C. M. Smith, Seth Nolan, R. Edwards, C. Conrad, P. Gordon, T. Smith, Michael P Smith
Hilcorp's Milne Point S-203 was drilled in 2019 targeting the biodegraded heavy oil of the Ugnu Formation, for exploration and development; being one of the first Ugnu wells to be successfully drilled, completed, and conventionally produced. S-203 crossed three fault blocks and intersected multiple Ugnu subunits. A volatiles analysis, via rock volatiles stratigraphy (RVS), of the cuttings from the main borehole and sidetracks enabled a spatial assessment of oil quantity, microbial activity, and the effect of faults in the different subunits. Produced oil from early in the life cycle of the well was analyzed with RVS, both RVS datasets were combined with completions to assess production contribution across the borehole. These results provide important insights for development of the Ugnu as a heavy oil play on the Alaskan North Slope.
Hilcorp的Milne Point S-203于2019年钻探，目标是Ugnu组的生物降解重油，用于勘探和开发;该井是Ugnu第一口成功钻井、完井和常规生产的井之一。S-203穿过三个断块，与多个乌格努亚单元相交。通过岩石挥发物地层学(RVS)对主井和侧钻的岩屑进行挥发物分析，可以对不同亚单元的含油量、微生物活动和断层影响进行空间评估。利用RVS对井生命周期早期的采出油进行分析，并将两种RVS数据集与完井作业相结合，以评估整个井眼的产量贡献。这些结果为阿拉斯加北坡Ugnu稠油区的开发提供了重要的见解。
{"title":"Evaluating Oil Quality and Microbial Activity Across Fault Blocks and Subunits of the Ugnu (N. Slope, Alaska) by Volatiles Analysis of Cuttings and Produced Crude - Implications for Completions and Production","authors":"C. M. Smith, Seth Nolan, R. Edwards, C. Conrad, P. Gordon, T. Smith, Michael P Smith","doi":"10.2118/214494-ms","DOIUrl":"https://doi.org/10.2118/214494-ms","url":null,"abstract":"\u0000 Hilcorp's Milne Point S-203 was drilled in 2019 targeting the biodegraded heavy oil of the Ugnu Formation, for exploration and development; being one of the first Ugnu wells to be successfully drilled, completed, and conventionally produced. S-203 crossed three fault blocks and intersected multiple Ugnu subunits. A volatiles analysis, via rock volatiles stratigraphy (RVS), of the cuttings from the main borehole and sidetracks enabled a spatial assessment of oil quantity, microbial activity, and the effect of faults in the different subunits. Produced oil from early in the life cycle of the well was analyzed with RVS, both RVS datasets were combined with completions to assess production contribution across the borehole. These results provide important insights for development of the Ugnu as a heavy oil play on the Alaskan North Slope.","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"31 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-05-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125125265","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}
Xianmin Zhou, Wei Yu, M. Elsayed, Ridha Al-Abdrabalnabi, Yushu Wu, S. Khan, M. Kamal
The release of CO2 into the atmosphere has been verified as a significant reason for global warming and climate change. To prevent a large amount of CO2 from being emitted into the atmosphere, its utilization and storage become very important for human survival. Regarding the utilization of CO2 in oil reservoir engineering practice, CO2 enhanced oil recovery (CO2EOR) as a mature technology has been widely applied in several types of reservoirs, such as sandstone, carbonate, and shale gas/oil reservoirs, and scientists and reservoir engineers aim to improve displacement efficiency with different injection modes and study its influencing factors over the past few decades. However, related to the experimental evaluation of storage capacity potential with the CO2EOR displacement mode and the long-term storage of CO2 in situ in the formation experienced by CO2 flooding is rarely studied experimentally. In this study, we investigated the effect of injection mode and reservoir heterogeneity on CO2EOR and its storage potential. Several core flooding experiments on displacing remaining oil and water by scCO2 after water flooding have been performed, including injection modes, which are horizontal, vertical, and tapered WAG injections, using reservoir carbonate rock, live crude oil, and seawater under reservoir conditions. The dual-core core flooding experiment was used to study the effect of reservoir heterogeneity on scCO2 storage capacity. As a result of this study, the previously proposed experimental methodology was used to calculate the scCO2 storage capacity, which involved that the scCO2 dissolves into residual water and oil after scCO2 injection, and evaluate the CO2 storage capacity efficiency for different injection modes. The vertical-continuous injection mode of scCO2 flooding can maximize the process of its storage advantage. This study found that the main scCO2 storage mechanism is mainly pore storage (structural trapping) for depleted oil reservoirs. Based on experimental results, the storage efficiency is related permeability of rocks, which expresses the logarithmic relation and increases with an increase in air permeability. The experimental results show that the scCO2 injectivity is not strongly affected, although the relative permeability to scCO2 decreased somewhat after the scCO2EOR process. In addition, the effect of rock heterogeneity on scCO2 storage efficiency is also discussed. The highlights of this study are that the comparison of the scCO2 storage potential was made based on experimental results of different injection modes, and improving the displacement efficiency in the low permeable zone also increases scCO2 storage efficiency. Furthermore, the experimental results can be applied directly to be helpful for the evaluation and strategy of scCO2 storage and can be used to simulate the performance during the injection process of scCO2 storage.
{"title":"Experimental Study on Supercritical CO2 Enhanced Oil Recovery and its Sequestration Potential with Different injection Modes for Carbonate Oil Reservoirs Under Reservoir Conditions","authors":"Xianmin Zhou, Wei Yu, M. Elsayed, Ridha Al-Abdrabalnabi, Yushu Wu, S. Khan, M. Kamal","doi":"10.2118/212992-ms","DOIUrl":"https://doi.org/10.2118/212992-ms","url":null,"abstract":"\u0000 The release of CO2 into the atmosphere has been verified as a significant reason for global warming and climate change. To prevent a large amount of CO2 from being emitted into the atmosphere, its utilization and storage become very important for human survival. Regarding the utilization of CO2 in oil reservoir engineering practice, CO2 enhanced oil recovery (CO2EOR) as a mature technology has been widely applied in several types of reservoirs, such as sandstone, carbonate, and shale gas/oil reservoirs, and scientists and reservoir engineers aim to improve displacement efficiency with different injection modes and study its influencing factors over the past few decades. However, related to the experimental evaluation of storage capacity potential with the CO2EOR displacement mode and the long-term storage of CO2 in situ in the formation experienced by CO2 flooding is rarely studied experimentally. In this study, we investigated the effect of injection mode and reservoir heterogeneity on CO2EOR and its storage potential.\u0000 Several core flooding experiments on displacing remaining oil and water by scCO2 after water flooding have been performed, including injection modes, which are horizontal, vertical, and tapered WAG injections, using reservoir carbonate rock, live crude oil, and seawater under reservoir conditions. The dual-core core flooding experiment was used to study the effect of reservoir heterogeneity on scCO2 storage capacity.\u0000 As a result of this study, the previously proposed experimental methodology was used to calculate the scCO2 storage capacity, which involved that the scCO2 dissolves into residual water and oil after scCO2 injection, and evaluate the CO2 storage capacity efficiency for different injection modes. The vertical-continuous injection mode of scCO2 flooding can maximize the process of its storage advantage. This study found that the main scCO2 storage mechanism is mainly pore storage (structural trapping) for depleted oil reservoirs. Based on experimental results, the storage efficiency is related permeability of rocks, which expresses the logarithmic relation and increases with an increase in air permeability. The experimental results show that the scCO2 injectivity is not strongly affected, although the relative permeability to scCO2 decreased somewhat after the scCO2EOR process. In addition, the effect of rock heterogeneity on scCO2 storage efficiency is also discussed.\u0000 The highlights of this study are that the comparison of the scCO2 storage potential was made based on experimental results of different injection modes, and improving the displacement efficiency in the low permeable zone also increases scCO2 storage efficiency. Furthermore, the experimental results can be applied directly to be helpful for the evaluation and strategy of scCO2 storage and can be used to simulate the performance during the injection process of scCO2 storage.","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"238 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-05-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116456252","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}
Accurate modeling of CO2/CH4 competitive adsorption behavior is a critical aspect of enhanced gas recovery associated with CO2 sequestration in organic-rich shales (CO2-ESGR). It not only improves the ultimate recovery of shale gas reservoirs that satisfies the increasing energy demand but also provides permanent geologic storage of atmospheric CO2 that contributes to the net-zero energy future. Determining a CO2/CH4 adsorption ratio is essential for the performance prediction of shale gas reservoirs and the evaluation of CO2 storage potential. However, experimental adsorption measurements are expensive and time-consuming that may not always be available for shale reservoirs of interest or at the investigated geologic conditions, and as a result, a sorption ratio cannot be assessed appropriately. Traditional models such as a Langmuir model are highly dependent on extensive experiments and cannot be widely applied. Therefore, a unified adsorption model must be developed to predict the CO2/CH4 competitive adsorption ratios, which is essential for CO2 sequestration and exploitation of natural gas from shale reservoirs. In recent years, the development of machine learning algorithms has significantly improved the accuracy and computational speed of prediction. In this work, we conducted a comparative machine learning algorithm study to effectively forecast the maximum CO2 adsorption capacity and CO2/CH4 competitive adsorption ratios. Four sensitive input parameters (i.e., temperature, total organic carbon, moisture content, and maximum adsorption capacity of CH4) were selected, along with their 50 data points collected from the existing literature. The artificial neural network (ANN), XGBoost, and Random Forest (RF) algorithms were investigated. By comparing the mean absolute errors (MAE) and coefficients of determination (R2), it was found that the ANN models can successfully forecast the required outputs within a 10% accuracy level. Furthermore, the descriptive statistics demonstrated that the CO2/CH4 competitive adsorption ratios were generally from 1.7 to 5.6. The proposed machine learning algorithm framework will provide insights beyond the isothermal conditions of classical adsorption models and the solid support to CO2-ESGR processes into which competitive adsorption can be a driven mechanism.
{"title":"Comparative Machine Learning Frameworks for Forecasting CO2/CH4 Competitive Adsorption Ratios in Shale","authors":"Haoming Ma, Yun Yang, Zhenqian Xue, Zhangxin Chen","doi":"10.2118/212994-ms","DOIUrl":"https://doi.org/10.2118/212994-ms","url":null,"abstract":"\u0000 Accurate modeling of CO2/CH4 competitive adsorption behavior is a critical aspect of enhanced gas recovery associated with CO2 sequestration in organic-rich shales (CO2-ESGR). It not only improves the ultimate recovery of shale gas reservoirs that satisfies the increasing energy demand but also provides permanent geologic storage of atmospheric CO2 that contributes to the net-zero energy future. Determining a CO2/CH4 adsorption ratio is essential for the performance prediction of shale gas reservoirs and the evaluation of CO2 storage potential. However, experimental adsorption measurements are expensive and time-consuming that may not always be available for shale reservoirs of interest or at the investigated geologic conditions, and as a result, a sorption ratio cannot be assessed appropriately. Traditional models such as a Langmuir model are highly dependent on extensive experiments and cannot be widely applied. Therefore, a unified adsorption model must be developed to predict the CO2/CH4 competitive adsorption ratios, which is essential for CO2 sequestration and exploitation of natural gas from shale reservoirs.\u0000 In recent years, the development of machine learning algorithms has significantly improved the accuracy and computational speed of prediction. In this work, we conducted a comparative machine learning algorithm study to effectively forecast the maximum CO2 adsorption capacity and CO2/CH4 competitive adsorption ratios. Four sensitive input parameters (i.e., temperature, total organic carbon, moisture content, and maximum adsorption capacity of CH4) were selected, along with their 50 data points collected from the existing literature.\u0000 The artificial neural network (ANN), XGBoost, and Random Forest (RF) algorithms were investigated. By comparing the mean absolute errors (MAE) and coefficients of determination (R2), it was found that the ANN models can successfully forecast the required outputs within a 10% accuracy level. Furthermore, the descriptive statistics demonstrated that the CO2/CH4 competitive adsorption ratios were generally from 1.7 to 5.6. The proposed machine learning algorithm framework will provide insights beyond the isothermal conditions of classical adsorption models and the solid support to CO2-ESGR processes into which competitive adsorption can be a driven mechanism.","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-05-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122563931","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}
Riten Prafulbhai Gajipara, A. Hill, D. Zhu, Najim AlNajjar, N. Chkolny, M. Weissenberger
Alternative acid systems for carbonate acidizing have been developed to overcome some weaknesses of conventionally used hydrochloric acid. Such systems are of particular interest for the reservoirs with high temperature because of high reactivity and corrosiveness of HCl at temperatures above 200°F. The main advantages of the evaluated alternative acid include better wormhole efficiency at lower injection rates and less corrosiveness to protect tubulars and surface equipment. In a high-temperature environment, the performance of alternative acids needs to be evaluated for the feasibility of being an effective stimulation fluid. Even though there are plenty of core flood data in the literature for carbonate rocks, there are fewer studies/publications that provide acid performance at high temperatures. In this paper, we present an experimental study of an alternative acid over a wide range of temperatures up to 300°F. The goal is to confirm the applicability and identify the optimal conditions for field operations. We conducted core flood tests using the alternative acid to generate wormhole efficiency curves with different interstitial velocities. The optimal condition was determined from the experimental results for each temperature tested. The temperature for testing ranged from 125°F to 300°F. The tested acid system created a preferred wormhole structure with a dominant wormhole for all test conditions. This indicates that the alternative acid system can be used as a matrix acidizing fluid for carbonate reservoirs over a broad range of temperatures up to 300°F. As observed by HCl core flood tests, wormhole efficiency for the alternative acid also decreases with increasing temperature when compared with its performance at low temperature, but it showed reasonable results of wormholing, while HCl experiments was not practical at 300°F. The challenge of stimulating high-temperature formations can be addressed when the acid system and injection condition are designed correctly. The data presented in this paper add new information for high-temperature acid core flood testing, and provide useful information for matrix acidizing design using alternative acid systems.
{"title":"Systematic Evaluation of Alternative Acid System for High-Temperature Carbonate Formation","authors":"Riten Prafulbhai Gajipara, A. Hill, D. Zhu, Najim AlNajjar, N. Chkolny, M. Weissenberger","doi":"10.2118/213006-ms","DOIUrl":"https://doi.org/10.2118/213006-ms","url":null,"abstract":"\u0000 Alternative acid systems for carbonate acidizing have been developed to overcome some weaknesses of conventionally used hydrochloric acid. Such systems are of particular interest for the reservoirs with high temperature because of high reactivity and corrosiveness of HCl at temperatures above 200°F. The main advantages of the evaluated alternative acid include better wormhole efficiency at lower injection rates and less corrosiveness to protect tubulars and surface equipment. In a high-temperature environment, the performance of alternative acids needs to be evaluated for the feasibility of being an effective stimulation fluid. Even though there are plenty of core flood data in the literature for carbonate rocks, there are fewer studies/publications that provide acid performance at high temperatures. In this paper, we present an experimental study of an alternative acid over a wide range of temperatures up to 300°F. The goal is to confirm the applicability and identify the optimal conditions for field operations. We conducted core flood tests using the alternative acid to generate wormhole efficiency curves with different interstitial velocities. The optimal condition was determined from the experimental results for each temperature tested. The temperature for testing ranged from 125°F to 300°F. The tested acid system created a preferred wormhole structure with a dominant wormhole for all test conditions. This indicates that the alternative acid system can be used as a matrix acidizing fluid for carbonate reservoirs over a broad range of temperatures up to 300°F. As observed by HCl core flood tests, wormhole efficiency for the alternative acid also decreases with increasing temperature when compared with its performance at low temperature, but it showed reasonable results of wormholing, while HCl experiments was not practical at 300°F. The challenge of stimulating high-temperature formations can be addressed when the acid system and injection condition are designed correctly. The data presented in this paper add new information for high-temperature acid core flood testing, and provide useful information for matrix acidizing design using alternative acid systems.","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"188 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-05-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"117307220","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}
The authors have been working with the challenges related to decommissioning facilities offshore California since 1996. In a 2018 OTC paper (OTC-28844-MS) they reviewed the challenges for offshore facility decommissioning in this region. This paper reviews and updates the oil and gas platform decommissioning projects being conducted on the federal Outer Continental Shelf (OCS) offshore California and the decommissioning outlook for OCS platforms through the end of this decade. There are a total of 23 oil and gas platforms on the federal OCS offshore California which are submerged lands located more than three nautical miles from the coastline. The authors project that one-third of the 23 OCS platforms and one state water platform are likely to be decommissioned by the end of the decade, and at least 50 percent of the OCS platforms are likely to be removed by the middle of the next decade. Three of the eight OCS platforms being decommissioned, if fully removed, would each establish world water depth records for removing conventional steel platform jackets from the seafloor. The paper also describes the major technical, logistical, environmental, and regulatory challenges operators face in planning and conducting decommissioning projects offshore California.
{"title":"California Outer Continental Shelf Platform Decommissioning Update, Outlook, and Challenges","authors":"J. B. Smith, R. Byrd","doi":"10.2118/213003-ms","DOIUrl":"https://doi.org/10.2118/213003-ms","url":null,"abstract":"\u0000 The authors have been working with the challenges related to decommissioning facilities offshore California since 1996. In a 2018 OTC paper (OTC-28844-MS) they reviewed the challenges for offshore facility decommissioning in this region. This paper reviews and updates the oil and gas platform decommissioning projects being conducted on the federal Outer Continental Shelf (OCS) offshore California and the decommissioning outlook for OCS platforms through the end of this decade. There are a total of 23 oil and gas platforms on the federal OCS offshore California which are submerged lands located more than three nautical miles from the coastline. The authors project that one-third of the 23 OCS platforms and one state water platform are likely to be decommissioned by the end of the decade, and at least 50 percent of the OCS platforms are likely to be removed by the middle of the next decade. Three of the eight OCS platforms being decommissioned, if fully removed, would each establish world water depth records for removing conventional steel platform jackets from the seafloor. The paper also describes the major technical, logistical, environmental, and regulatory challenges operators face in planning and conducting decommissioning projects offshore California.","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"67 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-05-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124135268","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}
Xingru Wu, Lei Dai, Q. Chang, Sadam Qiuhao, B. Shiau
Laboratory experiments have demonstrated that injecting urea solution as a CO2-generating agent into an oil reservoir may significantly enhance oil recovery. When the reservoir temperature is above 50°C, urea is hydrolyzed to carbon dioxide and ammonia. This technology overcomes many supercritical CO2 problems and can be very attractive for thousands of stripper wells that produce oil on marginal economic feasibility. However, previous efforts mainly focus on laboratory tests and mechanisms study. The actual field performance of this technology is likely dependent on reservoir heterogeneity, and its economic viability is expected to be closely related to its optimization. This highly relies on numerical modeling and simulation capability. The synergic mechanisms in in-situ CO2 EOR (ICE) using urea are complex. Firstly, the decomposition of urea injected leads to CO2 and ammonia under proper reservoir conditions. The generated CO2 in brine partitions preferably into the oil phase and decreases oil viscosity while swelling the oil effectively. The co-generated product, ammonia, can potentially reduce the interfacial tension (IFT) between the oil/water phase, which moves the relative permeability (or saturation) curves and position to offer additional oil production. In the first attempt, the dominant parameters, including urea reaction kinetics, the stoichiometry of the decomposition process, the oil swelling effect, and the impact of IFT reduction on the relative permeabilities, were considered and incorporated into the numerical modeling effort. We used the chosen numerical simulations to determine the contribution of the individual mechanism by history matching the results of laboratory tests collected previously. The one-D mechanistic numerical model was then upscaled to a synthetic homogeneous 3D model by simulating a quarter of the 5-spot sector model to evaluate the feasibility and engineering design of ICE for future field scale pilot tests and potential prize of ICE EOR. After comparing the base case with urea injection, a sensitivity analysis was performed. As part of the aims, the simulation results differentiate and reveal the incremental contributions of the synergetic behaviors among several mechanisms: oil viscosity reduction, oil swelling, and IFT reduction. Data also showed that the IFT reduction plays a rather minor role in this effort, and its contribution is basically indistinguishable. The predominant recovery mechanisms are mainly controlled by oil swelling and viscosity reduction; temperature plays a key role in influencing the extent of reaction kinetics of urea. In the 1D simulation, the temperature significantly impacted the production performance as the core cooled down quickly. In a 3D or field-scale scenario, the waterflooding does not change the in-depth reservoir temperature as the temperature gradient moves at a much slower rate (about two times slower) than the injected urea solution slug. However, the duration
{"title":"Study of Controlling Parameters of In-Situ CO2 EOR Using Numerical Simulations","authors":"Xingru Wu, Lei Dai, Q. Chang, Sadam Qiuhao, B. Shiau","doi":"10.2118/213010-ms","DOIUrl":"https://doi.org/10.2118/213010-ms","url":null,"abstract":"\u0000 Laboratory experiments have demonstrated that injecting urea solution as a CO2-generating agent into an oil reservoir may significantly enhance oil recovery. When the reservoir temperature is above 50°C, urea is hydrolyzed to carbon dioxide and ammonia. This technology overcomes many supercritical CO2 problems and can be very attractive for thousands of stripper wells that produce oil on marginal economic feasibility. However, previous efforts mainly focus on laboratory tests and mechanisms study. The actual field performance of this technology is likely dependent on reservoir heterogeneity, and its economic viability is expected to be closely related to its optimization. This highly relies on numerical modeling and simulation capability.\u0000 The synergic mechanisms in in-situ CO2 EOR (ICE) using urea are complex. Firstly, the decomposition of urea injected leads to CO2 and ammonia under proper reservoir conditions. The generated CO2 in brine partitions preferably into the oil phase and decreases oil viscosity while swelling the oil effectively. The co-generated product, ammonia, can potentially reduce the interfacial tension (IFT) between the oil/water phase, which moves the relative permeability (or saturation) curves and position to offer additional oil production. In the first attempt, the dominant parameters, including urea reaction kinetics, the stoichiometry of the decomposition process, the oil swelling effect, and the impact of IFT reduction on the relative permeabilities, were considered and incorporated into the numerical modeling effort. We used the chosen numerical simulations to determine the contribution of the individual mechanism by history matching the results of laboratory tests collected previously. The one-D mechanistic numerical model was then upscaled to a synthetic homogeneous 3D model by simulating a quarter of the 5-spot sector model to evaluate the feasibility and engineering design of ICE for future field scale pilot tests and potential prize of ICE EOR. After comparing the base case with urea injection, a sensitivity analysis was performed.\u0000 As part of the aims, the simulation results differentiate and reveal the incremental contributions of the synergetic behaviors among several mechanisms: oil viscosity reduction, oil swelling, and IFT reduction. Data also showed that the IFT reduction plays a rather minor role in this effort, and its contribution is basically indistinguishable. The predominant recovery mechanisms are mainly controlled by oil swelling and viscosity reduction; temperature plays a key role in influencing the extent of reaction kinetics of urea. In the 1D simulation, the temperature significantly impacted the production performance as the core cooled down quickly. In a 3D or field-scale scenario, the waterflooding does not change the in-depth reservoir temperature as the temperature gradient moves at a much slower rate (about two times slower) than the injected urea solution slug. However, the duration ","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-05-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130256740","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}
Produced water is commonly co-produced with oil and gas production and requires safe disposal in subsurface reservoirs. Knowing the amount of produced water that can be safely injected into the reservoir is important for disposal operations. While the methods of reservoir hydrocarbon storage are abundant in literature, the granularity of handling water injection capacity is rare, probably due to the misconception that production is similar to injection into a formation. The knowledge of hydrocarbon reservoir petrophysics shines some light on the problem. However, it is far from sufficient to make an economically viable decision as injecting water into the reservoir dramatically differs from producing it. Many practitioners take for granted that knowing the pore volume of the target formation would be sufficient to determine the storage volume. The actual water injection capacity is the product of the pore volume of the formation, total compressibility of the system, and maximum allowable pressure difference. Since the stress-strain relationship of a porous medium depends on the frequency and magnitude of the loading and unloading process, the total compressibility would be different. The maximum allowable injection pressure and reservoir pressure are functions of in-situ stresses, injection temperature and pressure, and reservoir geomechanical parameters, all of which have significant uncertainty. In practical design, we must consider all parameters and their respective uncertainties. This paper presents a procedure for determining the injection capacity through an in-depth discussion of involved parameters and their associated uncertainties from estimation and measurements. This paper will also demonstrate our practice using a field example as our case study to show our suggested approach.
{"title":"Determining the Storage Capacity of a Saltwater Disposal Reservoir in Practice","authors":"Xingru Wu, D. Childers, Lei Dai, K. Shaffer","doi":"10.2118/213029-ms","DOIUrl":"https://doi.org/10.2118/213029-ms","url":null,"abstract":"\u0000 Produced water is commonly co-produced with oil and gas production and requires safe disposal in subsurface reservoirs. Knowing the amount of produced water that can be safely injected into the reservoir is important for disposal operations. While the methods of reservoir hydrocarbon storage are abundant in literature, the granularity of handling water injection capacity is rare, probably due to the misconception that production is similar to injection into a formation. The knowledge of hydrocarbon reservoir petrophysics shines some light on the problem. However, it is far from sufficient to make an economically viable decision as injecting water into the reservoir dramatically differs from producing it.\u0000 Many practitioners take for granted that knowing the pore volume of the target formation would be sufficient to determine the storage volume. The actual water injection capacity is the product of the pore volume of the formation, total compressibility of the system, and maximum allowable pressure difference. Since the stress-strain relationship of a porous medium depends on the frequency and magnitude of the loading and unloading process, the total compressibility would be different. The maximum allowable injection pressure and reservoir pressure are functions of in-situ stresses, injection temperature and pressure, and reservoir geomechanical parameters, all of which have significant uncertainty. In practical design, we must consider all parameters and their respective uncertainties. This paper presents a procedure for determining the injection capacity through an in-depth discussion of involved parameters and their associated uncertainties from estimation and measurements. This paper will also demonstrate our practice using a field example as our case study to show our suggested approach.","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"116 3-4 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-05-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128671170","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}
Wellbore instability is a major preoccupation during drilling operations and is highly dependent of the physiochemical features of the drilling mud. The hydrophilic clays are used in making drilling mud as they provide extensive viscosity and gel strength, and other rheological properties important for optimum drilling mud performance. However, the segregation of the suspended particles of the once optimum mud to create mud cake against the wellbore formation leads to phases imbalance in the mud system, degrading the physiochemical characteristics of the now worn-out mud after several cycling in and out of the well. Although it is crucial to consider the influence of bottomhole conditions in mud rheological alteration, it is necessary to highlight the direct correlation of most mud physiochemical features with the swelling index of the mud. Therefore, optimization of drilling mud is still up to date mostly about swelling control of the mud thus solid-liquid balancing. Overtime, research papers addressing drilling mud enhancement transitioned from mechanical means such as Loss Circulation Materials (LCM) to chemical additives including polymers which as economically profitable and have swelling abilities. Polyvinyl alcohol one most desirable polymers for future drilling fluid designing as it has proved to influence mud rheology and cake filtration positively. Therefore, this study is an attempt to assess the impact of polyvinyl alcohol on wellbore isolation of a water-based drilling mud. The experiment included two types of Polyvinyl Alcohol (PVOH): Non-ionic PVOH and Cationic PVOH. Each PVOH was added to a set of 3 samples at concentrations 0.1, 0.3, and 0.5 wt.%. An additional sample with no polymer was used as a reference sample. The samples were each subjected to 5h of static pressurized filtration at atmospheric temperature. After which Spectral analysis where performed, and Permeability estimated using Darcy's Law. The results show significant influence on Polyvinyl Alcohol on mud phases distribution. Major dehydration of samples was observed as the sample without PVOH recorded the highest filtrate production while the samples with Cationic, Non-Ionic, and Conventional PVOH had average reduction of 21%,38%, and 43% respectively. The mud cake permeability of samples drastically drops at the least concentration of PVOH with a noticeable difference in permeability despite having the same PVOH concentrations. Those differences are attributed to PVOH-specific structural compositions. This study provides evidence of Polyvinyl Alcohol being responsible for improving mud thermal stability while helping any industry applying drilling activities to expand the range of polymer types that can be used to attain the desired drilling mud for a particular formation.
{"title":"Wellbore Stability Enhancement of Water Based Drilling Mud Using Polyvinyl Alcohol","authors":"Danielle Poungui, Y. Sugai, K. Sasaki","doi":"10.2118/213014-ms","DOIUrl":"https://doi.org/10.2118/213014-ms","url":null,"abstract":"\u0000 Wellbore instability is a major preoccupation during drilling operations and is highly dependent of the physiochemical features of the drilling mud. The hydrophilic clays are used in making drilling mud as they provide extensive viscosity and gel strength, and other rheological properties important for optimum drilling mud performance. However, the segregation of the suspended particles of the once optimum mud to create mud cake against the wellbore formation leads to phases imbalance in the mud system, degrading the physiochemical characteristics of the now worn-out mud after several cycling in and out of the well. Although it is crucial to consider the influence of bottomhole conditions in mud rheological alteration, it is necessary to highlight the direct correlation of most mud physiochemical features with the swelling index of the mud. Therefore, optimization of drilling mud is still up to date mostly about swelling control of the mud thus solid-liquid balancing. Overtime, research papers addressing drilling mud enhancement transitioned from mechanical means such as Loss Circulation Materials (LCM) to chemical additives including polymers which as economically profitable and have swelling abilities. Polyvinyl alcohol one most desirable polymers for future drilling fluid designing as it has proved to influence mud rheology and cake filtration positively. Therefore, this study is an attempt to assess the impact of polyvinyl alcohol on wellbore isolation of a water-based drilling mud. The experiment included two types of Polyvinyl Alcohol (PVOH): Non-ionic PVOH and Cationic PVOH. Each PVOH was added to a set of 3 samples at concentrations 0.1, 0.3, and 0.5 wt.%. An additional sample with no polymer was used as a reference sample. The samples were each subjected to 5h of static pressurized filtration at atmospheric temperature. After which Spectral analysis where performed, and Permeability estimated using Darcy's Law. The results show significant influence on Polyvinyl Alcohol on mud phases distribution. Major dehydration of samples was observed as the sample without PVOH recorded the highest filtrate production while the samples with Cationic, Non-Ionic, and Conventional PVOH had average reduction of 21%,38%, and 43% respectively. The mud cake permeability of samples drastically drops at the least concentration of PVOH with a noticeable difference in permeability despite having the same PVOH concentrations. Those differences are attributed to PVOH-specific structural compositions. This study provides evidence of Polyvinyl Alcohol being responsible for improving mud thermal stability while helping any industry applying drilling activities to expand the range of polymer types that can be used to attain the desired drilling mud for a particular formation.","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-05-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130441544","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}
A. A. Adewunmi, M. Kamal, Afeez O. Gbadamosi, S. Patil
This study was performed to examine the efficacy of corn husks (CH) fine particles as potential natural demulsifier for breaking crude oil emulsion. Stable emulsions were formed using distilled water/crude oil and oil-water ratio was 4:6. The concentrations of CH particles ranging from 0.25, 0.5, 0.75, and 1% were added into vials containing the prepared emulsions and demulsification test was conducted inside the oven at 75 °C. Rheology was used to illustrate the demulsification mechanism of CH as potential demulsifiers. According to the experimental outcomes, the demulsification activity from the bottle test showed that water removal increased with the increasing CH concentration. The demulsification efficiency (DE) of 0.25, 0.5, 0.75, and 1% CH was 8.33%, 50%, 73.33% and 81.67%, respectively; after 60 minutes of demulsification duration. Rheological characterization showed that the incorporation of CH particles caused the reduction of emulsion viscosity which indicated the breaking of emulsion and separation of oil and water. Optical microscopic analysis revealed the morphologies of emulsion immediately after preparation, as well as oil and water phases after separation.
{"title":"Natural Extracted Waste Materials for Breaking Crude Oil Emulsion","authors":"A. A. Adewunmi, M. Kamal, Afeez O. Gbadamosi, S. Patil","doi":"10.2118/213007-ms","DOIUrl":"https://doi.org/10.2118/213007-ms","url":null,"abstract":"\u0000 This study was performed to examine the efficacy of corn husks (CH) fine particles as potential natural demulsifier for breaking crude oil emulsion. Stable emulsions were formed using distilled water/crude oil and oil-water ratio was 4:6. The concentrations of CH particles ranging from 0.25, 0.5, 0.75, and 1% were added into vials containing the prepared emulsions and demulsification test was conducted inside the oven at 75 °C. Rheology was used to illustrate the demulsification mechanism of CH as potential demulsifiers. According to the experimental outcomes, the demulsification activity from the bottle test showed that water removal increased with the increasing CH concentration. The demulsification efficiency (DE) of 0.25, 0.5, 0.75, and 1% CH was 8.33%, 50%, 73.33% and 81.67%, respectively; after 60 minutes of demulsification duration. Rheological characterization showed that the incorporation of CH particles caused the reduction of emulsion viscosity which indicated the breaking of emulsion and separation of oil and water. Optical microscopic analysis revealed the morphologies of emulsion immediately after preparation, as well as oil and water phases after separation.","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-05-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125362314","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}
A. Dandekar, B. Bai, J. Barnes, D. Cercone, R. Edwards, S. Ning, R. Seright, B. Sheets, Dongmei Wang, Yin Zhang
The primary goal of the first ever polymer flood field pilot at Milne Point is to validate the use of polymers for heavy oil Enhanced Oil Recovery (EOR) on Alaska North Slope (ANS). The specific objectives are systematic evaluation of advanced technology that integrates polymer flooding, low salinity water flooding, horizontal wells, and numerical simulation based on polymer flood performance data. Accordingly, under the co-sponsorship of the US Department of Energy and Hilcorp Alaska LLC the first ever polymer field pilot commenced on August 28, 2018 in the Schrader Bluff heavy oil reservoir at the Milne Point Unit (MPU) on ANS. The pilot started injecting hydrolyzed polyacrylamide (HPAM), at a concentration of 1,750 ppm to achieve a target viscosity of 45 cP, into the two horizontal injectors in the J-pad flood pattern. Since July 2020, HPAM concentration was reduced to 1,200 ppm to control injectivity and optimize polymer utilization. Filter ratio tests conducted on site ensure uniform polymer solution properties. Injectivity is assessed by Hall plots, whereas production is monitored via oil and water rates from the two producers. Water samples are analyzed to determine the produced polymer concentration. Supporting laboratory corefloods on polymer retention, injection water salinity, polymer loading, and their combinations on oil recovery, match rock, fluid and test conditions. A calibrated and validated numerical multiphase reservoir model was developed for long-term reservoir performance prediction and for evaluating the project's economic performance in conjunction with an economic model. Concerns related to handling of produced fluids containing polymer are addressed by specialized experiments. As would be expected in a field experiment of this scale, barring some operational and hydration issues, continuous polymer injection has been achieved. As of September 30, 2022, a total of 1.41 million lbs of polymer or 2.99 million bbls of polymer solution (~18.8% of total pore volume), placed in the pattern serves as an effective indicator of polymer injectivity. During the first half of the pilot period, water cut (WC) drastically reduced in both producers and over the entire duration, the deemed EOR benefit over waterflood was in the range of 700-1,000 bopd, and that too at a low polymer utilization of 1.7 lbs/bbl. Low concentration polymer breakthrough was observed after 26-28 months, which is now stabilized at 600–800 ppm in congruence with the WC. Although as indicated by laboratory experiments, polymer retention in core material is high; ~70% of the injected polymer propagates without any delay, while the remaining 30% tails over several PVs. History matched simulation models consistently forecasts polymer recovery of 1.5–2 times that of waterflood, and when integrated with the economic modeling tool, establish the economic profitability of the first ever polymer flood field pilot. Produced fluid experiments provide operational guidance
Milne Point首次聚合物驱油田试验的主要目标是验证聚合物在阿拉斯加北坡稠油提高采收率(EOR)方面的应用。具体目标是系统评估先进技术，该技术将聚合物驱、低矿化度水驱、水平井和基于聚合物驱性能数据的数值模拟相结合。因此，在美国能源部和Hilcorp阿拉斯加有限责任公司的共同赞助下，于2018年8月28日在ANS Milne Point Unit (MPU)的Schrader Bluff稠油油藏进行了首次聚合物现场试验，试验开始将浓度为1750 ppm的水解聚丙烯酰胺(HPAM)注入J-pad的两个水平注入器中，以达到45 cP的目标粘度。自2020年7月起，HPAM浓度降至1200 ppm，以控制注入能力并优化聚合物利用率。在现场进行的过滤比测试确保聚合物溶液性质均匀。注入能力通过霍尔图进行评估，而产量则通过两个生产商的油水流量进行监测。对水样进行分析以确定产生的聚合物浓度。支持实验室岩心驱油的聚合物保留率、注入水中的矿化度、聚合物载荷以及它们在采收率方面的组合，匹配岩石、流体和测试条件。开发了一个经过校准和验证的多相油藏数值模型，用于长期油藏动态预测，并结合经济模型评估项目的经济绩效。与处理含聚合物的产出液有关的问题通过专门的实验来解决。在这种规模的现场实验中，排除了一些操作和水化问题，可以实现连续注入聚合物。截至2022年9月30日，该模式中共放置了141万磅聚合物或299万桶聚合物溶液(约占总孔隙体积的18.8%)，作为聚合物注入能力的有效指标。在试验的前半段，两家生产商的含水率(WC)都大幅降低，在整个试验期间，与注水相比，EOR的效益在700- 1000桶/天之间，而且聚合物的利用率很低，只有1.7磅/桶。26-28个月后，观察到低浓度聚合物突破，现在稳定在600-800 ppm，与WC一致。虽然实验室实验表明，聚合物在芯材中的保留率很高;约70%的注入聚合物无延迟地传播，而剩余的30%在几个pv上尾部。历史匹配模拟模型一致预测聚合物采收率是水驱的1.5-2倍，当与经济建模工具相结合时，建立了首次聚合物驱油田试验的经济盈利能力。产液实验为乳状液的处理和加热器的工作温度提供了操作指导。经过约4.5年的时间，解决了稠油聚合物驱的重要突出技术问题，为本文总结的成功案例奠定了基础。首次聚合物试验被认为在技术和经济上都取得了成功，显著提高了ANS稠油采收率，该试验不仅推动了在整个Milne Point油田应用聚合物EOR，而且为国家资助的针对ANS稠油的其他研究铺平了道路，这一工作的成功和未来的工作将有助于延长跨阿拉斯加管道系统(TAPS)的寿命。
{"title":"The Success Story of First Ever Polymer Flood Field Pilot to Enhance the Recovery of Heavy Oils on Alaska's North Slope","authors":"A. Dandekar, B. Bai, J. Barnes, D. Cercone, R. Edwards, S. Ning, R. Seright, B. Sheets, Dongmei Wang, Yin Zhang","doi":"10.2118/212973-ms","DOIUrl":"https://doi.org/10.2118/212973-ms","url":null,"abstract":"\u0000 The primary goal of the first ever polymer flood field pilot at Milne Point is to validate the use of polymers for heavy oil Enhanced Oil Recovery (EOR) on Alaska North Slope (ANS). The specific objectives are systematic evaluation of advanced technology that integrates polymer flooding, low salinity water flooding, horizontal wells, and numerical simulation based on polymer flood performance data. Accordingly, under the co-sponsorship of the US Department of Energy and Hilcorp Alaska LLC the first ever polymer field pilot commenced on August 28, 2018 in the Schrader Bluff heavy oil reservoir at the Milne Point Unit (MPU) on ANS. The pilot started injecting hydrolyzed polyacrylamide (HPAM), at a concentration of 1,750 ppm to achieve a target viscosity of 45 cP, into the two horizontal injectors in the J-pad flood pattern. Since July 2020, HPAM concentration was reduced to 1,200 ppm to control injectivity and optimize polymer utilization. Filter ratio tests conducted on site ensure uniform polymer solution properties. Injectivity is assessed by Hall plots, whereas production is monitored via oil and water rates from the two producers. Water samples are analyzed to determine the produced polymer concentration. Supporting laboratory corefloods on polymer retention, injection water salinity, polymer loading, and their combinations on oil recovery, match rock, fluid and test conditions. A calibrated and validated numerical multiphase reservoir model was developed for long-term reservoir performance prediction and for evaluating the project's economic performance in conjunction with an economic model. Concerns related to handling of produced fluids containing polymer are addressed by specialized experiments.\u0000 As would be expected in a field experiment of this scale, barring some operational and hydration issues, continuous polymer injection has been achieved. As of September 30, 2022, a total of 1.41 million lbs of polymer or 2.99 million bbls of polymer solution (~18.8% of total pore volume), placed in the pattern serves as an effective indicator of polymer injectivity. During the first half of the pilot period, water cut (WC) drastically reduced in both producers and over the entire duration, the deemed EOR benefit over waterflood was in the range of 700-1,000 bopd, and that too at a low polymer utilization of 1.7 lbs/bbl. Low concentration polymer breakthrough was observed after 26-28 months, which is now stabilized at 600–800 ppm in congruence with the WC. Although as indicated by laboratory experiments, polymer retention in core material is high; ~70% of the injected polymer propagates without any delay, while the remaining 30% tails over several PVs. History matched simulation models consistently forecasts polymer recovery of 1.5–2 times that of waterflood, and when integrated with the economic modeling tool, establish the economic profitability of the first ever polymer flood field pilot. Produced fluid experiments provide operational guidance","PeriodicalId":158776,"journal":{"name":"Day 3 Wed, May 24, 2023","volume":"54 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-05-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127637444","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}
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