Day 1 Mon, October 03, 2022最新文献

{"title":"Understanding Wettability of SiO2-Brine-CO2 System Using Modified DLVO Theory and its Applications in Carbon Geo-Sequestration Processes","authors":"Bhautik Agrawal","doi":"10.2118/212386-stu","DOIUrl":"https://doi.org/10.2118/212386-stu","url":null,"abstract":"\u0000 The reduction of Carbon footprints without hindering the evolution of the fossil fuel industry is the subject of prominent attention and research these days. In multi-phase rock-fluid systems, the wettability characteristics play a substantial role in determining the trustworthiness of underground reservoir formations for holding CO2 in situ for Carbon Geo-sequestration applications. Despite several struggles over the modern years in recognizing the aspects such as the information on the wettability of systems comprising CO2 under supercritical conditions and the zeta potential over the brine- CO2 film interfaces, inferring the wettability of the complete arrangement are crucial uncertainties and voids in our existing knowledge. Again, one needs to deal with the concepts of wettability and capillary pressures to understand the suitability of a formation for carbon sequestration. This study focuses on the sequestration of carbon in deep saline brine reservoirs. Under the intense pressure and temperature situations in these formations, CO2 can exist in a supercritical state and thus have a liquid-like density, enabling efficient utilization of the pore spaces in those formations.\u0000 In this research, a mathematical model based on the modified DLVO (Derjaguin, Landau, Verwey, and Overbeek) theory is designed to provide a better insight into the wettability of supercritical CO2 systems by utilizing fundamental principles to evaluate contact angles. The base model has been modified in the course of the study to accommodate for the properties of supercritical CO2. This model can also take up the experimental contact angle measurements as an input to anticipate values of critical properties that are presently unfamiliar, as they are challenging to analyze, such as the zeta potential on brine- CO2 interfaces. This model could also predict the suitability of geological reservoirs for carbon sequestration by evaluating the wettability under known conditions.","PeriodicalId":223474,"journal":{"name":"Day 1 Mon, October 03, 2022","volume":"6 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122280358","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 Novel Correction Method for Pressure Transient Analysis Results of Horizontal Wells in Stratified Carbonate Reservoir with High Permeability Zone","authors":"Ruicheng Ma, Zeqi Zhao, Yong Li, Chunmei Zou, D. Hu, Yajing Chen, Leifu Zhang","doi":"10.2118/210402-ms","DOIUrl":"https://doi.org/10.2118/210402-ms","url":null,"abstract":"\u0000 High permeability zone (HPZ) formed by sedimentation and diagenesis has been founded in numerous oil fields in Middle East. Meanwhile, horizontal well have been applied universally in these oil fields. To obtain wellbore status and reservoir properties, pressure transient analysis (PTA) is a convenient and economic surveillance method. However, when it comes to stratified reservoir, heterogeneity between layers should be noticed. Log-log plot of actual data will be far form ideal analytical solution with homogeneous hypothesis. Therefore, the interpreted results would not be representative for wellbore and reservoir condition. In this research, we proposed a novel correction mathematical model and correction workflow for PTA results of horizontal wells in stratified carbonate reservoir with HPZ. This research innovatively imports production performance analysis and other monitoring methods to PTA in the view of flow field. This new approach holds favorable potential to provide accurate wellbore status and reservoir parameters for making the most use of surveillance budget.","PeriodicalId":223474,"journal":{"name":"Day 1 Mon, October 03, 2022","volume":"43 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130470463","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":"General Considerations for the Use of Offshore Depleted Reservoirs for CO2 Sequestration","authors":"A. Amirlatifi, A. Ovalle, Somayeh Bakhtiari Ramezani, I. Mohamed, O. Abou-Sayed","doi":"10.2118/210059-ms","DOIUrl":"https://doi.org/10.2118/210059-ms","url":null,"abstract":"\u0000 Carbon dioxide (CO2) sequestration is one of the most effective ways of overcoming the excessive emissions of anthropogenic CO2 and the resulting climate change. The existence of large and accessible pore space, along with the wells, pipelines, and surface facilities, makes depleted oil and gas reservoirs a prime target for the deposition of CO2. This study aims to outline the primary considerations for sequestration of CO2 in abandoned oil and gas reservoirs, with a particular focus on offshore reservoirs in the Gulf of Mexico (GOM).\u0000 We examine publicly available data from the Bureau of the Ocean Energy Management (BOEM) to gather insight into the existing porous formations in the GOM. Particular interest is given to the formations that have been assessed, developed, and are now abandoned. This approach has enabled us to identify significant storage potentials in shelf, shallow and deep parts of the GOM, making it possible to offer an abundance of safe and long-term storage options in this region.\u0000 The first productions in the GOM started back in 1947. As of January 2018, over 900 GOM fields, including more than 5,000 reservoirs (also known as \"Sands\"), have since ceased production. The total pore volume of these reservoirs is over 175 million cubic feet or over 6.1 million cubic meters. Although many of the wells in these reservoirs are permanently plugged and abandoned (P&A), the existing knowledge about the pore space, the presence of proven seal and geomechanical stability, and the favorable depth of such sands are still highly relevant to commercially viable CO2 sequestration scenarios. Such knowledge can provide a wealth of knowledge, which had to be acquired otherwise prior to the development of the sequestration project.\u0000 The present paper offers an overview of the potential CO2 sequestration candidates in the GOM and practical considerations for commercially viable and environmentally friendly sequestration sites. We examine the main factors contributing to the safety and sustainability of long-term storage and sequestration projects, along with remedial techniques that would pave the road for commercial leasing of pore space in the GOM for safe and effective disposal of CO2.","PeriodicalId":223474,"journal":{"name":"Day 1 Mon, October 03, 2022","volume":"6 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134250513","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 Evaluation of Pressure Control Methods During Riser Gas Handling with MPD Equipment Based on Transient Multiphase Flow Modeling and Distributed Fiber Optic Sensing","authors":"Chen Wei, Yuanhang Chen, O. Santos, Mahendra Kunju, Shahriar Mahmud, M. Almeida, P. Sonnemann","doi":"10.2118/210410-ms","DOIUrl":"https://doi.org/10.2118/210410-ms","url":null,"abstract":"\u0000 During the past decade, the increased use of Managed Pressure Drilling (MPD) equipment has significantly improved the safety and efficiency of gas influx management. However, it is still not clear to the industry what should be the safest and most effective pressure control method for removing gas influxes out of a riser. The objective of this study is to perform a systematic evaluation of different pressure control methods for riser gas handling, including the constant surface backpressure method, the constant riser bottom pressure method, and the fixed choke and constant outflow method.\u0000 A transient multiphase flow simulator based on a Drift Flux Model was developed to simulate riser gas handling events in a Water Based Mud (WBM) system. Multiple sets of full-scale experimental data were used for the calibration and validation of the simulator. In the full-scale experiments, riser gas events were simulated by injecting gas into the bottom of an experimental well, followed by applying different pressure control methods. Besides conventional downhole and surface pressure and flow measurement instrumentations, a Distributed Fiber Optic Sensing (DFOS) system was used for the high-resolution monitoring of gas influxes in the annulus.\u0000 The performance of different pressure control methods was evaluated based on the simulation results, including the behaviors of surface and riser bottom pressures, peak surface outflow rates, and the time required for riser gas handling. The numerical simulations carried out in this study can help better understand the different pressure control methods and improve the design of riser gas handling strategies.","PeriodicalId":223474,"journal":{"name":"Day 1 Mon, October 03, 2022","volume":"43 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132739748","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":"Pros and Cons of Saline Aquifers Against Depleted Hydrocarbon Reservoirs for Hydrogen Energy Storage","authors":"M. Delshad, M. Alhotan, B. R. Batista Fernandes, Y. Umurzakov, K. Sepehrnoori","doi":"10.2118/210351-ms","DOIUrl":"https://doi.org/10.2118/210351-ms","url":null,"abstract":"\u0000 Hydrogen (H2) is an attractive energy carrier and its true potential is in decarbonizing industries such as providing heat for buildings and being a reliable fuel for trains, buses, and heavy trucks. Industry is already making tremendous progress in cutting costs and improving efficiency of hydrogen infrastructure. Currently heating is primarily provided by using natural gas and transportation by gasoline with a large carbon footprint. Hydrogen has a similarly high energy density but there are technical challenges preventing its large-scale use as an energy carrier. Among these include the difficulty of developing large storage capacities.\u0000 Underground geologic storage of hydrogen could offer substantial storage capacity at low cost as well as buffer capacity to meet changing seasonal demands or possible disruptions in supply. There are several options for large-scale hydrogen underground storage: lined caverns, salt domes, saline aquifers, and depleted oil/gas reservoirs where large quantities of gaseous hydrogen can be safely and cost-effectively stored and withdrawn as needed. Underground geologic storage must have adequate capacity, ability to inject/extract high volumes with a reliable caprock. A thorough study is essential for a large number of site surveys to locate and fully characterize the subsurface geological storage sites both onshore and offshore.\u0000 A non-isothermal compositional gas reservoir simulator and its suitability for hydrogen storage and withdrawal from saline aquifers and depleted oil/gas reservoirs was evaluated. The phase behavior, fluid properties, and petrophysical models were all calibrated against published laboratory data of density, viscosity, relative permeability, and capillary pressure for a given site. History-matched dynamic models of two CO2 injection field projects in saline aquifers and one natural gas storage in depleted oil reservoir were considered as hypothetical hydrogen seasonal storage sites. The results revealed the need to contain the stored working gas volume because of high mobility of gaseous H2 with an integrated approach of site selection and its geological features, well locations, and the need for pump wells to maximize the capacity and deliverability.","PeriodicalId":223474,"journal":{"name":"Day 1 Mon, October 03, 2022","volume":"48 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131945206","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":"Wettability Alteration with Weak Acid Assisted Surfactant Flood","authors":"Yue Shi, Fangya Niu, K. Mohanty","doi":"10.2118/210436-ms","DOIUrl":"https://doi.org/10.2118/210436-ms","url":null,"abstract":"\u0000 Oil-wetness and heterogeneity are two key reasons for low oil recovery by waterflooding in carbonate reservoirs. Surfactants have been effective in altering oil-wet matrix to a more water-wet condition and initiating spontaneous imbibition. Because it takes time for surfactant to alter wettability, oil recovery from the tight matrix is considered to be slow and sometimes not economically feasible. Acids have a potential of dissolving minerals, which may alter wettability. In this study, the EOR performance of acid-assisted surfactant water was evaluated for both low- and high-temperature applications. A set of acids and their acetates were tested. Bulk rock-acid reaction, wettability alteration (WA) tests and spontaneous imbibition measurements were conducted at both 35°C and 80°C to identify effective candidates. Coreflood tests were then performed to evaluate the selected acid-surfactant formulations. Before and after coreflood test, the core was scanned in a micro-CT to investigate pore structure alteration. Bulk reaction measurements showed that weak acids, especially acetic acid (AA), have the desired low reaction rates at 35°C. At 80°C, acetates exhibited a slow reaction. WA tests showed that, at 35°C, AA can remove the crude oil off the rock surface and alter wettability. Acetates showed wettability alteration potentials at 80°C. Spontaneous imbibition experiments showed that AA-surfactant solution results in the highest oil recovery at 35°C. Acetate-surfactant showed a high oil recovery and a long equilibrium time at 80°C. Coreflood tests showed that adding AA into surfactant water can significantly improve oil production and its rate through mineral dissolution and wettability alteration. Micro-CT showed that minerals were transported along the core and plugged vugs, which reduced permeability and diverted flow leading to improved oil recovery.","PeriodicalId":223474,"journal":{"name":"Day 1 Mon, October 03, 2022","volume":"13 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116240704","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":"Optimizing Wasson ROZ CO2 Flood Pattern Configuration for Capital Efficiency: Case Study of 40-Year Field History","authors":"Tao Gang, Andrew Jones, Kaitlyn Painter, Nick Cestari, S. Nezhad, J. Burgos, P. Bandyopadhyay, V. Sahni","doi":"10.2118/210212-ms","DOIUrl":"https://doi.org/10.2118/210212-ms","url":null,"abstract":"\u0000 The use of CO2 injection to produce oil from the residual oil zone (ROZ) of the Wasson field in the Permian Basin has proven to be highly successful when an appropriate development plan is used. The significant volume of oil in place in the ROZ presents a large target for both reserves addition and CO2 sequestration. More than 60% of the ROZ potential lies beneath the already developed San Andres main oil column (MOC) area, which is under CO2 flooding with varying states of maturity, making it challenging to develop such projects efficiently and economically.\u0000 Over the past 20 years, different pattern configurations (nine-spot, line drive, five-spot) and completion strategies (commingled injector, injection subsurface flow control devices, dual completion injection, dedicated and hybrid line drive) have been used at the Wasson oil development company (ODC) field to develop the ROZ. The results of these various pattern configurations and completion techniques and their pros and cons are discussed in this paper. Commingled production makes it more difficult to quantify incremental ROZ production and increases uncertainty in the performance forecast of future ROZ projects. The dedicated injectors provide better injection control to MOC and ROZ and improve CO2 utilization, especially where the MOC is mature.\u0000 In this paper, we present one of the key findings from a detailed analysis of field history that caused Oxy to switch from the original dedicated ROZ development to a hybrid line drive pattern configuration. This novel strategy will have higher CO2 retention and more sequestration potential, better areal sweep efficiency for improved oil recovery, and lower capital and operating cost. It also reduces the likelihood of injector interference, provides a stable injection throughput for a long time, and results in a sustained oil and CO2 production plateau, which leads to more efficient utilization of plant capacity.\u0000 Using ODC as an example, the total capital, F&D costs, and the number of new injection wells will be reduced by 33%, 35%, and 45%, respectively, for changing all the undeveloped patterns from the dedicated to hybrid line drive option. This novel development strategy improves the chance of promoting contingent resources (not currently considered to be commercially recoverable owing to one or more contingencies) to a higher category and offers higher returns with much lower F&D cost and shorter development time.","PeriodicalId":223474,"journal":{"name":"Day 1 Mon, October 03, 2022","volume":"65 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127259347","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":"Geological Neural Network Methodology for Automatic History Match; Real Case for Rubiales Field","authors":"Ruben Rodriguez-Torrado, Alberto Pumar-Jimenez, Pablo Ruiz-Mataran, Mohammad Sarabian, Julian Togelius, L. Toro Agudelo, Alexander Rueda, E. Gallardo, Ana María Naranjo, S. Arango, Jose Alberto Villasmil","doi":"10.2118/210133-ms","DOIUrl":"https://doi.org/10.2118/210133-ms","url":null,"abstract":"Full history match models in subsurface systems are challenging due to the large number of reservoir simulations required, and the need to preserve geological realism in matched models. This drawback increases significantly in big real fields due to the high heterogeneity of the geological models, the reservoir simulation computational time (which increases superlinearly). In this work, we propose a novel framework based on artificial intelligence to address these shortcomings. Our workflow is based on two main components: The first is the new combination of model order reduction techniques (e.g., principle component analysis (PCA), kernel-PCA (k-PCA)) and artificial intelligence for parameterizing complex three-dimensional (3D) geomodels, called \"Geo-Net\". Our new approach is able to create complex high dimensional heterogeneous reservoirs in seconds, providing better correspondence with the underlying geomodels, hard-data constraints and geological plausibility. The second component is a derivative-free optimization framework to complete the automatic history matching (AHM). This new approach allows us to perform local changes in the reservoir at the same time as we conserve geological plausibility. We have examined our methodology in a real field in Colombia. The Rubiales Oil Field is located in the Llanos Basin with original oil in place of around 6 billion barrels. The key finding here is that the Geo-Net is able to recreate the full geological workflow obtaining the same high order of statistics as traditional geo-statistical techniques. Nonetheless, our Geo-Net allows us to control the full process with a low-dimensional vector and reproduces the full geological workflow 10,000 times faster than commercial geo-statistical packages. Finally, the full optimization workflow has been applied to AHM. Results show an improvement with respect to best practice of traditional history match workflows.","PeriodicalId":223474,"journal":{"name":"Day 1 Mon, October 03, 2022","volume":"14 3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121771556","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":"Evaluation of the Oil Recovery and Economic Benefit of the First-Ever Polymer Flood Field Pilot to Enhance the Recovery of Heavy Oils on Alaska's North Slope using Machine-Assisted Reservoir Simulation","authors":"C. Keith","doi":"10.2118/212387-stu","DOIUrl":"https://doi.org/10.2118/212387-stu","url":null,"abstract":"The first-ever polymer flood field pilot to enhance the recovery of heavy oils on the Alaska North Slope is ongoing. This study seeks to evaluate the oil recovery and economic performance of the project via machine-assisted reservoir simulation. First, a reservoir simulation model is calibrated to the production data through the introduction and modification of transmissibility contrasts. Machine-assisted history matching techniques are crucial to the success of this procedure. To replicate the early water breakthrough observed during waterflooding, transmissibility contrasts are emplaced in the reservoir model to force the viscous fingering behavior expected when water is used to displace this 330 cp heavy oil. After injection is switched to tertiary polymer flooding, the transmissibility contrasts are reduced to replicate the significant decrease in the producing water cut. This behavior indicates the dampening of viscous fingering effects, which is expected from the switch to a less mobile injected fluid. Later, transmissibility contrasts are reinstated in the simulation model to recreate a producing water cut surge. This surge indicates a decrease in the injection conformance, likely from the overextension of fractures developed at the injecting wells. Next, oil recovery forecasts are produced using calibrated simulation models from each stage of the history matching process. These production forecasts are then input into an economic model, incremental to waterflooding expectations. The decision to pursue incremental economic analysis is fit-for-purpose, allowing for a focused evaluation of the decision to switch from waterflooding to polymer flooding whilst canceling out a number of impertinent and uncertain cash flows. In all cases, the forecasts demonstrate that the polymer flood will produce a much greater heavy oil recovery than waterflooding, yielding attractive project economics even under conservative oil price and polymer cost assumptions. Thus, we conclude this polymer flood field pilot is both technically and economically successful. However, significant variations in recovery and economics between the simulation scenarios indicate that a simulation model only remains valid for prediction if the flow structure in the reservoir remains consistent with its historic behavior. Thus, a simulation model calibrated for waterflooding may not capture the full technical and economic benefit of polymer flooding or other enhanced oil recovery processes. Furthermore, the overextension of fractures from injecting wells reduces the expected performance of the polymer flood, perhaps necessitating future conformance treatments.","PeriodicalId":223474,"journal":{"name":"Day 1 Mon, October 03, 2022","volume":"46 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129228870","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":"Effective Extraction of a Heavy Oil Resource by an Environmentally Friendly Green Solvent: Limonene.","authors":"T. A. Mathews, Paul Azzu, J. Cortes, B. Hascakir","doi":"10.2118/210138-ms","DOIUrl":"https://doi.org/10.2118/210138-ms","url":null,"abstract":"Global oil consumption is predicted to increase by 15% from 2021 to 2050. The increasing oil demand and decreasing conventional oil supply force us to find alternate energy supplies. The key to this problem lies with the vast untapped heavy oil and bitumen resources. In this study, we investigate the effectiveness of an environmentally friendly solvent, limonene, in recovering heavy oil.\u0000 Three core flood experiments representing three different recovery methods were carried out. These include steam flooding (E1), solvent flooding (E2), and solvent-steam co-injections (E3). The green solvent, limonene, is a citrus-based non-toxic solvent. It was chosen due to its high organic solvency and ready availability. Throughout the experiments, steam was injected at a cold water equivalent of 18 ml/min, while limonene was injected at 2 ml/min. The experiments were run with a back pressure of 45-55 psi. The core pack was prepared by filling the pore space of Ottawa sand with a 60% heavy oil sample and 40% water by volume (including water percentage in oil). Produced oil and water samples were collected every 20 min during the experiments. These samples were further analyzed by emulsion characterization to determine emulsion stability and oil quality. Spent rock analyses were done to calculate the displacement efficiency of each of the experiments. In addition, an economic analysis was done to determine the optimal recovery method.\u0000 Spent rock analysis showed that a sole injection of limonene (E2) had the highest oil recovery. This confirms the high organic solvency of limonene achieved miscible flooding producing about 46 vol % from a total of 60 vol % initial oil. Steam flooding (E1), on the other hand, did not perform as well, producing around 29 vol %. The post-mortem sample from E1 indicated asphaltene precipitation which could have lowered oil recovery. Co-injection of limonene and steam was expected to yield the highest recovery due to the presence of two active drive mechanisms, thermal and miscible flooding. However, it performed comparatively less (41 vol %) than a sole injection of limonene (E2). This is further explained with emulsion characterization results. Experiments involving steam (E1 and E2) revealed strong emulsions in the oil produced, indicating a lower quality.\u0000 Furthermore, it was seen that the solvent-steam process produced weaker emulsions compared to steam flooding alone. On the other hand, solvent flooding (E2) produced high-quality oil with little to no emulsions. These results along with the economic analysis, indicate that the optimal recovery method would be solvent flooding (E2).\u0000 Our results prove that limonene is a promising organic solvent. Limonene is non-toxic, readily available, and safe to handle. As a result, it can be a safe green alternative to commonly used toxic organic solvents such as toluene.","PeriodicalId":223474,"journal":{"name":"Day 1 Mon, October 03, 2022","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129353612","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}