Polymer flooding is one of the most commonly used chemical EOR methods. Conventionally, this technique was believed to improve macroscopic sweep efficiency by sweeping only bypassed oil. Nevertheless, recently it has been found that polymers exhibiting viscoelastic behavior in the porous medium can also improve microscopic displacement efficiency resulting in higher additional oil recovery. Therefore, an accurate prediction of the complex rheological response of polymers is crucial to obtain a proper estimation of incremental oil to polymer flooding. In this paper, a novel viscoelastic model is proposed to comprehensively analyze the polymer rheological behavior in porous media. The proposed viscoelastic model is considered an extension of the unified apparent viscosity model provided in the literature and is termed as extended unified viscosity model (E-UVM). The main advantage of the proposed model is its ability to capture the polymer mechanical degradation at ultimate shear rates primarily observed near wellbores. Furthermore, the fitting parameters used in the model were correlated to rock and polymer properties, significantly reducing the need for time-consuming coreflooding tests for future polymer screening works. Moreover, the extended viscoelastic model was implemented in MATLAB Reservoir Simulation Toolbox (MRST) and verified against the original shear model existing in the simulator. It was found that implementing the viscosity model in MRST might be more accurate and practical than the original method. In addition, the comparison between various viscosity models proposed earlier and E-UVM in the reservoir simulator revealed that the latter model could yield more reliable oil recovery predictions since it accommodates the mechanical degradation of polymers. This study presents a novel viscoelastic model that is more comprehensive and representative as opposed to other models in the literature.
{"title":"An Extended Viscoelastic Model for Predicting Polymer Apparent Viscosity at Different Shear Rates","authors":"Mursal Zeynalli, Emad W. Al-Shalabi, W. Alameri","doi":"10.2118/206010-ms","DOIUrl":"https://doi.org/10.2118/206010-ms","url":null,"abstract":"\u0000 Polymer flooding is one of the most commonly used chemical EOR methods. Conventionally, this technique was believed to improve macroscopic sweep efficiency by sweeping only bypassed oil. Nevertheless, recently it has been found that polymers exhibiting viscoelastic behavior in the porous medium can also improve microscopic displacement efficiency resulting in higher additional oil recovery. Therefore, an accurate prediction of the complex rheological response of polymers is crucial to obtain a proper estimation of incremental oil to polymer flooding. In this paper, a novel viscoelastic model is proposed to comprehensively analyze the polymer rheological behavior in porous media.\u0000 The proposed viscoelastic model is considered an extension of the unified apparent viscosity model provided in the literature and is termed as extended unified viscosity model (E-UVM). The main advantage of the proposed model is its ability to capture the polymer mechanical degradation at ultimate shear rates primarily observed near wellbores. Furthermore, the fitting parameters used in the model were correlated to rock and polymer properties, significantly reducing the need for time-consuming coreflooding tests for future polymer screening works. Moreover, the extended viscoelastic model was implemented in MATLAB Reservoir Simulation Toolbox (MRST) and verified against the original shear model existing in the simulator. It was found that implementing the viscosity model in MRST might be more accurate and practical than the original method. In addition, the comparison between various viscosity models proposed earlier and E-UVM in the reservoir simulator revealed that the latter model could yield more reliable oil recovery predictions since it accommodates the mechanical degradation of polymers. This study presents a novel viscoelastic model that is more comprehensive and representative as opposed to other models in the literature.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"233 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74982099","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}
For decades sucker rod pump artificially lifted wells have used devices called pump off controllers (POC) to match the pumping unit's runtime to the available reservoir production by idling the well for a set time where variable frequencies drives are not available. In doing this the POC allows the well to enter a set period of downtime when the downhole pump fillage is incomplete to avoid premature failures, and then brings the well back online to operate before production is lost. Although this method has been successful for several years, autonomous control algorithms can be utilized to reduce failures or increase production in cases where the downtime is not already optimized. Optimizing the idle time for a sucker rod pump artificially lifted well involves understanding the amount of time required to fill the near wellbore storage area before generating a fluid column above the pump intake that will begin to hinder inflow from the reservoir into the wellbore. By varying the idle time and observing the impact on production and cycles the program hunts for the optimal idle time. By constantly hunting for the optimal idle time the optimization process can adjust the idle time when operating conditions change. This gives the advantage of always meeting the current well bore and reservoir conditions without having to have a user make these changes and determine what the downtime for the well is. Autonomously modulating the idle time for a well, if done properly will either reduces incomplete fillage pump strokes, in cases where the idle time is too short, or will increase the wells production in cases where the idle time is too long. Overall this will result in the optimization of wells by reducing failures and/or increasing production, generating a huge value to the end user by automating the entire process of downtime optimization.
{"title":"Autonomous Control of Well Downtime to Optimize Production and Cycling in Sucker Rod Pump Artificially Lifted Wells","authors":"I. Nickell, Terry Treiberg","doi":"10.2118/206236-ms","DOIUrl":"https://doi.org/10.2118/206236-ms","url":null,"abstract":"\u0000 For decades sucker rod pump artificially lifted wells have used devices called pump off controllers (POC) to match the pumping unit's runtime to the available reservoir production by idling the well for a set time where variable frequencies drives are not available. In doing this the POC allows the well to enter a set period of downtime when the downhole pump fillage is incomplete to avoid premature failures, and then brings the well back online to operate before production is lost. Although this method has been successful for several years, autonomous control algorithms can be utilized to reduce failures or increase production in cases where the downtime is not already optimized. Optimizing the idle time for a sucker rod pump artificially lifted well involves understanding the amount of time required to fill the near wellbore storage area before generating a fluid column above the pump intake that will begin to hinder inflow from the reservoir into the wellbore. By varying the idle time and observing the impact on production and cycles the program hunts for the optimal idle time. By constantly hunting for the optimal idle time the optimization process can adjust the idle time when operating conditions change. This gives the advantage of always meeting the current well bore and reservoir conditions without having to have a user make these changes and determine what the downtime for the well is. Autonomously modulating the idle time for a well, if done properly will either reduces incomplete fillage pump strokes, in cases where the idle time is too short, or will increase the wells production in cases where the idle time is too long. Overall this will result in the optimization of wells by reducing failures and/or increasing production, generating a huge value to the end user by automating the entire process of downtime optimization.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75611967","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}
D. Zhang, Xiao-xing Shi, Chunyan Qi, Jianfei Zhan, Xue Han, D. Klemin
With the decline of conventional resources, the tight oil reserves in the Daqing oilfield are becoming increasingly important, but measuring relative permeability and determining production forecasts through laboratory core flow tests for tight formations are both difficult and time consuming. Results of laboratory testing are questionable due to the very small pore volume and low permeability of the reservoir rock, and there are challenges in controlling critical parameters during the special core analysis (SCAL) tests. In this paper, the protocol and workflow of a digital rock study for tight sandstones of the Daqing oilfield are discussed. The workflow includes 1) using a combination of various imaging methods to build rock models that are representative of reservoir rocks, 2) constructing digital fluid models of reservoir fluids and injectants, 3) applying laboratory measured wettability index data to define rock-fluid interaction in digital rock models, 4) performing pore-scale modelling to accelerate reservoir characterization and reduce the uncertainty, and 5) performing digital enhanced oil recovery (EOR) tests to analyze potential benefits of different scenarios. The target formations are tight (0.01 to 5 md range) sandstones that have a combination of large grain sizes juxtaposed against small pore openings which makes it challenging to select an appropriate set of imaging tools. To overcome the wide range of pore and grain scales, the imaging tools selected for the study included high resolution microCT imaging on core plugs and mini-plugs sampled from original plugs, overview scanning electron microscopy (SEM) imaging, mineralogical mapping, and high-resolution SEM imaging on the mini-plugs. High resolution digital rock models were constructed and subsequently upscaled to the plug level to differentiate bedding and other features could be differentiated. Permeability and porosity of digital rock models were benchmarked against laboratory measurements to confirm representativeness. The laboratory measured Amott-Harvey wettability index of restored core plugs was honored and applied to the digital rock models. Digital fluid models were built using the fluid PVT data. A Direct HydroDynamic (DHD) pore-scale flow simulator based on density functional hydrodynamics was used to model multiphase flow in the digital experiments. Capillary pressure, water-oil, surfactant solution-oil, and CO2-oil relative permeability were computed, as well as primary depletion followed with three-cycle CO2 huff-n-puff, and primary depletion followed with three-cycle surfactant solution huff-n-puff processes. Recovery factors were obtained for each method and resulting values were compared to establish most effective field development scenarios. The workflow developed in this paper provides fast and reliable means of obtaining critical data for field development design. Capillary pressure and relative permeability data obtained through digital experiments
{"title":"Formation Characterization and Production Forecast of Tight Sandstone Formations in Daqing Oilfield Through Digital Rock Technology","authors":"D. Zhang, Xiao-xing Shi, Chunyan Qi, Jianfei Zhan, Xue Han, D. Klemin","doi":"10.2118/206055-ms","DOIUrl":"https://doi.org/10.2118/206055-ms","url":null,"abstract":"\u0000 With the decline of conventional resources, the tight oil reserves in the Daqing oilfield are becoming increasingly important, but measuring relative permeability and determining production forecasts through laboratory core flow tests for tight formations are both difficult and time consuming. Results of laboratory testing are questionable due to the very small pore volume and low permeability of the reservoir rock, and there are challenges in controlling critical parameters during the special core analysis (SCAL) tests. In this paper, the protocol and workflow of a digital rock study for tight sandstones of the Daqing oilfield are discussed. The workflow includes 1) using a combination of various imaging methods to build rock models that are representative of reservoir rocks, 2) constructing digital fluid models of reservoir fluids and injectants, 3) applying laboratory measured wettability index data to define rock-fluid interaction in digital rock models, 4) performing pore-scale modelling to accelerate reservoir characterization and reduce the uncertainty, and 5) performing digital enhanced oil recovery (EOR) tests to analyze potential benefits of different scenarios.\u0000 The target formations are tight (0.01 to 5 md range) sandstones that have a combination of large grain sizes juxtaposed against small pore openings which makes it challenging to select an appropriate set of imaging tools. To overcome the wide range of pore and grain scales, the imaging tools selected for the study included high resolution microCT imaging on core plugs and mini-plugs sampled from original plugs, overview scanning electron microscopy (SEM) imaging, mineralogical mapping, and high-resolution SEM imaging on the mini-plugs. High resolution digital rock models were constructed and subsequently upscaled to the plug level to differentiate bedding and other features could be differentiated. Permeability and porosity of digital rock models were benchmarked against laboratory measurements to confirm representativeness. The laboratory measured Amott-Harvey wettability index of restored core plugs was honored and applied to the digital rock models. Digital fluid models were built using the fluid PVT data. A Direct HydroDynamic (DHD) pore-scale flow simulator based on density functional hydrodynamics was used to model multiphase flow in the digital experiments.\u0000 Capillary pressure, water-oil, surfactant solution-oil, and CO2-oil relative permeability were computed, as well as primary depletion followed with three-cycle CO2 huff-n-puff, and primary depletion followed with three-cycle surfactant solution huff-n-puff processes. Recovery factors were obtained for each method and resulting values were compared to establish most effective field development scenarios.\u0000 The workflow developed in this paper provides fast and reliable means of obtaining critical data for field development design. Capillary pressure and relative permeability data obtained through digital experiments ","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"77 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73904617","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}
G. Chaves, D. D. Monteiro, Virgílio José Martins Ferreira
Commingle production nodes are standard practice in the industry to combine multiple segments into one. This practice is adopted at the subsurface or surface to reduce costs, elements (e.g. pipes), and space. However, it leads to one problem: determine the rates of the single elements. This problem is recurrently solved in the platform scenario using the back allocation approach, where the total platform flowrate is used to obtain the individual wells’ flowrates. The wells’ flowrates are crucial to monitor, manage and make operational decisions in order to optimize field production. This work combined outflow (well and flowline) simulation, reservoir inflow, algorithms, and an optimization problem to calculate the wells’ flowrates and give a status about the current well state. Wells stated as unsuited indicates either the input data, the well model, or the well is behaving not as expected. The well status is valuable operational information that can be interpreted, for instance, to indicate the need for a new well testing, or as reliability rate for simulations run. The well flowrates are calculated considering three scenarios the probable, minimum and maximum. Real-time data is used as input data and production well test is used to tune and update well model and parameters routinely. The methodology was applied using a representative offshore oil field with 14 producing wells for two-years production time. The back allocation methodology showed robustness in all cases, labeling the wells properly, calculating the flowrates, and honoring the platform flowrate.
{"title":"A Back Allocation Methodology to Estimate the Real-Time Flow and Assist Production Monitoring","authors":"G. Chaves, D. D. Monteiro, Virgílio José Martins Ferreira","doi":"10.2118/205916-ms","DOIUrl":"https://doi.org/10.2118/205916-ms","url":null,"abstract":"\u0000 Commingle production nodes are standard practice in the industry to combine multiple segments into one. This practice is adopted at the subsurface or surface to reduce costs, elements (e.g. pipes), and space. However, it leads to one problem: determine the rates of the single elements. This problem is recurrently solved in the platform scenario using the back allocation approach, where the total platform flowrate is used to obtain the individual wells’ flowrates. The wells’ flowrates are crucial to monitor, manage and make operational decisions in order to optimize field production. This work combined outflow (well and flowline) simulation, reservoir inflow, algorithms, and an optimization problem to calculate the wells’ flowrates and give a status about the current well state. Wells stated as unsuited indicates either the input data, the well model, or the well is behaving not as expected. The well status is valuable operational information that can be interpreted, for instance, to indicate the need for a new well testing, or as reliability rate for simulations run. The well flowrates are calculated considering three scenarios the probable, minimum and maximum. Real-time data is used as input data and production well test is used to tune and update well model and parameters routinely. The methodology was applied using a representative offshore oil field with 14 producing wells for two-years production time. The back allocation methodology showed robustness in all cases, labeling the wells properly, calculating the flowrates, and honoring the platform flowrate.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84978716","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The Reservoir GeoMechanics Simulator (RGMS), a geomechanics simulator based on the finite element method and parallelized using the Message Passing Interface (MPI), is developed in this work to model the stresses and deformations in subsurface systems. RGMS can be used stand-alone, or coupled with flow and transport models. pT+H V1.5, a parallel MPI-based version of the serial T+H V1.5 code that describes mass and heat flow in hydrate-bearing porous media, is also developed. Using the fixed-stress split iterative scheme, RGMS is coupled with the pT+H V1.5 to investigate the geomechanical responses associated with gas production from hydrate accumulations. The code development and testing process involve evaluation of the parallelization and of the coupling method, as well as verification and validation of the results. The parallel performance of the codes is tested on the Ada Linux cluster of the Texas A&M High Performance Research Computing using up to 512 processors, and on a Mac Pro computer with 12 processors. The investigated problems are: Group 1: Geomechanical problems solved by RGMS in 2D Cartesian and cylindrical domains and a 3D problem, involving 4x106 and 3.375 x106 elements, respectively; Group 2: Realistic problems of gas production from hydrates using pT+H V1.5 in 2D and 3D systems with 2.45x105 and 3.6 x106 elements, respectively; Group 3: The 3D problem in Group 2 solved with the coupled RGMS-pT+H V1.5 simulator, fully accounting for geomechanics. Two domain partitioning options are investigated on the Ada Linux cluster and the Mac Pro, and the code parallel performance is monitored. On the Ada Linux cluster using 512 processors, the simulation speedups (a) of RGMS are 218.89, 188.13, and 284.70 in the Group 1 problems, (b) of pT+H V1.5 are 174.25 and 341.67 in the Group 2 cases, and (c) of the coupled simulators is 331.80 in Group 3. The results produced in this work show the necessity of using full geomechanics simulators in marine hydrate-related studies because of the associated pronounced geomechanical effects on production and displacements and (b) the effectiveness of the parallel simulators developed in this study, which can be the only realistic option in these complex simulations of large multi-dimensional domains.
储层地质力学模拟器(RGMS)是一种基于有限元方法并使用消息传递接口(MPI)并行化的地质力学模拟器，用于模拟地下系统的应力和变形。RGMS可以单独使用，也可以与流和传输模型结合使用。pT+H V1.5是一种基于mpi的并行T+H V1.5代码，用于描述含水合物多孔介质中的质量和热流。使用固定应力分裂迭代方案，RGMS与pT+H V1.5相结合，研究与水合物聚集产气相关的地质力学响应。代码开发和测试过程包括对并行化和耦合方法的评估，以及对结果的验证和确认。在Texas A&M High performance Research Computing的Ada Linux集群(多达512个处理器)和Mac Pro计算机(12个处理器)上测试了代码的并行性能。研究的问题包括:第1组:RGMS在二维笛卡尔和圆柱域中解决的地质力学问题，以及一个三维问题，分别涉及4x106和3.375 x106个单元;第2组:pT+H V1.5在2D和3D体系(分别为2.45x105和3.6 x106元素)中产气的现实问题;第3组:第2组的三维问题采用RGMS-pT+H V1.5耦合模拟器解决，充分考虑了地质力学。在Ada Linux集群和Mac Pro上研究了两种域分区选项，并对代码并行性能进行了监控。在使用512个处理器的Ada Linux集群上，RGMS在第1组问题中的仿真加速(a)分别为218.89、188.13和284.70,pT+H V1.5在第2组问题中的仿真加速(b)分别为174.25和341.67，耦合模拟器在第3组中的仿真加速(c)分别为331.80。这项工作产生的结果表明，在海洋水合物相关研究中使用完整的地质力学模拟器是必要的，因为相关的地质力学对产量和位移有明显的影响，并且(b)本研究中开发的并行模拟器的有效性，这可能是这些大型多维域复杂模拟中唯一现实的选择。
{"title":"Message-Passing-Interface MPI Parallelization of Iteratively Coupled Fluid Flow and Geomechanics Codes for the Simulation of System Behavior in Hydrate-Bearing Geologic Media","authors":"Jiecheng Zhang, G. Moridis, T. Blasingame","doi":"10.2118/206161-ms","DOIUrl":"https://doi.org/10.2118/206161-ms","url":null,"abstract":"\u0000 The Reservoir GeoMechanics Simulator (RGMS), a geomechanics simulator based on the finite element method and parallelized using the Message Passing Interface (MPI), is developed in this work to model the stresses and deformations in subsurface systems. RGMS can be used stand-alone, or coupled with flow and transport models. pT+H V1.5, a parallel MPI-based version of the serial T+H V1.5 code that describes mass and heat flow in hydrate-bearing porous media, is also developed. Using the fixed-stress split iterative scheme, RGMS is coupled with the pT+H V1.5 to investigate the geomechanical responses associated with gas production from hydrate accumulations. The code development and testing process involve evaluation of the parallelization and of the coupling method, as well as verification and validation of the results.\u0000 The parallel performance of the codes is tested on the Ada Linux cluster of the Texas A&M High Performance Research Computing using up to 512 processors, and on a Mac Pro computer with 12 processors. The investigated problems are:\u0000 Group 1: Geomechanical problems solved by RGMS in 2D Cartesian and cylindrical domains and a 3D problem, involving 4x106 and 3.375 x106 elements, respectively; Group 2: Realistic problems of gas production from hydrates using pT+H V1.5 in 2D and 3D systems with 2.45x105 and 3.6 x106 elements, respectively; Group 3: The 3D problem in Group 2 solved with the coupled RGMS-pT+H V1.5 simulator, fully accounting for geomechanics.\u0000 Two domain partitioning options are investigated on the Ada Linux cluster and the Mac Pro, and the code parallel performance is monitored. On the Ada Linux cluster using 512 processors, the simulation speedups (a) of RGMS are 218.89, 188.13, and 284.70 in the Group 1 problems, (b) of pT+H V1.5 are 174.25 and 341.67 in the Group 2 cases, and (c) of the coupled simulators is 331.80 in Group 3.\u0000 The results produced in this work show the necessity of using full geomechanics simulators in marine hydrate-related studies because of the associated pronounced geomechanical effects on production and displacements and (b) the effectiveness of the parallel simulators developed in this study, which can be the only realistic option in these complex simulations of large multi-dimensional domains.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85457292","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}
Oklahoma is known for having ample sources of CO2, pipelines and sinks where for many decades, oil and gas operators were injecting CO2 into geological formations for EOR purposes. We utilized SimCCS, an economic-engineering software tool (DOE-NETL), to integrate infrastructure related to CO2 sources, pipeline, and geological formations. The approved tax incentive program by IRS (45Q) has motivated many oil and gas operators to participate in reducing CO2 concentration and minimizing global warming effect by collecting CO2 from various sources, select the best pipeline route and the safest location to inject into geological formation for EOR purpose or deep saline aquifer for sequestration. This paper presents an economic evaluation of CO2 capture, utilization, storage (CCUS) into geological formation in the state of Oklahoma. Under this comprehensive approach, the process of capturing, transporting, and storing CO2 into geological or saline formations has been economically evaluated for different sites and routes utilizing an ad hoc simulation software (SimCCS) for integrated modeling of CCUS. The outcome of this paper determines the most optimal scenario using optimization algorithms embedded in SimCCS. This case study will mitigate the CO2 sequestration approval process when operator apply for tax credit under 45Q program. Our work will assist oil and gas operators by comparing different scenarios based on utilizing existing infrastructure, making decision in building new transportation system or new injection well to benefit the approved tax incentive program at its maximum capacity. Moreover, the outcome of this work will shed lights into future legislation demands (locally and nation-wide) to maintain CCUS momentum after its initial implementation phase is concluded.
{"title":"Economic Evaluation of CO2 Capture, Transportation, and Storage Potentials in Oklahoma","authors":"J. Daneshfar, D. Nnamdi, R. Moghanloo, K. Ochie","doi":"10.2118/206106-ms","DOIUrl":"https://doi.org/10.2118/206106-ms","url":null,"abstract":"\u0000 Oklahoma is known for having ample sources of CO2, pipelines and sinks where for many decades, oil and gas operators were injecting CO2 into geological formations for EOR purposes. We utilized SimCCS, an economic-engineering software tool (DOE-NETL), to integrate infrastructure related to CO2 sources, pipeline, and geological formations. The approved tax incentive program by IRS (45Q) has motivated many oil and gas operators to participate in reducing CO2 concentration and minimizing global warming effect by collecting CO2 from various sources, select the best pipeline route and the safest location to inject into geological formation for EOR purpose or deep saline aquifer for sequestration.\u0000 This paper presents an economic evaluation of CO2 capture, utilization, storage (CCUS) into geological formation in the state of Oklahoma. Under this comprehensive approach, the process of capturing, transporting, and storing CO2 into geological or saline formations has been economically evaluated for different sites and routes utilizing an ad hoc simulation software (SimCCS) for integrated modeling of CCUS. The outcome of this paper determines the most optimal scenario using optimization algorithms embedded in SimCCS.\u0000 This case study will mitigate the CO2 sequestration approval process when operator apply for tax credit under 45Q program. Our work will assist oil and gas operators by comparing different scenarios based on utilizing existing infrastructure, making decision in building new transportation system or new injection well to benefit the approved tax incentive program at its maximum capacity. Moreover, the outcome of this work will shed lights into future legislation demands (locally and nation-wide) to maintain CCUS momentum after its initial implementation phase is concluded.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83058266","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The success of supercritical CO2 Enhanced Oil Recovery (EOR) cannot be duplicated if the cost of CO2 transposition and processing becomes prohibitive. Research results of the in-situ CO2 EOR (ICE) approach offered a potential technology for many waterflooded stripper wells that lack access to affordable CO2 sources. Previously the ICE synergetic mechanisms were only qualitatively attributed to oil swelling and viscosity reduction due to the preferential partition of CO2 into the oleic phase. This study aims to quantify the contributions to recovery factors from several plausible mechanisms with numerical modeling and simulation. First, the urea reaction was modeled as the CO2 generating chemical decomposing to CO2 and ammonia in the reservoir conditions. The CO2 partitions into oil, which leads to the reaction continuation to generate more CO2. The resulting ammonia largely left in water may further react with certain crudes to generate surfactants, thus, decrease the oil/water interfacial tension (IFT). It is expected that the oil containing CO2 also has a lower IFT with water. The reaction kinetics under different temperatures were incorporated into the numerical model. A numerical model featuring the synergetic mechanisms was built including stoichiometry and kinetics of urea reaction, oil swelling effect, oil viscosity reduction, and IFT reduction effect on the relative permeabilities. The laboratory experiments, pore volume injection versus oil saturation were history matched for three different oils including Dodecane, Earlsboro oil, and DeepStar oil. The phase behavior was modeled with the equation of state (EOS) under different mole fractions of CO2. The reaction kinetics were also modified to history match the laboratory experiment. The estimated reduction of oil viscosity was calculated, 76% for Earlsboro oil, 91% in DeepStar oil, and 75% in dodecane oil. The oil swelling factors ranged from 1.60% to 19% in the three lab models, which translates to the recovery factor of oil. The endpoints of relative permeability were modified to account for the recovery contribution to the IFT and viscosity reduction. The impact of reaction kinetics on oil swelling and recovery factor was also determined, and they are not numerically close to reaction kinetics used in the lab cases. The matched reaction kinetics, activation energy and reaction frequency factor for the dodecane laboratory experiment were 91.80 kJ/gmol and 6.5E+09 min−1. The study concluded that the incremental recovery due to oil swelling ranges between 3.16% and 18.30%, and then from 12.91% to 41.59% is due to IFT reduction for all the cases. The relative permeability and urea reaction kinetics remained the most uncertain parameters during history matching and modeling the ICE synergetic mechanisms.
{"title":"Numerical Mechanistic Study of In-Situ CO2 EOR – Kinetics and Recovery Performance Analysis","authors":"S. Hussain, Xingru Wu, B. Shiau","doi":"10.2118/206292-ms","DOIUrl":"https://doi.org/10.2118/206292-ms","url":null,"abstract":"\u0000 The success of supercritical CO2 Enhanced Oil Recovery (EOR) cannot be duplicated if the cost of CO2 transposition and processing becomes prohibitive. Research results of the in-situ CO2 EOR (ICE) approach offered a potential technology for many waterflooded stripper wells that lack access to affordable CO2 sources. Previously the ICE synergetic mechanisms were only qualitatively attributed to oil swelling and viscosity reduction due to the preferential partition of CO2 into the oleic phase. This study aims to quantify the contributions to recovery factors from several plausible mechanisms with numerical modeling and simulation.\u0000 First, the urea reaction was modeled as the CO2 generating chemical decomposing to CO2 and ammonia in the reservoir conditions. The CO2 partitions into oil, which leads to the reaction continuation to generate more CO2. The resulting ammonia largely left in water may further react with certain crudes to generate surfactants, thus, decrease the oil/water interfacial tension (IFT). It is expected that the oil containing CO2 also has a lower IFT with water. The reaction kinetics under different temperatures were incorporated into the numerical model. A numerical model featuring the synergetic mechanisms was built including stoichiometry and kinetics of urea reaction, oil swelling effect, oil viscosity reduction, and IFT reduction effect on the relative permeabilities. The laboratory experiments, pore volume injection versus oil saturation were history matched for three different oils including Dodecane, Earlsboro oil, and DeepStar oil. The phase behavior was modeled with the equation of state (EOS) under different mole fractions of CO2. The reaction kinetics were also modified to history match the laboratory experiment.\u0000 The estimated reduction of oil viscosity was calculated, 76% for Earlsboro oil, 91% in DeepStar oil, and 75% in dodecane oil. The oil swelling factors ranged from 1.60% to 19% in the three lab models, which translates to the recovery factor of oil. The endpoints of relative permeability were modified to account for the recovery contribution to the IFT and viscosity reduction. The impact of reaction kinetics on oil swelling and recovery factor was also determined, and they are not numerically close to reaction kinetics used in the lab cases. The matched reaction kinetics, activation energy and reaction frequency factor for the dodecane laboratory experiment were 91.80 kJ/gmol and 6.5E+09 min−1. The study concluded that the incremental recovery due to oil swelling ranges between 3.16% and 18.30%, and then from 12.91% to 41.59% is due to IFT reduction for all the cases. The relative permeability and urea reaction kinetics remained the most uncertain parameters during history matching and modeling the ICE synergetic mechanisms.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"66 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83149912","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}
Formation evaluation in heterogeneous reservoirs can be very challenging especially in fields that extend over several kilometers in area where the permeability varies from 0.1 mD up to 1000 D within the same porosity. The porosity, hydrocarbon saturation and net sand thickness in most of Obaiyed field wells are consistent; hence, the productivity of these wells is enormously dependent on the reservoir permeability. Since the permeability is highly heterogeneous, initial production rate of the wells varies between few MMSCFD to almost one hundred MMSCFD. The huge permeability variation led to a tremendous uncertainty in the dynamic modeling, which resulted in an inaccurate production forecast affecting the field economics estimation. Understanding permeability distribution and heterogeneity in Obaiyed field is the key factor for establishing a realistic permeability model, which will lead to a successful field development strategy. Extensive work was performed to understand key factors that govern the permeability in Obaiyed using the data of 1-kilometer length of cores acquired in more than 50 wells covering different reservoir properties in the field. Core data were used to separate the reservoir into different Hydraulic Flow Units (HFU) according to Amaefule's work performed on the Kozeny-Carmen model. Afterwards, a correlation between the HFU and well logs was established using IPSOM Electro-Facies module in order to define the flow units in un-cored wells. The result of this correlation was used to calibrate a Porosity-Permeability relationship for each flow unit. The next step was examining the clay-type distribution and diagenesis in each flow unit using the petrographic analysis (XRD) results from the core xdata. All factors controlling the permeability can now be represented in hydraulic flow units which are considered as a method of measurement of the reservoir quality. Consequently, property maps were constructed showing the location and continuity of each of the flow units, leading to a more deterministic approach in the well placement process. Based on this new work methodology, a production cut-off criteria relating the reservoir productivity to both clay minerals presence and percentages was established for multiple wells scenarios. As a result, the development strategy of the field changed from only vertical wells to include horizontal wells as well which proved to be the only economic approach to produce the Illite dominated zones. This paper presents a workflow to provide a representative estimation of permeability in extremely heterogeneous reservoirs especially the ones dominated by complex clay distribution.
{"title":"Integrating XRD and Well Logging Data to Establish Electro-Facies and Permeability Models for an Unconventional Heterogeneous Tight Gas Reservoir, Obaiyed Giant Gas Field","authors":"I. Mabrouk","doi":"10.2118/208626-stu","DOIUrl":"https://doi.org/10.2118/208626-stu","url":null,"abstract":"\u0000 Formation evaluation in heterogeneous reservoirs can be very challenging especially in fields that extend over several kilometers in area where the permeability varies from 0.1 mD up to 1000 D within the same porosity. The porosity, hydrocarbon saturation and net sand thickness in most of Obaiyed field wells are consistent; hence, the productivity of these wells is enormously dependent on the reservoir permeability. Since the permeability is highly heterogeneous, initial production rate of the wells varies between few MMSCFD to almost one hundred MMSCFD.\u0000 The huge permeability variation led to a tremendous uncertainty in the dynamic modeling, which resulted in an inaccurate production forecast affecting the field economics estimation. Understanding permeability distribution and heterogeneity in Obaiyed field is the key factor for establishing a realistic permeability model, which will lead to a successful field development strategy. Extensive work was performed to understand key factors that govern the permeability in Obaiyed using the data of 1-kilometer length of cores acquired in more than 50 wells covering different reservoir properties in the field.\u0000 Core data were used to separate the reservoir into different Hydraulic Flow Units (HFU) according to Amaefule's work performed on the Kozeny-Carmen model. Afterwards, a correlation between the HFU and well logs was established using IPSOM Electro-Facies module in order to define the flow units in un-cored wells. The result of this correlation was used to calibrate a Porosity-Permeability relationship for each flow unit.\u0000 The next step was examining the clay-type distribution and diagenesis in each flow unit using the petrographic analysis (XRD) results from the core xdata. All factors controlling the permeability can now be represented in hydraulic flow units which are considered as a method of measurement of the reservoir quality. Consequently, property maps were constructed showing the location and continuity of each of the flow units, leading to a more deterministic approach in the well placement process.\u0000 Based on this new work methodology, a production cut-off criteria relating the reservoir productivity to both clay minerals presence and percentages was established for multiple wells scenarios. As a result, the development strategy of the field changed from only vertical wells to include horizontal wells as well which proved to be the only economic approach to produce the Illite dominated zones. This paper presents a workflow to provide a representative estimation of permeability in extremely heterogeneous reservoirs especially the ones dominated by complex clay distribution.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81564366","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The potential of tuned-composition waterflooding to enhance oil recovery from carbonate reservoirs has been widely investigated in the literature. The consensus is that wettability alteration occurs because of the electrostatic interactions between the carbonate rock surface and the potential determining ions, Ca2+, Mg2+, CO32−, and SO42−. Recently, glycine, the simplest amino acid, has also been investigated as a wettability modifier for carbonates that acts similarly as the sulfate ions in brine. The impact of wettability modifiers like glycine and calcite's potential determining ions has been described by surface complexation models (SCM) and the wetting-state of the rock has been related to change of the surface potential. However, determining the relevance of the geochemical reactions is obstructed by the complexity of the SCM. Moreover, the surface potential as a surrogate of the wetting-state of the rock does not correlate with the experimental results with glycine reported in the literature. The present research analyzed the results of single-phase displacement using a SCM for calcite to determine the important surface complexation reactions. Then, wettability alteration is modeled as a set of anion exchange reactions between wettability modifiers, like SO42− and Gly−, and adsorbed carboxylic acids. Finally, analytical solutions are presented for the coupled two-phase and multicomponent reactive-transport model with anion exchange reactions.
{"title":"Analytical Solutions for the Injection of Wettability Modifiers in Carbonate Reservoirs Based on a Reduced Surface Complexation Model","authors":"Ricardo A. Lara Orozco, R. Okuno, L. Lake","doi":"10.2118/206088-ms","DOIUrl":"https://doi.org/10.2118/206088-ms","url":null,"abstract":"\u0000 The potential of tuned-composition waterflooding to enhance oil recovery from carbonate reservoirs has been widely investigated in the literature. The consensus is that wettability alteration occurs because of the electrostatic interactions between the carbonate rock surface and the potential determining ions, Ca2+, Mg2+, CO32−, and SO42−. Recently, glycine, the simplest amino acid, has also been investigated as a wettability modifier for carbonates that acts similarly as the sulfate ions in brine. The impact of wettability modifiers like glycine and calcite's potential determining ions has been described by surface complexation models (SCM) and the wetting-state of the rock has been related to change of the surface potential. However, determining the relevance of the geochemical reactions is obstructed by the complexity of the SCM. Moreover, the surface potential as a surrogate of the wetting-state of the rock does not correlate with the experimental results with glycine reported in the literature.\u0000 The present research analyzed the results of single-phase displacement using a SCM for calcite to determine the important surface complexation reactions. Then, wettability alteration is modeled as a set of anion exchange reactions between wettability modifiers, like SO42− and Gly−, and adsorbed carboxylic acids. Finally, analytical solutions are presented for the coupled two-phase and multicomponent reactive-transport model with anion exchange reactions.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82521992","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}
Acid jobs with conventional acid systems like hydrochloric acid in high temperature conditions is challenging on various fronts. Enhanced reactivity of strong acids results in poor penetration and severe face dissolution. Also, it aggravates the issue of corrosion of downhole equipment and may also result in sludge formation/asphaltene deposition. Worldwide, chelating agents has emerged as a standalone stimulation fluid for high temperature acidizing. Their unique attributes and properties have been proved very useful for acid jobs at elevated temperatures. However, the chelating agents-based formulations need to be carefully evaluated on various acidization parameters for a fruitful stimulation. Mumbai Offshore field has been encountering the above-mentioned problems in acidizing of its high temperature (>275°F) limestone reservoirs. The paper presents innovative solutions devised for high temperature matrix acidizing. Two chelating agents viz., EDTA (Ethylenediaminetetraceticacid) and GLDA (L-Glutamic Acid N, N-diacetic acid) were explored and evaluated with meticulous laboratory studies. The performance of the chelating agent-based stimulation fluid was compared with acetic acid. Slurry tests were performed to quantify the dissolving power of each acid. Consequently, core flooding tests were carried out to to find the optimum pH of the chelating agents from stimulation point of view. Core flooding studies were performed at anticipated injection rates on representative core samples from a payzone A, with BHT 275-290° F, from Mumbai Offshore. pH optimized formulations were tested against N-80 metallurgy coupons at reservoir temperature for corrosion potential estimation. Also, sludge, asphaltene and emulsion formation tendencies were analyzed with representative oil samples. The results convey that both EDTA and GLDA were able to mitigate the challenges encountered at elevated temperatures. EDTA and GLDA were found to stimulate the cores with wormholes formed at wide pH range with no face dissolution observed. Chelating agents enjoyed good dissolving power with negligible corrosion rates, absence of sludge and asphaltene deposition, compatibility with formation fluid and excellent iron control properties.
{"title":"Mitigation of High Temperature Challenges in Limestone Acidizing through the use of Chelating Agents","authors":"Mandeep Khan, M. Qamruzzaman, D. Roy, R. Raman","doi":"10.2118/206039-ms","DOIUrl":"https://doi.org/10.2118/206039-ms","url":null,"abstract":"\u0000 Acid jobs with conventional acid systems like hydrochloric acid in high temperature conditions is challenging on various fronts. Enhanced reactivity of strong acids results in poor penetration and severe face dissolution. Also, it aggravates the issue of corrosion of downhole equipment and may also result in sludge formation/asphaltene deposition. Worldwide, chelating agents has emerged as a standalone stimulation fluid for high temperature acidizing. Their unique attributes and properties have been proved very useful for acid jobs at elevated temperatures. However, the chelating agents-based formulations need to be carefully evaluated on various acidization parameters for a fruitful stimulation.\u0000 Mumbai Offshore field has been encountering the above-mentioned problems in acidizing of its high temperature (>275°F) limestone reservoirs. The paper presents innovative solutions devised for high temperature matrix acidizing. Two chelating agents viz., EDTA (Ethylenediaminetetraceticacid) and GLDA (L-Glutamic Acid N, N-diacetic acid) were explored and evaluated with meticulous laboratory studies. The performance of the chelating agent-based stimulation fluid was compared with acetic acid. Slurry tests were performed to quantify the dissolving power of each acid. Consequently, core flooding tests were carried out to to find the optimum pH of the chelating agents from stimulation point of view. Core flooding studies were performed at anticipated injection rates on representative core samples from a payzone A, with BHT 275-290° F, from Mumbai Offshore. pH optimized formulations were tested against N-80 metallurgy coupons at reservoir temperature for corrosion potential estimation. Also, sludge, asphaltene and emulsion formation tendencies were analyzed with representative oil samples.\u0000 The results convey that both EDTA and GLDA were able to mitigate the challenges encountered at elevated temperatures. EDTA and GLDA were found to stimulate the cores with wormholes formed at wide pH range with no face dissolution observed. Chelating agents enjoyed good dissolving power with negligible corrosion rates, absence of sludge and asphaltene deposition, compatibility with formation fluid and excellent iron control properties.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82734119","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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