M. Khan, I. D. Piñerez Torrijos, S. Aldeen, T. Puntervold, S. Strand
Seawater (SW) injection is an enhanced oil recovery (EOR) success in the North Sea carbonate reservoirs due to wettability alteration toward a more water-wet state. This process is triggered by the difference in composition between injection and formation water (FW). “Smartwater” with optimized ionic composition can easily be made under laboratory conditions to improve oil recovery beyond that of SW. However, in the field, its preparation may require specific water treatment processes, e.g., desalination, nanofiltration, or addition of specific salts. In this work, a naturally occurring salt called Polysulphate (PS) is investigated as an additive to produce smartwater. Outcrop chalk from Stevns Klint (SK), consisting of 98% biogenic CaCO3, was used to investigate the potential and efficiency of the PS brines to alter wettability in chalk. The solubility of PS in SW and deionized water, and brine stability at high temperatures were measured. Energy dispersive X-ray and ion chromatography were used to determine the composition of the PS salt and EOR solutions, and to evaluate the sulphate adsorption on the chalk surface, a catalyst for the wettability alteration process. Spontaneous imbibition (SI), for evaluating wettability alteration of PS brines into mixed-wet chalk was performed at 90 and 110°C and compared against the recovery performance of FW and SW. The solubility tests showed that the salt was easily soluble in both deionized water and SW with less than 5% solid residue. The deionized PS brine contained sulphate and calcium ion concentrations of 31.5 and 15.2 mM, respectively, and total salinity was 4.9 g/L. This brine composition is very promising for triggering wettability alteration in chalk. The SW PS brine contained 29.6 mM calcium ions and 55.9 mM sulphate ions, and a total salinity of 38.1 g/L. Compared with ordinary SW, this brine has the potential for improved wettability alteration in chalk due to increased sulphate content. Ion chromatography revealed that the sulphate adsorbed when PS brines were flooded through the core, which is an indication that wettability alteration can take place during brine injection. The reactivity was also enhanced by increasing the temperature from 25 to 90°C. Finally, the oil recovery tests by SI showed that PS brines were capable of inducing wettability alteration, improving oil recovery beyond that obtained by FW imbibition. The difference in oil recovery between ordinary SW and SW PS imbibition was smaller due to the already favorable composition of SW. PS brines showed a significant potential for wettability alteration in carbonates and are validated as a potential EOR additive for easy and on-site preparation of smartwater brines for carbonate oil reservoirs. PS salt, added to the EOR solution, provides the essential ions for the wettability alteration process, but further optimization is needed to characterize the optimal mixing ratios, ion compositions, and temperature ranges at which
{"title":"Polysulphate: A New Enhanced Oil Recovery Additive to Maximize the Oil Recovery From Carbonate Reservoirs at High Temperature","authors":"M. Khan, I. D. Piñerez Torrijos, S. Aldeen, T. Puntervold, S. Strand","doi":"10.2118/211443-pa","DOIUrl":"https://doi.org/10.2118/211443-pa","url":null,"abstract":"\u0000 Seawater (SW) injection is an enhanced oil recovery (EOR) success in the North Sea carbonate reservoirs due to wettability alteration toward a more water-wet state. This process is triggered by the difference in composition between injection and formation water (FW). “Smartwater” with optimized ionic composition can easily be made under laboratory conditions to improve oil recovery beyond that of SW. However, in the field, its preparation may require specific water treatment processes, e.g., desalination, nanofiltration, or addition of specific salts. In this work, a naturally occurring salt called Polysulphate (PS) is investigated as an additive to produce smartwater.\u0000 Outcrop chalk from Stevns Klint (SK), consisting of 98% biogenic CaCO3, was used to investigate the potential and efficiency of the PS brines to alter wettability in chalk. The solubility of PS in SW and deionized water, and brine stability at high temperatures were measured. Energy dispersive X-ray and ion chromatography were used to determine the composition of the PS salt and EOR solutions, and to evaluate the sulphate adsorption on the chalk surface, a catalyst for the wettability alteration process. Spontaneous imbibition (SI), for evaluating wettability alteration of PS brines into mixed-wet chalk was performed at 90 and 110°C and compared against the recovery performance of FW and SW.\u0000 The solubility tests showed that the salt was easily soluble in both deionized water and SW with less than 5% solid residue. The deionized PS brine contained sulphate and calcium ion concentrations of 31.5 and 15.2 mM, respectively, and total salinity was 4.9 g/L. This brine composition is very promising for triggering wettability alteration in chalk. The SW PS brine contained 29.6 mM calcium ions and 55.9 mM sulphate ions, and a total salinity of 38.1 g/L. Compared with ordinary SW, this brine has the potential for improved wettability alteration in chalk due to increased sulphate content.\u0000 Ion chromatography revealed that the sulphate adsorbed when PS brines were flooded through the core, which is an indication that wettability alteration can take place during brine injection. The reactivity was also enhanced by increasing the temperature from 25 to 90°C. Finally, the oil recovery tests by SI showed that PS brines were capable of inducing wettability alteration, improving oil recovery beyond that obtained by FW imbibition. The difference in oil recovery between ordinary SW and SW PS imbibition was smaller due to the already favorable composition of SW.\u0000 PS brines showed a significant potential for wettability alteration in carbonates and are validated as a potential EOR additive for easy and on-site preparation of smartwater brines for carbonate oil reservoirs. PS salt, added to the EOR solution, provides the essential ions for the wettability alteration process, but further optimization is needed to characterize the optimal mixing ratios, ion compositions, and temperature ranges at which","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"51 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83295189","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}
B. Wei, Runxue Mao, Qintao Tian, Wenhai Lei, Jun Lu, Jinyu Tang
Preformed particle gel (PPG) holds promising potential for conformance control in fractured tight reservoirs as it enables mitigation of fracture channeling with insignificant leak off to matrix. However, conventional PPG is very susceptible to shrinkage, breakage, fatigue, and even degradation when extruding through narrow fractures due to its weak and brittle network. This hampers its development and application in the oilfields. This paper presents a comprehensive laboratory evaluation of a new kind of nanocellulose (NCF)-engineered robust particle gel (N-PPG) for this application. The results demonstrated that the presence of NCF noticeably improved the mechanical properties of N-PPG. The swelling kinetics and swelling ratio (SR) of N-PPG were almost independent of salinity. We packed porous media using millimeter-sized glass beads to replicate proppant-filled fractures after hydraulic fracturing. As anticipated, N-PPG exhibited a greater resistance factor (Fr) and residual resistance factor (Frr), and its plugging efficiency reached more than 99.3%. N-PPG was hardly broken even after extruding from pore-throat geometries with Dg/Dp up to 21.4, whereas the control PPG was notably ruptured at Dg/Dp = 14.7. Herein, this tough N-PPG could provide a solution to conformance control of fractured tight reservoirs.
{"title":"Performance Evaluation of Nanocellulose-Engineered Robust Preformed Particle Gel upon Extrusion Through 1 to 1.5 mm Bead-Packed Porous Media","authors":"B. Wei, Runxue Mao, Qintao Tian, Wenhai Lei, Jun Lu, Jinyu Tang","doi":"10.2118/210259-pa","DOIUrl":"https://doi.org/10.2118/210259-pa","url":null,"abstract":"\u0000 Preformed particle gel (PPG) holds promising potential for conformance control in fractured tight reservoirs as it enables mitigation of fracture channeling with insignificant leak off to matrix. However, conventional PPG is very susceptible to shrinkage, breakage, fatigue, and even degradation when extruding through narrow fractures due to its weak and brittle network. This hampers its development and application in the oilfields. This paper presents a comprehensive laboratory evaluation of a new kind of nanocellulose (NCF)-engineered robust particle gel (N-PPG) for this application. The results demonstrated that the presence of NCF noticeably improved the mechanical properties of N-PPG. The swelling kinetics and swelling ratio (SR) of N-PPG were almost independent of salinity. We packed porous media using millimeter-sized glass beads to replicate proppant-filled fractures after hydraulic fracturing. As anticipated, N-PPG exhibited a greater resistance factor (Fr) and residual resistance factor (Frr), and its plugging efficiency reached more than 99.3%. N-PPG was hardly broken even after extruding from pore-throat geometries with Dg/Dp up to 21.4, whereas the control PPG was notably ruptured at Dg/Dp = 14.7. Herein, this tough N-PPG could provide a solution to conformance control of fractured tight reservoirs.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"12 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82095180","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}
N. Alimohammadi, M. Pooladi-Darvish, B. Rostami, M. Khosravi
Many of the naturally fractured carbonate reservoirs of the Middle East exhibit low natural-depletion recoveries. The reason is that most of their oil reserves are stored in the low-permeability host rocks and are left behind by the fast advancing gas/oil contact (GOC) and water/oil contact (WOC) in fractures. Producing the remaining oil in the large gas-invaded zone of these reservoirs has been a crucial reservoir management issue. We show in this study using experimental observations, analytical calculations, and numerical investigations that repressurizing naturally fractured reservoirs (NFRs) by crestal immiscible gas injection has the potential to produce a large portion of this remaining oil by improving gravity drainage (GD) through two main mechanisms. One is that at higher pressures, the gas-oil interfacial tension (IFT) and hence the capillary forces that control recovery by GD are lessened, allowing additional recovery. This mechanism is aided by the other one, which is swelling of the oil at higher pressures. In this way, repressurization is thought to be not only a means for pressure maintenance but also a methodology for enhanced-oil recovery (EOR). This is confirmed by both laboratory studies and field performance of large-scale gas injection projects. Despite the desire for implementation of projects of repressurization, gas availability and cost of these projects are important concerns, requiring a cost-benefit analysis. Screening and ranking methodologies have been previously presented for some EOR techniques but not for repressurization by gas in NFRs. Evaluating the performance of gas injection in NFRs is often done using methodologies such as numerical simulations, which are in-depth, costly, and tedious. The methodology developed here is simple, requiring spreadsheet calculations. To develop the methodology, we first obtain simple relations to calculate additional GD recovery by considering the interplay of capillary and gravity forces in a matrix block subjected to pressurization by equilibrium gas injection and then use experimental data from literature to show that these relations can predict primary and secondary GD recoveries to a good approximation. We also show by mechanistic studies using a history-matched numerical model that IFT reduction and oil swelling are the main mechanisms contributing to additional oil recovery. Then, we propose a methodology to screen and rank candidate NFRs for gas injection that uses commonly available reservoir data and is based upon two criteria, these being additional oil recovered from a matrix block by pressurization and required volume of gas to produce an additional barrel of oil. We then implement this methodology to more than 20 Iranian NFRs and identify six reservoirs with potential for additional recovery of more than 20%. By quantifying and including the uncertainties associated with the reservoir data, we illustrate that for the reservoirs under study, capillary pressure p
{"title":"Improvement to Gravity Drainage Recovery by Repressurization as a Criterion to Screen and Rank Naturally Fractured Reservoirs for Gas Injection","authors":"N. Alimohammadi, M. Pooladi-Darvish, B. Rostami, M. Khosravi","doi":"10.2118/212302-pa","DOIUrl":"https://doi.org/10.2118/212302-pa","url":null,"abstract":"\u0000 Many of the naturally fractured carbonate reservoirs of the Middle East exhibit low natural-depletion recoveries. The reason is that most of their oil reserves are stored in the low-permeability host rocks and are left behind by the fast advancing gas/oil contact (GOC) and water/oil contact (WOC) in fractures. Producing the remaining oil in the large gas-invaded zone of these reservoirs has been a crucial reservoir management issue. We show in this study using experimental observations, analytical calculations, and numerical investigations that repressurizing naturally fractured reservoirs (NFRs) by crestal immiscible gas injection has the potential to produce a large portion of this remaining oil by improving gravity drainage (GD) through two main mechanisms. One is that at higher pressures, the gas-oil interfacial tension (IFT) and hence the capillary forces that control recovery by GD are lessened, allowing additional recovery. This mechanism is aided by the other one, which is swelling of the oil at higher pressures. In this way, repressurization is thought to be not only a means for pressure maintenance but also a methodology for enhanced-oil recovery (EOR). This is confirmed by both laboratory studies and field performance of large-scale gas injection projects. Despite the desire for implementation of projects of repressurization, gas availability and cost of these projects are important concerns, requiring a cost-benefit analysis.\u0000 Screening and ranking methodologies have been previously presented for some EOR techniques but not for repressurization by gas in NFRs. Evaluating the performance of gas injection in NFRs is often done using methodologies such as numerical simulations, which are in-depth, costly, and tedious. The methodology developed here is simple, requiring spreadsheet calculations. To develop the methodology, we first obtain simple relations to calculate additional GD recovery by considering the interplay of capillary and gravity forces in a matrix block subjected to pressurization by equilibrium gas injection and then use experimental data from literature to show that these relations can predict primary and secondary GD recoveries to a good approximation. We also show by mechanistic studies using a history-matched numerical model that IFT reduction and oil swelling are the main mechanisms contributing to additional oil recovery. Then, we propose a methodology to screen and rank candidate NFRs for gas injection that uses commonly available reservoir data and is based upon two criteria, these being additional oil recovered from a matrix block by pressurization and required volume of gas to produce an additional barrel of oil. We then implement this methodology to more than 20 Iranian NFRs and identify six reservoirs with potential for additional recovery of more than 20%. By quantifying and including the uncertainties associated with the reservoir data, we illustrate that for the reservoirs under study, capillary pressure p","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"89 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85951856","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}
An injectivity test consists of continuously injecting a phase (water or gas) into an oil-saturated reservoir during a period. According to the analysis of the wellbore pressure behavior, this procedure estimates reservoir parameters, such as permeability and skin factor, and the volume of recoverable oil. In this context, this study proposes an approximate analytical solution for the pressure behavior during a water injectivity test on a multilayer reservoir considering multiple injection flow rates. The accuracy of the proposed solution was evaluated through comparison with a commercial finite-difference-based flow simulator in different scenarios. The results indicate a considerable agreement between the data provided by the numerical simulator and the proposed model. In addition, we successfully estimated the equivalent reservoir permeability using the proposed model with satisfactory results.
{"title":"Modeling Water Injectivity Tests under Multiple Rate Schedule: An Approximate Solution","authors":"J. L. F. B. Neto, S. Pesco, A. B. Barreto Jr","doi":"10.2118/212867-pa","DOIUrl":"https://doi.org/10.2118/212867-pa","url":null,"abstract":"\u0000 An injectivity test consists of continuously injecting a phase (water or gas) into an oil-saturated reservoir during a period. According to the analysis of the wellbore pressure behavior, this procedure estimates reservoir parameters, such as permeability and skin factor, and the volume of recoverable oil. In this context, this study proposes an approximate analytical solution for the pressure behavior during a water injectivity test on a multilayer reservoir considering multiple injection flow rates. The accuracy of the proposed solution was evaluated through comparison with a commercial finite-difference-based flow simulator in different scenarios. The results indicate a considerable agreement between the data provided by the numerical simulator and the proposed model. In addition, we successfully estimated the equivalent reservoir permeability using the proposed model with satisfactory results.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"50 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82712601","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}
F. Bouchaala, A. Mohamed, M. S. Jouini, Y. Bouzidi, M. Y. Ali
Oil production and enhanced oil recovery in carbonate reservoirs in Abu Dhabi, UAE, are largely affected by fracture systems that control the fluid path and the permeability of reservoirs. Most fracture properties, such as fracture orientations and density, are obtained by interpreting petrophysical data acquired at the wellbores, whereas fracture properties between wells are typically derived from nonzero offset seismic data. However, deriving fracture properties from seismic data is challenging, as it requires a robust methodology and a careful seismic processing procedure. In the current case study, we used the azimuthal amplitude vs. offset (AVAz) method on 3D seismic data acquired in onshore Abu Dhabi, to generate maps of fracture orientation and density in a carbonate reservoir. A sophisticated processing series was carefully performed to increase signal-to-noise ratio (SNR) and preserve seismic amplitudes. The main parameters controlling the AVAz method were investigated and optimized before being applied to the 3D seismic data. The reservoir has a high fracture density in the lower regions, but a low fracture density in the upper parts, indicating a weaker anisotropy. The resulting dominant fracture directions span from north-northwest/south-southwest to north-northeast/south-southwest, as well as from northwest/southeast to east/west, which is consistent with the primary fracture orientations determined from the interpretation of fullbore formation microimager (FMI) data acquired at well locations. These fracture systems are the result of the Late Cretaceous obduction of the Semail ophiolite, which was oriented east/west and northeast/southwest, followed by the south/north to southwest/northeast trending Late Oligocene-Miocene continent-continent collision of the Arabian and Central Iran plates along the Zagros orogenic front.
{"title":"Azimuthal Investigation of a Fractured Carbonate Reservoir","authors":"F. Bouchaala, A. Mohamed, M. S. Jouini, Y. Bouzidi, M. Y. Ali","doi":"10.2118/212873-pa","DOIUrl":"https://doi.org/10.2118/212873-pa","url":null,"abstract":"\u0000 Oil production and enhanced oil recovery in carbonate reservoirs in Abu Dhabi, UAE, are largely affected by fracture systems that control the fluid path and the permeability of reservoirs. Most fracture properties, such as fracture orientations and density, are obtained by interpreting petrophysical data acquired at the wellbores, whereas fracture properties between wells are typically derived from nonzero offset seismic data. However, deriving fracture properties from seismic data is challenging, as it requires a robust methodology and a careful seismic processing procedure. In the current case study, we used the azimuthal amplitude vs. offset (AVAz) method on 3D seismic data acquired in onshore Abu Dhabi, to generate maps of fracture orientation and density in a carbonate reservoir. A sophisticated processing series was carefully performed to increase signal-to-noise ratio (SNR) and preserve seismic amplitudes. The main parameters controlling the AVAz method were investigated and optimized before being applied to the 3D seismic data. The reservoir has a high fracture density in the lower regions, but a low fracture density in the upper parts, indicating a weaker anisotropy. The resulting dominant fracture directions span from north-northwest/south-southwest to north-northeast/south-southwest, as well as from northwest/southeast to east/west, which is consistent with the primary fracture orientations determined from the interpretation of fullbore formation microimager (FMI) data acquired at well locations. These fracture systems are the result of the Late Cretaceous obduction of the Semail ophiolite, which was oriented east/west and northeast/southwest, followed by the south/north to southwest/northeast trending Late Oligocene-Miocene continent-continent collision of the Arabian and Central Iran plates along the Zagros orogenic front.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"102 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75737662","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}
Jose Antonio Gonzalez Guevara, Silvia Maria Chavez Morales, Thalia Iveth Hernandez Hernandez, Heron Gachuz-Muro, Bruno A. Lopez Jimenez
Sixty billion barrels of oil still reside in the matrix of mature onshore and offshore Mexican reservoirs located in the southeast basins after primary and secondary recovery. Capillary and viscous forces are responsible for this amount of oil retained within the pore structure of the matrix (immobile oil). Gravitational forces are not enough to counterattack these forces due to the high fracturing intensity. On the other hand, laboratory testing demonstrates that oil residing in the matrix could be mobilized by the exothermic reaction that takes place with air injection. Air injection in homogeneous heavy and light oil sandstones and nonfractured limestones, at small or large scales during short and long periods of time, is feasible for producing resources technically and economically nonrecoverable by other means. However, to the best of our knowledge, the published literature does not report any application of an air injection project in naturally fractured reservoirs. During 2015, an air injection pilot test was performed in a light oil naturally fractured reservoir in Mexico, referred to as “A” field. The implementation of the pilot test was preceded by its corresponding laboratory study, which consisted of five accelerating rate calorimeter (ARC) tests and two combustion tube (CT) experiments. The analysis of the aforementioned experimental work led us to corroborate that air and oil react at reservoir conditions. Based on the above finding, the pilot test was conducted by injecting air at a rate of 10 MMscf/D with a wellhead pressure of 4,500 psia for 1.5 years, which was followed by a 1.5-year production period giving a total of 3 years for the pilot test. The results indicate that combustion was successfully applied in the reservoir. However, no oil was produced. This paper discusses the results of a prematurely ended air injection pilot test in “A” field and the main lessons learned from it, which could help in the design and its subsequent implementation in other naturally fractured reservoirs.
{"title":"Lessons Learned from a Prematurely Ended High-Pressure Air Injection Test in a Light Oil Naturally Fractured Reservoir","authors":"Jose Antonio Gonzalez Guevara, Silvia Maria Chavez Morales, Thalia Iveth Hernandez Hernandez, Heron Gachuz-Muro, Bruno A. Lopez Jimenez","doi":"10.2118/212856-pa","DOIUrl":"https://doi.org/10.2118/212856-pa","url":null,"abstract":"\u0000 Sixty billion barrels of oil still reside in the matrix of mature onshore and offshore Mexican reservoirs located in the southeast basins after primary and secondary recovery. Capillary and viscous forces are responsible for this amount of oil retained within the pore structure of the matrix (immobile oil). Gravitational forces are not enough to counterattack these forces due to the high fracturing intensity. On the other hand, laboratory testing demonstrates that oil residing in the matrix could be mobilized by the exothermic reaction that takes place with air injection.\u0000 Air injection in homogeneous heavy and light oil sandstones and nonfractured limestones, at small or large scales during short and long periods of time, is feasible for producing resources technically and economically nonrecoverable by other means. However, to the best of our knowledge, the published literature does not report any application of an air injection project in naturally fractured reservoirs.\u0000 During 2015, an air injection pilot test was performed in a light oil naturally fractured reservoir in Mexico, referred to as “A” field. The implementation of the pilot test was preceded by its corresponding laboratory study, which consisted of five accelerating rate calorimeter (ARC) tests and two combustion tube (CT) experiments. The analysis of the aforementioned experimental work led us to corroborate that air and oil react at reservoir conditions. Based on the above finding, the pilot test was conducted by injecting air at a rate of 10 MMscf/D with a wellhead pressure of 4,500 psia for 1.5 years, which was followed by a 1.5-year production period giving a total of 3 years for the pilot test.\u0000 The results indicate that combustion was successfully applied in the reservoir. However, no oil was produced. This paper discusses the results of a prematurely ended air injection pilot test in “A” field and the main lessons learned from it, which could help in the design and its subsequent implementation in other naturally fractured reservoirs.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"113 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79736980","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}
Several authors have worked on combining decline curve analysis (DCA) models and stochastic algorithms for probabilistic DCAs. However, there are no publications on the application of these probabilistic decline curve models to all the major shale basins in the United States. Also, several empirical and analytical decline curve models have been developed to fit historical production data better; there is no systematic investigation of the relevance of the efforts on new model development compared with the efforts to quantify the uncertainty associated with the “noise” in the historical data. This work compares the uncertainty associated with determining the best-fit model (epistemic uncertainty) with the uncertainty associated with the historical data (aleatoric uncertainty) and presents a procedure to find DCA-stochastic algorithm combinations that encompass the epistemic uncertainty. We investigated two Bayesian methods—the approximate Bayesian computation and the Gibbs sampler—and two frequentist methods—the conventional bootstrap (BS) and modified BS (MBS). These stochastic algorithms were combined with five empirical DCA models (Arps, Duong, power law, logistic growth, and stretched exponential decline) and the analytical Jacobi theta-2 model. We analyzed historical production data from 1,800 wells (300 wells from each of the six major shale basins studied) with historical data lengths ranging from 12 to 60 months. We show the errors associated with the assumption of a uniform distribution for the model parameters and present an approach for integrating informative prior (IP) probabilistic distributions instead of the noninformative prior (NIP) or uniform prior distributions. Our results indicate the superior performance of the Bayesian methods, especially at short hindcasts (12–24 months of production history). We observed that the duration of the historical production data was the most critical factor. Using long hindcasts (up to 60 months) leveled the performance of all probabilistic methods regardless of the decline curve model or statistical methodology used. Additionally, we showed that it is possible to find DCA-stochastic model combinations that reflect the epistemic uncertainty in most of the shale basins investigated. The novelty of this work lies in the development of IPs for the Bayesian methodologies and the development of a systematic approach to determine the combination of statistical methods and DCA models that encompasses the epistemic uncertainty. The proposed approach was implemented using open-source software packages to make our results reproducible and to facilitate its practical application in forecasting production in unconventional oil and gas reservoirs.
{"title":"On the Application of Probabilistic Decline Curve Analysis to Unconventional Reservoirs","authors":"U. C. Egbe, O. Awoleke, O. Olorode, S. D. Goddard","doi":"10.2118/212837-pa","DOIUrl":"https://doi.org/10.2118/212837-pa","url":null,"abstract":"\u0000 Several authors have worked on combining decline curve analysis (DCA) models and stochastic algorithms for probabilistic DCAs. However, there are no publications on the application of these probabilistic decline curve models to all the major shale basins in the United States. Also, several empirical and analytical decline curve models have been developed to fit historical production data better; there is no systematic investigation of the relevance of the efforts on new model development compared with the efforts to quantify the uncertainty associated with the “noise” in the historical data. This work compares the uncertainty associated with determining the best-fit model (epistemic uncertainty) with the uncertainty associated with the historical data (aleatoric uncertainty) and presents a procedure to find DCA-stochastic algorithm combinations that encompass the epistemic uncertainty.\u0000 We investigated two Bayesian methods—the approximate Bayesian computation and the Gibbs sampler—and two frequentist methods—the conventional bootstrap (BS) and modified BS (MBS). These stochastic algorithms were combined with five empirical DCA models (Arps, Duong, power law, logistic growth, and stretched exponential decline) and the analytical Jacobi theta-2 model. We analyzed historical production data from 1,800 wells (300 wells from each of the six major shale basins studied) with historical data lengths ranging from 12 to 60 months. We show the errors associated with the assumption of a uniform distribution for the model parameters and present an approach for integrating informative prior (IP) probabilistic distributions instead of the noninformative prior (NIP) or uniform prior distributions. Our results indicate the superior performance of the Bayesian methods, especially at short hindcasts (12–24 months of production history). We observed that the duration of the historical production data was the most critical factor. Using long hindcasts (up to 60 months) leveled the performance of all probabilistic methods regardless of the decline curve model or statistical methodology used. Additionally, we showed that it is possible to find DCA-stochastic model combinations that reflect the epistemic uncertainty in most of the shale basins investigated.\u0000 The novelty of this work lies in the development of IPs for the Bayesian methodologies and the development of a systematic approach to determine the combination of statistical methods and DCA models that encompasses the epistemic uncertainty. The proposed approach was implemented using open-source software packages to make our results reproducible and to facilitate its practical application in forecasting production in unconventional oil and gas reservoirs.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"37 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79087733","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}
One essential process in reservoir characterization is the identification of hydraulic flow units (HFUs). It plays a critical role in determining hydrocarbon reserves and improving reservoir productivity. Flow zone indicator (FZI), determined from core data, is widely used to identify HFUs. One of the challenges in the FZI technique is that the number of HFUs is identified using qualitative methods and subjective estimation. This work proposes robust methods to identify the optimal HFUs using differential evolution (DE) and two-stage clustering. The first method tested in this work enumerates through a large number of HFUs scenarios using 10 clustering algorithms and different input parameters (number of clusters, minimum number of samples, etc.). The scenario with the largest average correlation coefficient is selected as optimum. The second method uses the DE algorithm to maximize the average correlation coefficient and hence obtain the optimal HFUs. The third method consists of two stages. The first stage uses the OPTICS clustering algorithm to determine the number of HFUs, while the second stage generates the desired clusters using the Gaussian mixture algorithm. Both iterative evaluation and DE optimization methods achieved the same clustering results. However, DE optimization resulted in 85% reduction in runtime due to the robust search capability of the DE algorithm which leads to the solution more efficiently. Furthermore, another significant reduction in runtime was achieved using the two-stage clustering method which yielded very close results. The proposed methods in this work provide unique and potential opportunity to improve the use of FZI data analysis to identify HFUs. This work uses the power of clustering and stochastic algorithms to support a critical process in reservoir characterization.
{"title":"Robust and Efficient Identification of Hydraulic Flow Units using Differential Evolution Optimization and Two-Stage Clustering Techniques","authors":"Menhal A. Al-Ismael, A. Awotunde","doi":"10.2118/212833-pa","DOIUrl":"https://doi.org/10.2118/212833-pa","url":null,"abstract":"\u0000 One essential process in reservoir characterization is the identification of hydraulic flow units (HFUs). It plays a critical role in determining hydrocarbon reserves and improving reservoir productivity. Flow zone indicator (FZI), determined from core data, is widely used to identify HFUs. One of the challenges in the FZI technique is that the number of HFUs is identified using qualitative methods and subjective estimation. This work proposes robust methods to identify the optimal HFUs using differential evolution (DE) and two-stage clustering. The first method tested in this work enumerates through a large number of HFUs scenarios using 10 clustering algorithms and different input parameters (number of clusters, minimum number of samples, etc.). The scenario with the largest average correlation coefficient is selected as optimum. The second method uses the DE algorithm to maximize the average correlation coefficient and hence obtain the optimal HFUs. The third method consists of two stages. The first stage uses the OPTICS clustering algorithm to determine the number of HFUs, while the second stage generates the desired clusters using the Gaussian mixture algorithm. Both iterative evaluation and DE optimization methods achieved the same clustering results. However, DE optimization resulted in 85% reduction in runtime due to the robust search capability of the DE algorithm which leads to the solution more efficiently. Furthermore, another significant reduction in runtime was achieved using the two-stage clustering method which yielded very close results. The proposed methods in this work provide unique and potential opportunity to improve the use of FZI data analysis to identify HFUs. This work uses the power of clustering and stochastic algorithms to support a critical process in reservoir characterization.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"18 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89807233","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}
R. Pérez-Romero, Javier Guerrero-Arrieta, H. Rodríguez-Prada
In the current energy transition era, oil exploitation and especially the development of heavy oil reservoirs are facing big challenges to overcome the possible limitations in terms of economy (oil price), energy efficiency, and carbon footprint. Particularly, thermal enhanced oil recovery processes need to be re-evaluated in an attempt to harness the injected and produced energy. In that sense, Ecopetrol is evaluating new strategies to optimize the current steam injection process using different hybrid technologies from laboratory to field scale. One of the most attractive initiatives is evaluating the in-situ steam generation using mist water-air injection. This process involves simultaneous air and water injection into the formation through a set of nozzles. It looks to use part of the in-situ oil as a fuel, using the reservoir not only as a tank of energy but also as a steam generator. The main contribution of the technique concerning conventional steam generation is the use of the heat from the combustion of the residual oil to generate an in-situ steam front to transfer the uncontacted oil. This is reflected in reduced carbon dioxide (CO2) emissions, reduced fuel and water requirements, and increased oil production and net energy recovery. This article describes the methodology, results, history matching, and kinetic modeling of experimental evaluations and the upscaling of the experimental observations to a representative sector model from a Colombian heavy oil field. Results are described in terms of incremental oil recovery, energy efficiency, and carbon intensity compared with the baseline (a traditional steamflooding scenario). The technology of in-situ steam generation using mist waterair injection led to benefits in terms of better energy use and reducing the external fuel dependency for steam generation at the surface. Additionally, it was possible to identify improvements in incremental oil recovery (around 90%), energy efficiency (about 10 times less energy required to produce 1 m3 of oil), and reduction in carbon intensity (up to 91%) considering as baseline a conventional steamflooding scenario. These results will be key input parameters for designing and commissioning future applications in the Colombian fields.
{"title":"In-Situ Steam Generation Using Mist Water-Air Injection as Enhanced Oil Recovery and Energy Efficiency Process: Kinetic Modeling and Numerical Simulation Approach","authors":"R. Pérez-Romero, Javier Guerrero-Arrieta, H. Rodríguez-Prada","doi":"10.2118/212853-pa","DOIUrl":"https://doi.org/10.2118/212853-pa","url":null,"abstract":"\u0000 In the current energy transition era, oil exploitation and especially the development of heavy oil reservoirs are facing big challenges to overcome the possible limitations in terms of economy (oil price), energy efficiency, and carbon footprint. Particularly, thermal enhanced oil recovery processes need to be re-evaluated in an attempt to harness the injected and produced energy. In that sense, Ecopetrol is evaluating new strategies to optimize the current steam injection process using different hybrid technologies from laboratory to field scale.\u0000 One of the most attractive initiatives is evaluating the in-situ steam generation using mist water-air injection. This process involves simultaneous air and water injection into the formation through a set of nozzles. It looks to use part of the in-situ oil as a fuel, using the reservoir not only as a tank of energy but also as a steam generator. The main contribution of the technique concerning conventional steam generation is the use of the heat from the combustion of the residual oil to generate an in-situ steam front to transfer the uncontacted oil. This is reflected in reduced carbon dioxide (CO2) emissions, reduced fuel and water requirements, and increased oil production and net energy recovery.\u0000 This article describes the methodology, results, history matching, and kinetic modeling of experimental evaluations and the upscaling of the experimental observations to a representative sector model from a Colombian heavy oil field. Results are described in terms of incremental oil recovery, energy efficiency, and carbon intensity compared with the baseline (a traditional steamflooding scenario).\u0000 The technology of in-situ steam generation using mist waterair injection led to benefits in terms of better energy use and reducing the external fuel dependency for steam generation at the surface. Additionally, it was possible to identify improvements in incremental oil recovery (around 90%), energy efficiency (about 10 times less energy required to produce 1 m3 of oil), and reduction in carbon intensity (up to 91%) considering as baseline a conventional steamflooding scenario. These results will be key input parameters for designing and commissioning future applications in the Colombian fields.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"52 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87603777","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}
Saeed Khezerloo-ye Aghdam, A. Kazemi, Mohammad Ahmadi
The majority of sandstone reservoirs contain clay particles. When clay is exposed to low-salinity water, fine detachment and migration occur due to multi-ion exchange and electrical double layer (EDL) expansion. Fine migration due to low-salinity water enhances oil recovery while damaging injection and production wells. This research investigates the effect of clay particles' weight percentage (wt%), ionic strength, total dissolved solids, and the injection rate of the low-salinity water on fine migration. The interparticle forces of kaolinite-kaolinite and kaolinite-quartz systems in various mediums were determined. Ten quartz sandpacks containing 2, 5, and 10 wt% of kaolinite were made to simulate clay-rich sandstone reservoirs. Afterward, different brines (10 and 50 mM solutions of NaCl, CaCl2, MgCl2, and Na2SO4 salts as well as seawater and its diluted samples) were injected into these sandpacks with different scenarios. It was observed that the interparticle forces for both systems in the presence of 10 mM solutions of NaCl, Na2SO4, and also 50 mM NaCl are repulsive. Therefore, even by injecting the low flow rate of these samples (0.1 cm3/min), the total fine migration was observed leading to intense permeability reduction in high clay-rich sandstones. However, in the case of low clay-containing sandpacks, the magnitude of permeability starts to rise a while after getting imposed to fine migration. In the presence of brines containing 50 mM MgCl2 and CaCl2, seawater, and its five-times diluted sample, the interparticle forces were an attraction, and fine migration occurred under no condition. However, using other samples of low-salinity water, the interparticle forces in the kaolin-kaolin system were repulsive and attractive in the kaolin-quartz system. Therefore, the phenomenon of partial fine migration occurs while flooding. So, in low-clay sandpacks, fines migrated only in high rate injection. However, the fine migration was evident for sandpacks containing 10 wt% of clay particles even by low flow rate injection. In general, there is a trade-off between the intensity of fine migration and divalent cations concentration in flooding water. Eliminating these cations or using them at 10 mM concentration may result in total fine migration, which is beneficial for low clay-containing media but damages clay-rich ones strongly. A high concentration of these cations prevents fines from movement, eradicating low-salinity flooding advantages. However, using medium concentrations results in partial fine migration, and the intensity, in this case, depends on clay concentration and flooding rate.
大多数砂岩储层含有粘土颗粒。当粘土暴露于低盐度水中时，由于多离子交换和双电层(EDL)膨胀，粘土发生了细小的剥离和迁移。低矿化度水的精细运移提高了采收率，同时也破坏了注采井。研究了粘土颗粒重量百分比(wt%)、离子强度、总溶解固形物和低矿化度水注入速率对细运移的影响。测定了高岭石-高岭石体系和高岭石-石英体系在不同介质中的颗粒间力。制作了10个石英砂岩包，分别含有2%、5%和10%的高岭石，以模拟富粘土砂岩储层。随后，在不同场景的沙包中注入不同的盐水(10和50 mM的NaCl、CaCl2、MgCl2和Na2SO4盐溶液以及海水及其稀释后的样品)。在10mm NaCl、Na2SO4和50mm NaCl溶液中，两种体系的粒子间力均为斥力。因此，即使注入这些样品的低流速(0.1 cm3/min)，也可以观察到总精细运移，导致高富粘土砂岩的渗透率大幅降低。而对于低含泥沙层，在进行细运移后，渗透率值开始上升一段时间。在含有50 mM MgCl2和CaCl2的盐水、海水及其5倍稀释的样品存在下，粒子间的作用力相互吸引，在任何条件下都发生了精细迁移。然而，在其他低盐度水样品中，高岭土-高岭土体系中的粒子间力为排斥力，而高岭土-石英体系中的粒子间力为吸引力。因此，在注水过程中会出现局部细运移现象。因此，在低粘土沙层中，细粒只有在高速注入时才会迁移。然而，对于含有10 wt%粘土颗粒的沙包，即使通过低流量注入，也存在明显的精细运移。一般来说，在驱油水中，细迁移强度与二价阳离子浓度之间存在一种权衡关系。去除这些阳离子或在10 mM浓度下使用它们可能会导致全细迁移，这对低含泥介质有利，但对富泥介质破坏强烈。高浓度的这些阳离子阻止了颗粒的移动，从而消除了低盐度驱油的优势。然而，使用中等浓度会导致部分精细运移，在这种情况下，其强度取决于粘土浓度和驱油速率。
{"title":"Theoretical and Experimental Study of Fine Migration During Low-Salinity Water Flooding: Effect of Brine Composition on Interparticle Forces","authors":"Saeed Khezerloo-ye Aghdam, A. Kazemi, Mohammad Ahmadi","doi":"10.2118/212852-pa","DOIUrl":"https://doi.org/10.2118/212852-pa","url":null,"abstract":"\u0000 The majority of sandstone reservoirs contain clay particles. When clay is exposed to low-salinity water, fine detachment and migration occur due to multi-ion exchange and electrical double layer (EDL) expansion. Fine migration due to low-salinity water enhances oil recovery while damaging injection and production wells.\u0000 This research investigates the effect of clay particles' weight percentage (wt%), ionic strength, total dissolved solids, and the injection rate of the low-salinity water on fine migration. The interparticle forces of kaolinite-kaolinite and kaolinite-quartz systems in various mediums were determined. Ten quartz sandpacks containing 2, 5, and 10 wt% of kaolinite were made to simulate clay-rich sandstone reservoirs. Afterward, different brines (10 and 50 mM solutions of NaCl, CaCl2, MgCl2, and Na2SO4 salts as well as seawater and its diluted samples) were injected into these sandpacks with different scenarios. It was observed that the interparticle forces for both systems in the presence of 10 mM solutions of NaCl, Na2SO4, and also 50 mM NaCl are repulsive.\u0000 Therefore, even by injecting the low flow rate of these samples (0.1 cm3/min), the total fine migration was observed leading to intense permeability reduction in high clay-rich sandstones. However, in the case of low clay-containing sandpacks, the magnitude of permeability starts to rise a while after getting imposed to fine migration. In the presence of brines containing 50 mM MgCl2 and CaCl2, seawater, and its five-times diluted sample, the interparticle forces were an attraction, and fine migration occurred under no condition. However, using other samples of low-salinity water, the interparticle forces in the kaolin-kaolin system were repulsive and attractive in the kaolin-quartz system. Therefore, the phenomenon of partial fine migration occurs while flooding. So, in low-clay sandpacks, fines migrated only in high rate injection. However, the fine migration was evident for sandpacks containing 10 wt% of clay particles even by low flow rate injection. In general, there is a trade-off between the intensity of fine migration and divalent cations concentration in flooding water. Eliminating these cations or using them at 10 mM concentration may result in total fine migration, which is beneficial for low clay-containing media but damages clay-rich ones strongly. A high concentration of these cations prevents fines from movement, eradicating low-salinity flooding advantages. However, using medium concentrations results in partial fine migration, and the intensity, in this case, depends on clay concentration and flooding rate.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"59 19 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73915769","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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