Vladislav Arekhov, Torsten Clemens, Jonas Wegner, Mohamed Abdelmoula, Taoufik Manai
Summary Underground hydrogen storage (UHS) has the potential to balance fluctuating sustainable energy generation and energy demand by offering large-scale seasonal energy storage. Depleted natural gas fields or underground gas storage fields are attractive for UHS as they might allow for cost-efficient hydrogen storage. The amount of cushion gas required and the purity of the backproduced hydrogen are important cost factors in UHS. This study focuses on the role of molecular diffusion within the reservoir during UHS. Although previous research has investigated various topics of UHS such as microbial activity, UHS operations, and gas mixing, the effects of diffusion within the reservoir have not been studied in detail. To evaluate the composition of the gas produced during UHS, numerical simulation was used here. The hydrogen recovery factor and methane-to-hydrogen production ratio for cases with and without diffusive mass flux were compared. A sensitivity analysis was carried out to identify important factors for UHS, including permeability contrast, vertical-to-horizontal permeability ratio, reservoir heterogeneity, binary diffusion coefficient, and pressure-dependent diffusion. Additionally, the effect of numerical dispersion on the results was evaluated. The simulations demonstrate that diffusion plays an important role in hydrogen storage in depleted gas reservoirs or underground gas storage fields. Ignoring molecular diffusion can lead to the overestimation of the hydrogen recovery factor by up to 9% during the first production cycle and underestimation of the onset of methane contamination by half of the back production cycle. For UHS operations, both the composition and amount of hydrogen are important to design facilities and determine the economics of UHS, and hence diffusion should be evaluated in UHS simulation studies.
{"title":"The Role of Diffusion on Reservoir Performance in Underground Hydrogen Storage","authors":"Vladislav Arekhov, Torsten Clemens, Jonas Wegner, Mohamed Abdelmoula, Taoufik Manai","doi":"10.2118/214435-pa","DOIUrl":"https://doi.org/10.2118/214435-pa","url":null,"abstract":"Summary Underground hydrogen storage (UHS) has the potential to balance fluctuating sustainable energy generation and energy demand by offering large-scale seasonal energy storage. Depleted natural gas fields or underground gas storage fields are attractive for UHS as they might allow for cost-efficient hydrogen storage. The amount of cushion gas required and the purity of the backproduced hydrogen are important cost factors in UHS. This study focuses on the role of molecular diffusion within the reservoir during UHS. Although previous research has investigated various topics of UHS such as microbial activity, UHS operations, and gas mixing, the effects of diffusion within the reservoir have not been studied in detail. To evaluate the composition of the gas produced during UHS, numerical simulation was used here. The hydrogen recovery factor and methane-to-hydrogen production ratio for cases with and without diffusive mass flux were compared. A sensitivity analysis was carried out to identify important factors for UHS, including permeability contrast, vertical-to-horizontal permeability ratio, reservoir heterogeneity, binary diffusion coefficient, and pressure-dependent diffusion. Additionally, the effect of numerical dispersion on the results was evaluated. The simulations demonstrate that diffusion plays an important role in hydrogen storage in depleted gas reservoirs or underground gas storage fields. Ignoring molecular diffusion can lead to the overestimation of the hydrogen recovery factor by up to 9% during the first production cycle and underestimation of the onset of methane contamination by half of the back production cycle. For UHS operations, both the composition and amount of hydrogen are important to design facilities and determine the economics of UHS, and hence diffusion should be evaluated in UHS simulation studies.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-11-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135340406","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Ibrahim Gomaa, Javier Guerrero, Zoya Heidari, D. Nicolas Espinoza
Summary Geological sequestration of carbon dioxide (CO2) in depleted gas reservoirs represents a cost-effective solution to mitigate global carbon emissions. The surface chemistry of the reservoir rock, pressure, temperature, and moisture content are critical factors that determine the CO2 adsorption capacity and storage mechanisms. Shale-gas reservoirs are good candidates for this application. However, the interactions between CO2 and organic content still need further investigation. The objectives of this paper are to (i) experimentally evaluate the adsorption isotherm of CO2 on activated carbon, (ii) quantify the nanoscale interfacial interactions between CO2 and the activated carbon surface using Monte Carlo (MC) and molecular dynamic (MD) simulations, (iii) evaluate the modeling reliability using experimental measurements, and (iv) quantify the influence of temperature and geochemistry on the adsorption behavior of CO2 on the surface of activated carbon. These objectives aim at obtaining a better understanding of the behavior of CO2 injection and storage in the kerogen structure of shale-gas formations, where activated carbon is used as a proxy for thermally mature kerogen. We performed experimental measurements, grand canonical Monte Carlo (GCMC) simulations, and MD simulations of CO2 adsorption and diffusion on activated carbon. The experimental work involved measurements of the high-pressure adsorption capacity of activated carbon using pure CO2 gas at a temperature of 300 K. The simulation work started with modeling and validating an activated carbon structure by calibrating the GCMC simulations with experimental CO2 adsorption measurements. Then, we extended the simulation work to quantify the adsorption isotherms at a temperature range of 250–500 K and various surface chemistry conditions. Moreover, CO2 self-diffusion coefficients were quantified at gas pressures of 0.5 MPa, 1 MPa, and 2 MPa using MD simulations. The experimental results showed a typical CO2 excess adsorption trend for the nanoporous structures, with a density of the sorbed gas phase of 504.76 kg/m3. The simulation results were in agreement with experimental adsorption isotherms with a 10.6% average absolute relative difference. The self-diffusion results showed a decrease in gas diffusion with increasing pressure due to the increase in the adsorbed gas amount. Increasing the simulation temperature from 300 K to 400 K led to a decrease in the amount of adsorbed CO2 molecules by about 87% at 2 MPa pressure. Finally, the presence of charged functional groups (e.g., hydroxyl–OH and carboxyl–COOH) led to an increase in the adsorption of CO2 gas to the activated carbon surface. The outcomes of this paper provide new insights about the parameters affecting CO2 adsorption and sequestration in depleted shale-gas reservoirs. This in turn helps in screening the candidate shale-gas reservoirs for carbon capture, sequestration, and storage to maximize the CO2 storage capacity.
{"title":"Experimental Measurements and Molecular Simulation of Carbon Dioxide Adsorption on Carbon Surface","authors":"Ibrahim Gomaa, Javier Guerrero, Zoya Heidari, D. Nicolas Espinoza","doi":"10.2118/210264-pa","DOIUrl":"https://doi.org/10.2118/210264-pa","url":null,"abstract":"Summary Geological sequestration of carbon dioxide (CO2) in depleted gas reservoirs represents a cost-effective solution to mitigate global carbon emissions. The surface chemistry of the reservoir rock, pressure, temperature, and moisture content are critical factors that determine the CO2 adsorption capacity and storage mechanisms. Shale-gas reservoirs are good candidates for this application. However, the interactions between CO2 and organic content still need further investigation. The objectives of this paper are to (i) experimentally evaluate the adsorption isotherm of CO2 on activated carbon, (ii) quantify the nanoscale interfacial interactions between CO2 and the activated carbon surface using Monte Carlo (MC) and molecular dynamic (MD) simulations, (iii) evaluate the modeling reliability using experimental measurements, and (iv) quantify the influence of temperature and geochemistry on the adsorption behavior of CO2 on the surface of activated carbon. These objectives aim at obtaining a better understanding of the behavior of CO2 injection and storage in the kerogen structure of shale-gas formations, where activated carbon is used as a proxy for thermally mature kerogen. We performed experimental measurements, grand canonical Monte Carlo (GCMC) simulations, and MD simulations of CO2 adsorption and diffusion on activated carbon. The experimental work involved measurements of the high-pressure adsorption capacity of activated carbon using pure CO2 gas at a temperature of 300 K. The simulation work started with modeling and validating an activated carbon structure by calibrating the GCMC simulations with experimental CO2 adsorption measurements. Then, we extended the simulation work to quantify the adsorption isotherms at a temperature range of 250–500 K and various surface chemistry conditions. Moreover, CO2 self-diffusion coefficients were quantified at gas pressures of 0.5 MPa, 1 MPa, and 2 MPa using MD simulations. The experimental results showed a typical CO2 excess adsorption trend for the nanoporous structures, with a density of the sorbed gas phase of 504.76 kg/m3. The simulation results were in agreement with experimental adsorption isotherms with a 10.6% average absolute relative difference. The self-diffusion results showed a decrease in gas diffusion with increasing pressure due to the increase in the adsorbed gas amount. Increasing the simulation temperature from 300 K to 400 K led to a decrease in the amount of adsorbed CO2 molecules by about 87% at 2 MPa pressure. Finally, the presence of charged functional groups (e.g., hydroxyl–OH and carboxyl–COOH) led to an increase in the adsorption of CO2 gas to the activated carbon surface. The outcomes of this paper provide new insights about the parameters affecting CO2 adsorption and sequestration in depleted shale-gas reservoirs. This in turn helps in screening the candidate shale-gas reservoirs for carbon capture, sequestration, and storage to maximize the CO2 storage capacity.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-09-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135385325","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Vladislav Arekhov, Timur Zhainakov, Torsten Clemens, Jonas Wegner
Summary If hydrogen is stored in depleted gas fields, the remaining hydrocarbon gas can be used as cushion gas. The composition of the backproduced gas depends on the magnitude of mixing between the hydrocarbon gas and the hydrogen injected. One important parameter that contributes to this process of mixing is molecular diffusion. Although diffusion models are incorporated in the latest commercial reservoir simulators, effective diffusion coefficients for specific rock types, pressures, temperatures, and gas compositions are not available in the literature. Thus, laboratory measurements were performed to improve storage performance predictions for an underground hydrogen storage (UHS) project in Austria. An experimental setup was developed that enables measurements of effective multicomponent gas diffusion coefficients. Gas concentrations are detected using infrared light spectroscopy, which eliminates the necessity of gas sampling. To test the accuracy of the apparatus, binary diffusion coefficients were determined using different gases and at multiple pressures and temperatures. Effective diffusion coefficients were then determined for different rock types. Experiments were performed multiple times for quality control and to test reproducibility. The measured binary diffusion coefficients without porous media show a very good agreement with the published literature data and available correlations based on the kinetic gas theory (Chapman-Enskog, Fuller-Schettler-Giddings). Measurements of effective diffusion coefficients were performed for three different rock types that represent various facies in a UHS project in Austria. A correlation between static rock properties and effective diffusion coefficients was established and used as input to improve the numerical model of the UHS. This input is crucial for the simulation of backproduced gas composition and properties which are essential parameters for storage economics. In addition, the results show the impact of pressure on effective diffusion coefficients, which impacts UHS performance.
{"title":"Measurement of Effective Hydrogen-Methane Gas Diffusion Coefficients in Reservoir Rocks","authors":"Vladislav Arekhov, Timur Zhainakov, Torsten Clemens, Jonas Wegner","doi":"10.2118/214451-pa","DOIUrl":"https://doi.org/10.2118/214451-pa","url":null,"abstract":"Summary If hydrogen is stored in depleted gas fields, the remaining hydrocarbon gas can be used as cushion gas. The composition of the backproduced gas depends on the magnitude of mixing between the hydrocarbon gas and the hydrogen injected. One important parameter that contributes to this process of mixing is molecular diffusion. Although diffusion models are incorporated in the latest commercial reservoir simulators, effective diffusion coefficients for specific rock types, pressures, temperatures, and gas compositions are not available in the literature. Thus, laboratory measurements were performed to improve storage performance predictions for an underground hydrogen storage (UHS) project in Austria. An experimental setup was developed that enables measurements of effective multicomponent gas diffusion coefficients. Gas concentrations are detected using infrared light spectroscopy, which eliminates the necessity of gas sampling. To test the accuracy of the apparatus, binary diffusion coefficients were determined using different gases and at multiple pressures and temperatures. Effective diffusion coefficients were then determined for different rock types. Experiments were performed multiple times for quality control and to test reproducibility. The measured binary diffusion coefficients without porous media show a very good agreement with the published literature data and available correlations based on the kinetic gas theory (Chapman-Enskog, Fuller-Schettler-Giddings). Measurements of effective diffusion coefficients were performed for three different rock types that represent various facies in a UHS project in Austria. A correlation between static rock properties and effective diffusion coefficients was established and used as input to improve the numerical model of the UHS. This input is crucial for the simulation of backproduced gas composition and properties which are essential parameters for storage economics. In addition, the results show the impact of pressure on effective diffusion coefficients, which impacts UHS performance.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-09-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136015182","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Summary North Sea Chalk reservoirs in Norway are potential candidates for enhanced hydrocarbon recovery by modifying the injected brine composition. This work investigates how barium (Ba), strontium (Sr), and magnesium (Mg) brines interact when injected into chalk. Ba and Sr are often associated with mineral precipitation and occur in formation water, while Mg is present in seawater, commonly injected in chalk. Relatively clean (>99% calcite) outcrop chalk cores from Mons, Belgium, were flooded at 130°C in triaxial cells with four brines containing 0.12 mol/L divalent cations, either 0.06 mol/L Sr and Ba, 0.06 mol/L Sr and Mg, or 0.12 mol/L Ba or Sr. Each brine was injected in a separate core, with 100–150 pore volumes (PV). The injection rate varied between 0.5 and 8 PV/D. Produced brine was analyzed continuously and compared with the injected composition. After flooding, the cores flooded with only Ba or only Sr were cut into slices and analyzed locally in terms of scanning electron microscopy (SEM), matrix density, specific surface area (SSA), and X-ray diffraction (XRD). In all experiments, the produced divalent cation concentration was reduced compared with the injected value. The total reduction of injected cation concentration closely equaled the produced Ca concentration (from calcite dissolution). When flooding 0.12 mol/L Sr, the Sr concentration depleted 55%, while when flooding 0.12 mol/L Ba, 15% Ba depleted. When injecting equal concentrations of Ba and Sr, 40% Sr and 7% Ba depleted, while with equal concentrations of Mg and Sr injected, ~50% Sr was retained and almost no Mg depleted. Sr appeared to dominate and suppress other reactions. There was less sensitivity in steady-state concentrations with variation in injection rate. The similar modification of the brine regardless of residence time suggests the reactions reached equilibrium. Cutting the cores revealed a visually clear front a few centimeters from the inlet. The material past the front was indistinguishable from unflooded chalk in terms of density, SSA, microscale structure, porosity, and composition [XRD and SEM-energy-dispersive spectroscopy (EDS)]. The material near the inlet was clearly altered. Images, XRD, SEM-EDS, and geochemical simulations indicated that BaCO3 and SrCO3 formed during BaCl2 and SrCl2 flooding, respectively. Geochemical simulations also predicted an equal exchange of cations to occur. The matrix densities, porosities, and the distance traveled by the front corresponded with these minerals and suggested that the chalk was completely converted to these minerals behind the front. It was demonstrated that Ba, Sr, and Mg brines and their mixtures can be highly reactive in chalk without clogging the core, even after 100 + PV. This is because the precipitation of minerals bearing these ions is associated with simultaneous dissolution of calcite. The Ca-, Ba-, and Sr-mineral reactions are effectively in equilibrium. Previous investigations with MgCl2
{"title":"Flow-Through Experiments of Reactive Ba-Sr-Mg Brines in Mons Chalk at North Sea Reservoir Temperature at Different Injection Rates","authors":"Pål Østebø Andersen, Sander Sunde Herlofsen, Reidar Inge Korsnes, Mona Wetrhus Minde","doi":"10.2118/214367-pa","DOIUrl":"https://doi.org/10.2118/214367-pa","url":null,"abstract":"Summary North Sea Chalk reservoirs in Norway are potential candidates for enhanced hydrocarbon recovery by modifying the injected brine composition. This work investigates how barium (Ba), strontium (Sr), and magnesium (Mg) brines interact when injected into chalk. Ba and Sr are often associated with mineral precipitation and occur in formation water, while Mg is present in seawater, commonly injected in chalk. Relatively clean (>99% calcite) outcrop chalk cores from Mons, Belgium, were flooded at 130°C in triaxial cells with four brines containing 0.12 mol/L divalent cations, either 0.06 mol/L Sr and Ba, 0.06 mol/L Sr and Mg, or 0.12 mol/L Ba or Sr. Each brine was injected in a separate core, with 100–150 pore volumes (PV). The injection rate varied between 0.5 and 8 PV/D. Produced brine was analyzed continuously and compared with the injected composition. After flooding, the cores flooded with only Ba or only Sr were cut into slices and analyzed locally in terms of scanning electron microscopy (SEM), matrix density, specific surface area (SSA), and X-ray diffraction (XRD). In all experiments, the produced divalent cation concentration was reduced compared with the injected value. The total reduction of injected cation concentration closely equaled the produced Ca concentration (from calcite dissolution). When flooding 0.12 mol/L Sr, the Sr concentration depleted 55%, while when flooding 0.12 mol/L Ba, 15% Ba depleted. When injecting equal concentrations of Ba and Sr, 40% Sr and 7% Ba depleted, while with equal concentrations of Mg and Sr injected, ~50% Sr was retained and almost no Mg depleted. Sr appeared to dominate and suppress other reactions. There was less sensitivity in steady-state concentrations with variation in injection rate. The similar modification of the brine regardless of residence time suggests the reactions reached equilibrium. Cutting the cores revealed a visually clear front a few centimeters from the inlet. The material past the front was indistinguishable from unflooded chalk in terms of density, SSA, microscale structure, porosity, and composition [XRD and SEM-energy-dispersive spectroscopy (EDS)]. The material near the inlet was clearly altered. Images, XRD, SEM-EDS, and geochemical simulations indicated that BaCO3 and SrCO3 formed during BaCl2 and SrCl2 flooding, respectively. Geochemical simulations also predicted an equal exchange of cations to occur. The matrix densities, porosities, and the distance traveled by the front corresponded with these minerals and suggested that the chalk was completely converted to these minerals behind the front. It was demonstrated that Ba, Sr, and Mg brines and their mixtures can be highly reactive in chalk without clogging the core, even after 100 + PV. This is because the precipitation of minerals bearing these ions is associated with simultaneous dissolution of calcite. The Ca-, Ba-, and Sr-mineral reactions are effectively in equilibrium. Previous investigations with MgCl2 ","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-08-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135033693","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Waterflooding will open natural fractures to form induced fractures, which differ from hydraulic fractures because the hydraulic fracture is filled with proppant but the induced fracture is not. Natural fractures are connected by waterflooding. However, because the waterflooding pressure is limited, induced fractures cannot run through the entire reservoir but instead form multiple parallel induced-fracture bands in the vertical direction. Currently, using conventional finite-conductivity methods to match field data will obtain unreasonable results, especially the half-length, conductivity of fracture, and reservoir permeability, which lead to the water breakthrough, which cannot be found in time. This paper presents the waterflooding-induced bilayer fracture (WIBF) model, considering induced-fracture dynamic closure (IDC), dynamic induced-fracture storage (DIS), and induced-fracture radial flow (IRF) effects. Two innovative flow regimes are interpreted, which are dynamic induced-fracture flow and early radial flow regimes. Five innovation parameters are introduced into the WIBF model to describe the IDC, DIS, and IRF effects. The WIBF model is calculated and solved by the Green equation and Newman product methods. Induced-fracture storage coefficient and half-length closure equations are derived to characterize the unique induced-fracture properties. Analytical and numerical methods verify the model’s accuracy. The WIBF model matches a type field case to prove its practicability. Results show that compared with the conventional finite-conductivity model, the proposed model matches the field case well and the interpreted parameters are consistent with the water injection profile and actual field data. The pressure derivative curve shows an early horizontal line, identified as a pressure response of bilayer-induced fractures. If the flow regime is misidentified as pseudoradial flow, some obtained parameters will be absurd, and permeability will be amplified many times. In conclusion, physical and mathematical models are established to describe induced fracture. Induced-fracture storage coefficient and half-length equations are derived. Model matching and equation calculation methods are mutually validated to improve the accuracy of the obtained parameters. Dynamic induced-fracture half-length is interpreted quantitatively to make the engineer take action before the water breakthrough. The model in this paper also provides some parameters for infilling well patterns or determining well spacing economically.
{"title":"Evaluation of Effects of Waterflooding-Induced Bilayer Fractures on Tight Reservoir Using Pressure-Transient Analysis Method","authors":"Zhipeng Wang, Z. Ning, J. Zhan, Wen-ming Guo","doi":"10.2118/217442-pa","DOIUrl":"https://doi.org/10.2118/217442-pa","url":null,"abstract":"\u0000 Waterflooding will open natural fractures to form induced fractures, which differ from hydraulic fractures because the hydraulic fracture is filled with proppant but the induced fracture is not. Natural fractures are connected by waterflooding. However, because the waterflooding pressure is limited, induced fractures cannot run through the entire reservoir but instead form multiple parallel induced-fracture bands in the vertical direction. Currently, using conventional finite-conductivity methods to match field data will obtain unreasonable results, especially the half-length, conductivity of fracture, and reservoir permeability, which lead to the water breakthrough, which cannot be found in time. This paper presents the waterflooding-induced bilayer fracture (WIBF) model, considering induced-fracture dynamic closure (IDC), dynamic induced-fracture storage (DIS), and induced-fracture radial flow (IRF) effects. Two innovative flow regimes are interpreted, which are dynamic induced-fracture flow and early radial flow regimes. Five innovation parameters are introduced into the WIBF model to describe the IDC, DIS, and IRF effects. The WIBF model is calculated and solved by the Green equation and Newman product methods. Induced-fracture storage coefficient and half-length closure equations are derived to characterize the unique induced-fracture properties. Analytical and numerical methods verify the model’s accuracy. The WIBF model matches a type field case to prove its practicability. Results show that compared with the conventional finite-conductivity model, the proposed model matches the field case well and the interpreted parameters are consistent with the water injection profile and actual field data. The pressure derivative curve shows an early horizontal line, identified as a pressure response of bilayer-induced fractures. If the flow regime is misidentified as pseudoradial flow, some obtained parameters will be absurd, and permeability will be amplified many times. In conclusion, physical and mathematical models are established to describe induced fracture. Induced-fracture storage coefficient and half-length equations are derived. Model matching and equation calculation methods are mutually validated to improve the accuracy of the obtained parameters. Dynamic induced-fracture half-length is interpreted quantitatively to make the engineer take action before the water breakthrough. The model in this paper also provides some parameters for infilling well patterns or determining well spacing economically.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":null,"pages":null},"PeriodicalIF":2.1,"publicationDate":"2023-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84215750","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Subsurface river systems constitute one of three major paleokarst types that make up Ordovician reservoirs in the Tahe area of the Tarim Basin. The total length of the river system is approximately 400 km, and the reserves associated with this karst type are more than 200 million tons. However, it is manifested that 47% of drilled wells have not encountered river paleokarst, while 50% of wells that have encountered river paleokarst are fully filled due to the poor understanding of the paleokarst of this region, resulting in a significant variation of production capacities. In this study, we propose a detailed data integration approach with outcrops, drilling, logging, seismic profiles, and dynamic data to delineate the complex paleokarst river system in the Tahe area. The karst geological theory with reservoir characterization is combined in particular. The workflow of clarifying the main controlling factors, architecture types, and development distribution modes of the subsurface river system is established. Fill material type, sequence of fill structure, and fill controlling factors are also revealed. A quantitative characterization method of the subsurface rivers is established adopting predictions based on seismic data and high-resolution geostatistical and geological modeling. The Ordovician reservoirs in the Tahe area comprise three paleokarst river systems with different characteristics. Karst paleogeomorphology is the main control over the overall flow direction and plane distribution of the subsurface rivers. Changes in the surface of the phreatic zone are crucial in controlling the vertical layers and scale of the rivers. The combined action of faults plays a decisive role in controlling the anastomosing pattern of the rivers. Single-branch channels, reticulated channels, and structural corridors in single-layer or multilayer styles are the main subsurface river types. Trunk channels, branch channels, hall caves, and inlets/outlets are dominant structures in the architecture of the river system. Sand-mud, breccia, and chemically precipitated materials are the most common fill types. Three typical sequences of fill structure and four spatial combination modes exist in the subsurface river system. The morphology and fill characteristics of rivers are predictable using seismic attributes, such as frequency division energy, frequency division inversion, and coherent energy gradient. 3D models are constructed by multivariate control multipoint geostatistical method, which can characterize the strong heterogeneity characteristics of subsurface river systems. This complex paleokarst system enables remarkable results for the adjustment of the reservoir development plan through quantitative characterization.
{"title":"Genesis, Distribution, and Characterization of a Paleokarst Subsurface River System in the Tahe Area, Tarim Basin, Western China","authors":"Xinrui Lyu, B. Ju, Xingwei Wu, Fengying Xiao","doi":"10.2118/217450-pa","DOIUrl":"https://doi.org/10.2118/217450-pa","url":null,"abstract":"\u0000 Subsurface river systems constitute one of three major paleokarst types that make up Ordovician reservoirs in the Tahe area of the Tarim Basin. The total length of the river system is approximately 400 km, and the reserves associated with this karst type are more than 200 million tons. However, it is manifested that 47% of drilled wells have not encountered river paleokarst, while 50% of wells that have encountered river paleokarst are fully filled due to the poor understanding of the paleokarst of this region, resulting in a significant variation of production capacities. In this study, we propose a detailed data integration approach with outcrops, drilling, logging, seismic profiles, and dynamic data to delineate the complex paleokarst river system in the Tahe area. The karst geological theory with reservoir characterization is combined in particular. The workflow of clarifying the main controlling factors, architecture types, and development distribution modes of the subsurface river system is established. Fill material type, sequence of fill structure, and fill controlling factors are also revealed. A quantitative characterization method of the subsurface rivers is established adopting predictions based on seismic data and high-resolution geostatistical and geological modeling. The Ordovician reservoirs in the Tahe area comprise three paleokarst river systems with different characteristics. Karst paleogeomorphology is the main control over the overall flow direction and plane distribution of the subsurface rivers. Changes in the surface of the phreatic zone are crucial in controlling the vertical layers and scale of the rivers. The combined action of faults plays a decisive role in controlling the anastomosing pattern of the rivers. Single-branch channels, reticulated channels, and structural corridors in single-layer or multilayer styles are the main subsurface river types. Trunk channels, branch channels, hall caves, and inlets/outlets are dominant structures in the architecture of the river system. Sand-mud, breccia, and chemically precipitated materials are the most common fill types. Three typical sequences of fill structure and four spatial combination modes exist in the subsurface river system. The morphology and fill characteristics of rivers are predictable using seismic attributes, such as frequency division energy, frequency division inversion, and coherent energy gradient. 3D models are constructed by multivariate control multipoint geostatistical method, which can characterize the strong heterogeneity characteristics of subsurface river systems. This complex paleokarst system enables remarkable results for the adjustment of the reservoir development plan through quantitative characterization.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":null,"pages":null},"PeriodicalIF":2.1,"publicationDate":"2023-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84844492","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper presents an overview of both current advancements and field applications of offshore chemical flooding technologies. Along with offshore oilfield development strategies that require the maximization of oil production in a short development cycle, chemical flooding can become a potential avenue to accelerate oil production in secondary oil recovery mode. This makes it different from onshore chemical flooding processes that mostly focus on enhanced oil recovery in mature or maturing reservoirs. The advancements in offshore chemical flooding field applications are reviewed and analyzed. By summarizing offshore application cases, the presented analysis also assesses the chemical formulations applied or studied and injection/production facilities required in offshore environments. The main technical challenges are also discussed for scaling up the applications on offshore platforms or floating production storage and offloading (FPSO) systems. The chemical flooding technologies reviewed include polymer flooding, surfactant-polymer (SP) flooding, and alkaline-surfactant-polymer (ASP) flooding. By assessing the technology readiness level of these technologies, this study presents their perspectives and practical relevance for offshore chemical flooding applications. It has been long realized that chemical flooding, especially polymer flooding, can improve oil recovery in offshore oil fields. The applications in Bohai Bay (China), Dalia (Angola), and Captain (North Sea) provide the know-how workflows for offshore polymer flooding from laboratory to full-field applications. It is feasible to implement offshore polymer injection either on a platform or in an FPSO system. It is recommended to implement polymer flooding at an early stage of reservoir development to maximize the investment in offshore facilities. By tuning the chemistry of polymer products, they can present very good compatibility with seawaters. Therefore, choosing a proper polymer is no longer a big issue for offshore polymer flooding. There are also some interesting findings reported on the development of novel surfactant chemistries for offshore applications. The outcome from a number of small-scale trials, including the single-well chemical tracer tests on surfactant, alkaline-surfactant (AS), and SP in offshore Malaysia, Abu Dhabi, Qatar, and South China Sea, provided valuable insights for the feasibility of chemical flooding in offshore environments. However, the technology readiness levels of surfactant-based chemical flooding processes are still low, partially due to their complex interactions with subsurface fluids and the lack of interest in producing residual oil from matured offshore reservoirs. Based on the lessons learned from offshore applications, it can be concluded that several major challenges still need to be overcome in terms of large well spacing, reservoir voidage, produced fluid treatment, and high operational expense to successfully scale up surfactant-
{"title":"Review of Offshore Chemical Flooding Field Applications and Key Lessons Learned","authors":"M. Han, S. Ayirala, Ali A. Al-Yousef","doi":"10.2118/209473-pa","DOIUrl":"https://doi.org/10.2118/209473-pa","url":null,"abstract":"\u0000 This paper presents an overview of both current advancements and field applications of offshore chemical flooding technologies. Along with offshore oilfield development strategies that require the maximization of oil production in a short development cycle, chemical flooding can become a potential avenue to accelerate oil production in secondary oil recovery mode. This makes it different from onshore chemical flooding processes that mostly focus on enhanced oil recovery in mature or maturing reservoirs. The advancements in offshore chemical flooding field applications are reviewed and analyzed. By summarizing offshore application cases, the presented analysis also assesses the chemical formulations applied or studied and injection/production facilities required in offshore environments. The main technical challenges are also discussed for scaling up the applications on offshore platforms or floating production storage and offloading (FPSO) systems.\u0000 The chemical flooding technologies reviewed include polymer flooding, surfactant-polymer (SP) flooding, and alkaline-surfactant-polymer (ASP) flooding. By assessing the technology readiness level of these technologies, this study presents their perspectives and practical relevance for offshore chemical flooding applications. It has been long realized that chemical flooding, especially polymer flooding, can improve oil recovery in offshore oil fields. The applications in Bohai Bay (China), Dalia (Angola), and Captain (North Sea) provide the know-how workflows for offshore polymer flooding from laboratory to full-field applications. It is feasible to implement offshore polymer injection either on a platform or in an FPSO system. It is recommended to implement polymer flooding at an early stage of reservoir development to maximize the investment in offshore facilities. By tuning the chemistry of polymer products, they can present very good compatibility with seawaters. Therefore, choosing a proper polymer is no longer a big issue for offshore polymer flooding.\u0000 There are also some interesting findings reported on the development of novel surfactant chemistries for offshore applications. The outcome from a number of small-scale trials, including the single-well chemical tracer tests on surfactant, alkaline-surfactant (AS), and SP in offshore Malaysia, Abu Dhabi, Qatar, and South China Sea, provided valuable insights for the feasibility of chemical flooding in offshore environments. However, the technology readiness levels of surfactant-based chemical flooding processes are still low, partially due to their complex interactions with subsurface fluids and the lack of interest in producing residual oil from matured offshore reservoirs. Based on the lessons learned from offshore applications, it can be concluded that several major challenges still need to be overcome in terms of large well spacing, reservoir voidage, produced fluid treatment, and high operational expense to successfully scale up surfactant-","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":null,"pages":null},"PeriodicalIF":2.1,"publicationDate":"2023-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84824403","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper examines the buildup (BU) pressure response of a vertical well that penetrates an unconventional tight naturally fractured carbonate reservoir in Mexico. Four BUs in the same well over a period of 4 months, with intermediate flow periods, suggest partial closure of natural fractures. Radial flow is dominant in the four BUs. This is recognized in semilogarithmic and pressure derivative crossplots. However, the formulations require a consistent empirical component to match the BU data. The four BU tests are evaluated with a semi-empirical dual porosity model with restricted interporosity flow. The restricted flow between matrix and fractures is the result of partial secondary mineralization (cementation) within the fractures, which can be visualized as a natural positive skin that reduces the oil flow from the matrix to the fractures. The empirical part of the method is provided by a severity exponent (SE), which helps improve the match between the BU semilog and derivative plots. The BU evaluations permit estimating several parameters of interest, including fracture capacity (k2·h), skin, storativity ratio (ω), and the extrapolated pressure (p*). Results suggest that although natural fractures are present, they tend to close once the well goes on production. Thus, the conclusion is reached that the carbonate reservoir is tight and likely stress dependent. The calculated skin goes from an improved condition around the wellbore to slightly damaged conditions, probably due to fracture closure. The value of ω increases continuously, suggesting a tendency of the reservoir to move from dual to single porosity behavior. The reservoir is overpressured (0.87 psi/ft) and the extrapolated pressures (p*) decrease because of the tight characteristics of the reservoir. However, given the large size of the reservoir, the likelihood of depletion is low. The novelty of this study is the development of a new easy-to-use semi-empirical well testing model for matching the BU pressure response of four tests performed in a well that penetrates an overpressured, unconventional, tight, naturally fractured carbonate reservoir. The tests could not be matched with conventional methods currently available in the literature.
{"title":"Buildup Evaluation of a Tight Overpressured Naturally Fractured Carbonate Reservoir with the Use of a Semi-Empirical Model","authors":"Brenda Azuara Diliegros, R. Aguilera","doi":"10.2118/212724-pa","DOIUrl":"https://doi.org/10.2118/212724-pa","url":null,"abstract":"\u0000 This paper examines the buildup (BU) pressure response of a vertical well that penetrates an unconventional tight naturally fractured carbonate reservoir in Mexico. Four BUs in the same well over a period of 4 months, with intermediate flow periods, suggest partial closure of natural fractures. Radial flow is dominant in the four BUs. This is recognized in semilogarithmic and pressure derivative crossplots. However, the formulations require a consistent empirical component to match the BU data.\u0000 The four BU tests are evaluated with a semi-empirical dual porosity model with restricted interporosity flow. The restricted flow between matrix and fractures is the result of partial secondary mineralization (cementation) within the fractures, which can be visualized as a natural positive skin that reduces the oil flow from the matrix to the fractures. The empirical part of the method is provided by a severity exponent (SE), which helps improve the match between the BU semilog and derivative plots.\u0000 The BU evaluations permit estimating several parameters of interest, including fracture capacity (k2·h), skin, storativity ratio (ω), and the extrapolated pressure (p*). Results suggest that although natural fractures are present, they tend to close once the well goes on production. Thus, the conclusion is reached that the carbonate reservoir is tight and likely stress dependent. The calculated skin goes from an improved condition around the wellbore to slightly damaged conditions, probably due to fracture closure. The value of ω increases continuously, suggesting a tendency of the reservoir to move from dual to single porosity behavior. The reservoir is overpressured (0.87 psi/ft) and the extrapolated pressures (p*) decrease because of the tight characteristics of the reservoir. However, given the large size of the reservoir, the likelihood of depletion is low.\u0000 The novelty of this study is the development of a new easy-to-use semi-empirical well testing model for matching the BU pressure response of four tests performed in a well that penetrates an overpressured, unconventional, tight, naturally fractured carbonate reservoir. The tests could not be matched with conventional methods currently available in the literature.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":null,"pages":null},"PeriodicalIF":2.1,"publicationDate":"2023-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87648243","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
To accurately predict saturation pressures for gas(es)-heavy oil/bitumen-water systems, several α functions have been selected and evaluated at a reduced temperature (Tr) of 0.70 and 0.60 for the Soave-Redlich-Kwong equation of state (EOS) and Peng-Robinson (PR) EOS, respectively. More specifically, 164 data points of measured saturation pressures of gas(es)-heavy oil/bitumen-water systems are collected from the public domain, while all α functions developed for heavy oil-associated mixtures and water have been reviewed and selected. At Tr = 0.70, the former, including three existing α functions, as well as two newly developed α functions at Tr = 0.70 together with three new α functions at Tr = 0.60, and the latter, including two alpha functions, are used to evaluate saturation pressures for various gas(es)-heavy oil/bitumen-water systems under various conditions. The absolute average relative deviation (AARD) between the measured saturation pressures and their predicted ones is found to decrease with either an increase in the pseudocomponent (PC) number or redefining the acentric factor (ω) at Tr = 0.60 other than the conventional one at Tr = 0.70. In addition to validating our coded program, the CMG WinProp module, together with its default binary interaction parameters (BIPs) is used to, respectively, quantify saturation pressures of the aforementioned systems with an overall AARD of 27.34 and 28.39% for the PR EOS and SRK EOS. The recommended α function newly developed at Tr = 0.60 by Chen and Yang (2017) predicts saturation pressures more accurately with an overall AARD of 3.88 and 1.64% by, respectively, treating the heavy oil as one PC and six PCs.
{"title":"Comparative Evaluation of a Functions for the Soave-Redlich-Kwong Equation of State and the Peng-Robinson Equation of State to Predict Saturation Pressures for Gas(es)-Heavy Oil/Bitumen-Water Systems","authors":"Esther Anyi Atonge, Daoyong Yang","doi":"10.2118/215835-pa","DOIUrl":"https://doi.org/10.2118/215835-pa","url":null,"abstract":"\u0000 To accurately predict saturation pressures for gas(es)-heavy oil/bitumen-water systems, several α functions have been selected and evaluated at a reduced temperature (Tr) of 0.70 and 0.60 for the Soave-Redlich-Kwong equation of state (EOS) and Peng-Robinson (PR) EOS, respectively. More specifically, 164 data points of measured saturation pressures of gas(es)-heavy oil/bitumen-water systems are collected from the public domain, while all α functions developed for heavy oil-associated mixtures and water have been reviewed and selected. At Tr = 0.70, the former, including three existing α functions, as well as two newly developed α functions at Tr = 0.70 together with three new α functions at Tr = 0.60, and the latter, including two alpha functions, are used to evaluate saturation pressures for various gas(es)-heavy oil/bitumen-water systems under various conditions. The absolute average relative deviation (AARD) between the measured saturation pressures and their predicted ones is found to decrease with either an increase in the pseudocomponent (PC) number or redefining the acentric factor (ω) at Tr = 0.60 other than the conventional one at Tr = 0.70. In addition to validating our coded program, the CMG WinProp module, together with its default binary interaction parameters (BIPs) is used to, respectively, quantify saturation pressures of the aforementioned systems with an overall AARD of 27.34 and 28.39% for the PR EOS and SRK EOS. The recommended α function newly developed at Tr = 0.60 by Chen and Yang (2017) predicts saturation pressures more accurately with an overall AARD of 3.88 and 1.64% by, respectively, treating the heavy oil as one PC and six PCs.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":null,"pages":null},"PeriodicalIF":2.1,"publicationDate":"2023-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86349858","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The lateral and vertical variations in porosity significantly impact the reservoir quality and the volumetric calculations in heterogeneous reservoirs. With a case study from Iran’s Zagros Basin Sarvak reservoir in the Dezful Embayment, this paper aims to demonstrate an efficient methodology for distributing porosity. Four facies models (based on electrofacies analysis data and seismic facies) with different geostatistical algorithms were used to examine the effect of different facies types on porosity propagation. Both deterministic and stochastic methods are adopted to check the impact of geostatistical algorithms on porosity modeling in the static model. A total of 40 scenarios were run and validated for porosity distribution through a blind test procedure to check the reliability of the models. The study’s findings revealed high correlation values in the blind test data for all porosity realizations linked to seismic facies, ranging from 0.778 to 0.876. In addition, co-kriging to acoustic impedance (AI), as a secondary variable, increases the correlation coefficient in all related cases. Unlike deterministic algorithms, using stochastic methods reduces the uncertainty and causes the porosity model to have an identical histogram compared with the original data. This study introduced a comprehensive workflow for porosity distribution in the studied carbonate Sarvak reservoir, considering the electrofacies, and seismic facies, and applying different geostatistical algorithms. As a result, based on this workflow, simultaneously linking the porosity distribution to seismic facies, co-kriging to AI, and applying the sequential Gaussian simulation (SGS) algorithm result in the best spatial modeling of porosity.
{"title":"The Best Scenario for Geostatistical Modeling of Porosity in the Sarvak Reservoir in an Iranian Oil Field, Using Electrofacies, Seismic Facies, and Seismic Attributes","authors":"V. Mehdipour, A. Rabbani, A. Kadkhodaie","doi":"10.2118/217428-pa","DOIUrl":"https://doi.org/10.2118/217428-pa","url":null,"abstract":"\u0000 The lateral and vertical variations in porosity significantly impact the reservoir quality and the volumetric calculations in heterogeneous reservoirs. With a case study from Iran’s Zagros Basin Sarvak reservoir in the Dezful Embayment, this paper aims to demonstrate an efficient methodology for distributing porosity. Four facies models (based on electrofacies analysis data and seismic facies) with different geostatistical algorithms were used to examine the effect of different facies types on porosity propagation. Both deterministic and stochastic methods are adopted to check the impact of geostatistical algorithms on porosity modeling in the static model. A total of 40 scenarios were run and validated for porosity distribution through a blind test procedure to check the reliability of the models. The study’s findings revealed high correlation values in the blind test data for all porosity realizations linked to seismic facies, ranging from 0.778 to 0.876. In addition, co-kriging to acoustic impedance (AI), as a secondary variable, increases the correlation coefficient in all related cases. Unlike deterministic algorithms, using stochastic methods reduces the uncertainty and causes the porosity model to have an identical histogram compared with the original data. This study introduced a comprehensive workflow for porosity distribution in the studied carbonate Sarvak reservoir, considering the electrofacies, and seismic facies, and applying different geostatistical algorithms. As a result, based on this workflow, simultaneously linking the porosity distribution to seismic facies, co-kriging to AI, and applying the sequential Gaussian simulation (SGS) algorithm result in the best spatial modeling of porosity.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":null,"pages":null},"PeriodicalIF":2.1,"publicationDate":"2023-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82141910","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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