M. A. Hryc, Daniela Verónica Renta, G. Dupuis, T. Leblanc, Maria Eugenia Peyrebonne Bispe, Mayra Goldman, M. Villambrosa, Gaston Fondevila Sancet
This paper presents the results obtained during the first thermo-responsive polymer field evaluation carried out in Pampa del Castillo – La Guitarra field located in Golfo San Jorge basin, Chubut province, Argentina. For the selected reservoir conditions, two thermo-responsive (TR) polymers with the same backbone and different moieties content (TR 1 and TR 2) were designed as alternatives to the conventional HPAM polymer currently injected in the field. TR polymers are aimed to be injected at low concentration and low viscosities under surface conditions and are characterized by an activation temperature. Below this temperature threshold, they behave like regular HPAMs whereas above it they behave like associative polymers. In contrast to HPAMs, higher resistance factors are obtained with increasing temperature beyond the activation threshold, which would be achieved at reservoir conditions. TR 1, TR 2 and a selected HPAM were injected in the same well and same layer, under the same conditions during a polymer injectivity test (PIT) in order to compare their performances. The evaluation was done in a multilayer, 80°C - temperature reservoir showing permeabilities around 20 mD. This reservoir had been waterflooded for 32 years before polymer injection started. The test was carried out using a compact polymer injection unit (PIUC) for 60 days involving TR 1, TR 2 and HPAM injection at different concentrations and flow rates, previously defined to target similar mobility reduction (Rm – also called Resistance Factor, ReF) according to coreflood experiences. Fall-off tests were run prior to, during and after polymer injection to assess changes in the well injectivity. Along with the operation, laboratory tests were carried out on site to monitor water and polymer solution parameters. TR 1 and TR 2 polymers showed good injectivity, stable rheological properties and good performance during the injection test at all concentration values and flow rates. Well head pressure (WHP) recorded with TR 2 was higher than with TR 1, in accordance with the number of thermo-responsive moieties in each polymer formulation. TR polymers demonstrated to be purely shear-thinning while HPAM showed shear-thickening behavior in near wellbore conditions. These results indicate promising cost reduction that can be achieved through a concentration cut-back of 67%, while sustaining similar resistance factors under reservoir conditions. The present article will elaborate on the first results of an injectivity test of thermo-responsive polymer technology conducted in Argentina.
本文介绍了在阿根廷Chubut省Golfo San Jorge盆地Pampa del Castillo - La Guitarra油田进行的首次热响应性聚合物油田评价的结果。针对选定的储层条件，设计了两种具有相同主链但不同组分含量的热响应聚合物(TR 1和TR 2)，作为目前油田注入的常规HPAM聚合物的替代品。TR聚合物的目标是在表面条件下以低浓度和低粘度注入，并以激活温度为特征。低于这个温度阈值，它们表现得像普通的hpam，而高于这个温度阈值，它们表现得像结合聚合物。与hpam相比，当温度超过激活阈值时，电阻系数会更高，这在油藏条件下可以实现。在聚合物注入测试(PIT)中，在相同的条件下，将TR 1、TR 2和选定的HPAM注入同一井、同一层，以比较它们的性能。该评价是在一个80°C的多层储层中进行的，渗透率约为20md。该储层在开始注入聚合物之前已经水淹了32年。测试使用紧凑型聚合物注射单元(PIUC)进行，为期60天，包括以不同浓度和流速注射TR 1、TR 2和HPAM，根据岩心驱油经验，之前定义的目标是相似的迁移率降低(Rm -也称为阻力系数，ReF)。在注入聚合物之前、期间和之后分别进行了脱落测试，以评估井注入能力的变化。随着操作的进行，在现场进行了实验室测试，以监测水和聚合物溶液的参数。在所有浓度和流量下，tr1和tr2聚合物均表现出良好的注入性、稳定的流变性能和良好的注入性能。根据每种聚合物配方中热响应基团的数量，使用TR 2记录的井口压力(WHP)高于使用TR 1记录的井口压力。在近井条件下，TR聚合物表现出纯粹的剪切减薄行为，而HPAM表现出剪切增厚行为。这些结果表明，通过降低浓度67%，可以实现成本降低，同时在油藏条件下保持相似的阻力系数。本文将详细介绍在阿根廷进行的热敏聚合物技术注入测试的初步结果。
{"title":"First Thermo-Responsive Polymer Field Evaluation in a High Temperature Reservoir of Golfo San Jorge, Argentina. Promising Results for Cost Optimization in a Polymer Project","authors":"M. A. Hryc, Daniela Verónica Renta, G. Dupuis, T. Leblanc, Maria Eugenia Peyrebonne Bispe, Mayra Goldman, M. Villambrosa, Gaston Fondevila Sancet","doi":"10.2118/209383-ms","DOIUrl":"https://doi.org/10.2118/209383-ms","url":null,"abstract":"\u0000 This paper presents the results obtained during the first thermo-responsive polymer field evaluation carried out in Pampa del Castillo – La Guitarra field located in Golfo San Jorge basin, Chubut province, Argentina. For the selected reservoir conditions, two thermo-responsive (TR) polymers with the same backbone and different moieties content (TR 1 and TR 2) were designed as alternatives to the conventional HPAM polymer currently injected in the field. TR polymers are aimed to be injected at low concentration and low viscosities under surface conditions and are characterized by an activation temperature. Below this temperature threshold, they behave like regular HPAMs whereas above it they behave like associative polymers. In contrast to HPAMs, higher resistance factors are obtained with increasing temperature beyond the activation threshold, which would be achieved at reservoir conditions.\u0000 TR 1, TR 2 and a selected HPAM were injected in the same well and same layer, under the same conditions during a polymer injectivity test (PIT) in order to compare their performances. The evaluation was done in a multilayer, 80°C - temperature reservoir showing permeabilities around 20 mD. This reservoir had been waterflooded for 32 years before polymer injection started. The test was carried out using a compact polymer injection unit (PIUC) for 60 days involving TR 1, TR 2 and HPAM injection at different concentrations and flow rates, previously defined to target similar mobility reduction (Rm – also called Resistance Factor, ReF) according to coreflood experiences. Fall-off tests were run prior to, during and after polymer injection to assess changes in the well injectivity. Along with the operation, laboratory tests were carried out on site to monitor water and polymer solution parameters.\u0000 TR 1 and TR 2 polymers showed good injectivity, stable rheological properties and good performance during the injection test at all concentration values and flow rates. Well head pressure (WHP) recorded with TR 2 was higher than with TR 1, in accordance with the number of thermo-responsive moieties in each polymer formulation. TR polymers demonstrated to be purely shear-thinning while HPAM showed shear-thickening behavior in near wellbore conditions. These results indicate promising cost reduction that can be achieved through a concentration cut-back of 67%, while sustaining similar resistance factors under reservoir conditions.\u0000 The present article will elaborate on the first results of an injectivity test of thermo-responsive polymer technology conducted in Argentina.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"86 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72891392","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 focuses on proper modeling of bypassed oil in tight chalk during gas injection, caused partly by the small-scale heterogeneity and the non-equilibrium contact especially in low permeable chalk. Conventional compositional simulators using the local equilibrium assumption tend to predict excessive vaporization of the residual oil. We present the laboratory gas flooding results in tight chalk and discuss how different non-equilibrium treatments can provide more realistic simulation results. Composite core flooding experiments with low-permeable tight chalk and natural gas were conducted at different pressures below the minimum miscibility pressure of the live oil used. The ECLIPSE compositional simulator E300, using an EoS model tuned with the swelling data, was used to history match the results. It was found that the simulation without considering non-equilibrium effects over-predicted the oil production in the late stage. Two methods were tested to avoid the excessive vaporization of oil: the Sorm method (excluding the residual oil from flash calculations) and the transport coefficients (alpha factors) method together with pseudo-relative permeability curves. Our results show that the sub-grid non-equilibrium effect is significant in tight chalk. Compositional simulation without considering this effect leads to unrestricted vaporization and over-prediction of the oil recovery in gas injection into tight chalk even for laboratory experiments. Both methods tested here are suitable for reproducing the flooding results, in particular, the residual oil in the late stage. For the experiments studied here, the Sorm method seems to show a better performance in maintaining no further mass transfer between the residual oil and gas after the ultimate recovery is reached, since it excludes the bypassed oil fraction from flash calculations and models the immobile saturation explicitly. For the alpha factors method, oil production keeps a slow increase at the late stage as long as gas is being injected. In addition, the use of pseudo-relative permeability method can lead to obtaining irrational trends in some cases. We therefore propose an alternative method by adjusting the alpha factors of the mobile components, which avoids the difficulties of modifying the relative permeability curves. This study contributes to the methodology on honoring the non-equilibrium effects and obtaining realistic residual oil saturation for gas injection in tight formation. The proposed method of adjusting the non-zero alpha factors can be used as an alternative to using pseudo-relative permeability, which avoids the possible drawbacks involved in this method.
{"title":"Modeling of Laboratory Gas Flooding in Tight Chalk with Different Non-Equilibrium Treatments","authors":"S. Mirazimi, D. Olsen, E. Stenby, Wei Yan","doi":"10.2118/209367-ms","DOIUrl":"https://doi.org/10.2118/209367-ms","url":null,"abstract":"\u0000 This paper focuses on proper modeling of bypassed oil in tight chalk during gas injection, caused partly by the small-scale heterogeneity and the non-equilibrium contact especially in low permeable chalk. Conventional compositional simulators using the local equilibrium assumption tend to predict excessive vaporization of the residual oil. We present the laboratory gas flooding results in tight chalk and discuss how different non-equilibrium treatments can provide more realistic simulation results.\u0000 Composite core flooding experiments with low-permeable tight chalk and natural gas were conducted at different pressures below the minimum miscibility pressure of the live oil used. The ECLIPSE compositional simulator E300, using an EoS model tuned with the swelling data, was used to history match the results. It was found that the simulation without considering non-equilibrium effects over-predicted the oil production in the late stage. Two methods were tested to avoid the excessive vaporization of oil: the Sorm method (excluding the residual oil from flash calculations) and the transport coefficients (alpha factors) method together with pseudo-relative permeability curves.\u0000 Our results show that the sub-grid non-equilibrium effect is significant in tight chalk. Compositional simulation without considering this effect leads to unrestricted vaporization and over-prediction of the oil recovery in gas injection into tight chalk even for laboratory experiments. Both methods tested here are suitable for reproducing the flooding results, in particular, the residual oil in the late stage. For the experiments studied here, the Sorm method seems to show a better performance in maintaining no further mass transfer between the residual oil and gas after the ultimate recovery is reached, since it excludes the bypassed oil fraction from flash calculations and models the immobile saturation explicitly. For the alpha factors method, oil production keeps a slow increase at the late stage as long as gas is being injected. In addition, the use of pseudo-relative permeability method can lead to obtaining irrational trends in some cases. We therefore propose an alternative method by adjusting the alpha factors of the mobile components, which avoids the difficulties of modifying the relative permeability curves.\u0000 This study contributes to the methodology on honoring the non-equilibrium effects and obtaining realistic residual oil saturation for gas injection in tight formation. The proposed method of adjusting the non-zero alpha factors can be used as an alternative to using pseudo-relative permeability, which avoids the possible drawbacks involved in this method.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74244319","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}
Many conventional surfactant-brine-oil phase behavior tests are conducted under ambient pressure conditions without the solution gas. It is known that the solution gas lowers the optimum salinity. Researchers often mix toluene (or cyclohexane) with the dead oil and form a surrogate oil to mimic the live oil. The objective of our work is to study the effect of gas and toluene on phase behavior, and to provide the proper amount of toluene to be mixed to mimic the live oil. Effects of toluene in surrogate oil and solution gas in live oil are examined by hydrophilic-lipophilic difference and net average curvature (HLD-NAC) structural model simulation and the equivalent alkane carbon number (EACN). Experimental values from literature and our experiments are also examined to compare those with the simulation results. For the simulation, both the mole fraction and mass fraction were used to calculate mixture EACN and examine the effect of additional components. HLD-NAC simulation results showed that the mass fraction-based simulation is more accurate (~7% error) than mole fraction-based simulation (~19% error) with a toluene EACN of 1. For larger molecules like toluene in surrogate oil, EACN using mole fraction also works with a toluene EACN of 5.2. The EACN of the surrogate oil should match the EACN of the live oil to determine the proper amount of toluene in the surrogate oil.
{"title":"Design of Surrogate Oils for Surfactant-Brine-Oil Phase Behavior","authors":"Jaebum Park, K. Mohanty","doi":"10.2118/209427-ms","DOIUrl":"https://doi.org/10.2118/209427-ms","url":null,"abstract":"\u0000 Many conventional surfactant-brine-oil phase behavior tests are conducted under ambient pressure conditions without the solution gas. It is known that the solution gas lowers the optimum salinity. Researchers often mix toluene (or cyclohexane) with the dead oil and form a surrogate oil to mimic the live oil. The objective of our work is to study the effect of gas and toluene on phase behavior, and to provide the proper amount of toluene to be mixed to mimic the live oil. Effects of toluene in surrogate oil and solution gas in live oil are examined by hydrophilic-lipophilic difference and net average curvature (HLD-NAC) structural model simulation and the equivalent alkane carbon number (EACN). Experimental values from literature and our experiments are also examined to compare those with the simulation results. For the simulation, both the mole fraction and mass fraction were used to calculate mixture EACN and examine the effect of additional components. HLD-NAC simulation results showed that the mass fraction-based simulation is more accurate (~7% error) than mole fraction-based simulation (~19% error) with a toluene EACN of 1. For larger molecules like toluene in surrogate oil, EACN using mole fraction also works with a toluene EACN of 5.2. The EACN of the surrogate oil should match the EACN of the live oil to determine the proper amount of toluene in the surrogate oil.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"32 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89976303","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}
Miguel Gonzalez, S. Ayirala, Lyla Maskeen, A. Sofi
There are currently no technologies available to measure polymer solution viscosities at realistic downhole conditions in a well during enhanced oil recovery (EOR). In this paper, custom-made probes using quartz tuning fork (QTF) resonators are demonstrated for measurements of viscosity of polymer fluids. The electromechanical response of the resonators was calibrated in simple Newtonian fluids and in non-Newtonian polymer fluids at different concentrations. The responses were then used to measure field-collected samples of polymer injection fluids. The measured viscosity values by tuning forks were lower than those measured by the conventional rheometer at 6.8 s-1, indicating the effect of viscoelasticity of the fluid. However, the predicted rheometer viscosity versus QTF measured viscosity showed a perfect exponential correlation, allowing for calibration between the two viscometers. The QTF sensors were shown to successfully produce accurate viscosity measurements of polymer fluids within the required polymer concentration ranges used in the field, and predicted field sample viscosities with less than 5% error from the rheometer data. These devices can be easily integrated into portable systems for lab or wellsite deployment as well as logging tools for downhole deployment.
{"title":"Miniature Viscosity Sensors for EOR Polymer Fluids","authors":"Miguel Gonzalez, S. Ayirala, Lyla Maskeen, A. Sofi","doi":"10.2118/209430-ms","DOIUrl":"https://doi.org/10.2118/209430-ms","url":null,"abstract":"\u0000 There are currently no technologies available to measure polymer solution viscosities at realistic downhole conditions in a well during enhanced oil recovery (EOR). In this paper, custom-made probes using quartz tuning fork (QTF) resonators are demonstrated for measurements of viscosity of polymer fluids. The electromechanical response of the resonators was calibrated in simple Newtonian fluids and in non-Newtonian polymer fluids at different concentrations. The responses were then used to measure field-collected samples of polymer injection fluids. The measured viscosity values by tuning forks were lower than those measured by the conventional rheometer at 6.8 s-1, indicating the effect of viscoelasticity of the fluid. However, the predicted rheometer viscosity versus QTF measured viscosity showed a perfect exponential correlation, allowing for calibration between the two viscometers. The QTF sensors were shown to successfully produce accurate viscosity measurements of polymer fluids within the required polymer concentration ranges used in the field, and predicted field sample viscosities with less than 5% error from the rheometer data. These devices can be easily integrated into portable systems for lab or wellsite deployment as well as logging tools for downhole deployment.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"2006 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88134506","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}
Residual Oil Zone (ROZ) refers to a formation whose discovery saturation equals the rock's residual oil saturation. The ROZ makes up an excellent target for CO2 flooding since this oil is immovable by primary and secondary production processes. The San Andres ROZ has been recognized as an extensive residual oil saturated fairway in the Permian created during the Leonardian uplift, which caused spillage from the natural traps (Melzer, 2006). It has been developed through CO2 flooding in several fields across the Permian, including the Denver Unit in the Wasson San Andres formation, where it was developed years after the Main Oil Column (MOC). Both zones are producing from commingled producers and are flooded by commingled or dedicated injectors. This commingled configuration presents a challenge in discerning the production coming from each zone. In this paper, we will present an analytical approach to distinguish between MOC and ROZ production without the need for numerical simulation or costly well interventions such as production logging or zonal isolation. A sector of the Denver Unit's CO2 flood was used as an example in this paper. Dimensionless analysis, which entails normalizing production and injection to the target pore volume, was used along with the Pulser process (Liu, Sahni, and Hsu, 2014; informal communication with Deepak Gupta, 2019) to history-match MOC production and then extrapolate it using zonal injection obtained from injection profile logs. This calculated MOC production is then subtracted from the total production to calculate ROZ production, with its dimensionless response function fitted with Pulser for forecasting. Additionally, a fully compositional numerical simulation of the same area was history-matched and used to validate the approach mentioned above. The results of the analytical approach showed excellent agreement with the numerical simulation results and with historical performance through multiple years. A few challenges presented themselves, such as pattern-to-pattern interference, the quality of injection profile logs, and pattern reconfigurations, which we will discuss below along with limitations and assumptions that must be considered when using this approach. The methodology presented in this paper presents a simple method to allocate and forecast MOC and ROZ performance individually despite changes in injection throughput, based on injection distribution without the need for complex simulation or costly well configuration. This approach could also be applied to any commingled flood that meets the criteria outlined in this paper.
剩余油带是指发现饱和度等于岩石剩余油饱和度的地层。ROZ是二氧化碳驱油的绝佳目标，因为这种油在一次和二次生产过程中都是不可移动的。San Andres ROZ被认为是在Leonardian隆起期间形成的二叠纪广泛的残余油饱和通道，导致天然圈闭溢出(Melzer, 2006)。在二叠纪盆地的几个油田，包括Wasson San Andres地层的Denver单元，它是在主油柱(MOC)开发多年后开发的。这两个区域都是由混合生产商生产的，并由混合或专用注入器进行注水。这种混合结构给识别每个层的产出带来了挑战。在本文中，我们将提出一种分析方法来区分MOC和ROZ产量，而不需要数值模拟或昂贵的油井干预措施，如生产测井或层间隔离。本文以丹佛机组某部门的CO2洪水为例。无因次分析，需要将生产和注入到目标孔隙体积，与Pulser工艺一起使用(Liu, Sahni, and Hsu, 2014;与Deepak Gupta(2019年)进行非正式沟通，以匹配MOC产量的历史数据，然后使用从注入剖面测井中获得的分层注入进行推断。然后将计算出的MOC产量从总产量中减去，计算出ROZ产量，并将其无因次响应函数拟合为Pulser进行预测。此外，对同一区域进行了历史匹配的全成分数值模拟，并用于验证上述方法。分析方法的结果与数值模拟结果和多年来的历史性能具有很好的一致性。一些挑战出现了，比如模式对模式的干扰、注入剖面日志的质量和模式重新配置，我们将在下面讨论这些问题，以及使用这种方法时必须考虑的限制和假设。本文提出的方法提供了一种简单的方法，可以根据注入分布分别分配和预测MOC和ROZ性能，而不需要复杂的模拟或昂贵的井配置。这种方法也可以应用于任何符合本文概述的标准的混合型洪水。
{"title":"Analytical Method for Forecasting ROZ Production in a Commingled MOC and ROZ CO2 Flood","authors":"D. W. Hampton, Ahmed Wagia-Alla","doi":"10.2118/209365-ms","DOIUrl":"https://doi.org/10.2118/209365-ms","url":null,"abstract":"\u0000 Residual Oil Zone (ROZ) refers to a formation whose discovery saturation equals the rock's residual oil saturation. The ROZ makes up an excellent target for CO2 flooding since this oil is immovable by primary and secondary production processes. The San Andres ROZ has been recognized as an extensive residual oil saturated fairway in the Permian created during the Leonardian uplift, which caused spillage from the natural traps (Melzer, 2006). It has been developed through CO2 flooding in several fields across the Permian, including the Denver Unit in the Wasson San Andres formation, where it was developed years after the Main Oil Column (MOC). Both zones are producing from commingled producers and are flooded by commingled or dedicated injectors. This commingled configuration presents a challenge in discerning the production coming from each zone. In this paper, we will present an analytical approach to distinguish between MOC and ROZ production without the need for numerical simulation or costly well interventions such as production logging or zonal isolation.\u0000 A sector of the Denver Unit's CO2 flood was used as an example in this paper. Dimensionless analysis, which entails normalizing production and injection to the target pore volume, was used along with the Pulser process (Liu, Sahni, and Hsu, 2014; informal communication with Deepak Gupta, 2019) to history-match MOC production and then extrapolate it using zonal injection obtained from injection profile logs. This calculated MOC production is then subtracted from the total production to calculate ROZ production, with its dimensionless response function fitted with Pulser for forecasting. Additionally, a fully compositional numerical simulation of the same area was history-matched and used to validate the approach mentioned above.\u0000 The results of the analytical approach showed excellent agreement with the numerical simulation results and with historical performance through multiple years. A few challenges presented themselves, such as pattern-to-pattern interference, the quality of injection profile logs, and pattern reconfigurations, which we will discuss below along with limitations and assumptions that must be considered when using this approach.\u0000 The methodology presented in this paper presents a simple method to allocate and forecast MOC and ROZ performance individually despite changes in injection throughput, based on injection distribution without the need for complex simulation or costly well configuration. This approach could also be applied to any commingled flood that meets the criteria outlined in this paper.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91134337","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}
Conformance control via near-wellbore mechanical and chemical treatments is well established. However, for extreme heterogeneities, effective conformance control mandates deep treatments. Such deep treatments or diversion would sustain sweep enhancement far from wells, deep into the reservoir. Deep diversion is even more mandatory for enhanced oil recovery (EOR) to assure the expensive injectants optimally contact the remaining oil. In this paper, we comprehensively present efforts to research, develop, and trial a crosslinked-gel system for deep diversion. We started by reviewing conformance control options including crosslinked systems. The review supported the immaturity of deep conformance control. Various gel-based solutions, especially preformed particle gels (PPGs) and colloidal dispersed gels (CDGs), were proposed; however, diversion effects were not clearly illustrated. For crosslinked-gels, all systems exhibited fast gelation, something suitable for near-wellbore treatments. We then studied the key crosslinked systems. We characterized their behavior using rheometry, bottle tests, and single-phase corefloods. We assessed their potential through oil-displacement corefloods in artificially fractured cores with and without in-situ imaging. In-house studies, on key gel systems demonstrated the feasibility of gels to affect diversion and enhance recovery but corroborated the extreme challenge to design systems with delayed gelation. To assure representative gelation, we developed, and utilized a continuous bi-directional injection protocol to assess gelation times in-situ. From there, we collaboratively developed, and characterized a unique delayed-gelation formulation. The collaborative study addressed this challenge where systems with delayed gelation were developed. In-situ gelation time estimation confirmed this delayed gelation capacity. Further corefloods addressed the key uncertainties including injectivity losses, limited propagation, and ineffective blockage. Simulations were performed to assess the process feasibility.The simulation studies supported the utility of deep diversion treatments. Simulation also guided the initial design of a trial. We focused on the design of a practical field trial.For further derisking, the first trial was optimized to serve as a practical proof-of-concept. Taking into account economics, success measurement, flow assurance, and depth of placement, we diverged from a trial where we observe deep diversion (and infer delayed gelation and effective blockage) then converged into a trial where we infer deep diversion (by observing delayed gelation and effective blockage). With that, we screened candidates with a clear hierarchy of screening criteria. Through this program, and for the first-time in the industry, we demonstrate the potential utility and feasibility of a crosslinked-gel system for deep diversion applications. This potential is supported by comprehensive experimentation including novel in-
{"title":"Toward Deep Diversion for Waterflooding and EOR: From Representative Delayed Gelation to Practical Field-Trial Design","authors":"A. AlSofi, W. Dokhon","doi":"10.2118/209457-ms","DOIUrl":"https://doi.org/10.2118/209457-ms","url":null,"abstract":"\u0000 Conformance control via near-wellbore mechanical and chemical treatments is well established. However, for extreme heterogeneities, effective conformance control mandates deep treatments. Such deep treatments or diversion would sustain sweep enhancement far from wells, deep into the reservoir. Deep diversion is even more mandatory for enhanced oil recovery (EOR) to assure the expensive injectants optimally contact the remaining oil. In this paper, we comprehensively present efforts to research, develop, and trial a crosslinked-gel system for deep diversion.\u0000 We started by reviewing conformance control options including crosslinked systems. The review supported the immaturity of deep conformance control. Various gel-based solutions, especially preformed particle gels (PPGs) and colloidal dispersed gels (CDGs), were proposed; however, diversion effects were not clearly illustrated. For crosslinked-gels, all systems exhibited fast gelation, something suitable for near-wellbore treatments. We then studied the key crosslinked systems. We characterized their behavior using rheometry, bottle tests, and single-phase corefloods. We assessed their potential through oil-displacement corefloods in artificially fractured cores with and without in-situ imaging. In-house studies, on key gel systems demonstrated the feasibility of gels to affect diversion and enhance recovery but corroborated the extreme challenge to design systems with delayed gelation. To assure representative gelation, we developed, and utilized a continuous bi-directional injection protocol to assess gelation times in-situ. From there, we collaboratively developed, and characterized a unique delayed-gelation formulation. The collaborative study addressed this challenge where systems with delayed gelation were developed. In-situ gelation time estimation confirmed this delayed gelation capacity. Further corefloods addressed the key uncertainties including injectivity losses, limited propagation, and ineffective blockage. Simulations were performed to assess the process feasibility.The simulation studies supported the utility of deep diversion treatments. Simulation also guided the initial design of a trial. We focused on the design of a practical field trial.For further derisking, the first trial was optimized to serve as a practical proof-of-concept. Taking into account economics, success measurement, flow assurance, and depth of placement, we diverged from a trial where we observe deep diversion (and infer delayed gelation and effective blockage) then converged into a trial where we infer deep diversion (by observing delayed gelation and effective blockage). With that, we screened candidates with a clear hierarchy of screening criteria.\u0000 Through this program, and for the first-time in the industry, we demonstrate the potential utility and feasibility of a crosslinked-gel system for deep diversion applications. This potential is supported by comprehensive experimentation including novel in-","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82328703","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}
Water is accumulated near the fracture surface after fracturing, which will block oil flow out. The water blockage can be mitigated through the immediate well flow back or through shutting in the well before flow back. Which method is more effective? There are mixed results in the literature from field reports and experimental or simulation studies. This paper discussed the literature results and simulation data obtained from this study. It is found that the oil recovery mainly depends on the magnitude of pressure drawdown and the strength of imbibition. When the pressure drawdown is high, immediate flow back may lead to higher oil recovery than shutting in a well before flow back. When imbibition is strong, shutting in may be beneficial to enhance oil recovery through counter-current flow. Although many parameters of reservoir properties and operations may affect the shut-in effect, those parameters may be grouped into the pressure drawdown and imbibition strength. The parameters of matrix permeability, wettability, initial water saturation, and formation compressibility are discussed. Analysis and discussion of simulation data also suggest that the oil recovery is a linear function of pressure drawdown, but the relationship between oil recovery and capillary pressure is non-linear and more complex. The results and discussion from this study suggest that the immediate flow back may outperform the shut-in if a large pressure drawdown is applied. If a reservoir provides a strong imbibition condition, the shut-in may be beneficial. Surfactants may be chosen to enhance imbibition. The surfactants which alter the reservoir from oil-wet to water-wet may be preferred.
{"title":"Discussion of the Effect of Shut-In After Fracturing on Oil Recovery","authors":"J. Sheng, F. Zeng","doi":"10.2118/209436-ms","DOIUrl":"https://doi.org/10.2118/209436-ms","url":null,"abstract":"\u0000 Water is accumulated near the fracture surface after fracturing, which will block oil flow out. The water blockage can be mitigated through the immediate well flow back or through shutting in the well before flow back. Which method is more effective? There are mixed results in the literature from field reports and experimental or simulation studies.\u0000 This paper discussed the literature results and simulation data obtained from this study. It is found that the oil recovery mainly depends on the magnitude of pressure drawdown and the strength of imbibition. When the pressure drawdown is high, immediate flow back may lead to higher oil recovery than shutting in a well before flow back. When imbibition is strong, shutting in may be beneficial to enhance oil recovery through counter-current flow. Although many parameters of reservoir properties and operations may affect the shut-in effect, those parameters may be grouped into the pressure drawdown and imbibition strength. The parameters of matrix permeability, wettability, initial water saturation, and formation compressibility are discussed. Analysis and discussion of simulation data also suggest that the oil recovery is a linear function of pressure drawdown, but the relationship between oil recovery and capillary pressure is non-linear and more complex.\u0000 The results and discussion from this study suggest that the immediate flow back may outperform the shut-in if a large pressure drawdown is applied. If a reservoir provides a strong imbibition condition, the shut-in may be beneficial. Surfactants may be chosen to enhance imbibition. The surfactants which alter the reservoir from oil-wet to water-wet may be preferred.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79138325","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}
Cyclic injection-flowback (huff and puff, HnP) of natural gas or carbon dioxide has been shown to improve the recovery of oil from low permeability, low porosity shale reservoirs. However, natural gas and carbon dioxide are limited in effectiveness and utility; natural gas has a high miscibility pressure and high mobility and hence potential for leak-off and inter-well communication; carbon dioxide is not readily available, is costly, and corrosive. In this study, a novel shale oil HnP EOR process, utilising a liquid solvent comprised of mixtures of propane and butane (C3 and C4), referred to as SuperEORTM (Downey et al, 2021), was evaluated for its efficacy in recovering oil compared to methane and carbon dioxide. The advantages of the propane and butane solvent are its low miscibility pressure with the produced oil, it is injected as a liquid, and is easy to separate and recycle. In this study, an Eagle Ford shale core with produced Eagle Ford oil and a Permian Wolfcamp shale core with produced Wolfcamp oil were investigated. PVT and minimum miscibility tests of the fluids were combined with petrophysical analysis to design laboratory tests and provide metrics for tuning a compositional model. Two Eagle Ford facies were investigated, a calcite/quartz-rich mudstone/siltstone with a porosity of up to 10% and a calcite-rich limestone with porosity ranging from 3% to 6%. At reservoir stress, the matrix permeability averages about 2E-4 md. One facies of the Wolfcamp shale was tested, which is 80% quartz, has a porosity of about 7-11%, and average matrix permeability of 9E-3 md. SuperEOR was carried out on core plugs re-saturated with produced oil for 16 days at reservoir conditions of 5000 psi at 101°C for the Eagle Ford and 79°C for the Wolfcamp. For the Eagle Ford shale, five to 6 HnP cycles using a 1:1 ratio of C3 and C4, at injection pressures of 5000 and 3000 psi, with 20 hours of soaking per cycle, yielded a recovery of 55% to 75% of the original oil in place (OOIP) for the lower porosity facies and over 80% for the higher porosity facies of the Eagle Ford. For the Wolfcamp shale, at an injection pressure of 3000 psi, 85% of the original oil in place was recovered using 1:1 ratio of C3 and C4. In comparison, the Wolfcamp shale, at similar experiment conditions and number of HnP cycles, yielded about 30% of the OOIP when methane was used as an injectant/solvent and yielded 75% of OOIP when carbon dioxide was used. The efficacy of the HnP process on the Eagle Ford shale at the core scale was investigated through reservoir modelling using a general equation-of-state compositional simulator and the results were compared to the laboratory data and a field scale EOR simulation on three horizontal wells using carbon dioxide, methane, and the C3:C4 solvent. The wells had a production rate of <3 bbl/day prior to shut-in and responded poorly to natural gas HnP EOR due to excessive leak-off. The HnP simulations comprise cycling 23 days of injection f
{"title":"Laboratory Analyses and Compositional Simulation of the Eagle Ford and Wolfcamp Shales: A Novel Shale Oil EOR Process","authors":"A. Bustin, R. Bustin, R. Downey, K. Venepalli","doi":"10.2118/209348-ms","DOIUrl":"https://doi.org/10.2118/209348-ms","url":null,"abstract":"\u0000 Cyclic injection-flowback (huff and puff, HnP) of natural gas or carbon dioxide has been shown to improve the recovery of oil from low permeability, low porosity shale reservoirs. However, natural gas and carbon dioxide are limited in effectiveness and utility; natural gas has a high miscibility pressure and high mobility and hence potential for leak-off and inter-well communication; carbon dioxide is not readily available, is costly, and corrosive. In this study, a novel shale oil HnP EOR process, utilising a liquid solvent comprised of mixtures of propane and butane (C3 and C4), referred to as SuperEORTM (Downey et al, 2021), was evaluated for its efficacy in recovering oil compared to methane and carbon dioxide. The advantages of the propane and butane solvent are its low miscibility pressure with the produced oil, it is injected as a liquid, and is easy to separate and recycle.\u0000 In this study, an Eagle Ford shale core with produced Eagle Ford oil and a Permian Wolfcamp shale core with produced Wolfcamp oil were investigated. PVT and minimum miscibility tests of the fluids were combined with petrophysical analysis to design laboratory tests and provide metrics for tuning a compositional model. Two Eagle Ford facies were investigated, a calcite/quartz-rich mudstone/siltstone with a porosity of up to 10% and a calcite-rich limestone with porosity ranging from 3% to 6%. At reservoir stress, the matrix permeability averages about 2E-4 md. One facies of the Wolfcamp shale was tested, which is 80% quartz, has a porosity of about 7-11%, and average matrix permeability of 9E-3 md. SuperEOR was carried out on core plugs re-saturated with produced oil for 16 days at reservoir conditions of 5000 psi at 101°C for the Eagle Ford and 79°C for the Wolfcamp. For the Eagle Ford shale, five to 6 HnP cycles using a 1:1 ratio of C3 and C4, at injection pressures of 5000 and 3000 psi, with 20 hours of soaking per cycle, yielded a recovery of 55% to 75% of the original oil in place (OOIP) for the lower porosity facies and over 80% for the higher porosity facies of the Eagle Ford. For the Wolfcamp shale, at an injection pressure of 3000 psi, 85% of the original oil in place was recovered using 1:1 ratio of C3 and C4. In comparison, the Wolfcamp shale, at similar experiment conditions and number of HnP cycles, yielded about 30% of the OOIP when methane was used as an injectant/solvent and yielded 75% of OOIP when carbon dioxide was used.\u0000 The efficacy of the HnP process on the Eagle Ford shale at the core scale was investigated through reservoir modelling using a general equation-of-state compositional simulator and the results were compared to the laboratory data and a field scale EOR simulation on three horizontal wells using carbon dioxide, methane, and the C3:C4 solvent. The wells had a production rate of <3 bbl/day prior to shut-in and responded poorly to natural gas HnP EOR due to excessive leak-off. The HnP simulations comprise cycling 23 days of injection f","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75889624","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}
K. Kaprielova, M. Yutkin, Ahmed Gmira, S. Ayirala, C. Radke, T. Patzek
Spontaneous counter-current imbibition in Amott cell experiments is a convenient laboratory method of studying oil recovery from oil-saturated rock samples in secondary or tertiary oil recovery by waterflood of adjustable composition. Classical Amott cell experiment estimates ultimate oil recovery. It is not designed, however, for studying the dynamics of oil recovery. In this work we identify a flaw in the classical Amott cell imbibition experiments that hinders the development of predictive recovery models for mixed-wet carbonates. We revise the standard Amott procedure in order to produce smoother experimental production curves, which then can be described by a mathematical model more accurately. We apply Generalized Extreme Value distribution to model the cumulative oil production. We start with the Amott imbibition experiments and scaling analysis for Indiana limestone core plugs saturated with mineral oil. The knowledge gained from this study will allow us to develop a predictive model of water-oil displacement for reservoir carbonate rock and crude oil recovery systems.
{"title":"Improved Amott Cell Procedure for Predictive Modeling of Oil Recovery Dynamics from Mixed-Wet Carbonates","authors":"K. Kaprielova, M. Yutkin, Ahmed Gmira, S. Ayirala, C. Radke, T. Patzek","doi":"10.2118/209444-ms","DOIUrl":"https://doi.org/10.2118/209444-ms","url":null,"abstract":"\u0000 Spontaneous counter-current imbibition in Amott cell experiments is a convenient laboratory method of studying oil recovery from oil-saturated rock samples in secondary or tertiary oil recovery by waterflood of adjustable composition. Classical Amott cell experiment estimates ultimate oil recovery. It is not designed, however, for studying the dynamics of oil recovery. In this work we identify a flaw in the classical Amott cell imbibition experiments that hinders the development of predictive recovery models for mixed-wet carbonates. We revise the standard Amott procedure in order to produce smoother experimental production curves, which then can be described by a mathematical model more accurately. We apply Generalized Extreme Value distribution to model the cumulative oil production. We start with the Amott imbibition experiments and scaling analysis for Indiana limestone core plugs saturated with mineral oil. The knowledge gained from this study will allow us to develop a predictive model of water-oil displacement for reservoir carbonate rock and crude oil recovery systems.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82125278","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 methodology is presented for determining reaction kinetics from core flooding: A core is flooded with reactive brine at different compositions with injection rates varied systematically. Each combination is performed until steady state, when effluent concentrations no longer change significantly with time. Lower injection rate gives the brine more time to react. We also propose shut-in tests where brine reacts statically with the core a defined period and then is flushed out. The residence time and produced brine composition is compared with the flooding experiments. This design allows characterization of the reaction kinetics from a single core. Efficient modeling and matching of the experiments can be performed as the steady state data are directly comparable to equilibrating the injected brine gradually with time and does not require spatial and temporal modeling of the entire dynamic experiments. Each steady state data point represents different information that helps constrain parameter selection. The reaction kinetics can predict equilibrium states and time needed to reach equilibrium. Accounting for dispersion increases the complexity by needing to find a spatial distribution of coupled solutions and is recommended as a second step when a first estimate of the kinetics has been obtained. It is still much more efficient than simulating the full dynamic experiment. Experiments were performed injecting 0.0445 and 0.219 mol/L MgCl2 into Stevns Klint chalk from Denmark, and Kansas chalk from USA. The reaction kinetics of chalk are important as oil-bearing chalk reservoirs are chemically sensitive to injected seawater. The reactions can alter wettability and weaken rock strength which has implications for reservoir compaction, oil recovery and reservoir management. The temperature was 100 and 130°C (North Sea reservoir temperature). The rates during flooding were varied from 0.25 to 16 PV/d while shut-in tests provided equivalent rates down to 1/28 PV/d. The results showed that Ca2+ ions were produced and Mg2+ ions retained (associated with calcite dissolution and magnesite precipitation, respectively). This occurred in a substitution-like manner, where the gain of Ca was similar to the loss of Mg2+. A simple reaction kinetic model based on this substitution with three independent tuning parameters (rate coefficient, reaction order and equilibrium constant) was implemented together with advection to analytically calculate steady state effluent concentrations when injected composition, injection rate and reaction kinetic parameters were stated. By tuning reaction kinetic parameters, the experimental steady state data could be fitted efficiently. From data trends, the parameters were determined relatively accurate for each core. The roles of reaction parameters, pore velocity and dispersion were illustrated with sensitivity analyses. The steady state method allows computationally efficient matching even with complex reaction kinetics. Using
{"title":"Reaction Kinetics Determined from Core Flooding and Steady State Principles for Stevns Klint and Kansas Chalk Injected with MgCl2 Brine at Reservoir Temperature","authors":"P. Andersen, R. Korsnes, A. Olsen, Erik Bukkholm","doi":"10.2118/209380-ms","DOIUrl":"https://doi.org/10.2118/209380-ms","url":null,"abstract":"\u0000 A methodology is presented for determining reaction kinetics from core flooding: A core is flooded with reactive brine at different compositions with injection rates varied systematically. Each combination is performed until steady state, when effluent concentrations no longer change significantly with time. Lower injection rate gives the brine more time to react. We also propose shut-in tests where brine reacts statically with the core a defined period and then is flushed out. The residence time and produced brine composition is compared with the flooding experiments. This design allows characterization of the reaction kinetics from a single core. Efficient modeling and matching of the experiments can be performed as the steady state data are directly comparable to equilibrating the injected brine gradually with time and does not require spatial and temporal modeling of the entire dynamic experiments. Each steady state data point represents different information that helps constrain parameter selection. The reaction kinetics can predict equilibrium states and time needed to reach equilibrium. Accounting for dispersion increases the complexity by needing to find a spatial distribution of coupled solutions and is recommended as a second step when a first estimate of the kinetics has been obtained. It is still much more efficient than simulating the full dynamic experiment.\u0000 Experiments were performed injecting 0.0445 and 0.219 mol/L MgCl2 into Stevns Klint chalk from Denmark, and Kansas chalk from USA. The reaction kinetics of chalk are important as oil-bearing chalk reservoirs are chemically sensitive to injected seawater. The reactions can alter wettability and weaken rock strength which has implications for reservoir compaction, oil recovery and reservoir management. The temperature was 100 and 130°C (North Sea reservoir temperature). The rates during flooding were varied from 0.25 to 16 PV/d while shut-in tests provided equivalent rates down to 1/28 PV/d. The results showed that Ca2+ ions were produced and Mg2+ ions retained (associated with calcite dissolution and magnesite precipitation, respectively). This occurred in a substitution-like manner, where the gain of Ca was similar to the loss of Mg2+. A simple reaction kinetic model based on this substitution with three independent tuning parameters (rate coefficient, reaction order and equilibrium constant) was implemented together with advection to analytically calculate steady state effluent concentrations when injected composition, injection rate and reaction kinetic parameters were stated. By tuning reaction kinetic parameters, the experimental steady state data could be fitted efficiently. From data trends, the parameters were determined relatively accurate for each core. The roles of reaction parameters, pore velocity and dispersion were illustrated with sensitivity analyses.\u0000 The steady state method allows computationally efficient matching even with complex reaction kinetics. Using ","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"32 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81941284","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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