In this paper, we present a procedure for high pressure resin impregnation of microporous rock. This procedure produces the high- quality pore casts that reveal the fine details of the complex pore space of micritic carbonates. We carefully test our resin impregnation procedure and demonstrate that it renders the high resolution, 3D confocal images of pore casts. In our work, we use silicon micromodels as a reference to validate the key parameters of high-pressure resin impregnation. We demonstrate possible artifacts and defects that might develop during rock impregnation with resin, e.g., the resin shrinkage and gas trapping. The main outcome of this paper is a robust protocol for obtaining the high-quality epoxy pore casts suitable for rock imaging with Confocal Laser Scanning Microscopy (CLSM). We have implemented this protocol and provided the high resolution, three-dimensional (3D) imagery and description of microporosity in micritic carbonates.
{"title":"Validation of High Pressure Resin Impregnation Technique for High Resolution Confocal Imaging of Geological Samples","authors":"A. Hassan, M. Yutkin, V. Chandra, T. Patzek","doi":"10.2118/195020-MS","DOIUrl":"https://doi.org/10.2118/195020-MS","url":null,"abstract":"\u0000 In this paper, we present a procedure for high pressure resin impregnation of microporous rock. This procedure produces the high- quality pore casts that reveal the fine details of the complex pore space of micritic carbonates. We carefully test our resin impregnation procedure and demonstrate that it renders the high resolution, 3D confocal images of pore casts. In our work, we use silicon micromodels as a reference to validate the key parameters of high-pressure resin impregnation. We demonstrate possible artifacts and defects that might develop during rock impregnation with resin, e.g., the resin shrinkage and gas trapping. The main outcome of this paper is a robust protocol for obtaining the high-quality epoxy pore casts suitable for rock imaging with Confocal Laser Scanning Microscopy (CLSM). We have implemented this protocol and provided the high resolution, three-dimensional (3D) imagery and description of microporosity in micritic carbonates.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85125019","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}
B. Tiwari, S. Al-Sayegh, H. R. Al-Muraikhi, Pranay Kumar, P. Cueille, Frederic Lislaud
This paper highlights an unconventional approach of using DPDP (Dual Porosity Dual permeability) simulation technique for modelling hydraulic fractures in a full field simulation model during the forecast analysis performed on a tight carbonate reservoir in Kuwait. This was a part of integrated study in which ‘multi-stage hydraulic fracturing’ was recommended as the most optimum stimulation technique in order to enhance the productivity of all the proposed horizontal producers. Importance of DPDP model increases multi-fold when contrast between fracture and matrix permeability is in the order of 10 times or more. In the studied case, as average matrix permeability of the reservoir is in the range of 2-3 mD, this contrast is magnified to the order of 1000-10000 times (considering fracture permeability is in Darcies) which further complements the use of DPDP model. Three different approaches were tried to model the impact of multi-stage hydraulic fracturing in the full field simulation model; 1) ‘Enhance Well PI’ for all the stimulated wells, 2) ‘Enhance Matrix Permeability’ in the vicinity of all the stimulated wells, hereby referred as SPSP (Single Porosity Single Permeability) approach, and 3) build ‘DPDP Model’ by using upscaled fracture porosity and fracture permeability without changing the matrix properties. First two approaches are very common in the industry but most of the times are not able to capture the real impact of hydraulic fracturing on flow behaviour (bi-linear flow), whereas DPDP model is designed to capture the flow through dual medium. In both SPSP and DPDP approaches permeability anisotropy (increased permeability in the direction perpendicular to horizontal section of the well) in the fractured zone was very well captured and was needed to honour the hydraulic fractures direction. Fracture permeability was calculated using the Poiseuille's law; few sensitivity cases were run to address the associated uncertainty. Field cumulative oil production and recovery factor were analysed for ‘Enhanced Well PI’ case, SPSP cases and DPDP cases. Field oil cumulative production in DPDP cases is 6% more than SPSP cases and around 10% more than ‘Enhanced Well PI’ case. The hypothesis for the higher recovery in DPDP case with respect to other two cases is that bi-linear flow (fractures are getting filled with the matrix fluid and then feeding to well) is better represented in the DPDP model. Impact in this case is more significant due to the big contrast between matrix and fracture permeability. Low capacity with high conductivity signature of hydraulic fracture is difficult to model in the SPSP or just by enhancing the well PI. Study clearly demonstrated the benefits of DPDP model for modelling hydraulic fractures over the conventional methods.
{"title":"Modelling Hydraulic Fractures in a Full-Field Dynamic Model Using DPDP Simulation Techniques - An Unconventional Approach Applied in a Tight Carbonate Oil Reservoir, Kuwait, Middle-East","authors":"B. Tiwari, S. Al-Sayegh, H. R. Al-Muraikhi, Pranay Kumar, P. Cueille, Frederic Lislaud","doi":"10.2118/195156-MS","DOIUrl":"https://doi.org/10.2118/195156-MS","url":null,"abstract":"\u0000 This paper highlights an unconventional approach of using DPDP (Dual Porosity Dual permeability) simulation technique for modelling hydraulic fractures in a full field simulation model during the forecast analysis performed on a tight carbonate reservoir in Kuwait. This was a part of integrated study in which ‘multi-stage hydraulic fracturing’ was recommended as the most optimum stimulation technique in order to enhance the productivity of all the proposed horizontal producers. Importance of DPDP model increases multi-fold when contrast between fracture and matrix permeability is in the order of 10 times or more. In the studied case, as average matrix permeability of the reservoir is in the range of 2-3 mD, this contrast is magnified to the order of 1000-10000 times (considering fracture permeability is in Darcies) which further complements the use of DPDP model.\u0000 Three different approaches were tried to model the impact of multi-stage hydraulic fracturing in the full field simulation model; 1) ‘Enhance Well PI’ for all the stimulated wells, 2) ‘Enhance Matrix Permeability’ in the vicinity of all the stimulated wells, hereby referred as SPSP (Single Porosity Single Permeability) approach, and 3) build ‘DPDP Model’ by using upscaled fracture porosity and fracture permeability without changing the matrix properties. First two approaches are very common in the industry but most of the times are not able to capture the real impact of hydraulic fracturing on flow behaviour (bi-linear flow), whereas DPDP model is designed to capture the flow through dual medium. In both SPSP and DPDP approaches permeability anisotropy (increased permeability in the direction perpendicular to horizontal section of the well) in the fractured zone was very well captured and was needed to honour the hydraulic fractures direction. Fracture permeability was calculated using the Poiseuille's law; few sensitivity cases were run to address the associated uncertainty.\u0000 Field cumulative oil production and recovery factor were analysed for ‘Enhanced Well PI’ case, SPSP cases and DPDP cases. Field oil cumulative production in DPDP cases is 6% more than SPSP cases and around 10% more than ‘Enhanced Well PI’ case. The hypothesis for the higher recovery in DPDP case with respect to other two cases is that bi-linear flow (fractures are getting filled with the matrix fluid and then feeding to well) is better represented in the DPDP model. Impact in this case is more significant due to the big contrast between matrix and fracture permeability.\u0000 Low capacity with high conductivity signature of hydraulic fracture is difficult to model in the SPSP or just by enhancing the well PI. Study clearly demonstrated the benefits of DPDP model for modelling hydraulic fractures over the conventional methods.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84405720","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 wave velocity is defined theoretically by the Newton-Laplace equation, which relates the wave velocity, V, to the square root of the ratio of the elastic modulus, M, and density, ρ. Therefore, the equation indicates that the velocity is inversely proportional to density. However, the in-situ field measurements and laboratory experiments of compressional wave velocity through different rocks show otherwise, where the velocity is directly proportional to approximately the 4th power of density as stated by Gardner's numerical approximation. To clarify the apparent contrast between theory and observations, a new expression for the elastic modulus, M, is derived using Wyllie's time average equation and the Newton-Laplace equation. The new derived expression of the elastic modulus, M, provides dependence of M on density to approximately the 9th power, which subsequently results with the observed dependence of velocity on the 4th power of density. In addition, Gardner's equation is modified to accurately obtain the velocity over range of densities (from 1 g/cm3 to around 3 g/cm3). The findings are tested on real velocity and density well-log data. The results validate the derived expression of the elastic modulus as well as the generalized form of Gardner's equation.
{"title":"New Model for the Elastic Modulus for Saturated Porous Carbonate Rocks","authors":"M. A. Ismail, F. Morgan","doi":"10.2118/194764-MS","DOIUrl":"https://doi.org/10.2118/194764-MS","url":null,"abstract":"\u0000 The wave velocity is defined theoretically by the Newton-Laplace equation, which relates the wave velocity, V, to the square root of the ratio of the elastic modulus, M, and density, ρ. Therefore, the equation indicates that the velocity is inversely proportional to density. However, the in-situ field measurements and laboratory experiments of compressional wave velocity through different rocks show otherwise, where the velocity is directly proportional to approximately the 4th power of density as stated by Gardner's numerical approximation. To clarify the apparent contrast between theory and observations, a new expression for the elastic modulus, M, is derived using Wyllie's time average equation and the Newton-Laplace equation. The new derived expression of the elastic modulus, M, provides dependence of M on density to approximately the 9th power, which subsequently results with the observed dependence of velocity on the 4th power of density. In addition, Gardner's equation is modified to accurately obtain the velocity over range of densities (from 1 g/cm3 to around 3 g/cm3). The findings are tested on real velocity and density well-log data. The results validate the derived expression of the elastic modulus as well as the generalized form of Gardner's equation.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"72 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86265565","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}
O. Borozdina, M. Mamaghani, R. Barsalou, M. Lantoine, Agnès Pain
This work presents a new workflow to obtain a better-constrained reservoir-scale model for an Alkaline-Surfactant-Polymer (ASP) injection pilot design. It is explained how the impact of uncertain parameters related to ASP flooding can be quantified, using calibrated core-scale simulation based on experimental results, and how the influential parameters range for future reservoir-scale simulation can be determined. Computational costs of core-scale model are therefore much lower, and the final reservoir model is better constrained. ASP flooding feasibility implies core scale studies, where chemical formulations are validated in the laboratory under field conditions. In the objective of the pilot designing, a numerical model is constructed and calibrated to history-match the core flood sequences: Remaining Oil Saturation (ROS), surfactant-polymer (SP) and polymer-alkaline (PA) injection and eventually the chase water slug. In order to quantify the impact of ASP chemical parameters on the history match, the Global Sensitivity Analysis (GSA) was performed using Response Surface Modeling (RSM). To obtain the acceptable range of influential parameters for future reservoir-scale simulation, the Bayesian optimization is used. Applying this methodology on a real reservoir core, the laboratory measurements are accurately reproduced. Nevertheless, once the core-scale model was matched, the transition to reservoir-scale model must be done. Due to a large number of parameters and their associated uncertainties, this transition is not straight-forward. Thus, an additional step in our workflow is included. A new methodology is applied to firstly quantify the impact of uncertain parameters related to ASP flooding (adsorption of surfactant on the rock, critical micellar concentration, water mobility reduction by polymer etc.). To do so, the RSM is used and influential parameters are identified. In this study, the surfactant adsorption coefficients are the most influential parameters while others related to SPA have a poor impact on experiment results matching. Secondly, the acceptable range of influential parameters for future reservoir-scale simulation and feasibility study is obtained during Bayesian optimization. Thus, instead of using a wide (prior) range of uncertain parameters values, refined (posterior) distribution laws can be used for future reservoir model. While the classical approach consists in matching experimental results to obtain calibrated values of certain properties (that are then entered in the reservoir model) and finally determine the influential parameters at the reservoir scale, here the choice was made to determine influential parameters and characterize their impacts at the core scale. This step helps to better constrain the reservoir model. Ongoing work is using the results of this workflow for pilot design and risk analysis.
{"title":"Coreflood Model Optimization Workflow for ASP Pilot Design Risk Analysis","authors":"O. Borozdina, M. Mamaghani, R. Barsalou, M. Lantoine, Agnès Pain","doi":"10.2118/194855-MS","DOIUrl":"https://doi.org/10.2118/194855-MS","url":null,"abstract":"\u0000 This work presents a new workflow to obtain a better-constrained reservoir-scale model for an Alkaline-Surfactant-Polymer (ASP) injection pilot design. It is explained how the impact of uncertain parameters related to ASP flooding can be quantified, using calibrated core-scale simulation based on experimental results, and how the influential parameters range for future reservoir-scale simulation can be determined. Computational costs of core-scale model are therefore much lower, and the final reservoir model is better constrained.\u0000 ASP flooding feasibility implies core scale studies, where chemical formulations are validated in the laboratory under field conditions. In the objective of the pilot designing, a numerical model is constructed and calibrated to history-match the core flood sequences: Remaining Oil Saturation (ROS), surfactant-polymer (SP) and polymer-alkaline (PA) injection and eventually the chase water slug. In order to quantify the impact of ASP chemical parameters on the history match, the Global Sensitivity Analysis (GSA) was performed using Response Surface Modeling (RSM). To obtain the acceptable range of influential parameters for future reservoir-scale simulation, the Bayesian optimization is used.\u0000 Applying this methodology on a real reservoir core, the laboratory measurements are accurately reproduced. Nevertheless, once the core-scale model was matched, the transition to reservoir-scale model must be done. Due to a large number of parameters and their associated uncertainties, this transition is not straight-forward. Thus, an additional step in our workflow is included. A new methodology is applied to firstly quantify the impact of uncertain parameters related to ASP flooding (adsorption of surfactant on the rock, critical micellar concentration, water mobility reduction by polymer etc.). To do so, the RSM is used and influential parameters are identified. In this study, the surfactant adsorption coefficients are the most influential parameters while others related to SPA have a poor impact on experiment results matching. Secondly, the acceptable range of influential parameters for future reservoir-scale simulation and feasibility study is obtained during Bayesian optimization. Thus, instead of using a wide (prior) range of uncertain parameters values, refined (posterior) distribution laws can be used for future reservoir model.\u0000 While the classical approach consists in matching experimental results to obtain calibrated values of certain properties (that are then entered in the reservoir model) and finally determine the influential parameters at the reservoir scale, here the choice was made to determine influential parameters and characterize their impacts at the core scale. This step helps to better constrain the reservoir model. Ongoing work is using the results of this workflow for pilot design and risk analysis.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73237743","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}
Proppant flowback can cause equipment damage and restrict hydrocarbon production, making it an expensive issue. In response to industry demands for a solution, this paper presents a methodology designed to identify and help prevent flowback issues and to exhibit high cohesive strength to increase the stability of proppant packs. Liquid resin proppant coating applied during pumping operations shows significant conductivity enhancement and fines control in hydraulic fracturing operations, as compared with traditional curable resin-coated proppant (CRCP). The concentration of resin applied follows proven industry standards. Placement technique and concentration of resin can delay the cure time if needed, which enables the proppant pack to consolidate after placement in the fractures. In addition, it enables the proppant to obtain better grain-to-grain contact in the fracture, and capillary action pulls the liquid resin coating to the contact points of the proppant grains. This process provides a highly cohesive, consolidated proppant pack. The liquid resin system was designed to be mixed with the proppant immediately before it is added to the fracturing fluid during pumping operations, to consolidate after it is carried into the fracture. Laboratory analysis demonstrates that the resin will prevent fines from flowing back, and it will remain coated on the proppant in the fracture. During the post-treatment cleanout process, a flowback sample was collected and sent to the laboratory to verify that there was no resin content present. The sample was analyzed using Fourier transform infrared (FTIR) spectroscopy, and the resulting spectra were compared to the original resin chart. No resin was present. To confirm the results, a sample of the resin used on the treatment was mixed and analyzed for comparison in FTIR spectra. This paper describes the methodology to identify the presence of resin during well cleanout and to evaluate the proppant consolidations expected. A new methodology is presented to compare the fluid returned during well cleanup and to evaluate samples in laboratory experiments.
{"title":"Methodology to Identify Presence of Resin During Post-Fracturing Flowback","authors":"Ibrahim Al-Hulail, Abeer Al-Abdullatif","doi":"10.2118/194794-MS","DOIUrl":"https://doi.org/10.2118/194794-MS","url":null,"abstract":"\u0000 Proppant flowback can cause equipment damage and restrict hydrocarbon production, making it an expensive issue. In response to industry demands for a solution, this paper presents a methodology designed to identify and help prevent flowback issues and to exhibit high cohesive strength to increase the stability of proppant packs.\u0000 Liquid resin proppant coating applied during pumping operations shows significant conductivity enhancement and fines control in hydraulic fracturing operations, as compared with traditional curable resin-coated proppant (CRCP). The concentration of resin applied follows proven industry standards. Placement technique and concentration of resin can delay the cure time if needed, which enables the proppant pack to consolidate after placement in the fractures. In addition, it enables the proppant to obtain better grain-to-grain contact in the fracture, and capillary action pulls the liquid resin coating to the contact points of the proppant grains. This process provides a highly cohesive, consolidated proppant pack.\u0000 The liquid resin system was designed to be mixed with the proppant immediately before it is added to the fracturing fluid during pumping operations, to consolidate after it is carried into the fracture. Laboratory analysis demonstrates that the resin will prevent fines from flowing back, and it will remain coated on the proppant in the fracture. During the post-treatment cleanout process, a flowback sample was collected and sent to the laboratory to verify that there was no resin content present. The sample was analyzed using Fourier transform infrared (FTIR) spectroscopy, and the resulting spectra were compared to the original resin chart. No resin was present. To confirm the results, a sample of the resin used on the treatment was mixed and analyzed for comparison in FTIR spectra.\u0000 This paper describes the methodology to identify the presence of resin during well cleanout and to evaluate the proppant consolidations expected. A new methodology is presented to compare the fluid returned during well cleanup and to evaluate samples in laboratory experiments.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74880880","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 development of unconventional resources is capital intensive and challenging where operators spend a large amount of resources to maximize value. This is a direct result of completing thousands of wells with multistage fracturing. The optimization of well completion to enhance hydrocarbon recovery will help to reduce development costs and enhance project economics under the uncertainty parameters: geological, engineering, and economic. The paper demonstrates a novel workflow as an effective way to optimize completion design by integrating advanced multi-stage fracture modeling with reservoir simulation in an unconventional resource play. This work shows an integrated workflow using a compositional dynamic simulation study for gas condensate well. The complexity of gas flow physics in both nano-darcy reservoir as well as hydraulically fractured Stimulated Rock Volume (SRV) are considered. The physics include gas desorption, pressure dependent permeability, non-Darcy flow and gas condensate fluid behavior. The workflow includes QA/QC of the geologic model with a fine model resolution to map the hydraulic fractures. Long-term flow back data is used to calibrate the simulation model using history matching regions following the analytical trilinear model. After achieving a reasonable history matching, a detailed uncertainty assessment was performed to estimate P10, P50 and P90 of the well's EUR (Estimated Ultimate Recovery) using Proxy modeling workflow. Uncertainty parameters include hydraulic fracture half-length, SRV permeability, dew point pressure, under-saturated desorption pressure, rock compaction trend, etc. Finally, what-if scenarios were performed to assess the impact of cluster spacing, fracture height, horizontal well length and minimum well head pressure (WHP) on the well's EUR. The results of this work illustrates the workflow used to optimize well completion design including the number of stages along the lateral, length of the lateral, treatment sizes and how it impacts well performance as well to support management decision making.
{"title":"Use of Numerical Modeling to Optimize Completion Design of Horizontal Multistage Fractured Well in Unconventional Source Rock under Uncertainty Parameters","authors":"M. Rabah, B. Mustafa, H. Ali, S. Aramco","doi":"10.2118/195076-MS","DOIUrl":"https://doi.org/10.2118/195076-MS","url":null,"abstract":"\u0000 The development of unconventional resources is capital intensive and challenging where operators spend a large amount of resources to maximize value. This is a direct result of completing thousands of wells with multistage fracturing. The optimization of well completion to enhance hydrocarbon recovery will help to reduce development costs and enhance project economics under the uncertainty parameters: geological, engineering, and economic.\u0000 The paper demonstrates a novel workflow as an effective way to optimize completion design by integrating advanced multi-stage fracture modeling with reservoir simulation in an unconventional resource play. This work shows an integrated workflow using a compositional dynamic simulation study for gas condensate well. The complexity of gas flow physics in both nano-darcy reservoir as well as hydraulically fractured Stimulated Rock Volume (SRV) are considered. The physics include gas desorption, pressure dependent permeability, non-Darcy flow and gas condensate fluid behavior.\u0000 The workflow includes QA/QC of the geologic model with a fine model resolution to map the hydraulic fractures. Long-term flow back data is used to calibrate the simulation model using history matching regions following the analytical trilinear model. After achieving a reasonable history matching, a detailed uncertainty assessment was performed to estimate P10, P50 and P90 of the well's EUR (Estimated Ultimate Recovery) using Proxy modeling workflow. Uncertainty parameters include hydraulic fracture half-length, SRV permeability, dew point pressure, under-saturated desorption pressure, rock compaction trend, etc.\u0000 Finally, what-if scenarios were performed to assess the impact of cluster spacing, fracture height, horizontal well length and minimum well head pressure (WHP) on the well's EUR.\u0000 The results of this work illustrates the workflow used to optimize well completion design including the number of stages along the lateral, length of the lateral, treatment sizes and how it impacts well performance as well to support management decision making.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82179656","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}
Chemicals in oil fields have shown a great potential for enhancing/improving oil recovery (EOR/IOR) beyond waterflood baseline. The objectives of this work are: (1) to develop a cost-effective method to deliver chemicals to deeper layers in reservoirs compared to conventional chemical operations, (2) to synthesize nano-capsules with improved stability under typical reservoir temperatures (80-110 °C), and (3) to demonstrate the gradual release of EOR/IOR chemicals over time at a given temperature within the above range. Multiple slow-release technologies were developed; (1) Nano-salt (2) liposomes and (3) nano-capsules. In the first method, nano-size surfactant salt particle that has a limited solubility can traverse the reservoir and deliver, over a long period of time, a constant concentration of surfactant was synthesized. In addition to surfactant salts, surfactant-loaded nano-capsules were synthesized by dissolving a known lipid formula in 20.0 mL chloroform, then, evaporating the solvent to form a dried lipid film. Acid nano-capsules for improving oil recovery operations were synthesized using In situ and interfacial polymerization. Scanning electron microscopy, an optical microscopy, dynamic light scattering, Inductive coupled plasma (ICP-AES), pH and surfactant electrodes were used to characterize the nano-capsules and dispersion. To assist the nano-platforms slow-release profile and the particles stability under reservoir conditions, the samples were incubated in oven at 95 °C. The nano-capsules’ slow-release and stability were monitored for several days. The liposomes contain 11 wt. % of PETRONATE® EOR2095 with particles’ average size of ~80 nm, the surfactant released was gradually increased over sixty hours. The acid nano-capsules contain 15 wt. % acid precursor with particles’ average size of 200 nm. The capsules release versus time curve showed that the release occurred when the temperature reached 95 °C, indicating that nano-capsules’ release is triggered by the temperature increment. The pH versus time release curve exhibits a gradual decreasing in the pH over six day indicating the acid precursor hydrolysis at 95 °C. Our results demonstrate the possibility of improving current chemicals flood via nano-encapsulation. The slow release technology may bring new potentials to the current hydrocarbon production operations.
{"title":"Novel Nano-Capsules for Oil Field Chemicals Delivery and Slow Release","authors":"Al-Jabri Nouf Mohammed, Yun-Min Chang","doi":"10.2118/194696-MS","DOIUrl":"https://doi.org/10.2118/194696-MS","url":null,"abstract":"\u0000 Chemicals in oil fields have shown a great potential for enhancing/improving oil recovery (EOR/IOR) beyond waterflood baseline. The objectives of this work are: (1) to develop a cost-effective method to deliver chemicals to deeper layers in reservoirs compared to conventional chemical operations, (2) to synthesize nano-capsules with improved stability under typical reservoir temperatures (80-110 °C), and (3) to demonstrate the gradual release of EOR/IOR chemicals over time at a given temperature within the above range. Multiple slow-release technologies were developed; (1) Nano-salt (2) liposomes and (3) nano-capsules. In the first method, nano-size surfactant salt particle that has a limited solubility can traverse the reservoir and deliver, over a long period of time, a constant concentration of surfactant was synthesized. In addition to surfactant salts, surfactant-loaded nano-capsules were synthesized by dissolving a known lipid formula in 20.0 mL chloroform, then, evaporating the solvent to form a dried lipid film. Acid nano-capsules for improving oil recovery operations were synthesized using In situ and interfacial polymerization. Scanning electron microscopy, an optical microscopy, dynamic light scattering, Inductive coupled plasma (ICP-AES), pH and surfactant electrodes were used to characterize the nano-capsules and dispersion. To assist the nano-platforms slow-release profile and the particles stability under reservoir conditions, the samples were incubated in oven at 95 °C. The nano-capsules’ slow-release and stability were monitored for several days. The liposomes contain 11 wt. % of PETRONATE® EOR2095 with particles’ average size of ~80 nm, the surfactant released was gradually increased over sixty hours. The acid nano-capsules contain 15 wt. % acid precursor with particles’ average size of 200 nm. The capsules release versus time curve showed that the release occurred when the temperature reached 95 °C, indicating that nano-capsules’ release is triggered by the temperature increment. The pH versus time release curve exhibits a gradual decreasing in the pH over six day indicating the acid precursor hydrolysis at 95 °C. Our results demonstrate the possibility of improving current chemicals flood via nano-encapsulation. The slow release technology may bring new potentials to the current hydrocarbon production operations.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86465867","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}
As part of a multi-disciplinary study to explore the unconventional shale oil/ gas potential within a prospective carbonate/shale formation in Middle East, geomechanical analysis was carried out to understand the formation characteristics in order to evaluate hydraulic stimulation feasibility. The main objective of the geomechanical analysis was to select the most suitable area for fracturing in the few fields under study. To understand the geomechanical setting across different fields, well based 1-D geomechanical models were built for dozens of wells from few adjacent fields. Rock mechanical tests specifically designed for unconventional reservoirs were performed in cores of selected wells and the results were incorporated in the calibration of geomechanical models. In general, a mild and very strong strike-slip stress regime was identified over target lime shale and bounding limestone formations, respectively, with very high horizontal stress magnitude and anisotropy noticed in low clay and low TOC layers. Different stimulation scenarios were investigated by using hydraulic fracturing simulation software. The results suggest that the high horizontal stress contrast between target shale and the bounding organic-free limestone formations provide a very strong stress barrier which reduces the risk of out of zone propagation of hydraulic fractures and therefore, increases the efficiency of fracturing job. However, depletion reported within certain layers of interbedded limestone formations in some of these fields in this study, reduces the stress contrast and fracture containment in those fields due to poro-elastic effects. A geomechanical ranking system was developed to evaluate the relative feasibility and effectiveness of hydraulic fracturing treatments in the prospective shale target and also to identify sweet spots across four fields in the study. In order to develop this ranking system, several properties have been defined and estimated, based on the derived rock mechanical properties and stress models. These parameters address the containment of the fracture within the target shale, complexity of generated fracture and also amount of estimated over-pressure in the target interval. A final geomechanical rank was calculated by assigning a weight multiplier for each ranking parameter based on its relative influence on feasibility and quality of stimulated hydraulic fracture. Geomechanical ranking (resource accessibility) along with petrophysical ranking (resource volume) have been considered together to produce an integrated "chance of success" statement for different areas within the subject fields. Composite risk maps were developed based on rankings of wells from the study fields. These maps provide information on sweet spots which in turn have been used to shortlist highest ranked areas for the subsequent unconventional development program.
{"title":"Development of a Geomechanical Ranking System to Investigate Hydraulic Fracturing Feasibility of an Unconventional Shale Oil/Gas Reservoir: Case Study from Middle East","authors":"A. Ghadimipour, Hemant Singh, S. Perumalla","doi":"10.2118/194826-MS","DOIUrl":"https://doi.org/10.2118/194826-MS","url":null,"abstract":"\u0000 As part of a multi-disciplinary study to explore the unconventional shale oil/ gas potential within a prospective carbonate/shale formation in Middle East, geomechanical analysis was carried out to understand the formation characteristics in order to evaluate hydraulic stimulation feasibility. The main objective of the geomechanical analysis was to select the most suitable area for fracturing in the few fields under study. To understand the geomechanical setting across different fields, well based 1-D geomechanical models were built for dozens of wells from few adjacent fields. Rock mechanical tests specifically designed for unconventional reservoirs were performed in cores of selected wells and the results were incorporated in the calibration of geomechanical models.\u0000 In general, a mild and very strong strike-slip stress regime was identified over target lime shale and bounding limestone formations, respectively, with very high horizontal stress magnitude and anisotropy noticed in low clay and low TOC layers. Different stimulation scenarios were investigated by using hydraulic fracturing simulation software. The results suggest that the high horizontal stress contrast between target shale and the bounding organic-free limestone formations provide a very strong stress barrier which reduces the risk of out of zone propagation of hydraulic fractures and therefore, increases the efficiency of fracturing job. However, depletion reported within certain layers of interbedded limestone formations in some of these fields in this study, reduces the stress contrast and fracture containment in those fields due to poro-elastic effects.\u0000 A geomechanical ranking system was developed to evaluate the relative feasibility and effectiveness of hydraulic fracturing treatments in the prospective shale target and also to identify sweet spots across four fields in the study. In order to develop this ranking system, several properties have been defined and estimated, based on the derived rock mechanical properties and stress models. These parameters address the containment of the fracture within the target shale, complexity of generated fracture and also amount of estimated over-pressure in the target interval. A final geomechanical rank was calculated by assigning a weight multiplier for each ranking parameter based on its relative influence on feasibility and quality of stimulated hydraulic fracture.\u0000 Geomechanical ranking (resource accessibility) along with petrophysical ranking (resource volume) have been considered together to produce an integrated \"chance of success\" statement for different areas within the subject fields. Composite risk maps were developed based on rankings of wells from the study fields. These maps provide information on sweet spots which in turn have been used to shortlist highest ranked areas for the subsequent unconventional development program.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"714 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88933468","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 the paper is to share the experience and result of deployment of Virtual Workstation in Malaysia Oil and Gas Company replacing the more expensive high-end workstation. This is a part of company's digital transformation program towards the 4th Industrial Revolution. VWS is a modern technology that accelerates and improves subsurface and petroleum engineering application and function. It replaces outdated high-end workstation set-up. In high-end workstation set-up, subsurface technical software was installed at user workstations. Master Data on the other hand, located at centralized data center, BDC; but in order for the user to retrieve the data, it has to go through regional data center at KPC first. All these processes happened through existing small 1 GB cable networks capacity. Separate software and data location, multiple location points for data retrieval and weaker cable network capacity lead to less efficient software performance and data insecurity. But in VWS set-up, issues of under-performed software and data security are eliminated. Now both software and data are installed and located at BDC. Then the user will access their software and data virtually via company's intranet at with the strength of 10 GB cable network capacity that VWS has. VWS deployment resulting in: i) Performance and productivity: increased efficiency for technical applications and optimization of technical resources. ii) Cost: optimization of cost on IT infrastructure. iii) HSE: Reduced IT footprint and energy consumption. iv) Data security: increased data security. v) Flexibility: improved collaboration for technical users. vi) Standardization: standardized desktop environment for enhanced support. VWS deployment only need the VWS system and standard normal workstation to function as good as the more expensive high-end workstation. With VWS, standard workstation is enough to process and run petroleum engineering software and data, since the workstation only act as a visualizer of their actual software and data that located in BDC. With deployment of standard workstation instead of high-end workstation, VWS expected to contribute to cost saving of RM 86k per user for 3 years of leasing.
{"title":"Virtual Workstation Deployment in Malaysia Oil and Gas Company: Performance Improvement and Cost Reduction Experience","authors":"M. H. Mat Dait","doi":"10.2118/195064-MS","DOIUrl":"https://doi.org/10.2118/195064-MS","url":null,"abstract":"\u0000 The objective of the paper is to share the experience and result of deployment of Virtual Workstation in Malaysia Oil and Gas Company replacing the more expensive high-end workstation. This is a part of company's digital transformation program towards the 4th Industrial Revolution. VWS is a modern technology that accelerates and improves subsurface and petroleum engineering application and function. It replaces outdated high-end workstation set-up. In high-end workstation set-up, subsurface technical software was installed at user workstations. Master Data on the other hand, located at centralized data center, BDC; but in order for the user to retrieve the data, it has to go through regional data center at KPC first. All these processes happened through existing small 1 GB cable networks capacity. Separate software and data location, multiple location points for data retrieval and weaker cable network capacity lead to less efficient software performance and data insecurity. But in VWS set-up, issues of under-performed software and data security are eliminated. Now both software and data are installed and located at BDC. Then the user will access their software and data virtually via company's intranet at with the strength of 10 GB cable network capacity that VWS has. VWS deployment resulting in: i) Performance and productivity: increased efficiency for technical applications and optimization of technical resources. ii) Cost: optimization of cost on IT infrastructure. iii) HSE: Reduced IT footprint and energy consumption. iv) Data security: increased data security. v) Flexibility: improved collaboration for technical users. vi) Standardization: standardized desktop environment for enhanced support. VWS deployment only need the VWS system and standard normal workstation to function as good as the more expensive high-end workstation. With VWS, standard workstation is enough to process and run petroleum engineering software and data, since the workstation only act as a visualizer of their actual software and data that located in BDC. With deployment of standard workstation instead of high-end workstation, VWS expected to contribute to cost saving of RM 86k per user for 3 years of leasing.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88481557","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
G. S. Padhy, Pruthviraj Kasaraneni, Tahani Al-Rashidi, L. Tagarieva, A. Abba
Carbonate Reservoir characteristics and fluid properties can vary among multiple layers within the same stratigraphic unit. The objective of this case study is to emphasize the added values of integrating the data from a newly introduced formation testing technology along with open hole logs and core data to enhance the understanding of the Minagish Ooilte reservoir permeability distribution and fluid typing. The methodology implies the first time application of the newly introduced formation testing techology external mounted quartz pressure gauge and fluid typing sensors (density, viscosity, resistivity, capacitance, pressure and temperature), which could minimize reservoir fluid samples contamination and later validated by comparison to laboratory analysis results. The fluid sampling operation was conducted in different reservoir units with varying mobility values where the tested zones were selected based on the pressure pretests done prior to the sampling deployment. The success criteria to evaluate the pressure measurements capability of the new techgnology was met as set by the operator to have accuracy within 0.1psi range for two build-up in pretest at the same point. The data was integrated with open hole logs and laboratory measurements to provide a comprehensive formation evaluation and conclusive reservoir characterization after validation of the permeability. Heterogeniety in permeability measured/captured through RFT-tool was helpful to understand the reservoir flow capacity at the well location and subsequently select the right perforation intervals. Multiple fluid samples collected during this job aided in understanding the compositional variation with depth in the reservoir. Conjoining fluid variation with flow capacity of the reservoir was immensely useful to understand the true oil potential of the well and eventually select right production allowables. Production performance and productivity of the resulting well obtained after completing in the appropriate interval is better than other wells in the near vicinity. The high well performance and productivity reflect the value of the information provided by the novel formation testing technology sonde helped, as it achieve the well objectives, design the appropriate completion and most importantly resolve many Minagish Oolite reservoir characterization uncertainties in a timely efficient operation.
{"title":"Fluid Characterization Using a Novel Formation Testing Technology, A Case study","authors":"G. S. Padhy, Pruthviraj Kasaraneni, Tahani Al-Rashidi, L. Tagarieva, A. Abba","doi":"10.2118/194928-MS","DOIUrl":"https://doi.org/10.2118/194928-MS","url":null,"abstract":"\u0000 Carbonate Reservoir characteristics and fluid properties can vary among multiple layers within the same stratigraphic unit. The objective of this case study is to emphasize the added values of integrating the data from a newly introduced formation testing technology along with open hole logs and core data to enhance the understanding of the Minagish Ooilte reservoir permeability distribution and fluid typing.\u0000 The methodology implies the first time application of the newly introduced formation testing techology external mounted quartz pressure gauge and fluid typing sensors (density, viscosity, resistivity, capacitance, pressure and temperature), which could minimize reservoir fluid samples contamination and later validated by comparison to laboratory analysis results. The fluid sampling operation was conducted in different reservoir units with varying mobility values where the tested zones were selected based on the pressure pretests done prior to the sampling deployment. The success criteria to evaluate the pressure measurements capability of the new techgnology was met as set by the operator to have accuracy within 0.1psi range for two build-up in pretest at the same point. The data was integrated with open hole logs and laboratory measurements to provide a comprehensive formation evaluation and conclusive reservoir characterization after validation of the permeability.\u0000 Heterogeniety in permeability measured/captured through RFT-tool was helpful to understand the reservoir flow capacity at the well location and subsequently select the right perforation intervals. Multiple fluid samples collected during this job aided in understanding the compositional variation with depth in the reservoir. Conjoining fluid variation with flow capacity of the reservoir was immensely useful to understand the true oil potential of the well and eventually select right production allowables. Production performance and productivity of the resulting well obtained after completing in the appropriate interval is better than other wells in the near vicinity.\u0000 The high well performance and productivity reflect the value of the information provided by the novel formation testing technology sonde helped, as it achieve the well objectives, design the appropriate completion and most importantly resolve many Minagish Oolite reservoir characterization uncertainties in a timely efficient operation.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"63 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90970005","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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