Day 1 Wed, March 15, 2023最新文献

{"title":"Could the Post-SAGD Heat Recovery Supply the Direct Air CO2 Capture (DAC) Energy in a Net Negative Carbon Emission Environment?","authors":"Shima Bashti, Asghar Sadeghi, S. McCoy, N. Mahinpey","doi":"10.2118/212816-ms","DOIUrl":"https://doi.org/10.2118/212816-ms","url":null,"abstract":"\u0000 Direct Air CO2 Capture (DAC) is a promising negative emission technology. The main challenge associated with DAC is the high energy and material requirements, which results in a relatively high cost and may limit its environmental benefit. Steam-Assisted Gravity Drainage (SAGD), most established in situ recovery approach for Alberta oil sands reservoirs, leave a considerable amount of energy under the ground at the end of their life. The objective of this work is to investigate the energy and environmental viability of exploiting the abandoned thermal energy from oil sands reservoirs to generate DAC energy requirements. This work focuses on a unique concept of integrating DAC with SAGD after the cessation of bitumen recovery to recover energy from the reservoir and use this to supply energy for DAC. The retained energy in reservoirs can be extracted by water circulation. The recovered hot water is sent to surface energy extraction unit to generate power and heat energy. CO2 captured from the atmosphere is then transported by pipeline and sequestered in a suitable geologic reservoir. To conduct our analysis, we create an energy balance on the coupled system and calculate the life cycle carbon balance with the goal of creating a stand-alone, carbon-negative CO2 capture system.\u0000 We consider the electrical and thermal energy for CO2 capture in the range of 100-600 tCO2/day using a solid-based DAC process, in which the loaded sorbents are regenerated at a temperature of 90-105 °C. An isobutane Organic Rankine Cycle (ORC) is utilized to generate electricity from a geofluid circulated in post-SAGD heat recovery process with the temperature varying from 130 to 170 °C. The heat required by the DAC is extracted directly from the produced geothermal fluid. The analysis uncovers that Direct Air Capture and post-SAGD reservoir can be combined in a stand-alone power island to capture up to 284.5 tCO2/d at 130°C and 427 tCO2/d at 170 °C geofluid surface temperature assuming deploying the technique in 40 production wells.\u0000 Furthermore, our modelling results show that CO2 capture efficiency for abovementioned ranges of capture rate and geofluid temperature varies between 70-99%. For no external energy demand, CO2 capture efficiency touches 99% but as the external sources of energy is being involved, the efficiency declines to a minimum of 70%. This study presents a novel concept for using the waste heat in oil sands reservoirs to provide DAC energy.","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"46 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":"123735883","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 Multifaceted Laboratory Approach to Screen Paraffin Inhibitors for Canadian Unconventional Resources","authors":"K. Tsui, A. Habibi, Shu Jun Yuan","doi":"10.2118/212718-ms","DOIUrl":"https://doi.org/10.2118/212718-ms","url":null,"abstract":"\u0000 Paraffin deposition during oil and gas production is a common challenge and may partially or completely plug the wellbore, production tubing and flowlines. This results in significant reduction in well production and frequent paraffin remediation jobs. Chemical treatment is used widely and is one of the most practical ways to mitigate paraffin deposition. In previous studies, conventional test methods such as cold finger testing have been implemented to screen paraffin inhibitors for field applications. However, poor correlations between laboratory results and field observations challenge the reliability of the method. Developing a comprehensive laboratory protocol is imperative for screening effective paraffin inhibitors.\u0000 In this study, we introduce a systematic laboratory procedure to assess the performance of paraffin inhibitors on oil samples produced from formations located in the Western Canadian Sedimentary Basin (WCSB). These formations include Duvernay, Montney, and Cardium. The laboratory protocol is composed of three test procedures. First, we measure the viscosity of the oil samples mixed with paraffin inhibitors over a wide range of temperature values. Second, we perform cold finger tests using oil samples mixed with the various paraffin inhibitors. Lastly, we quantify the fouling tendency of oil samples with and without paraffin inhibitors using a para-window instrument by dynamically measuring near-infrared light transmittance on a temperature controlled reflective surface.\u0000 Several polymeric chemical families including ethylene vinyl acetate (PI-1), maleic ester (PI-2), maleic amide (PI-3), and alkylphenol (PI-4) are evaluated using this laboratory protocol. The measured performance of the paraffin inhibitors varies depending on the technique used and the temperature at which the evaluation is performed. In the case of experiments performed on the Montney oil sample, it is found that inhibitor containing maleic ester (PI-2) demonstrates 31% of reduction in viscosity testing, 75% of inhibition from cold finger testing, but only 8% of fouling reduction in the para-window testing. As this protocol is implemented over a wide range of temperature values, it provides valuable insights about the effectiveness and versatility of paraffin inhibitors at different operational conditions. In the case of PI-2, it shows higher inhibition at temperature near 0°C, rather than near the Wax Appearance Temperature (WAT) of 30°C, indicating that it might not be a suitable candidate for inhibiting the more problematic high molecular weight paraffins generated at 30°C.\u0000 The laboratory protocol developed in this study helps narrow the gap between laboratory results and field observations. It highlights the importance of matching representative field temperature conditions within the laboratory; and provides new insights about the performance of paraffin inhibitors for oil field applications.","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"47 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":"121319503","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":"Heavy Oil Late Life Energy Recovery—Maximizing the Value of Mature Thermal Assets","authors":"Ivan Beentjes, D. Bogatkov","doi":"10.2118/212820-ms","DOIUrl":"https://doi.org/10.2118/212820-ms","url":null,"abstract":"\u0000 The Heavy Oil Late Life Energy Recovery (HOLLER) project is the application of geothermal technology in steam assisted gravity drainage (SAGD) wells that are near end of life. While conventional geothermal technology is encumbered by the high cost of drilling deep wells to reach formations with the temperatures required for economic power generation, in situ bitumen producers have access to existing SAGD wells within mature reservoirs that are at shallow depths and high temperatures. The thermal energy from just one SAGD well can produce enough electricity to power thousands of homes for a year and major oilsands producers collectively have thousands of such wells.\u0000 Our goal is to harness this thermal energy using the existing well inventory to create a closed geothermal system using process effluent water (PEW) such as boiler blowdown or tailings pond water as the heat recovery medium. This strategy has the potential to improve SAGD economics through incremental bitumen recovery, the generation of low-carbon base load electricity, and driving down SAGD greenhouse gas (GHG) emissions by recovering some of the spent energy. This strategy also provides an option to dispose process water and/or tailings water to accelerate the reclamation of tailings ponds. Suncor’s In Situ Technology team applied a stage-gated technology development process to progress HOLLER from Technology Readiness Level (TRL) 0—Idea to TRL 7—Field test. We applied the diverge-converge approach to 30 ideas that were distilled into four recommended commercial solutions. Our de-risking activities include numerical reservoir simulation, chemical process simulation, post-SAGD core and water analysis, laboratory studies for compatibility of various PEW sources with reservoir fluids and rock, core flooding, corrosion studies, facility design, economics, risk and uncertainty analysis, patenting, and testing in the field.\u0000 As a result of the technology development work, we have developed a three-phase strategy to maximize the value of depleted in situ reservoirs: water disposal, energy recovery and permanent closure. This strategy offers synergies between mining and in situ operations, reduction in GHG emissions and environmental liabilities all while generating a net profit for the enterprise. If applied industry-wide, HOLLER technology has the potential of reducing not only the intensity, but also the absolute GHG emissions, while offering unique opportunities for collaboration between the in situ producers and mining operations.\u0000 HOLLER is unique in its potential to retroactively reduce the GHG intensity of bitumen already recovered by thermal methods. It offers low emissions incremental bitumen production, nearly emissions-free power generation, increased efficiency of existing facilities through the direct use of recovered heat – while reducing mine tailings liabilities. HOLLER enhances the oilsands industry’s sustainability efforts.","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"37 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":"134439679","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 Laboratory Protocol to Investigate EOR by Surfactants During Pre-Loading of Parent Wells to Mitigate Fracture Hit","authors":"Amin Alinejad, Lan Wang, H. Dehghanpour","doi":"10.2118/212743-ms","DOIUrl":"https://doi.org/10.2118/212743-ms","url":null,"abstract":"\u0000 Generally, pressure and fluid communications between parent and child wells which is referred to as frac hit deteriorate the production performance of the parent well. Small pre-loading technique is one of the cost-efficient and operationally simple strategies to mitigate frac hit. However, the production outcome of the parent well is unsatisfactory after flowback of pre-loading fluid in most of the pilots. To overcome this negative impact, we intend to evaluate the extent of additional oil recovery by imbibition of fluids with two types of non-ionic surfactant additives (SF-1 and SF-2) during pre-loading and flowback processes. We utilize a high-pressure and high-temperature visualization cell to conduct the pre-loading experiments using Montney rock and fluid samples. We restore the initial reservoir condition in the core plug and then simulate the primary production stage of the reservoir to establish a depleted core plug. Then, we conduct two sets of experiments on the depleted core plug: 1) soaking the plug with SF-1 surfactant solution under atmospheric conditions and 2) pre-loading the depleted core plug with the SF-1 surfactant solution at a pressure of 3,500 psig and reservoir temperature of 78°C. We also pre-load an oil-saturated core plug with SF-2 surfactant solution at similar operational conditions. Our results show that 31.4% of the original oil-in-place is produced during the primary production stage with solution-gas drive as the dominant oil-recovery mechanism. We observe an additional 3.9% (of original oil-in-place) oil recovery due to counter-current imbibition of the SF-1 surfactant solution after soaking under atmospheric conditions. The interfacial tension reduction and wettability alteration are two possible oil-recovery mechanisms during surfactant soaking. Pre-loading the depleted core plug with SF-1 surfactant solution at a set pressure of 3,370 psig and a temperature of 78°C does not result in additional oil recovery. However, pre-loading the oil-saturated core plug with SF-2 surfactant solution at the same operational conditions results in an approximately 29.6% oil recovery. We observe oil droplets formed on the rock surface during soaking of the oil-saturated plug with SF-2 surfactant solution. We conclude that longer soaking periods may assist in additional oil recovery in core plugs with depleted state compared to the non-depleted plugs.","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"26 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":"129113395","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":"Numerical Modeling of Field Pilot Data Designed to Evaluate CO2 Storage Potential in the Deep Mannville Coal Seams of Alberta","authors":"Yun Yang, H. Hamdi, C. Clarkson, M. Blinderman","doi":"10.2118/212792-ms","DOIUrl":"https://doi.org/10.2118/212792-ms","url":null,"abstract":"\u0000 Injection of CO2 into subsurface coal seams is a viable technology for reducing the carbon footprint. The primary storage mechanism in coal, gas adsorption, is distinctively different from other subsurface reservoirs, providing secure and long-term storage for carbon; however, CO2 adsorption can reduce coal permeability and injectivity due to matrix swelling. In this work, a reservoir simulation study was performed to assist with the design of a field pilot for injecting CO2 into the deep Mannville coals of Alberta. The proposed field pilot consists of a vertical well for injection of CO2, and a closely spaced offset vertical well for observation (pressure measurement and fluid sampling). Extensive numerical modeling was carried out before the pilot implementation to aid with pilot design, assess injectivity, and optimize pilot operations.\u0000 Because of the scarcity of reservoir information in the study area, most reservoir attributes were obtained by history-matching the Fenn Big Valley (FBV) micro-pilot (single vertical well) injection data, the closest analog field case performed in the Mannville coal. Accordingly, the reservoir simulation study was conducted in two phases: (1) testing of the numerical model setup using the FBV micro-pilot data and (2) construction of a new pilot area-specific simulation model, corresponding to the new pilot area. During the testing phase, the FBV injection well bottomhole pressure and produced gas compositions were adequately matched. During the new pilot area-specific simulation phase, a full field model (multilayer, two-well) covering a drainage area of 40000 m2 was constructed to represent the target coal seams and the bounding zones. Because the studied coal reservoir is considered to be geomechanically anisotropic with complex cleat systems, the anisotropic Palmer-Higgs model was integrated into the flow simulation to accurately simulate the stress-dependent permeability changes during CO2 injection.\u0000 Utilizing geologic information and analog field studies, the new pilot area-specific simulation suggests that the target amount of 1500 tonnes CO2 can be securely stored in the Mannville coal seam at the planned pilot site. To optimize the injection scheme operations, and maximize injectivity, two hypothetical injection scenarios were considered: a constant-rate injection scheme at 5 tonnes per hour and a variable- rate injection scenario at a rate of up to 15 tonnes per hour. Both pre-field simulation scenarios suggest that 1500 tonnes of CO2 can be securely injected into the target coal seam (at 1500 m, with an initial permeability of 1.5 md). However, the time to inject the target amount of CO2 in the variable-rate scenario is significantly less than for the constant-rate scenario. Therefore, a variable injection rate schedule with a progressive increase of 5, 10, and 15 tonnes per hour was suggested for the actual field trial. Additionally, the effect of coal anisotropy on CO2 migration was accounted fo","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"17 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":"123361802","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":"Unsupervised PSD Clustering to Assess Reservoir Quality Along the Horizontal Wells: An Efficient Inflow Control Devices Design","authors":"H. Izadi, Morteza Roostaei, Mahdi Mahmoudi, G. Rosi, J. Stevenson, Aubrey Tuttle, Colby Sutton, R. Mirzavand, J. Leung, Vahidoddin Fattahpour","doi":"10.2118/212812-ms","DOIUrl":"https://doi.org/10.2118/212812-ms","url":null,"abstract":"\u0000 In steam-assisted gravity drainage (SAGD) operations, inflow control devices (ICDs) might provide an extra pressure drop (ΔP) on top of the liquid pool's ΔP. To avoid hot-spot zones, this ΔP design heavily relies on reservoir quality. Flow-loop experiments can provide flow قate measurements versus ΔP for various nozzle designs. Therefore, an efficient ICD design should be investigated in a numerical flow simulation that represents reservoir quality and heterogeneity by employing flow-loop data.\u0000 In this study, core analysis and 40 PSD data drilled in the same location are collected, and permeability for each PSD is estimated using a correlation developed in our previous study. Given PSD offers a measure of hydraulic properties and heterogeneity, it can provide an indirect indicator of potential hot-spot zones. Moreover, representative PSDs are determined by using a clustering algorithm to tie the best-designed ICD to the relevant geology. The reservoir model for the database's location is generated using real data, three tabular data from flow-loop experiments are assigned to the reservoir simulation, and the ICDs' performances are compared.\u0000 The clustering algorithm generated five groups with a weighted average permeability of 4,013 mD. The first and second largest clusters with 6.55% and 35.05% fines content cover 55% and 23% of the database, respectively. By employing a relatively conservative production with subcooling between 10°C and 15°C, the cases with liner deployed (LD) ICDs offered a greater oil production rate, better steam conformance, and lower cumulative steam oil ratio (cSOR) than the cases without ICDs. However, in a rather risky production scenario with subcool between 1°C and 5°C, the case without ICDs could not be simulated in the desired the subcool temperature. Because of its enhanced steam conformance and slightly higher oil production rate, LDICD#1 was picked as the best case for the two scenarios. Compared to the case without ICDs, the oil production rate and cSOR for the case with LDICD#1 at higher subcool temperature rose by 17% and reduced by 8%, respectively. Compared to the case without ICDs, the oil production rate and cSOR for the case at lower subcool temperature with LDICD#1 raised by 21% and reduced by 12%, respectively.\u0000 The findings demonstrate the effectiveness of ICDs at various subcool levels. The results could be applied in SAGD projects to reduce greenhouse gas emissions by reducing the water and natural gas usage to generate steam. Completion and production engineers would benefit from a better understanding of production relative performance to develop more effective operations design.","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"26 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":"123155722","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":"Hydrocarbon gas Foam Injection in Fractured Oil-Wet Carbonate Samples: An Experimental Investigation of the Effect of Fracture-Matrix Permeability Contrast on Oil Recovery","authors":"M. I. Youssif, K. Sharma, M. Piri","doi":"10.2118/212736-ms","DOIUrl":"https://doi.org/10.2118/212736-ms","url":null,"abstract":"\u0000 Foam-based EOR techniques have surfaced as a promising approach for unconventional reservoirs with high heterogeneity, adverse wettability, and natural fractures. Constraints such as permeability contrast (PCF/M) between fractures and the matrix can delimit the effectiveness of gas injection-based EOR methods, resulting in an early gas breakthrough and poor sweep efficiency. Furthermore, the foam generation capacity of surfactants can be significantly affected by the permeability of fractures. Therefore, careful evaluation of the effects of variations in fracture permeability on foam performance in fractured oil-wet porous systems is warranted under reservoir conditions.\u0000 In this study, several fractured oil-wet Minnesota Northern Cream (MNC) core samples possessing comparable matrix permeabilities were employed. The fractures were packed with oil-wet proppants of different mesh sizes to create varying fracture permeabilities. A set of foam flooding experiments were conducted on these propped oil-wet fractured cores at reservoir conditions (3,500 psi and 115 °C). An amphoteric surfactant was used as the foaming agent. The foam was generated in situ via simultaneous injection of the surfactant's aqueous solution and gaseous methane into the fracture. The pressure gradients across the core samples were recorded during the flow process, and foam performance was quantified in terms of the foam's apparent viscosity and oil recovery from the oil-bearing matrix.\u0000 The results established the feasibility of the foam-based EOR approach in propped fractured oil-wet carbonate samples as an efficient alternative for gas injection. The foam significantly reduced the gas mobility in the fracture and diverted the gas to the tight matrix, resulting in notable mobilization of the matrix oil toward the fracture area. This behavior can be attributed to numerous factors associated with this study. For example, the amphoteric surfactant generated stable foam at the chosen operating parameters, resulting in enhanced fracture-matrix interactions and thereby recovering a significant portion of the oil hosted in the tight matrix. On the other hand, the permeability of the fracture played an essential role in governing the foam behavior in oil-wet porous media. It was observed that, in the lower range, the apparent viscosity of foam increases with permeability up to a specific permeability value, whereas at higher permeabilities, a drastic decrease in the foam strength was noticed. The optimum fracture permeability was identified, which facilitated the generation of small and stable bubbles, considerably reducing the gas mobility and resulting in increased oil recovery. The results also revealed that limiting capillary pressure conditions in tighter fractures adversely impacts the generation of stable foams.\u0000 This study presents new insights into the impact of fracture-matrix permeability contrast (PCF/M) on foam performance in fractured oil-wet carbonate systems at elev","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"42 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":"128795361","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":"Experimental and Numerical Study of Asphaltene Deposition and Precipitation in the Vapor Extraction Process","authors":"S. Esmaeili, Seyed Emad Siadatifar, M. Mesbah, B. Maini, A. Kantzas","doi":"10.2118/212769-ms","DOIUrl":"https://doi.org/10.2118/212769-ms","url":null,"abstract":"\u0000 Vapor Extraction (VAPEX) is one of the most promising solvent-based methods to tackle the issues associated with SAGD. Asphaltene precipitation due to solvent injection and its in-situ upgrading plays an essential role in VAPEX. As the VAPEX chamber expands laterally and vertically, the speed of the front movement and the angle of the chamber boundary varies. This research investigates the rate of asphaltene precipitation and deposition in VAPEX using different solvents.\u0000 In this research, three VAPEX experiments are carried out in a physical model using bitumen and three solvents (propane, butane, and pentane), where VAPEX chamber movement, expansion rate, and the amount of precipitated asphaltenes are monitored. In addition, an Eulerian-Lagrangian model, including the Eulerian approach for the continuous phase (solvent-rich area of the chamber) and the Lagrangian approach for the extracted asphaltene solid particles by bitumen dilution, is generated for numerical modelling. The movement and the deposition of the asphaltene particles at the front are calculated and then validated with the physical model experiments.\u0000 A significant amount of precipitated asphaltenes was observed when pentane was used, as it creates a pattern on the wall of the physical model, especially near the wellbore area. However, no specific pattern was observed for other experiments. In terms of chamber expansion and movement, the chamber expanded laterally and then vertically in the pentane and propane systems, while the butane system revealed vertical movement at the beginning, followed by lateral movement. In all cases, the amount of precipitated asphaltenes was always higher near the wellbore compared with areas far from the production well. A numerical model has been implemented to capture the transport phenomena, simulate the asphaltene deposition mechanisms, and reveal the variations in the behavior of different solvents.\u0000 This study can assist the oil sands industry in optimizing the VAPEX process to have an effective in-situ upgrading and the highest production rate with better oil API gravity, as the literature suffers from a lack of understanding of the mass transfer physics involved in VAPEX. Also, this study sheds light on the physics behind the asphaltene deposition and precipitation process in VAPEX, as it is impossible to be understood without molecular dynamic simulation besides laboratory experiments.","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"16 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":"121518001","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 Flow Units and Capillary Pressures of the Giant Chicontepec Tight Oil Paleochannel in Mexico and a Fresh Look at Drilling and Completions","authors":"Alejandra Gutierrez Oseguera, R. Aguilera","doi":"10.2118/212745-ms","DOIUrl":"https://doi.org/10.2118/212745-ms","url":null,"abstract":"\u0000 The Chicontepec Paleochannel is a giant shaly sandstone reservoir(s) with volumes of OOIP ranging between 137 and 59 billion STB (Guzman, 2019), which has been equated recently to the Permian Basin. However, the oil recoveries are very small, ranging between 0.32 to 0.75% of the OOIP. Thus, the objective of this study is to evaluate flow units and capillary pressures of Chicontepec, as well as drilling and completion methods, with a view to improve the characterization of the reservoir(s) and, thus, oil recoveries.\u0000 Current cumulative oil production of Chicontepec is 440.38 million STB. Although it is a significant volume, it represents a very small percent recovery from the reservoir (0.32 to 0.75% of the OOIP). To help improving recovery, a method is developed for characterizing the tight Chicontepec paleochannel using flow units and capillary pressures. Like in the case of many tight unconventional reservoirs, the capillary pressures can go to very high values, reaching 55,000 psi in the Chicontepec case. Therefore, a special procedure is developed to generate a consistent interpretation of all the available capillary pressure curves for the entire range of pressures.\u0000 Results highlight the important oil recovery potential of the Chicontepec Paleochannel (Misantla-Tampico Basin), which has been equated recently to the Permian Basin in the United States and has been termed by Guzman (2022) \"a premier super-basin in waiting.\" The assessment is supported by quantitative formation evaluation work performed by Gutierrez Oseguera and Aguilera (2022). Although natural fractures are present, most wells must be hydraulically fractured to achieve commercial success.\u0000 Process or delivery speed (the ratio of permeability and porosity) for the Chicontepec samples used in the capillary pressure experimental work range between 159.1 md and 0.17 md (porosity in the denominator is a fraction). Flow units show pore throat apertures (rp35) ranging from less than 0.1 microns to about 4.5 microns. These values and flow units compare well with data available for prolific unconventional reservoirs such as the Cardium sandstone in Canada and the giant Permian Basin in the United States. The radius rp35 refers to pore throat aperture at 35% cumulative pore volume.\u0000 The novelty of this study is the development of a consistent procedure for interpreting the entire range of pressures measured during mercury injection capillary pressures. Such pressures go up to 55,000 psi for the core samples considered in this study. The integration with flow units and formation evaluation suggests that the potential of the Chicontepec unconventional reservoirs can rival successful results obtained in the Cardium sandstone and the Permian Basin. Some ideas are advanced regarding drilling and completion for Chicontepec based on the results of the present study and production success in the Permian Basin.","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"223 1 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":"127295417","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":"Learnings from the Planning and Execution of a Heavy Oil Polymer Flood Pilot in North Saskatchewan, Canada","authors":"D. Raffa, A. Abedini","doi":"10.2118/212760-ms","DOIUrl":"https://doi.org/10.2118/212760-ms","url":null,"abstract":"\u0000 The oil recovery in Section 14-50-25W3 (province of Saskatchewan, Canada) has evolved through multiple stages as technology has changed over time. Oil was initially produced through vertical wells beginning in the early 1970s. In the 2010s horizontal drilling was established and the Lloydminster sandstone formation was produced on primary with horizontal wells. In 2014 the secondary waterflooding was implemented. At the beginning of 2018 a tertiary polymer flood was implemented and is still running (year 2022). Along the past several years three different injection fluid viscosities were injected.\u0000 The discussion centers on the water and polymer flood displacement process performance and its implications for wells operation and economics.\u0000 Performance to date is discussed in detail and learnings and future steps are presented in the conclusions.","PeriodicalId":437231,"journal":{"name":"Day 1 Wed, March 15, 2023","volume":"1 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":"131344944","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}