B. Hornby, Ruijia Wang, M. Collins, Joonshik Kim, R. Confer
This paper presents a case study in which new methods that use full-waveform sonic data are applied in an unconventional well setting to determine depth-dependent elastic anisotropy of formations penetrated by the well and estimate parameters of interest. The study objectives include the following: Estimate Thomsen's shear anisotropy parameter γ in an unconventional well that penetrates fast formationsUse rock physics and other approximations to further estimate a complete vertical transverse isotropic (VTI) elastic tensor at each depthCompare results with ground truth in terms of dynamic and static core measurementsUse these results to derive anisotropic geomechanical parameters for well completion and fracture treatment design and to compute upscaled seismic-equivalent elastic anisotropy for the calibration of anisotropic seismic velocity models Formation speeds in this well were extremely fast, typical for unconventional shale reservoirs, which created a challenging environment for estimating VTI Thomsen's parameter γ because of the extreme sensitivity of the inversion to the accuracy of the borehole fluid slowness estimate. The key to the study's success was development and application of methods to invert for a depth-dependent mud slowness curve. This allowed for much more accurate inversion of the VTI parameter γ than the conventional method that uses a constant mud slowness value. In addition to enabling a more accurate inversion, it is observed that the mud slowness curve not only varied with depth [likely because of pressure/temperature (P/T) changes and possible settling] but also reflected quite different properties across a drilling fluid pill that was placed around the reservoir formations. This analysis provides an additional benefit for drilling engineers because the mud slowness curve tracks mud property changes in the well and can determine the actual location of the drilling fluid pill after placement and stabilization. Additional work estimated the depth-continuous elastic tensor and geomechanics (anisotropic Poisson's ratios and Young's moduli necessary for computing horizontal stresses) for well completion and fracture treatment design. Seismic-scale properties were estimated using anisotropic Backus averaging for the calibration of the anisotropic seismic velocity model for prestack depth migration.
{"title":"Case Study Demonstrating the Estimation of Depth-Continuous Formation Anisotropy with Application to Geomechanics and Seismic Velocity Model Calibration","authors":"B. Hornby, Ruijia Wang, M. Collins, Joonshik Kim, R. Confer","doi":"10.2118/194867-MS","DOIUrl":"https://doi.org/10.2118/194867-MS","url":null,"abstract":"\u0000 This paper presents a case study in which new methods that use full-waveform sonic data are applied in an unconventional well setting to determine depth-dependent elastic anisotropy of formations penetrated by the well and estimate parameters of interest. The study objectives include the following: Estimate Thomsen's shear anisotropy parameter γ in an unconventional well that penetrates fast formationsUse rock physics and other approximations to further estimate a complete vertical transverse isotropic (VTI) elastic tensor at each depthCompare results with ground truth in terms of dynamic and static core measurementsUse these results to derive anisotropic geomechanical parameters for well completion and fracture treatment design and to compute upscaled seismic-equivalent elastic anisotropy for the calibration of anisotropic seismic velocity models\u0000 Formation speeds in this well were extremely fast, typical for unconventional shale reservoirs, which created a challenging environment for estimating VTI Thomsen's parameter γ because of the extreme sensitivity of the inversion to the accuracy of the borehole fluid slowness estimate. The key to the study's success was development and application of methods to invert for a depth-dependent mud slowness curve. This allowed for much more accurate inversion of the VTI parameter γ than the conventional method that uses a constant mud slowness value. In addition to enabling a more accurate inversion, it is observed that the mud slowness curve not only varied with depth [likely because of pressure/temperature (P/T) changes and possible settling] but also reflected quite different properties across a drilling fluid pill that was placed around the reservoir formations. This analysis provides an additional benefit for drilling engineers because the mud slowness curve tracks mud property changes in the well and can determine the actual location of the drilling fluid pill after placement and stabilization.\u0000 Additional work estimated the depth-continuous elastic tensor and geomechanics (anisotropic Poisson's ratios and Young's moduli necessary for computing horizontal stresses) for well completion and fracture treatment design. Seismic-scale properties were estimated using anisotropic Backus averaging for the calibration of the anisotropic seismic velocity model for prestack depth migration.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"96 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74752777","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A solid understanding of challenging reservoir complexities such as, naturally fractured "super-k" zones, layered systems, or, wellbore conditions such as, thermally induced mobility changes in the near wellbore region due to injection and uneven formation damage distribution across the wellbore, is essential for a successful development of carbonate reservoirs. These type of complexities play a major role for both reservoir fluid flow and well productivity. An efficient and holistic approach encompassing multiple data sources like image logs, production analysis logs, and pressure transient analysis (PTA) outcomes is of paramount importance in the characterization process of carbonate systems. In this paper illustrative examples showing different complexities, at reservoir level and also at well level, are presented in a systematic way to show the importance of pressure transient analysis (PTA) insights as a building block in the description process of these challenging reservoir features. Reconciling the differences between the static and dynamic data sources in each case was a crucial step to minimize the uncertainties encountered and to significantly broaden the dynamic understanding of these complex reservoir heterogeneities under a synergistic approach. Pressure buildups and falloffs data from multi-well groups, were incorporated and analyzed by advanced numerical models. The selected interpretation models were dependent on the reservoir and wellbore condition diagnosed from the pressure derivative plots. The analyses of wireline and large, real-time Intelligent Field data have provided key dynamic well parameters, such as permeability-thickness product (kh), productivity index and anisotropy ratio (kv/kh), that were critical input parameters in the characterization process of these complex reservoir systems.
{"title":"An Integrated Approach to Deal with Challenges of Interpreting Pressure-Transient Data in Complex-Reservoir Systems","authors":"R. Guerrero, O. H. Al-Obathani","doi":"10.2118/195075-MS","DOIUrl":"https://doi.org/10.2118/195075-MS","url":null,"abstract":"\u0000 A solid understanding of challenging reservoir complexities such as, naturally fractured \"super-k\" zones, layered systems, or, wellbore conditions such as, thermally induced mobility changes in the near wellbore region due to injection and uneven formation damage distribution across the wellbore, is essential for a successful development of carbonate reservoirs. These type of complexities play a major role for both reservoir fluid flow and well productivity. An efficient and holistic approach encompassing multiple data sources like image logs, production analysis logs, and pressure transient analysis (PTA) outcomes is of paramount importance in the characterization process of carbonate systems.\u0000 In this paper illustrative examples showing different complexities, at reservoir level and also at well level, are presented in a systematic way to show the importance of pressure transient analysis (PTA) insights as a building block in the description process of these challenging reservoir features. Reconciling the differences between the static and dynamic data sources in each case was a crucial step to minimize the uncertainties encountered and to significantly broaden the dynamic understanding of these complex reservoir heterogeneities under a synergistic approach. Pressure buildups and falloffs data from multi-well groups, were incorporated and analyzed by advanced numerical models. The selected interpretation models were dependent on the reservoir and wellbore condition diagnosed from the pressure derivative plots. The analyses of wireline and large, real-time Intelligent Field data have provided key dynamic well parameters, such as permeability-thickness product (kh), productivity index and anisotropy ratio (kv/kh), that were critical input parameters in the characterization process of these complex reservoir systems.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76594827","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The paper discusses the feasibility study approach of polymer flooding enhanced oil recovery. This work is focused on understanding and quantifying key aspects of polymer flooding and design parameter optimization case. A synthetic reservoir simulation model was employed for the study. The first stage is to identify and understand key factors that have most significant impact to polymer flooding response. There are eight parameters that are considered in the analysis, such as polymer concentration, polymer thermal degradation, polymer injection duration, and polymer-rock properties (adsorption, residual resistance factor, etc.). The impact of each parameter to oil recovery response was sensitized with its low, mid, and high values. The difference of high to low oil recovery output for all parameters was ranked to determine their significance levels. The top three parameters obtained from the sensitivity analysis are polymer injection duration, thermal degradation, and polymer concentration. Sensitivity cases of polymer injectivity and thermal degradation effects were covered in this work. The second stage is to determine optimum design parameters of polymer flooding. The most significant parameters from the sensitivity analysis results were considered for further optimization. Three parameters that were selected for design optimization include polymer injection duration, polymer concentration, and well spacing. An optimization workflow with simplex algorithm is linked with a reservoir simulator to generate optimization cases by varying values of optimized parameters. The optimization iteration stops when the maximum value of the objective function, which is the net revenue, is reached. The optimization cycle was done for rock permeability of 500 md and 1000 md. For a low rock permeability reservoir, the well spacing should be short and a lower polymer concentration is sufficient to provide a good response, in addition to avoiding potential injectivity problem. There should be minimum injectivity problem for reservoir with permeability above 1000 md. It is very important to apply polymer thermal degradation in the simulation model to avoid an optimistic performance prediction. The sensitivity analysis results provide a good understanding on the significance impact of parameters controlling polymer injection response and potential challenges. The optimization approach used in the study aids in investigating many optimization scenario within a short period of time.
{"title":"Polymer Flooding Simulation Modeling Feasibility Study: Understanding Key Aspects and Design Optimization","authors":"W. Hidayat, Nasser ALMolhem","doi":"10.2118/194774-MS","DOIUrl":"https://doi.org/10.2118/194774-MS","url":null,"abstract":"\u0000 The paper discusses the feasibility study approach of polymer flooding enhanced oil recovery. This work is focused on understanding and quantifying key aspects of polymer flooding and design parameter optimization case. A synthetic reservoir simulation model was employed for the study.\u0000 The first stage is to identify and understand key factors that have most significant impact to polymer flooding response. There are eight parameters that are considered in the analysis, such as polymer concentration, polymer thermal degradation, polymer injection duration, and polymer-rock properties (adsorption, residual resistance factor, etc.). The impact of each parameter to oil recovery response was sensitized with its low, mid, and high values. The difference of high to low oil recovery output for all parameters was ranked to determine their significance levels. The top three parameters obtained from the sensitivity analysis are polymer injection duration, thermal degradation, and polymer concentration. Sensitivity cases of polymer injectivity and thermal degradation effects were covered in this work.\u0000 The second stage is to determine optimum design parameters of polymer flooding. The most significant parameters from the sensitivity analysis results were considered for further optimization. Three parameters that were selected for design optimization include polymer injection duration, polymer concentration, and well spacing. An optimization workflow with simplex algorithm is linked with a reservoir simulator to generate optimization cases by varying values of optimized parameters. The optimization iteration stops when the maximum value of the objective function, which is the net revenue, is reached. The optimization cycle was done for rock permeability of 500 md and 1000 md.\u0000 For a low rock permeability reservoir, the well spacing should be short and a lower polymer concentration is sufficient to provide a good response, in addition to avoiding potential injectivity problem. There should be minimum injectivity problem for reservoir with permeability above 1000 md. It is very important to apply polymer thermal degradation in the simulation model to avoid an optimistic performance prediction. The sensitivity analysis results provide a good understanding on the significance impact of parameters controlling polymer injection response and potential challenges. The optimization approach used in the study aids in investigating many optimization scenario within a short period of time.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"93 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75852065","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A.M.Q.M. Al-Ajmi, Abdulaziz Al-Rushoud, Ashis Gohain, F. Khatib, Hussain Al-Haj, Faisal Al-naqa, F. Al-Mutawa, Majed Al-Gharib, Hrishikesh Shinde, Saurabh Arora, Bader Arrar, Manar Bumaryoum, A. Al-Mousa, Rustem Sagirov, Tamer Reda, R. Hamed
To optimize production from a key reservoir, obtaining a core sample with minimum fluid invasion and damage was necessary. In addition, operational nonproductive time (NPT) related to drilling challenges, such as interbedded formations of varying formation pressures, wellbore instability in the reactive, stressed shale sections, and hole cleaning concerns, needed to be mitigated. This paper describes the design of the drilling fluid and its performance in the field. After completion of the first dump flood water injection well drilled using an 80/20 conventional nonaqueous fluid (NAF) weighted with barite, low injectivity was observed, which led to acquiring cores to analyze permeability and porosity along with the change in mineralogy resulting from long exposure of the reservoir in the water zone. A 70/30 organophilic clay-free (OCF) NAF was selected to mitigate equivalent circulating density (ECD) risks and minimize damage. Proprietary software was used to customize the bridging design, which was verified during laboratory testing, and to help ensure adequate hole cleaning with the customized low-ECD fluid. The engineered OCF NAF contained no damaging materials, such as barite, asphaltic material, or organophilic clay. OCF NAFs are well suited to low-ECD drilling operations because they are more resistant to weighting material sag than conventional NAF systems of similar rheology. This is a product of the high gel strengths developed, even in low-rheology (low-ECD) fluids. Downhole pressure fluctuations are low because these gels are fragile and break easily. For the well in which this OCF NAF was used, drilling, coring, and logging operations were successfully completed without incident. Four cores were acquired with minimal damage compared to the previous wells resulting from the engineered design of the bridging material and fluid-loss control polymers. In addition, there was minimal erosion to these four cores, which was a result of the low-ECD fragile gel fluid used. The fluid-loss control properties of the fluid were also effective in strengthening the wellbore and eliminating differential stuck pipe tendencies that had been observed in previous wells. The fluid properties resulted in minimal ECD, and the OCF NAF displayed excellent suspension along with improved pressure management; no pressure spikes occurred while breaking circulation. There was no NPT related to wellbore instability or any of the drilling challenges previously identified. This unique organophilic clay-free and organolignite-free drilling and coring fluid relies on a specialized technology involving an interaction between the emulsifier package and the polymer additives in the fluid. This provides the behaviors needed for reliable weight material suspension and suitable hole cleaning properties in a low-ECD drilling fluid. Together with the appropriately designed bridging package, the OCF NAF provided a better understanding of the reservoir characteristics by del
{"title":"Successful Field Application of Organophilic Clay-Free Invert Emulsion Fluid to Protect the Reservoir Core from Drilling Fluid Damage: Case Study from a Kuwait Field","authors":"A.M.Q.M. Al-Ajmi, Abdulaziz Al-Rushoud, Ashis Gohain, F. Khatib, Hussain Al-Haj, Faisal Al-naqa, F. Al-Mutawa, Majed Al-Gharib, Hrishikesh Shinde, Saurabh Arora, Bader Arrar, Manar Bumaryoum, A. Al-Mousa, Rustem Sagirov, Tamer Reda, R. Hamed","doi":"10.2118/194707-MS","DOIUrl":"https://doi.org/10.2118/194707-MS","url":null,"abstract":"\u0000 To optimize production from a key reservoir, obtaining a core sample with minimum fluid invasion and damage was necessary. In addition, operational nonproductive time (NPT) related to drilling challenges, such as interbedded formations of varying formation pressures, wellbore instability in the reactive, stressed shale sections, and hole cleaning concerns, needed to be mitigated. This paper describes the design of the drilling fluid and its performance in the field.\u0000 After completion of the first dump flood water injection well drilled using an 80/20 conventional nonaqueous fluid (NAF) weighted with barite, low injectivity was observed, which led to acquiring cores to analyze permeability and porosity along with the change in mineralogy resulting from long exposure of the reservoir in the water zone. A 70/30 organophilic clay-free (OCF) NAF was selected to mitigate equivalent circulating density (ECD) risks and minimize damage. Proprietary software was used to customize the bridging design, which was verified during laboratory testing, and to help ensure adequate hole cleaning with the customized low-ECD fluid.\u0000 The engineered OCF NAF contained no damaging materials, such as barite, asphaltic material, or organophilic clay. OCF NAFs are well suited to low-ECD drilling operations because they are more resistant to weighting material sag than conventional NAF systems of similar rheology. This is a product of the high gel strengths developed, even in low-rheology (low-ECD) fluids. Downhole pressure fluctuations are low because these gels are fragile and break easily. For the well in which this OCF NAF was used, drilling, coring, and logging operations were successfully completed without incident. Four cores were acquired with minimal damage compared to the previous wells resulting from the engineered design of the bridging material and fluid-loss control polymers. In addition, there was minimal erosion to these four cores, which was a result of the low-ECD fragile gel fluid used. The fluid-loss control properties of the fluid were also effective in strengthening the wellbore and eliminating differential stuck pipe tendencies that had been observed in previous wells. The fluid properties resulted in minimal ECD, and the OCF NAF displayed excellent suspension along with improved pressure management; no pressure spikes occurred while breaking circulation. There was no NPT related to wellbore instability or any of the drilling challenges previously identified.\u0000 This unique organophilic clay-free and organolignite-free drilling and coring fluid relies on a specialized technology involving an interaction between the emulsifier package and the polymer additives in the fluid. This provides the behaviors needed for reliable weight material suspension and suitable hole cleaning properties in a low-ECD drilling fluid. Together with the appropriately designed bridging package, the OCF NAF provided a better understanding of the reservoir characteristics by del","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78266563","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Wai Li, Jishan Liu, Jie Zeng, Jianwei Tian, Lin Li, Min Zhang, Jia Jia, Yufei Li, Hui Peng, Xionghu Zhao, Ji-wei Jiang
Nanomaterials have drawn considerable attention of the oil and gas industry due to their peculiar properties and interesting behaviors. Many experiments, trials and practices were conducted by petroleum scientists and engineers in the last two decades to use various novel nanomaterials to improve exploration and production. Based on the published literature, this article comprehensively reviews the strategies and experience of nanomaterial application in frac fluids, the current problems, and relevant challenges. Based on elaborated design, the nanomaterials such as nano-sized metal, metal oxide, silica, carbonate, carbon, polymer, fiber, organic-inorganic hybrid and other composites can be incorporated in frac fluids to greatly enhance or precisely tune the properties and performances. Consequently, nanomaterial-assisted frac fluids perform well in different aspects including density, rheology, stability, heat conductivity, specific heat capacity, fluid loss, breaking, clean up, proppant suspendability and frictional drag. To optimize the performance and cost-effectiveness of nano-frac fluids, advanced principles and theories in physical chemistry, heat and mass transfer, mechanics and rheology along with industrial design philosophy have been considered and applied. According to the investigation of the literature, nanomaterials have successfully fulfilled the following functions in frac fluids: (1) Improving the rheological behavior by intermolecular interactions (e.g., pseudo-crosslinking in frac fluids, or changing the aggregation pattern of surface-active molecules in surfactant based fluids); (2) Increasing the stability of fluids by enhancing the interfacial strength and toughness, especially in foams and emulsions; (3) Forming a low-permeability pseudo-filter cake to lower the fluid loss; (4) Increasing the viscosifying effect of polymers, which dramatically decreases the required loading of polymer in the fluid; (5) Boosting the thermal stability of frac fluids; (6) Improving the regained fracture conductivity; (7) Reducing the frictional drag of frac fluids; (8) Helping self-suspended proppants achieve better performance and (9) Reducing the required displacing pressure for the residual frac fluid by decreasing interfacial tension to help clean up. These achievements, along with the related design ideas, are reviewed. This paper also discusses the major difficulties and challenges for nano-frac fluids including compatibility, cost and HSE issues. Comprehensive laboratory work should be performed before field application to ensure the reliability of nano-assisted fluid formulations. Large-scale industrial production and a steady supply of nanomaterials will promote the application of nano-frac fluids. Exposure risk, eco-toxicity and biodegradability of nanomateials should be paid more attention. Incorporating the attractive, cutting-edged achievements in chemical and material sciences, nano-frac fluid is predicted to be fully accepted
{"title":"A Critical Review of the Application of Nanomaterials in Frac Fluids: The State of the Art and Challenges","authors":"Wai Li, Jishan Liu, Jie Zeng, Jianwei Tian, Lin Li, Min Zhang, Jia Jia, Yufei Li, Hui Peng, Xionghu Zhao, Ji-wei Jiang","doi":"10.2118/195029-MS","DOIUrl":"https://doi.org/10.2118/195029-MS","url":null,"abstract":"\u0000 Nanomaterials have drawn considerable attention of the oil and gas industry due to their peculiar properties and interesting behaviors. Many experiments, trials and practices were conducted by petroleum scientists and engineers in the last two decades to use various novel nanomaterials to improve exploration and production. Based on the published literature, this article comprehensively reviews the strategies and experience of nanomaterial application in frac fluids, the current problems, and relevant challenges. Based on elaborated design, the nanomaterials such as nano-sized metal, metal oxide, silica, carbonate, carbon, polymer, fiber, organic-inorganic hybrid and other composites can be incorporated in frac fluids to greatly enhance or precisely tune the properties and performances. Consequently, nanomaterial-assisted frac fluids perform well in different aspects including density, rheology, stability, heat conductivity, specific heat capacity, fluid loss, breaking, clean up, proppant suspendability and frictional drag. To optimize the performance and cost-effectiveness of nano-frac fluids, advanced principles and theories in physical chemistry, heat and mass transfer, mechanics and rheology along with industrial design philosophy have been considered and applied. According to the investigation of the literature, nanomaterials have successfully fulfilled the following functions in frac fluids: (1) Improving the rheological behavior by intermolecular interactions (e.g., pseudo-crosslinking in frac fluids, or changing the aggregation pattern of surface-active molecules in surfactant based fluids); (2) Increasing the stability of fluids by enhancing the interfacial strength and toughness, especially in foams and emulsions; (3) Forming a low-permeability pseudo-filter cake to lower the fluid loss; (4) Increasing the viscosifying effect of polymers, which dramatically decreases the required loading of polymer in the fluid; (5) Boosting the thermal stability of frac fluids; (6) Improving the regained fracture conductivity; (7) Reducing the frictional drag of frac fluids; (8) Helping self-suspended proppants achieve better performance and (9) Reducing the required displacing pressure for the residual frac fluid by decreasing interfacial tension to help clean up. These achievements, along with the related design ideas, are reviewed. This paper also discusses the major difficulties and challenges for nano-frac fluids including compatibility, cost and HSE issues. Comprehensive laboratory work should be performed before field application to ensure the reliability of nano-assisted fluid formulations. Large-scale industrial production and a steady supply of nanomaterials will promote the application of nano-frac fluids. Exposure risk, eco-toxicity and biodegradability of nanomateials should be paid more attention. Incorporating the attractive, cutting-edged achievements in chemical and material sciences, nano-frac fluid is predicted to be fully accepted","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81369346","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Karem Al-Garadi, A. Aldughaither, Mustafa Ba alawi, H. Al-Hashim, Najmudeen Sibaweihi, M. Said
Condensate banking has been identified to cause significant drop in gas relative permeability and consequently reduction of the productivity of gas condensate wells. To overcome this problem, hydraulic fracturing has been used as a mean to minimize or eliminate this phenomenon. Furthermore multistage hydraulic fracturing techniques have been used to enhance the productivity of horizontal gas condensate wells especially in low permeability formation. Even though multistage hydraulic fracturing has provided an effective solution for condensate blockage to some extent as it promotes linear flow modes which will minimize the pressure drops and consequently improves the inflow performance considerably. However, this technique is very costly, and has to be optimized to get the best long-term performance of the multistage fractured horizontal gas condensate wells. In this paper, multiple sensitivity analyses were conducted in order to come up with an optimum multistage hydraulic fracturing scenario. In these analyses, our manipulations were focused mainly on the operational parameters such as fractures half length, fractures conductivity using compositional commercial simulator. CMG-GEM simulator was used to investigate the different cases proposed for applying multistage hydraulic fracturing of horizontal gas condensate wells. The investigation began with a base case scenario where the fractures half-length were fixed for all stages with equal spacing between them. Then, six more fractures half-length patterns were created by introducing new approach where the well performance was studied if they are in increasing trend away from the wellbore (coning-up), or in a decreasing trend (coning-down). Well performance is furtherly addressed when the fractures half-length arrangements formed parabolic shapes including both occasions of concaving upward and downward. Finally, the last two patterns illustrated the effect of having the fractures half-length arrangements both skewed to the left and right on well productivity. The investigation of the effect of changing the multistage hydraulic fractures half-length distribution patterns on the performance of a gas condensate well was conducted and resulted in parabolic up distribution pattern to be the optimum pattern amongst the other tested ones. It results in the highest cumulative both gas and condensate production. It also maintains the gas flow rate and bottom hole pressure more efficiently. The parabolic up distribution pattern confirms that the majority of gas production was fed by the fractures at the heel and at the toe of the horizontal drainhole which is in agreement with the flux distribution along the horizontal well.
{"title":"A Novel Approach for Optimizing Multistage Hydraulic Fracturing of Gas Condensate Horizontal Wells","authors":"Karem Al-Garadi, A. Aldughaither, Mustafa Ba alawi, H. Al-Hashim, Najmudeen Sibaweihi, M. Said","doi":"10.2118/194971-MS","DOIUrl":"https://doi.org/10.2118/194971-MS","url":null,"abstract":"Condensate banking has been identified to cause significant drop in gas relative permeability and consequently reduction of the productivity of gas condensate wells. To overcome this problem, hydraulic fracturing has been used as a mean to minimize or eliminate this phenomenon. Furthermore multistage hydraulic fracturing techniques have been used to enhance the productivity of horizontal gas condensate wells especially in low permeability formation. Even though multistage hydraulic fracturing has provided an effective solution for condensate blockage to some extent as it promotes linear flow modes which will minimize the pressure drops and consequently improves the inflow performance considerably. However, this technique is very costly, and has to be optimized to get the best long-term performance of the multistage fractured horizontal gas condensate wells.\u0000 In this paper, multiple sensitivity analyses were conducted in order to come up with an optimum multistage hydraulic fracturing scenario. In these analyses, our manipulations were focused mainly on the operational parameters such as fractures half length, fractures conductivity using compositional commercial simulator. CMG-GEM simulator was used to investigate the different cases proposed for applying multistage hydraulic fracturing of horizontal gas condensate wells. The investigation began with a base case scenario where the fractures half-length were fixed for all stages with equal spacing between them. Then, six more fractures half-length patterns were created by introducing new approach where the well performance was studied if they are in increasing trend away from the wellbore (coning-up), or in a decreasing trend (coning-down). Well performance is furtherly addressed when the fractures half-length arrangements formed parabolic shapes including both occasions of concaving upward and downward. Finally, the last two patterns illustrated the effect of having the fractures half-length arrangements both skewed to the left and right on well productivity.\u0000 The investigation of the effect of changing the multistage hydraulic fractures half-length distribution patterns on the performance of a gas condensate well was conducted and resulted in parabolic up distribution pattern to be the optimum pattern amongst the other tested ones. It results in the highest cumulative both gas and condensate production. It also maintains the gas flow rate and bottom hole pressure more efficiently. The parabolic up distribution pattern confirms that the majority of gas production was fed by the fractures at the heel and at the toe of the horizontal drainhole which is in agreement with the flux distribution along the horizontal well.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81522463","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Iron sulfide is a $1.4 billion/year problem in the oil and gas industry receiving little R&D attention. The low success rate of organic acids and polyaminocarboxylic acids (PACA) prompts a more focused investigation and development of new dissolvers for the treatment of iron sulfide scales. This study evaluates the solubility of the iron sulfide scale by commonly used simple organic acids and describes two new blends that outperform the aforementioned standalone dissolvers at 1,000 psi and 150°F. Bottle and autoclave tests evaluated the efficacy of various dissolvers to dissolve the iron sulfide scale. Bottle tests helped in evaluating the dissolvers’ potential to dissolve iron sulfide. A Hastelloy-B autoclave with a maximum operating pressure and temperature of 1,800 psi and 350°F, respectively, contained the iron sulfide and the dissolver for the anoxic dissolution tests. Formic acid, maleic acid, lactic acid, citric acid, oxalic acid, ethylenediaminetetraacetic acid disodium salt (Na2EDTA), and pentapotassium diethyltriaminepentaacetic acid (K5DTPA) were used. The simple organic acids added to Na2EDTA helped in improving the solubility of the scale. Two final experiments with the most successful blends were conducted for 24 hours. Concentration of the dissolver varied from 1-10 wt%. The experiments were conducted for 4 hours at 150°F, and a pressure of 1,000 psi. Elemental analysis using the Inductively Coupled Plasma (ICP) determined the efficiency of scale removal. Dräger tubes measured the H2S concentration inside the autoclave at the end of the experiment. The degree of saturation of the dissolvers calculated from the ICP measurements helped in evaluating its utilization. An XRD study showed the initial iron sulfide scale was mainly pyrrhotite (67%), mackinawite (23%), troilite (5%), and remaining wuestite (5%). Bottle tests showed that maleic acid is the best reactant for iron sulfide in terms of the speed of the reaction. However, citric acid can react with the iron sulfide at lower concentrations and is more effective. Similar to the bottle test, maleic acid yielded the maximum solubility among standalone treatments. An inductively coupled plasma analysis of iron concentration showed a solubility of 10.6 g/L iron in maleic acid. The next best treatment was with formic acid, dissolving a maximum of 9.7 g/L iron. Oxalic acid converted the iron sulfide to iron (II) oxalate, which is insoluble in water. K5DTPA was a poor dissolver of iron sulfide with less than 1 g/L iron solubility. Blends of Na2EDTA and a synergist helped in improving the dissolution. Adding 5 wt% potassium oxalate to 15 wt% Na2EDTA helped in dissolving 70.1% of the initial iron at 1,000 psi, 150°F, and 24 hours soaking time. A blend of 15 wt% Na2EDTA and 5 wt% potassium citrate dissolved 87% of iron at the same conditions. Development of novel dissolvers that are less corrosive and safer than traditional dissolvers is a necessary step to improve the dissolution of i
{"title":"Improving the Dissolution of Iron Sulfide by Blending Chelating Agents and its Synergists","authors":"R. Ramanathan, H. Nasr-El-Din","doi":"10.2118/195128-MS","DOIUrl":"https://doi.org/10.2118/195128-MS","url":null,"abstract":"\u0000 Iron sulfide is a $1.4 billion/year problem in the oil and gas industry receiving little R&D attention. The low success rate of organic acids and polyaminocarboxylic acids (PACA) prompts a more focused investigation and development of new dissolvers for the treatment of iron sulfide scales. This study evaluates the solubility of the iron sulfide scale by commonly used simple organic acids and describes two new blends that outperform the aforementioned standalone dissolvers at 1,000 psi and 150°F.\u0000 Bottle and autoclave tests evaluated the efficacy of various dissolvers to dissolve the iron sulfide scale. Bottle tests helped in evaluating the dissolvers’ potential to dissolve iron sulfide. A Hastelloy-B autoclave with a maximum operating pressure and temperature of 1,800 psi and 350°F, respectively, contained the iron sulfide and the dissolver for the anoxic dissolution tests. Formic acid, maleic acid, lactic acid, citric acid, oxalic acid, ethylenediaminetetraacetic acid disodium salt (Na2EDTA), and pentapotassium diethyltriaminepentaacetic acid (K5DTPA) were used. The simple organic acids added to Na2EDTA helped in improving the solubility of the scale. Two final experiments with the most successful blends were conducted for 24 hours. Concentration of the dissolver varied from 1-10 wt%. The experiments were conducted for 4 hours at 150°F, and a pressure of 1,000 psi. Elemental analysis using the Inductively Coupled Plasma (ICP) determined the efficiency of scale removal. Dräger tubes measured the H2S concentration inside the autoclave at the end of the experiment. The degree of saturation of the dissolvers calculated from the ICP measurements helped in evaluating its utilization.\u0000 An XRD study showed the initial iron sulfide scale was mainly pyrrhotite (67%), mackinawite (23%), troilite (5%), and remaining wuestite (5%). Bottle tests showed that maleic acid is the best reactant for iron sulfide in terms of the speed of the reaction. However, citric acid can react with the iron sulfide at lower concentrations and is more effective. Similar to the bottle test, maleic acid yielded the maximum solubility among standalone treatments. An inductively coupled plasma analysis of iron concentration showed a solubility of 10.6 g/L iron in maleic acid. The next best treatment was with formic acid, dissolving a maximum of 9.7 g/L iron. Oxalic acid converted the iron sulfide to iron (II) oxalate, which is insoluble in water. K5DTPA was a poor dissolver of iron sulfide with less than 1 g/L iron solubility. Blends of Na2EDTA and a synergist helped in improving the dissolution. Adding 5 wt% potassium oxalate to 15 wt% Na2EDTA helped in dissolving 70.1% of the initial iron at 1,000 psi, 150°F, and 24 hours soaking time. A blend of 15 wt% Na2EDTA and 5 wt% potassium citrate dissolved 87% of iron at the same conditions.\u0000 Development of novel dissolvers that are less corrosive and safer than traditional dissolvers is a necessary step to improve the dissolution of i","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89955616","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
It's difficult to fully discover all the geological reserves during exploration stage, because the fracture system of complex fault block oilfield is very complicated. As the reserve scale in single block is limited, the decline rate of the oilfield is usually very fast. As a result, finding new replacement reserves inside the oilfield is an important method to ensure stable production of complex fault block oilfields. Base on the improvement of the Vogel method and material balance method to calculate the reservoir dynamic reserves under the degassing conditions of A14 well area. Using Allan profiling to construct lithologic docking relationship between A14 well area and adjacent fault block. Calculate SGR(Shale Gouge Ratio) for different docking areas. According to the statistics of shale content and porosity in the oilfield area, core experiment results with porosity and displacement pressure, the displacement pressure on both sides of the fault docking area can be used to predict the oil column height of adjacent block. To ensure the initially high-speed production of A14 well area, it's necessary to reduce the times of shut-in static pressure measurement. The continuous reservoir pressure under the degassing conditions is calculated by the improvement of the Vogel method. Avoid the error of dynamic geological reserve calculation caused by too little reservoir pressure data. Result shows that the geological reserves of A14 well area is much smaller than its dynamic reserves. Study on the sealing property of faults around the A14 well area shows that the fault on the east side of the A14 well area is a non-closed fault, and the adjacent fault block is an oil-bearing fault block. Well A20 confirmed the oil-bearing properties for the fault block on the east side of the A14 well area. The result of pressure testing while drilling also shows that pressure drop in the east block of the A14 well area. All of that verify the reliability of previous research. Aiming at the development of complex fault block oilfield, a method based on dynamic reserves research result to study the sealing property of peripheral faults to predict the height of oil columns in adjacent blocks is proposed. Achieved the purpose of finding new replacement reserves inside the oilfield. The reliability of the research is verified by the pressure testing while drilling. It provides a valuable experience for the development in similar oilfield.
{"title":"A New Discovery in Complex Fault Block Oilfield Based on Dynamic Reserves Study and Fault Sealing Study: A Case Study of Bz29-4 Oilfield in Southern Bohai Bay","authors":"Pengyu Gao, L. Cao, Cong Jiang, Runsen Qin, Longtao Cui, Zhonghua Meng","doi":"10.2118/194804-MS","DOIUrl":"https://doi.org/10.2118/194804-MS","url":null,"abstract":"\u0000 It's difficult to fully discover all the geological reserves during exploration stage, because the fracture system of complex fault block oilfield is very complicated. As the reserve scale in single block is limited, the decline rate of the oilfield is usually very fast. As a result, finding new replacement reserves inside the oilfield is an important method to ensure stable production of complex fault block oilfields.\u0000 Base on the improvement of the Vogel method and material balance method to calculate the reservoir dynamic reserves under the degassing conditions of A14 well area. Using Allan profiling to construct lithologic docking relationship between A14 well area and adjacent fault block. Calculate SGR(Shale Gouge Ratio) for different docking areas. According to the statistics of shale content and porosity in the oilfield area, core experiment results with porosity and displacement pressure, the displacement pressure on both sides of the fault docking area can be used to predict the oil column height of adjacent block.\u0000 To ensure the initially high-speed production of A14 well area, it's necessary to reduce the times of shut-in static pressure measurement. The continuous reservoir pressure under the degassing conditions is calculated by the improvement of the Vogel method. Avoid the error of dynamic geological reserve calculation caused by too little reservoir pressure data. Result shows that the geological reserves of A14 well area is much smaller than its dynamic reserves. Study on the sealing property of faults around the A14 well area shows that the fault on the east side of the A14 well area is a non-closed fault, and the adjacent fault block is an oil-bearing fault block. Well A20 confirmed the oil-bearing properties for the fault block on the east side of the A14 well area. The result of pressure testing while drilling also shows that pressure drop in the east block of the A14 well area. All of that verify the reliability of previous research.\u0000 Aiming at the development of complex fault block oilfield, a method based on dynamic reserves research result to study the sealing property of peripheral faults to predict the height of oil columns in adjacent blocks is proposed. Achieved the purpose of finding new replacement reserves inside the oilfield. The reliability of the research is verified by the pressure testing while drilling. It provides a valuable experience for the development in similar oilfield.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90288689","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The objective of this work is to present the development of a numerical model for wave propagation in materials with time-varying, heterogeneous, and non-linear properties. Materials change with time as the result of complex linear and non-linear processes, which can occur due to natural causes or induced. Wave phenomena in this context brings about an interesting and complex problem, which involves the solution to coupled equations which describe interlinked multiphysics phenomena. Thus, understanding the dynamics of this interaction is beneficial to numerous applications across different industries and applied research; e.g. acoustic characterization of moving fluids, laser-fluid interaction, distributed optical fiber sensing, photonic integrated systems, among others. Numerical models, therefore, are indispensable to gain a deeper insight about the physical dynamics of the process and, ultimately, purvey a platform to design and test new applications and technologies. Over time some numerical models have been proposed to simulate wave phenomena in these situations. The method and solution reviewed in this work provides a unique solution to develop and optimize multiple applications. For example, it can be used to model the interaction of electromagnetic waves with travelling Bragg mirrors produced by temperature or pressure changes in optical fibers, which is the basis of fiber-based distributed fiber sensing; the scattering of acoustic waves by transient disturbances in fluid flow that may arise from gas bubbles or variations in the density of fluids; and the propagation of an electromagnetic pulse in a rapidly moving and varying fluid. The mathematical description of the process was derived originally for electromagnetics; yet, the numerical solver and mathematical treatment is generic and can be applied to other wave phenomena. The derivation departs from physical principles to write a generalized set of equations that describe wave propagation in time-varying, heterogeneous, and non-linear materials. The resulting set of hyperbolic partial differential equations (PDE) includes diffusive and convective terms that fully describe the wave interaction and process. Linear and nonlinear spatial and time heterogeneities in the material are assimilated into the convective terms of the hyperbolic wave equation. The solver was implemented using a semi-discrete and multidimensional scheme based in the finite-volume method which is highly scalable. Extension to other wave phenomena is discussed by analyzing the parameter correspondence for the acoustic and electromagnetic case.
{"title":"The Role of Transient Perturbations and Heterogeneities in Subsurface Wave Propagation - A Scalable Numerical Solution","authors":"D. San-Roman-Alerigi","doi":"10.2118/194888-MS","DOIUrl":"https://doi.org/10.2118/194888-MS","url":null,"abstract":"\u0000 The objective of this work is to present the development of a numerical model for wave propagation in materials with time-varying, heterogeneous, and non-linear properties. Materials change with time as the result of complex linear and non-linear processes, which can occur due to natural causes or induced. Wave phenomena in this context brings about an interesting and complex problem, which involves the solution to coupled equations which describe interlinked multiphysics phenomena. Thus, understanding the dynamics of this interaction is beneficial to numerous applications across different industries and applied research; e.g. acoustic characterization of moving fluids, laser-fluid interaction, distributed optical fiber sensing, photonic integrated systems, among others. Numerical models, therefore, are indispensable to gain a deeper insight about the physical dynamics of the process and, ultimately, purvey a platform to design and test new applications and technologies.\u0000 Over time some numerical models have been proposed to simulate wave phenomena in these situations. The method and solution reviewed in this work provides a unique solution to develop and optimize multiple applications. For example, it can be used to model the interaction of electromagnetic waves with travelling Bragg mirrors produced by temperature or pressure changes in optical fibers, which is the basis of fiber-based distributed fiber sensing; the scattering of acoustic waves by transient disturbances in fluid flow that may arise from gas bubbles or variations in the density of fluids; and the propagation of an electromagnetic pulse in a rapidly moving and varying fluid.\u0000 The mathematical description of the process was derived originally for electromagnetics; yet, the numerical solver and mathematical treatment is generic and can be applied to other wave phenomena. The derivation departs from physical principles to write a generalized set of equations that describe wave propagation in time-varying, heterogeneous, and non-linear materials. The resulting set of hyperbolic partial differential equations (PDE) includes diffusive and convective terms that fully describe the wave interaction and process. Linear and nonlinear spatial and time heterogeneities in the material are assimilated into the convective terms of the hyperbolic wave equation. The solver was implemented using a semi-discrete and multidimensional scheme based in the finite-volume method which is highly scalable. Extension to other wave phenomena is discussed by analyzing the parameter correspondence for the acoustic and electromagnetic case.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"509 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85245655","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Zhilin Cheng, Z. Ning, Qing Wang, Mingqi Li, W. Sui
As potential alternative resources, tight oil and gas reservoirs are generally exploited with multistage hydraulic fracturing technology to meet the rising demand for energy in the world. Considerable production recovered by the infiltration of fracturing fluids into the rock matrix shows that spontaneous imbibition (SI) is an effective oil recovery method. Through the use of Nuclear Magnetic Resonance (NMR) detection technique, the features of SI in oil-water and gas-water systems for tight sandstones were studied. The T2 spectra of these samples were used to reflect the migration patterns of fluids in various pores under different imbibition systems. In addition, the impacts of the boundary conditions on imbibition outcomes were also determined via the variations in T2 spectra under imbibition stages. The results indicate that tight sandstone samples display the feature of complex pore structure with a wide range of pore size distribution, and the dominant types are micropores and small mesopores. With the progression of imbibition experiments, oil in micropores will be more easily displaced by wetting fluid and flow out through interconnected smaller pores due to greater capillary pressure. The majority of the production through imbibition can be attributed to the contribution made by the micropores. However, water could not enter the mesopores readily under the gas-water system if it is only driven by capillary pressure owing to the snap-off effect of gas. The boundary conditions have notable effects on the imbibition rate and ultimate recovery for the oil-water system and increasing the areas available for water imbibition helps to maintain higher imbibition rate and recovery. However, regarding the gas-water system, boundary conditions have little influence on the imbibition recovery but have a remarkable influence on the imbibition rate. The traditional scaling equations used to scale the imbibition data for both the oil-water and gas-water systems and predict imbibition recovery is acceptable if the wettability of the tight medium remains unchanged. This research aims to uncover the imbibition characteristics of fluids and the nontrivial effect of boundary conditions in tight sandstone samples, which would contribute to the successful development of tight formations.
{"title":"Experimental Investigation of Boundary Conditions Effects on Spontaneous Imbibition in Oil-Water and Gas-Water Systems for Tight Sandstones","authors":"Zhilin Cheng, Z. Ning, Qing Wang, Mingqi Li, W. Sui","doi":"10.2118/194858-MS","DOIUrl":"https://doi.org/10.2118/194858-MS","url":null,"abstract":"\u0000 As potential alternative resources, tight oil and gas reservoirs are generally exploited with multistage hydraulic fracturing technology to meet the rising demand for energy in the world. Considerable production recovered by the infiltration of fracturing fluids into the rock matrix shows that spontaneous imbibition (SI) is an effective oil recovery method. Through the use of Nuclear Magnetic Resonance (NMR) detection technique, the features of SI in oil-water and gas-water systems for tight sandstones were studied. The T2 spectra of these samples were used to reflect the migration patterns of fluids in various pores under different imbibition systems. In addition, the impacts of the boundary conditions on imbibition outcomes were also determined via the variations in T2 spectra under imbibition stages. The results indicate that tight sandstone samples display the feature of complex pore structure with a wide range of pore size distribution, and the dominant types are micropores and small mesopores. With the progression of imbibition experiments, oil in micropores will be more easily displaced by wetting fluid and flow out through interconnected smaller pores due to greater capillary pressure. The majority of the production through imbibition can be attributed to the contribution made by the micropores. However, water could not enter the mesopores readily under the gas-water system if it is only driven by capillary pressure owing to the snap-off effect of gas. The boundary conditions have notable effects on the imbibition rate and ultimate recovery for the oil-water system and increasing the areas available for water imbibition helps to maintain higher imbibition rate and recovery. However, regarding the gas-water system, boundary conditions have little influence on the imbibition recovery but have a remarkable influence on the imbibition rate. The traditional scaling equations used to scale the imbibition data for both the oil-water and gas-water systems and predict imbibition recovery is acceptable if the wettability of the tight medium remains unchanged. This research aims to uncover the imbibition characteristics of fluids and the nontrivial effect of boundary conditions in tight sandstone samples, which would contribute to the successful development of tight formations.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83745592","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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