The development Chemical EOR technologies is increasing rapidly due to the massive need of hydrocarbons in the world and because most of the reservoirs have reached tertiary recovery phase. Carbonate reservoir have challenging conditions of high salinity and high temperature that affect the performance of SP flooding. In this paper, we are using a commertial simulator to optimize the design SP flooding in these harsh conditions, and use our previous core-flooding experiment to calibrate our simulation model. The porosity distribution for the model was determined by using the micro-CT imaging which gave the distribution along the core. The permeability was calculated based on the porosity-permeability relationship from the real core data. The real surfactant and polymer properties were measured in the lab in terms of rheology and IFT. History matching of the base case to the real core data was performed using particle swarm optimization machine. The matching parameters were the critical capillary number for de-trapping for both low and high IFT flooding, besides the relative permeability curvature parameter. Many scenarios were investigated after having a match with 2.3 AAE. The polymers used are a Thermo-Viscosifying Polymer (TVP) and an Acrylamido Tertiary Butyl Sulfonate (ATBS)/acrylamide (AM) copolymer. The surfactants are carboxybetaine based amphoteric surfactants SS-880 and SS-885. We did previous study to optimize the core-flooding design for SP flooding in the lab but we faced the problem of inconsistency. Because there are some factors that, we cannot control and keep them constant to compare results, like the core permeability and porosity and their distribution and mineralogy. The combination of surfactant and polymer in one slug gives more recovery than the injecting them individually. ATBS gave higher recovery than TVP. There is no difference in recovery due to changing the surfactants because their IFT is close to each other. The observation is that increasing the slug size will increase the recovery so we recommend using diminishing return economic analyses to determine the slug that gives the highest profit. Injecting SW-SP-SW is the best sequence among the other three sequences, taking the advantage of injecting longer slug of viscous fluid, as the increment due to IFT reduction is minor. The viscosity sensitivity study shows higher recovery with more viscous fluids so the limiting factor will be the economics and the pump capacity. Optimizing the SP flooding design for carbonate reservoirs using simulation with the help of lab experiments results for calibration will decrease the uncertainty. This technique is better because you can control the fixed and variable parameters to know exactly the effect of individual ones.
{"title":"Optimization of Sp Flooding Design Using Simulation Calibrated with Lab Core Flooding","authors":"M. Ahmed, A. Sultan","doi":"10.2118/200228-ms","DOIUrl":"https://doi.org/10.2118/200228-ms","url":null,"abstract":"\u0000 The development Chemical EOR technologies is increasing rapidly due to the massive need of hydrocarbons in the world and because most of the reservoirs have reached tertiary recovery phase. Carbonate reservoir have challenging conditions of high salinity and high temperature that affect the performance of SP flooding. In this paper, we are using a commertial simulator to optimize the design SP flooding in these harsh conditions, and use our previous core-flooding experiment to calibrate our simulation model.\u0000 The porosity distribution for the model was determined by using the micro-CT imaging which gave the distribution along the core. The permeability was calculated based on the porosity-permeability relationship from the real core data. The real surfactant and polymer properties were measured in the lab in terms of rheology and IFT. History matching of the base case to the real core data was performed using particle swarm optimization machine. The matching parameters were the critical capillary number for de-trapping for both low and high IFT flooding, besides the relative permeability curvature parameter. Many scenarios were investigated after having a match with 2.3 AAE.\u0000 The polymers used are a Thermo-Viscosifying Polymer (TVP) and an Acrylamido Tertiary Butyl Sulfonate (ATBS)/acrylamide (AM) copolymer. The surfactants are carboxybetaine based amphoteric surfactants SS-880 and SS-885. We did previous study to optimize the core-flooding design for SP flooding in the lab but we faced the problem of inconsistency. Because there are some factors that, we cannot control and keep them constant to compare results, like the core permeability and porosity and their distribution and mineralogy. The combination of surfactant and polymer in one slug gives more recovery than the injecting them individually. ATBS gave higher recovery than TVP. There is no difference in recovery due to changing the surfactants because their IFT is close to each other. The observation is that increasing the slug size will increase the recovery so we recommend using diminishing return economic analyses to determine the slug that gives the highest profit. Injecting SW-SP-SW is the best sequence among the other three sequences, taking the advantage of injecting longer slug of viscous fluid, as the increment due to IFT reduction is minor. The viscosity sensitivity study shows higher recovery with more viscous fluids so the limiting factor will be the economics and the pump capacity.\u0000 Optimizing the SP flooding design for carbonate reservoirs using simulation with the help of lab experiments results for calibration will decrease the uncertainty. This technique is better because you can control the fixed and variable parameters to know exactly the effect of individual ones.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78852597","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}
Injection of foams can be used to optimize different gas injection processes such as CCUS (Carbon Capture Use & Storage) and possibly to boost oil recovery kinetics in heterogenous or naturally fractured reservoirs (Enick R.M. 2012). In this case, foams, which are more viscous and dense than gases, aim at limiting early gas breakthrough during field operation by improving the sweeping efficiency of reservoirs and by blocking the most permeable areas of the latters (A. Al Sumaiti 2017, Chabert M. and D'Souza D. 2016). A large part of the world oil reservoirs that have already been operated by primary and secondary recovery methods are carbonate reservoirs and are mostly located in the Middle East (Talebian S.H. 2014). In these reservoirs, which are often operated by CO2 injection, the adsorption of surfactants on positively charged carbonates may be a major hindrance to foam injection (Pownall 1989, Cui L. and Ma K. 2014). That is why, cationic surfactants have been developed for these CO2 foam applications (Chen Y. 2016). However, these cationics are often hardly soluble at pH>6 (Jian G. 2019) and/or not industrially avalaible (Cui et Dubos 2018). For this study, we selected three different cationic surfactants. Using automated robotic platforms, we explored a large range of surfactant combination (combining each cationic surfactant with a whole co-surfactant portfolio) at high temperature and in a hard concentrated brine (120g/LTDS, [Ca2+]= 8100ppm). We show that adding co-surfactants to each of these cationics boosts their foaming properties in porous media as well as their solubility at high pH (pH=8) while maintaining low levels of adsorption on carbonates. While a high shear rate is required for cationic surfactants to generate foam in sandpacks, formulations combining cationics and co-surfactants form foams at much lower shear rates. Moreover, the fact that these formulations are soluble at pH=8 means that, on field, the water would no longer need to be acidified at the wellhead to solubilize the surfactant blend. Thus, pipe corrosion induced by the flow of acidified solutions in the surface facilities is prevented. Lastly, all the molecules that are tested in this study are industrially available.
注入泡沫可用于优化不同的注气工艺，如CCUS(碳捕获利用与储存)，并可能提高非均质或天然裂缝油藏的采油动力学(Enick R.M. 2012)。在这种情况下，泡沫比气体更粘稠、密度更大，其目的是通过提高储层的清扫效率和堵塞后者最具渗透性的区域，在现场作业中限制早期气体突破(A. Al Sumaiti 2017, Chabert M. and D'Souza D. 2016)。世界上大部分已经采用一次和二次采油方法的油藏都是碳酸盐岩油藏，而且大部分位于中东地区(Talebian S.H. 2014)。在这些油藏中，通常通过注入二氧化碳进行作业，表面活性剂在带正电的碳酸盐上的吸附可能是泡沫注入的主要障碍(Pownall 1989, Cui L. and Ma K. 2014)。这就是为什么阳离子表面活性剂已经被开发用于这些二氧化碳泡沫应用(Chen Y. 2016)。然而，这些阳离子在pH>6时通常难以溶解(Jian G. 2019)和/或无法在工业上使用(Cui et Dubos 2018)。在这项研究中，我们选择了三种不同的阳离子表面活性剂。利用自动化机器人平台，我们在高温和浓硬性盐水(120g/LTDS， [Ca2+]= 8100ppm)中探索了大范围的表面活性剂组合(将每种阳离子表面活性剂与整个助表面活性剂组合在一起)。研究表明，在这些阳离子中加入助表面活性剂可以提高它们在多孔介质中的发泡性能以及在高pH值(pH=8)下的溶解度，同时保持对碳酸盐的低吸附水平。虽然阳离子表面活性剂在沙层中产生泡沫需要很高的剪切速率，但结合阳离子和共表面活性剂的配方可以以更低的剪切速率形成泡沫。此外，这些配方在pH=8时可溶解，这意味着在现场，不再需要在井口酸化水来溶解表面活性剂混合物。因此，防止了由表面设施中酸化溶液流动引起的管道腐蚀。最后，在这项研究中测试的所有分子都是工业上可用的。
{"title":"Co2 Foams in Carbonate Reservoirs at High Temperature: Boosting Cationics Formulation Performances By Additives","authors":"Kerdraon Margaux, Chevallier Eloise, Gland Nicolas, Batot Guillaume","doi":"10.2118/200052-ms","DOIUrl":"https://doi.org/10.2118/200052-ms","url":null,"abstract":"\u0000 Injection of foams can be used to optimize different gas injection processes such as CCUS (Carbon Capture Use & Storage) and possibly to boost oil recovery kinetics in heterogenous or naturally fractured reservoirs (Enick R.M. 2012). In this case, foams, which are more viscous and dense than gases, aim at limiting early gas breakthrough during field operation by improving the sweeping efficiency of reservoirs and by blocking the most permeable areas of the latters (A. Al Sumaiti 2017, Chabert M. and D'Souza D. 2016). A large part of the world oil reservoirs that have already been operated by primary and secondary recovery methods are carbonate reservoirs and are mostly located in the Middle East (Talebian S.H. 2014). In these reservoirs, which are often operated by CO2 injection, the adsorption of surfactants on positively charged carbonates may be a major hindrance to foam injection (Pownall 1989, Cui L. and Ma K. 2014). That is why, cationic surfactants have been developed for these CO2 foam applications (Chen Y. 2016). However, these cationics are often hardly soluble at pH>6 (Jian G. 2019) and/or not industrially avalaible (Cui et Dubos 2018).\u0000 For this study, we selected three different cationic surfactants. Using automated robotic platforms, we explored a large range of surfactant combination (combining each cationic surfactant with a whole co-surfactant portfolio) at high temperature and in a hard concentrated brine (120g/LTDS, [Ca2+]= 8100ppm). We show that adding co-surfactants to each of these cationics boosts their foaming properties in porous media as well as their solubility at high pH (pH=8) while maintaining low levels of adsorption on carbonates. While a high shear rate is required for cationic surfactants to generate foam in sandpacks, formulations combining cationics and co-surfactants form foams at much lower shear rates. Moreover, the fact that these formulations are soluble at pH=8 means that, on field, the water would no longer need to be acidified at the wellhead to solubilize the surfactant blend. Thus, pipe corrosion induced by the flow of acidified solutions in the surface facilities is prevented. Lastly, all the molecules that are tested in this study are industrially available.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"2000 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91548511","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}
Li‐Qin Jin, Wenyong Li, Yan Lu, Jiabo Liang, Jian’an Dong, Shouxin Wang, Hussein Kadhim Laaby, Ali Jabbar Ammar, Ali Ouda Tayih, R. Muteer, Tammeem Muktadh, Fang Yongjun, Jon Tuck
CNOOC Iraq Limited (CILB) operates the Missan oilfield in Iraq, which consists of three oilfields: Buzurgan oilfield, Abu Gharib oilfield and Fauqi oilfield. To maximize production from the field it has been necessary to overcome different challenges related to asphaltenes (tubing deposition, formation damage, emulsions) – firstly by properly understanding the fluid behaviour, and then by developing and implementing mitigation strategies. To understand the asphaltene stability of the reservoir fluids, an isothermal depressurization study was performed on a monophasic bottomhole sample from the reservoir’s main production unit. Asphaltene Onset Pressures (AOPs) were identified and used for tuning an equation-of-state model to generate an asphaltene precipitation envelope (APE). Modelling software was used to calculate pressure-temperature profile of fluids both in the near wellbore region and production wells and determine if they entered the APE. This was reviewed against historical field data to assess if asphaltene issues were predictable. Common fluid property screening tests (e.g. De Boer plots, Colloidal Instability Index) under-predicted the occurrence of asphaltene precipitation in the oilfields. When fluid pressures and temperatures in the reservoir and well environment were compared against the modelled APE, they showed the reservoir fluids passing through the asphaltene instability region for most wells, indicating a risk of deposition in the tubing and in the formation. Comparing predictions with field data highlighted that precipitation of asphaltenes does not always result in tubing deposition and additional factors such as watercut and oil viscosity need to be considered. Other fluid-related issues, such as stable emulsions and formation damage, have been observed in the field and require managing. Results from this study show that these can be explained in terms of asphaltene stability issues arising from fluid P/T behavior and interactions with water. The importance of drawdown management, already practiced by the field operator, is shown to be a key tool for managing and controlling asphaltene issues. The value of optimizing solvent-based stimulations and retaining the ability to stimulate ESP-lifted wells is also demonstrated. Measuring asphaltene stability using virgin reservoir samples, and applying fluid screening tests, are common activities during new field appraisals. The results inform high value decisions, ranging from completion design to reservoir management strategy. This study, conducted on a mature field with known production history, shows how results from fluid characterisation studies relate to actual experience of asphaltenes during production. The use of fluid studies in diagnosis and treatment of operational challenges is also demonstrated.
{"title":"Diverse Asphaltene Challenges in a Mature Field: A Fluid Study from Iraq","authors":"Li‐Qin Jin, Wenyong Li, Yan Lu, Jiabo Liang, Jian’an Dong, Shouxin Wang, Hussein Kadhim Laaby, Ali Jabbar Ammar, Ali Ouda Tayih, R. Muteer, Tammeem Muktadh, Fang Yongjun, Jon Tuck","doi":"10.2118/200202-ms","DOIUrl":"https://doi.org/10.2118/200202-ms","url":null,"abstract":"\u0000 CNOOC Iraq Limited (CILB) operates the Missan oilfield in Iraq, which consists of three oilfields: Buzurgan oilfield, Abu Gharib oilfield and Fauqi oilfield. To maximize production from the field it has been necessary to overcome different challenges related to asphaltenes (tubing deposition, formation damage, emulsions) – firstly by properly understanding the fluid behaviour, and then by developing and implementing mitigation strategies.\u0000 To understand the asphaltene stability of the reservoir fluids, an isothermal depressurization study was performed on a monophasic bottomhole sample from the reservoir’s main production unit.\u0000 Asphaltene Onset Pressures (AOPs) were identified and used for tuning an equation-of-state model to generate an asphaltene precipitation envelope (APE). Modelling software was used to calculate pressure-temperature profile of fluids both in the near wellbore region and production wells and determine if they entered the APE. This was reviewed against historical field data to assess if asphaltene issues were predictable.\u0000 Common fluid property screening tests (e.g. De Boer plots, Colloidal Instability Index) under-predicted the occurrence of asphaltene precipitation in the oilfields.\u0000 When fluid pressures and temperatures in the reservoir and well environment were compared against the modelled APE, they showed the reservoir fluids passing through the asphaltene instability region for most wells, indicating a risk of deposition in the tubing and in the formation.\u0000 Comparing predictions with field data highlighted that precipitation of asphaltenes does not always result in tubing deposition and additional factors such as watercut and oil viscosity need to be considered. Other fluid-related issues, such as stable emulsions and formation damage, have been observed in the field and require managing. Results from this study show that these can be explained in terms of asphaltene stability issues arising from fluid P/T behavior and interactions with water.\u0000 The importance of drawdown management, already practiced by the field operator, is shown to be a key tool for managing and controlling asphaltene issues. The value of optimizing solvent-based stimulations and retaining the ability to stimulate ESP-lifted wells is also demonstrated.\u0000 Measuring asphaltene stability using virgin reservoir samples, and applying fluid screening tests, are common activities during new field appraisals. The results inform high value decisions, ranging from completion design to reservoir management strategy.\u0000 This study, conducted on a mature field with known production history, shows how results from fluid characterisation studies relate to actual experience of asphaltenes during production. The use of fluid studies in diagnosis and treatment of operational challenges is also demonstrated.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76303012","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}
Matthew J. Monette, Alolika Das, R. Nasralla, R. Farajzadeh, Abdulaziz Shaqsi, Q. Nguyen
Past laboratory experiments have shown Low Tension Gas (LTG) floods to be a promising tertiary oil recovery technology in low permeability and high salinity carbonate reservoirs. Gas availability and cost are the major challenges in applying this technology under field conditions. The cost of importing gas from an outside source or on-site generation of nitrogen can be eliminated if the produced gas from the oilfield can be re-injected for generating in-situ foam. Also, the cost of both purchasing freshwater and processing the produced water can be decreased dramatically by injecting both the ultra-low IFT inducing surfactant slug and the drive at the same (constant) salinity. LTG corefloods were conducted for a carbonate reservoir with low permeability (<100 mD), moderate temperature (69 °C) and high formation brine salinity (180,000 ppm). Microemulsion phase behavior experiments were conducted at reservoir conditions with different gases. Dynamic foam propagation experiments with methane and a mix of methane-ethane (80 mol. % methane) were performed. The effect of microemulsion (generated using the constant salinity approach) on foam stability was also studied. Optimal conditions for both foam propagations and IFT reduction based on these experiments were identified and used to further develop injection strategies for enhancing oil recovery in coreflood on the same rock type. High pressure microemulsion phase behavior experiments showed that produced gas increased the optimum solubilization ratio compared to methane or nitrogen. The solubilization ratio at fixed salinity was a strong function of the surfactant formulation, pressure and the composition of the produced gas. Foam strength experiments showed that produced gas could generate an in-situ foam strength similar to the nitrogen gas. Lower foam quality showed higher apparent viscosity at lower injected surfactant concentration. Preliminary results from core flood experiments indicated that using constant salinity for both slug and drive could result in a remarkable increase in the oil recovery, even though ultra-low IFT inducing surfactants were only injected for a small slug. It also helped improve surfactant transport, which is important for the application of LTG process in high salinity carbonate reservoirs without the use of alkali. The results have advanced our understanding of how field gas can be combined with a high performance surfactant formulation to (i) provide necessary conformance control for surfactant flooding, (ii) improve surfactant transport in a very high salinity environment without the need for alkali, and thus soft water, (iii) reduce the complexity of salinity reduction from slug to drive that is typically required in ASP flooding, and (iv) further improve surfactant efficiency due to the increase of oil solubilization and oil viscosity reduction with the injection gas enrichment.
{"title":"Laboratory Investigation on Impact of Gas Type on the Performance of Low-Tension-Gas Flooding in High Salinity, Low Permeability Carbonate Reservoirs","authors":"Matthew J. Monette, Alolika Das, R. Nasralla, R. Farajzadeh, Abdulaziz Shaqsi, Q. Nguyen","doi":"10.2118/200192-ms","DOIUrl":"https://doi.org/10.2118/200192-ms","url":null,"abstract":"\u0000 Past laboratory experiments have shown Low Tension Gas (LTG) floods to be a promising tertiary oil recovery technology in low permeability and high salinity carbonate reservoirs. Gas availability and cost are the major challenges in applying this technology under field conditions. The cost of importing gas from an outside source or on-site generation of nitrogen can be eliminated if the produced gas from the oilfield can be re-injected for generating in-situ foam. Also, the cost of both purchasing freshwater and processing the produced water can be decreased dramatically by injecting both the ultra-low IFT inducing surfactant slug and the drive at the same (constant) salinity.\u0000 LTG corefloods were conducted for a carbonate reservoir with low permeability (<100 mD), moderate temperature (69 °C) and high formation brine salinity (180,000 ppm). Microemulsion phase behavior experiments were conducted at reservoir conditions with different gases. Dynamic foam propagation experiments with methane and a mix of methane-ethane (80 mol. % methane) were performed. The effect of microemulsion (generated using the constant salinity approach) on foam stability was also studied. Optimal conditions for both foam propagations and IFT reduction based on these experiments were identified and used to further develop injection strategies for enhancing oil recovery in coreflood on the same rock type.\u0000 High pressure microemulsion phase behavior experiments showed that produced gas increased the optimum solubilization ratio compared to methane or nitrogen. The solubilization ratio at fixed salinity was a strong function of the surfactant formulation, pressure and the composition of the produced gas. Foam strength experiments showed that produced gas could generate an in-situ foam strength similar to the nitrogen gas. Lower foam quality showed higher apparent viscosity at lower injected surfactant concentration. Preliminary results from core flood experiments indicated that using constant salinity for both slug and drive could result in a remarkable increase in the oil recovery, even though ultra-low IFT inducing surfactants were only injected for a small slug. It also helped improve surfactant transport, which is important for the application of LTG process in high salinity carbonate reservoirs without the use of alkali.\u0000 The results have advanced our understanding of how field gas can be combined with a high performance surfactant formulation to (i) provide necessary conformance control for surfactant flooding, (ii) improve surfactant transport in a very high salinity environment without the need for alkali, and thus soft water, (iii) reduce the complexity of salinity reduction from slug to drive that is typically required in ASP flooding, and (iv) further improve surfactant efficiency due to the increase of oil solubilization and oil viscosity reduction with the injection gas enrichment.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"92 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80477962","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}
This paper discusses how re-designing the well is driving the performance and maximizing the well life considering all risks and challenges associated with drilling in Oman thermal Q fields that required further engineering solutions and in-depth simulation and analysis. Managing the risk and delivering wells safely in the most competitive and economical approach are most critical value drivers of these wells. Main risks in Q field are shallow gas, high level of H2s, highly fractured formation, drilling in total losses scenario with ERD wells profile, managing high reactive shale, cement bond quality and critical zonal isolation requirement. It also reflects the unique well control approach in managing gas cap risk with total losses scenario. Collecting the data and list all risks and challenges associated with drilling operation to identify the functionality and other enablers was the most critical step in evaluating what givens and opportunities are. Then, utilizing well plan landmark and other simulation tools to simulate torque and drag, shock and vibration, hydraulics and hole cleaning to optimize the design of the well profile and BHA configurations. Consequently, re-designing the well and proposed the most suitable and fit for purpose design along with different loads and stress checks utilizing wellcat tool. Real-time data utilized during the execution phase to maximize drilling efficiency and design effectiveness. Finally, the well delivered assessed against its critical function requirements like minimum zonal isolation between different reservoirs and well integrity. By proposing engineering solutions and design optimization, utilizing both frontend simulation and past filed best practices, all Q field wells delivered safely with required quality within its budget and time frame. All challenges and risks have been overcome and managed to deliver the project efficiently like torque and drag, hole cleaning, shock and vibration, and back-reaming. Also landing criteria and drilling parameters have been developed to avoid losses while landing the well in a highly depleted reservoir and manage the threat of getting well control scenario. Furthermore, in the execution phase, real-time data monitored to enhance the efficiency and drilling parameters were optimized to keep them within the planned operating envelope. As the design focused on long-term well integrity and longevity, further evaluation post well delivery curried out to check the zonal isolation with positive results that reflect healthy well integrity and fulfillment all functional requirement. This paper reflects the complexity and unique approach in managing well control risk with dynamic kill procedure (Natih procedure) while drilling gas cap in highly fractured formation associated with concertation of H2S gas. Also, it is echoing the importance of advance engineering analysis and solutions in delivering the high ERD ratio wells with their challenges and risk profile. As w
{"title":"Well Design Advancement – Engineering Solutions to Overcome Risks and Challenges in Drilling Risky Thermal Filed in North of Oman","authors":"Qasim Rawahi, H. Rashdi","doi":"10.2118/200268-ms","DOIUrl":"https://doi.org/10.2118/200268-ms","url":null,"abstract":"\u0000 This paper discusses how re-designing the well is driving the performance and maximizing the well life considering all risks and challenges associated with drilling in Oman thermal Q fields that required further engineering solutions and in-depth simulation and analysis. Managing the risk and delivering wells safely in the most competitive and economical approach are most critical value drivers of these wells. Main risks in Q field are shallow gas, high level of H2s, highly fractured formation, drilling in total losses scenario with ERD wells profile, managing high reactive shale, cement bond quality and critical zonal isolation requirement. It also reflects the unique well control approach in managing gas cap risk with total losses scenario.\u0000 Collecting the data and list all risks and challenges associated with drilling operation to identify the functionality and other enablers was the most critical step in evaluating what givens and opportunities are. Then, utilizing well plan landmark and other simulation tools to simulate torque and drag, shock and vibration, hydraulics and hole cleaning to optimize the design of the well profile and BHA configurations. Consequently, re-designing the well and proposed the most suitable and fit for purpose design along with different loads and stress checks utilizing wellcat tool. Real-time data utilized during the execution phase to maximize drilling efficiency and design effectiveness. Finally, the well delivered assessed against its critical function requirements like minimum zonal isolation between different reservoirs and well integrity.\u0000 By proposing engineering solutions and design optimization, utilizing both frontend simulation and past filed best practices, all Q field wells delivered safely with required quality within its budget and time frame. All challenges and risks have been overcome and managed to deliver the project efficiently like torque and drag, hole cleaning, shock and vibration, and back-reaming. Also landing criteria and drilling parameters have been developed to avoid losses while landing the well in a highly depleted reservoir and manage the threat of getting well control scenario. Furthermore, in the execution phase, real-time data monitored to enhance the efficiency and drilling parameters were optimized to keep them within the planned operating envelope. As the design focused on long-term well integrity and longevity, further evaluation post well delivery curried out to check the zonal isolation with positive results that reflect healthy well integrity and fulfillment all functional requirement.\u0000 This paper reflects the complexity and unique approach in managing well control risk with dynamic kill procedure (Natih procedure) while drilling gas cap in highly fractured formation associated with concertation of H2S gas. Also, it is echoing the importance of advance engineering analysis and solutions in delivering the high ERD ratio wells with their challenges and risk profile. As w","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"328 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77599585","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}
S. Masalmeh, S. A. Farzaneh, M. Sohrabi, M. Ataei, Muataz Alshuaibi
Gas injection is the most widely applied recovery method in light, condensate, and volatile oil carbonate reservoirs. Gas has high displacement efficiency and usually results in a low residual oil saturation in the part of the reservoirs that is contacted with gas. The displacement efficiency increases when the injected gas is near-miscible or miscible with the oil. In addition to nitrogen and hydrocarbon gas projects, CO2- EOR has been the dominant gas EOR process. Gas-based EOR has been implemented in both mature and waterflooded carbonate reservoirs. In this paper, we present the results of a detailed experimental study aimed at understanding the performance and efficiency of gas injection in carbonate reservoirs. A series of immiscible and miscible gas injection coreflood experiments were performed using limestone reservoir cores under different injection strategies. To minimize laboratory artefacts, long cores were used in the experiments and to observe the effect of gravity both 2-inch diameter and 4-inch diameter (whole core) were used. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by ageing the core in crude oil for several weeks under reservoir temperature. Hydrocarbon gas (methane) was used as the immiscible injectant, CO2 was used as a miscible agent and a mixture of 50% C1 and 50% CO2 was used as near miscible injectant. All gas injection experiments were performed using vertically oriented cores and the gas was injected from the top unless it is stated otherwise. The main parameters investigated in this study are: 1- The effect of miscibility on oil recovery for both continuous gas injection and WAG, 2- The effect of gravity on gas sweep efficiency compared to water flooding, 3- the effect of gas-oil IFT on oil recovery when using the same oil, 4- the effect of oil type on oil recovery using the same injected gas at miscible and immiscible conditions, 5- the effect of immiscible gas injection on subsequent miscible gas injection performance and 6- Impact of CO2 cycle length on ultimate oil recovery. In addition, this work investigated the impact of the order of fluid injection where multiple WAG injection cycles were performed in separate experiments after water or gas injection. The main conclusions of this study are: 1- As expected miscibility has a significant impact on displacement efficiency and oil recovery, however a significant variation in oil recovery is observed, i.e., about 10 saturation units difference, depending on the oil properties even when both experiments are performed at miscible conditions using the same injected gas. 2- The performance of tertiary CO2 flood was adversely affected by the slug of immiscible gas injected. Therefore, it is not recommended to have immiscible gas injection before miscible gas injection. 3- Regardless of injected gas type, gas injection with similar IFTs achieved similar oil recovery. 4- During WAG experiments, s
{"title":"A Systematic Experimental Study to Understand the Performance and Efficiency of Gas Injection in Carbonate Reservoirs","authors":"S. Masalmeh, S. A. Farzaneh, M. Sohrabi, M. Ataei, Muataz Alshuaibi","doi":"10.2118/200057-ms","DOIUrl":"https://doi.org/10.2118/200057-ms","url":null,"abstract":"\u0000 Gas injection is the most widely applied recovery method in light, condensate, and volatile oil carbonate reservoirs. Gas has high displacement efficiency and usually results in a low residual oil saturation in the part of the reservoirs that is contacted with gas. The displacement efficiency increases when the injected gas is near-miscible or miscible with the oil. In addition to nitrogen and hydrocarbon gas projects, CO2- EOR has been the dominant gas EOR process. Gas-based EOR has been implemented in both mature and waterflooded carbonate reservoirs.\u0000 In this paper, we present the results of a detailed experimental study aimed at understanding the performance and efficiency of gas injection in carbonate reservoirs. A series of immiscible and miscible gas injection coreflood experiments were performed using limestone reservoir cores under different injection strategies. To minimize laboratory artefacts, long cores were used in the experiments and to observe the effect of gravity both 2-inch diameter and 4-inch diameter (whole core) were used. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by ageing the core in crude oil for several weeks under reservoir temperature. Hydrocarbon gas (methane) was used as the immiscible injectant, CO2 was used as a miscible agent and a mixture of 50% C1 and 50% CO2 was used as near miscible injectant. All gas injection experiments were performed using vertically oriented cores and the gas was injected from the top unless it is stated otherwise.\u0000 The main parameters investigated in this study are: 1- The effect of miscibility on oil recovery for both continuous gas injection and WAG, 2- The effect of gravity on gas sweep efficiency compared to water flooding, 3- the effect of gas-oil IFT on oil recovery when using the same oil, 4- the effect of oil type on oil recovery using the same injected gas at miscible and immiscible conditions, 5- the effect of immiscible gas injection on subsequent miscible gas injection performance and 6- Impact of CO2 cycle length on ultimate oil recovery. In addition, this work investigated the impact of the order of fluid injection where multiple WAG injection cycles were performed in separate experiments after water or gas injection.\u0000 The main conclusions of this study are: 1- As expected miscibility has a significant impact on displacement efficiency and oil recovery, however a significant variation in oil recovery is observed, i.e., about 10 saturation units difference, depending on the oil properties even when both experiments are performed at miscible conditions using the same injected gas. 2- The performance of tertiary CO2 flood was adversely affected by the slug of immiscible gas injected. Therefore, it is not recommended to have immiscible gas injection before miscible gas injection. 3- Regardless of injected gas type, gas injection with similar IFTs achieved similar oil recovery. 4- During WAG experiments, s","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86906662","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}
Injection of cold fluid is injected into hot reservoirs and rocks undergo contraction due to temperature difference. This contrast in temperatures causes the in-situ stress to reduce considerably. When the Minimum Horizontal Stress (σhmin) falls below the Bottomhole Pressure (BHP) due to temperature changes, fractures may initiate and/or propagate. Fractures resulted from thermal processes is referred as Thermally Induced Fractures (TIFs). TIFs can cause highly non-uniform distribution of the injected water flow in the wellbores, reduction in the sweep efficiency, and early water breakthrough in the nearby production wells. The objective of this paper is to evaluate the effectiveness of Inflow Control Device (ICD) to mitigate these fractures in water injection wells. A real field history matched sector model with evidence of TIF occurrence is utilized in this paper using a 3D reservoir thermal simulator coupled with a 2D TIF model and a geomechanical model. The impact of different completions in injection well with TIF modelling under different scenarios is investigated. The added value of ICD was quantified and proved to be effective in controlling TIF initiation and propagation as well as in improving the wellbore flow performance. The selected ICD size should be neither too big (no control) nor too small (over-restriction of injection rate). TIFs mitigation method proposed in this paper is practical, efficient, and strongly contribute to the research aimed at improving waterflood performance in oil fields. Recommendations and guidelines can be utilized in waterflooding operations during modelling, designing, and planning stages.
{"title":"Evaluation of Inflow Control Device Effectiveness to Mitigate Thermally Induced Fractures in Injection Wells","authors":"Misfer J. Almarri","doi":"10.2118/200185-ms","DOIUrl":"https://doi.org/10.2118/200185-ms","url":null,"abstract":"\u0000 Injection of cold fluid is injected into hot reservoirs and rocks undergo contraction due to temperature difference. This contrast in temperatures causes the in-situ stress to reduce considerably. When the Minimum Horizontal Stress (σhmin) falls below the Bottomhole Pressure (BHP) due to temperature changes, fractures may initiate and/or propagate. Fractures resulted from thermal processes is referred as Thermally Induced Fractures (TIFs). TIFs can cause highly non-uniform distribution of the injected water flow in the wellbores, reduction in the sweep efficiency, and early water breakthrough in the nearby production wells. The objective of this paper is to evaluate the effectiveness of Inflow Control Device (ICD) to mitigate these fractures in water injection wells.\u0000 A real field history matched sector model with evidence of TIF occurrence is utilized in this paper using a 3D reservoir thermal simulator coupled with a 2D TIF model and a geomechanical model. The impact of different completions in injection well with TIF modelling under different scenarios is investigated.\u0000 The added value of ICD was quantified and proved to be effective in controlling TIF initiation and propagation as well as in improving the wellbore flow performance. The selected ICD size should be neither too big (no control) nor too small (over-restriction of injection rate).\u0000 TIFs mitigation method proposed in this paper is practical, efficient, and strongly contribute to the research aimed at improving waterflood performance in oil fields. Recommendations and guidelines can be utilized in waterflooding operations during modelling, designing, and planning stages.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86578696","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}
Pierre-Edouard Schreiber, Andrea Osorio Ochoa, Jean-Claude Hild, C. Prinet, M. Bourgeois, Amit Kumar
This paper is based on a study performed on an offshore Middle East field. The field is a giant complex mostly carbonate oil field, which is characterized by a thin oil column, a low permeability associated with fractures, a large transition zone and a lateral variation in fluid properties. Even after an extensive and efficient water-flood development, there are substantial amounts of oil remaining in the reservoir due to the highly oil-wet nature of the rock. Various Enhanced Oil Recovery (EOR) techniques have been envisaged to enhance oil production. The most mature one is the immiscible hydrocarbon Water Alternating Gas (WAG) injection. This High Pressure (HP)-WAG project started in September 2012 after the encouraging results of the continuous Low Pressure (LP) gas injection trial performed in 2008. This paper presents the latest analysis of the performances of this HP-WAG project. The HP-WAG project performances is evaluated through (i) the oil gain (versus a water-flood baseline), (ii) the water injectivity evolution over the WAG cycles, (iii) the gas management and (iv) the well and surface integrity. The paper also aims to share the methodology for analyzing the contribution of the main mechanisms occurring over the WAG cycles: the oil-gas interaction mechanisms and the desaturation mechanisms. The oil-gas interactions that occur in immiscible gas injection cases lead to significant long-lasting WAG effects thanks to both the swelling effects that continue even once the oil is saturated and a permanent mobility ratio improvement. The contribution of both macroscopic and microscopic oil desaturation is also described and quantified in this paper. The work presented in this paper has evidenced the HP-WAG technique benefits and has improved the understanding of the impacts of the main mechanism occurring in the reservoir. This knowledge paved the way towards more extensive WAG deployment on the field. It also emphasized the need of laboratory experiments to calibrate the three-phase models and the absolute need of compositional models to capture the entire WAG benefits even in immiscible gas injection cases.
{"title":"A Comprehensive Analysis of Water Alternating Gas Recovery Mechanisms in a Giant Middle East Field","authors":"Pierre-Edouard Schreiber, Andrea Osorio Ochoa, Jean-Claude Hild, C. Prinet, M. Bourgeois, Amit Kumar","doi":"10.2118/200067-ms","DOIUrl":"https://doi.org/10.2118/200067-ms","url":null,"abstract":"\u0000 This paper is based on a study performed on an offshore Middle East field. The field is a giant complex mostly carbonate oil field, which is characterized by a thin oil column, a low permeability associated with fractures, a large transition zone and a lateral variation in fluid properties. Even after an extensive and efficient water-flood development, there are substantial amounts of oil remaining in the reservoir due to the highly oil-wet nature of the rock. Various Enhanced Oil Recovery (EOR) techniques have been envisaged to enhance oil production. The most mature one is the immiscible hydrocarbon Water Alternating Gas (WAG) injection. This High Pressure (HP)-WAG project started in September 2012 after the encouraging results of the continuous Low Pressure (LP) gas injection trial performed in 2008.\u0000 This paper presents the latest analysis of the performances of this HP-WAG project. The HP-WAG project performances is evaluated through (i) the oil gain (versus a water-flood baseline), (ii) the water injectivity evolution over the WAG cycles, (iii) the gas management and (iv) the well and surface integrity. The paper also aims to share the methodology for analyzing the contribution of the main mechanisms occurring over the WAG cycles: the oil-gas interaction mechanisms and the desaturation mechanisms. The oil-gas interactions that occur in immiscible gas injection cases lead to significant long-lasting WAG effects thanks to both the swelling effects that continue even once the oil is saturated and a permanent mobility ratio improvement. The contribution of both macroscopic and microscopic oil desaturation is also described and quantified in this paper.\u0000 The work presented in this paper has evidenced the HP-WAG technique benefits and has improved the understanding of the impacts of the main mechanism occurring in the reservoir. This knowledge paved the way towards more extensive WAG deployment on the field. It also emphasized the need of laboratory experiments to calibrate the three-phase models and the absolute need of compositional models to capture the entire WAG benefits even in immiscible gas injection cases.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"115 2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83636250","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}
Enhanced Gas Recovery (EGR) is the process whereby an inert gas like nitrogen or flue gas is injected in a gas reservoir to improve hydrocarbon gas recovery. One of the objectives of EGR is recovery of remaining gas in place at the prevailing abandonment pressure by sweeping native hydrocarbon gas with an inert gas. This paper treats the reservoir engineering aspects of dispersion in gas displacement by nitrogen. Relevant theory and knowledge from literature are applied to an example sandstone gas reservoir. The displacement is typically miscible, and the higher viscosity and density of the injected nitrogen over the native hydrocarbon gas improves the stability of the vertical displacement front. However, dispersion in the reservoir is another potential source of spreading of the front. This leads to early nitrogen breakthrough and a slowly growing nitrogen concentration in the production stream that needs to be dealt with prior to sales through N2 removal or dilution of the produced gas with other gas streams. Reservoirs with low formation dispersivity are therefore the most suitable targets for EGR. This leads to the selection of homogeneous reservoirs with short correlation distances of depositional features. Formation dispersivity is ideally measured upfront using a tracer push-pull test. As a result of the physics of the dispersion process a line drive with a large displacement well spacing provides an optimum selection as (horizontal or vertical) well configuration. Selection of high viscosity injection gas helps to increase the stability of the displacement front. Stabilization of the injection front by foam would significantly enlarge the targeted group of fields for EGR to include reservoirs with more adverse heterogeneity. R&D is required to establish a likely reduction in dispersion. Accurate modelling of the mixing process is possible by tagging the injection fluid with a passive tracer while solving the advection equations explicitly using a higher order scheme to reduce numerical dispersion. Only physical dispersion at the sub-grid scale should be included. This modelling method could however lead to unstable displacement in the simulator because the density and viscosity contrasts are ignored.
{"title":"The Role of Dispersion in Enhanced Gas Recovery and Gas Field Pressure Maintenance","authors":"Johan J. Van Dorp","doi":"10.2118/200261-ms","DOIUrl":"https://doi.org/10.2118/200261-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Enhanced Gas Recovery (EGR) is the process whereby an inert gas like nitrogen or flue gas is injected in a gas reservoir to improve hydrocarbon gas recovery. One of the objectives of EGR is recovery of remaining gas in place at the prevailing abandonment pressure by sweeping native hydrocarbon gas with an inert gas.\u0000 This paper treats the reservoir engineering aspects of dispersion in gas displacement by nitrogen.\u0000 \u0000 \u0000 \u0000 Relevant theory and knowledge from literature are applied to an example sandstone gas reservoir.\u0000 \u0000 \u0000 \u0000 The displacement is typically miscible, and the higher viscosity and density of the injected nitrogen over the native hydrocarbon gas improves the stability of the vertical displacement front. However, dispersion in the reservoir is another potential source of spreading of the front. This leads to early nitrogen breakthrough and a slowly growing nitrogen concentration in the production stream that needs to be dealt with prior to sales through N2 removal or dilution of the produced gas with other gas streams. Reservoirs with low formation dispersivity are therefore the most suitable targets for EGR. This leads to the selection of homogeneous reservoirs with short correlation distances of depositional features. Formation dispersivity is ideally measured upfront using a tracer push-pull test. As a result of the physics of the dispersion process a line drive with a large displacement well spacing provides an optimum selection as (horizontal or vertical) well configuration. Selection of high viscosity injection gas helps to increase the stability of the displacement front.\u0000 \u0000 \u0000 \u0000 Stabilization of the injection front by foam would significantly enlarge the targeted group of fields for EGR to include reservoirs with more adverse heterogeneity. R&D is required to establish a likely reduction in dispersion.\u0000 Accurate modelling of the mixing process is possible by tagging the injection fluid with a passive tracer while solving the advection equations explicitly using a higher order scheme to reduce numerical dispersion. Only physical dispersion at the sub-grid scale should be included. This modelling method could however lead to unstable displacement in the simulator because the density and viscosity contrasts are ignored.\u0000","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87957531","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}
Pub Date : 1986-12-31DOI: 10.1515/9783112494721-018
E. Kolley, W. Kolley
{"title":"Fokker-Planck Equation in the Spin-Glass Dynamics","authors":"E. Kolley, W. Kolley","doi":"10.1515/9783112494721-018","DOIUrl":"https://doi.org/10.1515/9783112494721-018","url":null,"abstract":"","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"51 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"1986-12-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79991867","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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