Day 1 Wed, March 15, 2023最新文献

{"title":"Extensive Experimental Study of Low-Salinity Waterflooding Using Hele-Shaw Cell: A Focus on Gravity and Mobility Ratio Effects","authors":"A. Belhaj, S. H. Fakir, N. Singh, H. Sarma","doi":"10.2118/212785-ms","DOIUrl":"https://doi.org/10.2118/212785-ms","url":null,"abstract":"\u0000 Recently, low-salinity waterflooding (LSWF) has garnered attention as a promising enhanced oil recovery (EOR) method. LSWF implies the injection of a modified-composition brine into oil reservoirs with a promising potential of enhancing the oil recovery. In this study, two-dimensional visualization of oil displacement mechanism during LSWF is performed in a Hele-Shaw cell. A set of comprehensive experiments is conducted to investigate the areal sweep efficiency between different oils and brines as a function of various parameters. The movement in the Hele-Shaw cell is considered similar to two-dimensional flow in porous medium. Various parameters (ionic strength, injection rate, gravity, and mobility ratio) were extensively studied. The effect of ionic strength was studied between seawater (SW) and 1%diluted-seawater (1%dSW). It was indicated that the dilution of SW to 1%dSW has resulted in a lower areal sweep efficiency. This observation suggests the less dominant impact of oil-water interactions during LSWF. The effect of injection rate was studied for low, intermediate, and high flow rates and the results showed a clear increase in oil recovery with the increase of the injection rate. The effect of gravity was studied at different degrees of inclination angles up to 15°. It was clearly observed that the increase of the inclination angle has resulted in a lower areal sweep efficiency. These results showed that the effect of gravity can have a significant impact on the areal sweep efficiency; moreover, it showed a more profound effect on water fingering at the breakthrough. Light and waxy oils were used in this study, which generated varying mobility ratios with different injected brines. The analyzed images illustrated a lower oil recovery at a higher mobility ratio, as it was clearly observed that the injected brines achieved better areal sweep efficiency displacing the light oil as compared to the waxy oil. Most LSWF studies rely on coreflooding experiments to evaluate the performance of the process. Due to the complexity of the interactions between oil/brine/rock, the mechanisms of this process are not yet fully understood. Investigating the LSWF process in the absence of the rock can provide further explanation of the fluid-fluid (brine-oil) interactions. The gravity effect in this type of experiment was generally ignored and including it in this study makes its findings more representative of inclined oil-bearing formations.","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"361 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122308431","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":"Carbon Sequestration: The Ignored Promise of the Non-Utilization of Carbon Route","authors":"S. Gupta","doi":"10.2118/212815-ms","DOIUrl":"https://doi.org/10.2118/212815-ms","url":null,"abstract":"\u0000 Despite the mature nature of carbon capture and storage (CCS) technology and its combination with various ways of carbon utilization (CCUS), the extent of its global application has been less than 0.1% in addressing the emissions challenge. The reason is the high cost of CCS compared to the prevailing price on carbon in most jurisdictions. The objective of this paper is to present potentially low-cost alternatives to CCS/CCUS.\u0000 Petroleum is the most suitable fuel for the transport needs of the society due to its unparalleled energy density and affordability. The goal of limiting atmospheric CO2 can be met equivalently either by addressing emissions from petroleum (e.g., with CCS) at a cost, or with use of low carbon fuels such as renewables. So far, alternatives to petroleum, despite some advances, have faced an even higher cost hurdle. Therefore petroleum-based fuels with carbon mitigation, deserve a fresh look. CCS has a cost range of $70 - 150/t CO2. While at this cost, oil may still have an advantage over some alternatives, it is an edge that can be further enhanced with new developing technologies such as Lower-oxidation (L-ox) among others (SPE-196109). In L-Ox, energy is derived from carbonaceous fuels in a manner that does not produce a gaseous waste product - CO2.\u0000 The current work first starts with highlighting the limitations of various now-familiar options such as hydrogen, direct air capture, or renewables etc., then it discusses the technical feasibility of electro-thermo-chemical (ETC) routes that show promise and require relatively limited further development of technology, utilizing insights and support from recent advances in unrelated fields. ETC-based approaches can be used both for deriving energy without CO2 production (as in L-Ox), as well as for chemical reduction of the CO2 (produced in the combustion process of energy generation) into ‘useless’ liquids or solids. This latter approach – ‘non-utilization and sequestration’, quite opposite to CCUS, along with L-Ox presents a more economically sustainable option for carbon abatement. This paper lends substance to support the expected feasibility of each.\u0000 Aside from providing a critique of various alternatives, this work offers new insights into developing novel electro-thermo-chemical methods for a low-cost carbon abatement. The significance of this is in helping sustain and preserve global living standards, through affordable, energy-dense, and carbon-neutralized petroleum.","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126889455","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":"Reducing Simulation Time in a Huff-And-Puff Gas Injection Project in Complex Shale Reservoirs: Sequence-Based Proxy Multi-Porosity Reservoir Simulator","authors":"Cristhian Aranguren, Carlos Rodríguez Araque, Santiago Cuervo, A. Fragoso, R. Aguilera","doi":"10.2118/212821-ms","DOIUrl":"https://doi.org/10.2118/212821-ms","url":null,"abstract":"\u0000 The objective of this project is to explore cutting-edge sequence-based machine learning models commonly used in language processing to reproduce a multi-porosity reservoir simulator. The proposed method integrates advanced techniques to significantly reduce the numerical simulation time and improve the decision-making process for Huff and Puff (H-n-P) gas injection optimization in shale reservoirs. The proposed approach follows three crucial steps to predict an output sequence given an input sequence: 1) the simulation results should be validated against actual data, 2) train and validate a machine learning model using simulation results from either commercial or in-house numerical simulators, 3) exhaustive exploration of hyperparameter tuning and selection of machine learning techniques, such as sequence-to-sequence (Seq2Seq), Luong attention and ConvLSTM. The proxy model considers as input variables well control parameters such as injection and production periods, number of cycles and gas injection rates to estimate the proxy model results.\u0000 The multi-porosity proxy reservoir simulation model is a complementary tool that integrates numerical simulation and data-driven techniques. Although tuning the model typically demands significant time, it can speed up the simulation time up to 20,000X allowing for generating hundreds or even thousands of scenarios at the expense of accepting a reduction in the accuracy of the results in a matter of minutes. One of the most notable findings is that considering a small training dataset, the proxy model can reproduce the capabilities for predicting oil production in complex low and ultra-low permeability reservoirs with significantly reduced error, relative to the multi-porosity reservoir simulator. Finally, the possibility of reproducing a considerable number of scenarios in minutes opens the door to exploring different well control configurations such as injection and production periods, number of cycles and gas injection rates. The novelty of the proxy multi-porosity reservoir simulator is to notably accelerate the numerical simulation time by using techniques capable of solving sequence learning problems in which the output is dependent on previous outputs.","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"50 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121267799","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":"Stage-by-Stage Hydraulic Fracture and Reservoir Characterization Through Post-Fracture-Pressure-Decay Technique and Flowback DFIT Method Integration","authors":"D. Zeinabady, C. Clarkson","doi":"10.2118/212726-ms","DOIUrl":"https://doi.org/10.2118/212726-ms","url":null,"abstract":"\u0000 The post-fracture-pressure-decay (PFPD) technique is a low-cost method allowing for stage-by-stage hydraulic fracture characterization. The physics of the PFPD method are complex, with data affected by both hydraulic fracture and reservoir properties. Available analysis methods in the literature are oversimplified; reservoir or fracture properties are often assumed to be constant along the horizontal well, and therefore changes in the trend of pressure decay data are attributed to hydraulic fracture or to reservoir properties only. Moreover, methods analogous to those applied to the analysis of conventional diagnostic fracture injection tests (DFITs) are often used and ignore critical mechanisms involved in main-stage hydraulic fracture stimulation.\u0000 A conceptual numerical simulation study was first conducted herein to understand the key physics involved in main-stage hydraulic fracturing. An analytical model was then developed to account for the dynamic behavior of the hydraulic fracture, pressure-dependent leakoff, proppant distribution, multiple fractures, and propped- and unpropped-closure events. The analytical model is cast in the form of a new straight-line analysis (SLA) method that provides stage-by-stage estimates of the ratio of unpropped fracture surface area to total fracture surface area. The SLA method was validated against numerical simulation results. Moreover, to account for the variation of reservoir properties along the horizontal well, the PFPD model is integrated with DFIT-flowback (DFIT-FBA) tests, performed at some points along the lateral, to obtain a reliable stage-by-stage hydraulic fracture and reservoir characterization approach. The practical application of the proposed integrated approach was demonstrated using PFPD and DFIT-FBA data from a horizontal well completed in 22 stages in the Montney Formation.\u0000 The numerical simulation study demonstrated that the use of proppant and injection into multiple clusters (creating multiple fractures) results in multiple-closure events. The closure process may start early after the pump-in period at a pressure significantly higher than the minimum in-situ stress. Employing DFIT-based analytical models, which ignore the presence of proppant, causes significant errors in hydraulic fracture and reservoir property estimation. The PFPD field data examined herein exhibited a similar pressure trend to the numerical simulation cases. The ratio of unpropped fracture surface area to total fracture surface area was determined stage-by-stage using the PFPD SLA method, constrained by DFIT-FBA data. Engineers can use this information to optimize hydraulic fracture stimulation design in real-time, optimize well spacing, and forecast production. The cost and time advantages of this diagnostic method make this approach very attractive.","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"112 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121334359","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 Review-Dissolution and Mineralization Storage of CO2 Geological Storage in Saline Aquifers","authors":"Bo Wang, Xiangzen Wang, Yiming Chen, Quansheng Liang, F. Zeng","doi":"10.2118/212790-ms","DOIUrl":"https://doi.org/10.2118/212790-ms","url":null,"abstract":"\u0000 Saline aquifer has become the preferred storage location of carbon capture, and storage (CCS) technology because of its wide distribution, large storage capacity and high safety factor. According to IPCC statistics, the storage capacity of saline aquifers worldwide is 400 – 10000 Gt, which is dozens of times that of oil and gas reservoirs and hundreds of times that of coal seams. Therefore, the carbon storage in saline aquifer has the most potential for CO2 storage.\u0000 Carbon sequestration in saline aquifers includes four trapping mechanisms: short-term geological and hydrodynamic capture and long-term geochemical (solubility and mineral) capture. Moreover, the solubility of CO2 in saline aquifer and the mechanism of mineral capture (salt precipitation) depends on the injected CO2 and the water-rock characteristics of saline aquifer. However, current knowledge on geochemical capture is still at an early stage compared to other capture theories. Recent researches indicate that although temperature, pressure, salinity of formation water and mineral composition of formation rocks are important factors affecting mineral storage, other reservoir parameters, such as reservoir thickness, dip angle, anisotropy, and bedding distribution, may also significantly affect salt precipitation, mineral storage, and geo-chemical storage. In this paper, we would like to present a comprehensive review on the solubility model of CO2 in saline aquifers, the phase permeability change of CO2 and saline aquifers, the mechanism of CO2-water -rock interaction, the dissolution and precipitation model of inorganic salt minerals, and the influencing factors for CO2 sequestration in saline aquifers. We believe that this review lays a foundation for future study of carbon storage technology in saline aquifer.","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"8 14","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133652383","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":"Fluids Migration Behind Casings: An Offshore Well Integrity Issue Restoration Experience of AGM043 in Gabon, West-Africa","authors":"Jestril Ebaga Ololo, Dieudonné Ndong-Ovono","doi":"10.2118/212770-ms","DOIUrl":"https://doi.org/10.2118/212770-ms","url":null,"abstract":"\u0000 Minimizing risks in offshore oil and gas production facilities is of upmost importance for oil producers to reduce possibilities of liability claims, hydrocarbons production rate loss, and most importantly environmental impacts. In this regard, well integrity parameters such as MAASP and MAWOP become key tools to carefully follow and watch production tubings and annulus pressures behaviors at the surface.\u0000 AGM043 is an oil producing well which presented a high downgraded situation mainly with abnormal pressure in the annuli A and B and the christmas tree not holding the pressure. The pressure rate observed in the annulus B (104 bars) was considered higher than the limit set as per the MAASP (72 bars) presenting a risk of fracture at the 13-3/8″ casing shoe.\u0000 To regain full integrity of the well, since purging the annuli did not contribute to pressure stabilization and due to the presence of gas (mainly methane), actions were taken to conduct a well killing job split in four phases:\u0000 Phase 1: Purging, investigate communication point between tubing and annuli, echometer for fluid level determination. Phase 2: Well killing by bull heading in the tubing and lubricate and bleed in the annuli. Phase 3: Establishment of a double barriers Phase 4: Valves changes and test of Christmas tree integrity.\u0000 This manuscript discusses the rise of an abnormal pressure behavior in the annular, its management, and the lessons learnt at the end of the integrity regain after the killing job offshore Gabon. The experience gained can be applied to other wells with similar problems.","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"38 2","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133170062","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":"Scaling Issues on Horizontal Multi-Fractured Wells: An Alternative Intervention Approach with Novel Technologies for Diversion and Scale Inhibition","authors":"M. Giammancheri, G. Tassone, G. Carpineta, A. Okoka, R. Itoua, R. Ilyasov, B. Reilly, Venkata Bhamidipati","doi":"10.2118/212771-ms","DOIUrl":"https://doi.org/10.2118/212771-ms","url":null,"abstract":"\u0000 In this paper we present case studies describing the approach adopted to solve scaling issues in a complex well architecture, an analysis of the scaling root causes, and the construction of a novel execution plan incorporating scale inhibitors, diverting agents with different acid systems to maximize the treatment efficiency.\u0000 Even when producing at a low water cut fraction, most of the offshore multi-fractured wells in the field experienced scale deposition phenomena because of instability of the calcium ions present in the formation water. When pressure drawdown is applied on the producing wells, a progressive and severe worsening of production performance was observed, and in certain cases this led to a complete obstruction of the well.\u0000 Previous stimulations executed on the under-performing wells were able to temporarily restore the production. Those treatments were performed using a conventional HCl acid system with coil tubing and these yielded positive results initially, but performance progressively decreased after a few months.\u0000 For this reason, it was a priority to analyze the root cause of the deposition and define an improved method to extend the effectiveness of the intervention. Scale tendency analysis of the formation water highlighted the instability and predicted calcium carbonate presence at the reservoirs’ pressure and temperature range. Based on the evaluation of Saturation Index it was determined that calcite build-up can occur at any point in the production system. This was confirmed by field evidence, with scale deposit samples recovered at the choke, surface line and along the completion tubing.\u0000 A nitrified organic acid blend was applied to invade deeply into the fracture body, together with a liquid scale inhibitor squeeze treatment that was designed to prevent further re-depositions in the short-term. A diversion technology was implemented to treat the multi-fractured horizontal wells in efficient manner by rig-less bullheading.\u0000 Furthermore, due to unavailability of a rig in place, efforts were made to solve the different challenges to operate in rig-less mode: a lack of space on the production platform deck prevented any pumping intervention, and the well restart and clean up was executed directly in a high-pressure sea line.\u0000 This alternative approach, with novel technologies for diversion and scale inhibition, yielded excellent well responses to the placement of the acid mixtures, which were designed to dissolve the carbonate scales with minimum impact on the sandstone formation, completion equipment, and production facilities. The selected solid diverting agent self-degraded by hydrolysis once in contact with water base fluids in the high temperature environment. This diverter was able to effectively distribute the acid treatment into each of the fractures: the particle size distribution was designed to efficiently bridge on the proppant pack in the fractures.\u0000 The well start-up production rates confirmed the maj","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"73 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114415293","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":"Diverting Fracturing Stimulation Technique Using a Novel Temporary Plugging Agent with Multiphase Transition Properties at Different Temperatures","authors":"Xiang Chen, Pingli Liu, Liqiang Zhao, Juan Du, Jiangang Zheng, Zhangxing Chen, Jian Yang, Wanwei Zhao, Fei Liu, Fengcheng Lou, Guan Wang, Jinming Liu, Chengxi Huang","doi":"10.2118/212735-ms","DOIUrl":"https://doi.org/10.2118/212735-ms","url":null,"abstract":"\u0000 Given the fact that diverting fracturing technique can improve the effective stimulation reservoir volume, and the currently-used temporary plugging materials of chemical particles and fibers are difficult to pass through sand-control completion tools and enter into fractures due to their solid nature, this work thus developed a novel temporary plugging agent (TPA) with multiphase transition properties at different temperatures. Laboratory and field experiments were both conducted to study its feasibility on industrial field applications.\u0000 Laboratory experiments were first carried out to investigate the properties of this TPA, including multiphase transition temperature and time, plugging strength, compatibility with other fluids, and core permeability damage, in order to guide the design of plugging agent dosage, fracturing construction parameters, and wellbore-fracture temperature. Then, field experiments were conducted to demonstrate its feasibility on actual field applications. Well A and Well R with almost the same geological and engineering conditions were chosen in this experiment where Well A adopted the developed novel technique and Well R, as a comparison well, adopted a conventional fracturing technique.\u0000 The results from the laboratory experiments indicated that the performance of this TPA met the requirements of industrial standards. With an increase in temperature, this TPA underwent a solution (liquid state) - gel (semi-solid state) - solution (liquid state) transition to meet the needs of different stages in a fracturing treatment, and its multiphase transition speed was controllable. Its plugging strength was positively correlated with its plugging length, with a gradient of 8.9MPa/m. This TPA had good compatibility with other fluids and little damage to rock permeability, only 2%, much less than 25% specified in the standard.\u0000 The results from the field experiments demonstrated that this innovative technique was feasible and effective. The construction curve of Well A indicated that the construction pressure increased by 3.1MPa and the formation broke again after injecting this TPA. The micro-seismic monitoring also supported this finding and showed that new fractures propagated to the north-by-east direction instead of the due west direction. Under the same production system, the initial daily gas production of Well A was 1.3 times that of Well R. After 100 days of production, the daily gas production of Well A was 1.5 times that of Well R.","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"8 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129639142","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":"Determination of Optimal Distance Between Wells in SAGD and VAPEX Methods Using Reservoir Simulation","authors":"M. Bataee, Mahmood Abduljabbar Hebah, Mohsen Shabib-Asl, Z. Hamdi, B. Moradi, S. Ridha","doi":"10.2118/212782-ms","DOIUrl":"https://doi.org/10.2118/212782-ms","url":null,"abstract":"\u0000 Energy resource extraction is getting more difficult and using the enhanced and advanced level of technology for oil production is getting more common. Steam-assisted gravity drainage (SAGD) and Vapor extraction (VAPEX) are two favorable methods of EOR in heavy oil reservoirs. However, there are some obscure points about these methods, like optimum distances between wells and the overall cost of each method. The main objectives of this project were to find the best distance of wells in these types of EOR methods and to enhance the production of heavy oil reservoirs by SAGD and VAPEX methods, taking into consideration of the economic aspects of this project. In this project, SAGD and VAPEX methods were modeled to increase the production rate. Each stage of the Enhance Oil Recovery (EOR) was simulated and modified through many scenarios in terms of the injection patterns, production & injection wells’ locations as well as the adjustment of different injection steam injection and solvent injection. This project analyzed the SAGD method in the shallow reservoir (RF of 69.8%), and in the deep reservoir (RF of 38%). In addition, the maximum allowable depth to apply the SAGD method was found in this study (3500ft). Based on the calculation from the software, it was observed that the heat loss for this reservoir was around 350°F. The cumulative oil production of the SAGD method in the shallow reservoir was 3.87×10^6 bbl and the deep reservoir was2.1×10^6 bbl, and it for the VAPEX method at the shallow reservoir was 2.74×10^6 bbl, and at deep reservoir around 2.64×10^6 bbl, based on the results of each method the VAPEX method remain with the same quality at both reservoirs, however, the SAGD has the lower production in the deep reservoir which means this method is not suitable for the deep reservoir. Furthermore, the profit of each method was calculated; the profit of SAGD and VAPEX were (190.97 MM$ & 168.97 MM$) at the shallow reservoir, and (72.97 MM$ 162.32 MM$) at the deep reservoir for each process. Finally, the spacing between injection and production wells was obtained at different distances and the best distance was 30 m.","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"18 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126727493","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":"Microfluidic-Based Optimization of Polymer flooding for Heavy Oil Recovery","authors":"Zhenbang Qi, Xingyu Fan, A. Abedini, D. Raffa","doi":"10.2118/212758-ms","DOIUrl":"https://doi.org/10.2118/212758-ms","url":null,"abstract":"\u0000 Polymer flooding has been implemented in Western Canada, specifically in Saskatchewan and Alberta since 2000s. Flooding with polymer has been more effective than with water in heavy oil reservoirs due to a more favorable mobility ratio, resulting in more a stable front and less fingering. Optimization of polymer flood strategies is essential for successful implementation of field-scale operations. Core and sand-pack flood testing have been a reliable method for laboratory evaluation of different injection methods and chemicals as the cores are representative of the reservoir geometries and rock chemistries. However, few drawbacks exist such as long turnaround time when multiple strategies need to be compared and inconsistency in pore geometry. Most importantly, this approach cannot resolve the pore scale displacement mechanisms, falling short to compare injection cases in which the recovery factors are similar, but pore-scale dynamics are different. In this study, a microfluidic-based platform was developed to visually evaluate the performance of different polymer flood cases in heavy oil recovery. Two secondary injection tests were performed with water and polymer. A tertiary polymer injection test was also performed with the waterflood followed by the polymer flood. Recovery factors and pore-scale flow behaviour and dynamics of the displacement processes were quantified. The results reported here demonstrate that the microfluidic system is a unique screening tool that can be potentially implemented in conjunction to the traditional core-flooding method to provide more efficient and reliable information to optimize the polymer flooding parameters and inform the operators.","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"57 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121221899","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}