the wellbore was angled at 30 degrees from vertical with the eccentric drill pipe rotating at 100 RPM, the foams were susceptible to degradation compared to an equivalent scenario of a vertical wellbore with concentric rotating drill pipe. The gas migration tests at the pilot-scale showed the foam was capable of significantly slowing down an upwardly moving gas bubble with and without pipe rotation.","PeriodicalId":385693,"journal":{"name":"Day 2 Tue, April 26, 2022","volume":"2 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124650998","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":"Interference Analysis in Reservoirs with Bottom-Water Drive During Water Injection Processes Through Subsurface Connectivity","authors":"V. Martinez, E. Ozkan, Heber Cinco Ley","doi":"10.2118/209376-ms","DOIUrl":"https://doi.org/10.2118/209376-ms","url":null,"abstract":"\u0000 This work analyzes the feasibility of implementing water injection processes through subsurface connectivity between different formations through communicating wells, allowing the water to flow from a source aquifer to a depleted formation. It presents a 3-dimensional semi-analytical model for estimating water influx in reservoirs with bottom-water drive and analyzing interference between reservoirs when subsurface connectivity is carried out to supply energy from an aquifer. It applies to both finite and infinite aquifers and reservoirs sharing an aquifer. The general solution is obtained by solving the diffusion equation employing Laplace and Fourier cosine transforms and is presented in Laplace space, requiring a numerical inversion method to convert the results to the real space. The functionality of the analytical solution is evaluated with reservoir numerical simulation and communicating well models. Results show that implementing this solution brings notable advantages because the ultimate oil recovery factor improves considerably. Additionally, it delays the water encroachment in reservoirs adjoined to the source aquifer and reduces water production.","PeriodicalId":385693,"journal":{"name":"Day 2 Tue, April 26, 2022","volume":"87 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123163879","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":"Fundamental Improvements in Modeling Surfactant Behavior in Reservoir Simulators","authors":"L. Chang, Zhitao Li, Haishan Luo, G. Pope","doi":"10.2118/209423-ms","DOIUrl":"https://doi.org/10.2118/209423-ms","url":null,"abstract":"\u0000 Most chemical EOR formulations are surfactant mixtures, but these mixtures are usually modeled as a single pseudo-component in reservoir simulators. However, the composition of an injected surfactant mixture changes as it flows through a reservoir. For example, as the mixture is diluted, the CMC changes, which changes both the adsorption of each surfactant component and the microemulsion phase behavior. Modeling the physical chemistry of surfactant mixtures in a reservoir simulator was found to be more significant than anticipated and is needed to make accurate reservoir-scale predictions of both chemical floods and the use of surfactants to stimulate shale wells.","PeriodicalId":385693,"journal":{"name":"Day 2 Tue, April 26, 2022","volume":"140 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123277673","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":"Impact of Brine Chemistry on Waterflood Oil Recovery: Experimental Evaluation and Recovery Mechanisms","authors":"B. Aminzadeh, S. Chandrasekhar, M. Srivastava, T. Tang, A. Inouye, M. Villegas, Monika Valjak, V. Dwarakanath","doi":"10.2118/209426-ms","DOIUrl":"https://doi.org/10.2118/209426-ms","url":null,"abstract":"\u0000 Water floods are typically conducted using the least expensive, easily available, non-damaging brine. Very little attention is given to the possibility of changing brine composition to improve oil recovery. Over the last 20 years, there has been laboratory and field trial evidence that shows changing brine chemistry, especially to low salinity, can sometimes increase the recovery. The various mechanisms of additional oil recovery from changing brine chemistry are not entirely clear. We report here on the effect of using low salinity and divalent altered brines on oil recovery through a variety of laboratory methods and materials. More than twenty corefloods were conducted to evaluate the effect of brine chemistry and initial wettability on incremental oil recovery. We also performed phase behavior tests, contact angle measurements, and wettability index measurements to evaluate recovery mechanisms. Initial wettability of the core was altered by ageing it with different crude oil containing wide range of asphaltene content. The core flood with lowest wettability index (least water-wet) produced about 12% incremental recovery while the most water-wet core only produced ∼ 4% during the secondary low salinity waterflood.","PeriodicalId":385693,"journal":{"name":"Day 2 Tue, April 26, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134356325","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":"Polymer Stabilized Foam Rheology and Stability for Unconventional EOR Application","authors":"C. Griffith, J. Jin, Harold C. Linnemeyer, Gayani Pinnawala, B. Aminzadeh, Samuel Lau, Do Hoon Kim, D. Alexis, Taimur Malik, V. Dwarakanath","doi":"10.2118/209465-ms","DOIUrl":"https://doi.org/10.2118/209465-ms","url":null,"abstract":"\u0000 It has been shownthat injecting surfactants into unconventional hydraulically fractured wells can improve oil recovery. It is hypothesized that oil recovery can be further improved by more efficiently distributing surfactants into the reservoir using foam. The challenge is that in high temperature applications (e.g., 240 F) many of these formulations may not make stable foams as they have only moderate foaming properties (short half-life). Therefore, we are evaluating polymers that can be used to improve foam stability in high temperature wells which has the potential to improve oil recovery beyond surfactant only injection.Surfactant stabilized nitrogen foams were evaluated using a foam rheometer at pressures and temperatures representative of a field pilot well. The evaluation process consisted of measuring baseline properties (foam viscosity and stability) of a surfactant stabilized foam without any added stabilizer. Next, conventional enhanced oil recovery polymers (HPAMs, modified-HPAMs, and nonionic polymers) were added at different concentrations to determine their impacts on foam stability.\u0000 Our results demonstrate that inclusion of a relatively low concentration (0.05 wt% – 0.2 wt%) of polymer has a pronounced impact on foam stability. It was determined that reservoir temperature plays a key role in selecting astabilizing polymer. For example, at higher temperatures (>240 F), sulfonated HPAM polymers at just 0.2 wt% more than doubled the stability of the foam. The polymer that was selected from this lab work was tested in a foam field trial in an unconventional well. It is thought that improved foam stability could potentially help improve the distribution of surfactants in fracture network and further improve oil recovery.","PeriodicalId":385693,"journal":{"name":"Day 2 Tue, April 26, 2022","volume":"8 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126248990","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":"An Unconventional Approach to Model a Polymer Flood in the Kalamkas Oilfield","authors":"M. Sagyndikov, R. Seright, Nauryzbek Tuyakov","doi":"10.2118/209355-ms","DOIUrl":"https://doi.org/10.2118/209355-ms","url":null,"abstract":"\u0000 This article describes the main features of an unconventional approach to model a polymer flood in the Kalamkas oilfield. This non-standard simulation method is based on specially performed inter-well tracer tests, step-rate tests, pressure fall-off tests, dedicated field studies, well monitoring, and lab analysis. Our approach excludes permeability reduction as a mechanism to provide more mobility reduction than expected from rheology measurements (resistance factor) and by improving the recovery during post-polymer water flooding (residual resistance factor). Evidence is presented to support this exclusion for real field applications. Additionally, our approach places a significant emphasis on history matching bottomhole pressures. Our effort accounts well for the decreased mobility of the injected polymer solution and increased rock permeability during a polymer flood. In contrast to most other simulation approaches to polymer flooding, our method incorporates open fractures during polymer injection and their impact on injectivity and sweep efficiency. A literature review (lab tests and field cases) and our laboratory and field studies confirm the validity of our approach and its advantages over other modern simulator modeling of polymer flooding. From viscosity measurements of back-produced polymer solutions from injectors and well tests (inter-well tracer tests, pressure fall-off tests, step rate tests), we proved that polymer flooding induces fractures or fracture-like features and consequently, the polymer solution flows through the fracture with increased injectivity proportional to a resistance factor. Also, incorporated are expectations during a brine post-flush and the absence of the residual resistance factor (i.e., equal to 1). Implementation of these concepts brings our model closer to reality for simulating polymer floods.","PeriodicalId":385693,"journal":{"name":"Day 2 Tue, April 26, 2022","volume":"2 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126133617","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":"Conformance Improvement in Fractured Tight Reservoirs Using a Mechanically Robust and Eco-Friendly Particle Gel PG","authors":"B. Wei, Runxue Mao, Qingtao Tian, Xingguang Xu, Lele Wang, Jinyu Tang, Jun Lu","doi":"10.2118/209442-ms","DOIUrl":"https://doi.org/10.2118/209442-ms","url":null,"abstract":"\u0000 Conformance control in tight reservoirs remains challenging largely because of the drastic permeability contrast between fracture and matrix. Thus, reliable, durable and effective conformance improvement methods are urgently needed to increase the success of EOR plays in tight reservoirs. In this work, we rationally designed and prepared a mechanically robust and eco-friendly nanocellulose-engineered particle gel (referred to NPG) toward this application due to the superior stability. The impacts of superficial velocity, NPG concentration and particle/fracture ratio on the transport behavior in fracture were thoroughly investigated. We demonstrated that the mechanical properties of NPG such as strength, elasticity, toughness and tensile strain were substantially promoted as a result of the interpenetrated nanocellulose. During NPG passing through fracture model, it produced a noticeably greater flow resistance in comparison with the control sample (nanocellulose-free), suggesting the better capacity in improving the conformance of fractured core. It was found that the generated pressure drop (ΔP) was more dependent on the particle/fracture ratio and NPG concentration.","PeriodicalId":385693,"journal":{"name":"Day 2 Tue, April 26, 2022","volume":"144 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122937132","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}