O. Talabi, Ali Didanloo, M. F. Harun, I. Traboulay
The Oil Industry has been implementing Integrated Operations (IO), with several fields documenting value achieved from past and present IO initiatives. Largely, these documented IO initiatives have focused on well and equipment performance and general planning. However, Enhanced Oil Recovery (EOR) methods including thermal, chemical and gas injection which are increasingly being pursued in many fields globally require additional meticulous reservoir surveillance to understand and quantify the effectiveness of the EOR scheme which adds to the value of such projects. Interpretation and integration of all available data and processes into clear, structured and reproducible EOR well and reservoir management workflows to support decision making is still challenging due to the variety of disciplines, data acquisition, processing, analysis, and modeling techniques and technologies involved, and the level of collaboration required. Using an EOR-IO framework as a companion to the Reservoir Management Plan (RMP) can help address these challenges and increase the likelihood of project success. This paper describes such an EOR-IO framework which can be adapted for a wide variety of EOR processes as well as any general injection scheme (including water or gas) and presents a case study where this framework was implemented. The framework is a system for generating a clear framing and mapping of the EOR equipment, data, required analyses and decision processes using an assessment involving all EOR stakeholders and based on the Reservoir Management Plan (RMP). The framework enables all stakeholders to unambiguously understand and agree on how EOR performance will be quantified, what surveillance methods are required and what decisions will need to be taken. The framework facilitates a way for EOR management decision processes to be mapped onto technology-and-people enabled workflows that will help organize data, streamline analysis, define roles and enable efficient management of the EOR implementation in 5 clearly defined layers: Physical, Technology/Infrastructure, Process/Computational, Visualization and Organizational. Depending on the asset and project, the number of workflows may vary but they should fall into one of 3 groups: Operational Group: a system to support implementation of strategy at the operational level using real-time and in-time data.Tactical Group: a system that supports quantification of the overall effectiveness of the EOR scheme in the subsurface in terms of sweep, displacement, pressure, chemical loss, etc. using in-time analysis results.Strategic Group: a system to support identification of situations when an adjustment in EOR strategy is required and enable optimization of the strategy adjustment. This framework was successfully applied to a Field in Malaysia where a total of 6 EOR workflows were designed for managing the EOR scheme. The framework was flexible enough to enable design, development and implementation of the workflow
{"title":"An Integrated Operations Framework for Enhanced Oil Recovery EOR Management","authors":"O. Talabi, Ali Didanloo, M. F. Harun, I. Traboulay","doi":"10.2118/194663-MS","DOIUrl":"https://doi.org/10.2118/194663-MS","url":null,"abstract":"\u0000 The Oil Industry has been implementing Integrated Operations (IO), with several fields documenting value achieved from past and present IO initiatives. Largely, these documented IO initiatives have focused on well and equipment performance and general planning. However, Enhanced Oil Recovery (EOR) methods including thermal, chemical and gas injection which are increasingly being pursued in many fields globally require additional meticulous reservoir surveillance to understand and quantify the effectiveness of the EOR scheme which adds to the value of such projects. Interpretation and integration of all available data and processes into clear, structured and reproducible EOR well and reservoir management workflows to support decision making is still challenging due to the variety of disciplines, data acquisition, processing, analysis, and modeling techniques and technologies involved, and the level of collaboration required. Using an EOR-IO framework as a companion to the Reservoir Management Plan (RMP) can help address these challenges and increase the likelihood of project success. This paper describes such an EOR-IO framework which can be adapted for a wide variety of EOR processes as well as any general injection scheme (including water or gas) and presents a case study where this framework was implemented.\u0000 The framework is a system for generating a clear framing and mapping of the EOR equipment, data, required analyses and decision processes using an assessment involving all EOR stakeholders and based on the Reservoir Management Plan (RMP). The framework enables all stakeholders to unambiguously understand and agree on how EOR performance will be quantified, what surveillance methods are required and what decisions will need to be taken. The framework facilitates a way for EOR management decision processes to be mapped onto technology-and-people enabled workflows that will help organize data, streamline analysis, define roles and enable efficient management of the EOR implementation in 5 clearly defined layers: Physical, Technology/Infrastructure, Process/Computational, Visualization and Organizational. Depending on the asset and project, the number of workflows may vary but they should fall into one of 3 groups: Operational Group: a system to support implementation of strategy at the operational level using real-time and in-time data.Tactical Group: a system that supports quantification of the overall effectiveness of the EOR scheme in the subsurface in terms of sweep, displacement, pressure, chemical loss, etc. using in-time analysis results.Strategic Group: a system to support identification of situations when an adjustment in EOR strategy is required and enable optimization of the strategy adjustment.\u0000 This framework was successfully applied to a Field in Malaysia where a total of 6 EOR workflows were designed for managing the EOR scheme. The framework was flexible enough to enable design, development and implementation of the workflow","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81686612","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}
Using optical fibers to instrument hydraulically fractured wells is becoming routine in US unconventional plays. Instrumented wells facilitate understanding of proppant distribution among perforation clusters and the inefficiencies of geometric fracturing and well planning techniques. However, converting fiber-optic data into proppant distribution requires management of high volumes of data and correlation of the data to factors such as well conditions, fracturing parameters, and temperatures. A user-friendly workflow for understanding hydraulic fracturing proppant and slurry distribution among different perforation clusters over time is presented. Ideally, slurry flow is equal between perforation clusters and, at least, constant in time, but the reality is very different. The interpretation workflow is based on proprietary algorithms within a general wellbore software platform and aims to greatly expedite the analysis. We propose using distributed acoustic sensing (DAS) data (in the form of custom frequency band energy (FBE) logs), distributed temperature measurements (DTS) and surface pumping data to obtain a quantitative analysis of proppant distribution within minutes, with various options for reporting and visualizing results. The software platform selected provides data integration, visualization, and customization of in-built algorithms. The new workflow enables users to upload DAS, DTS, flow rate, pressure, and other measurements and use customized algorithms to quantitatively analyze proppant distribution, enabling decisions in real time to optimize the fracturing operation. The validity of the approach is illustrated by a case study involving a well with 28 stages and four to five clusters per stage. The workflow is automated to provide results in real time, enabling quick corrective actions and significantly improving the efficiency and economics of hydraulic fracturing.
{"title":"Fast-Loop Quantitative Analysis of Proppant Distribution Among Perforation Clusters","authors":"Dmitry Kortukov, Michael Williams","doi":"10.2118/195219-MS","DOIUrl":"https://doi.org/10.2118/195219-MS","url":null,"abstract":"\u0000 Using optical fibers to instrument hydraulically fractured wells is becoming routine in US unconventional plays. Instrumented wells facilitate understanding of proppant distribution among perforation clusters and the inefficiencies of geometric fracturing and well planning techniques. However, converting fiber-optic data into proppant distribution requires management of high volumes of data and correlation of the data to factors such as well conditions, fracturing parameters, and temperatures. A user-friendly workflow for understanding hydraulic fracturing proppant and slurry distribution among different perforation clusters over time is presented. Ideally, slurry flow is equal between perforation clusters and, at least, constant in time, but the reality is very different. The interpretation workflow is based on proprietary algorithms within a general wellbore software platform and aims to greatly expedite the analysis. We propose using distributed acoustic sensing (DAS) data (in the form of custom frequency band energy (FBE) logs), distributed temperature measurements (DTS) and surface pumping data to obtain a quantitative analysis of proppant distribution within minutes, with various options for reporting and visualizing results. The software platform selected provides data integration, visualization, and customization of in-built algorithms. The new workflow enables users to upload DAS, DTS, flow rate, pressure, and other measurements and use customized algorithms to quantitatively analyze proppant distribution, enabling decisions in real time to optimize the fracturing operation. The validity of the approach is illustrated by a case study involving a well with 28 stages and four to five clusters per stage. The workflow is automated to provide results in real time, enabling quick corrective actions and significantly improving the efficiency and economics of hydraulic fracturing.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"53 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89654489","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}
H. Alkinani, A. T. Al-Hameedi, S. Dunn-Norman, M. Alkhamis, R. A. Mutar
Lost circulation is a complicated problem to be predicted with conventional statistical tools. As the drilling environment is getting more complicated nowadays, more advanced techniques such as artificial neural networks (ANNs) are required to help to estimate mud losses prior to drilling. The aim of this work is to estimate mud losses for induced fractures formations prior to drilling to assist the drilling personnel in preparing remedies for this problem prior to entering the losses zone. Once the severity of losses is known, the key drilling parameters can be adjusted to avoid or at least mitigate losses as a proactive approach. Lost circulation data were extracted from over 1500 wells drilled worldwide. The data were divided into three sets; training, validation, and testing datasets. 60% of the data are used for training, 20% for validation, and 20% for testing. Any ANN consists of the following layers, the input layer, hidden layer(s), and the output layer. A determination of the optimum number of hidden layers and the number of neurons in each hidden layer is required to have the best estimation, this is done using the mean square of error (MSE). A supervised ANNs was created for induced fractures formations. A decision was made to have one hidden layer in the network with ten neurons in the hidden layer. Since there are many training algorithms to choose from, it was necessary to choose the best algorithm for this specific data set. Ten different training algorithms were tested, the Levenberg-Marquardt (LM) algorithm was chosen since it gave the lowest MSE and it had the highest R-squared. The final results showed that the supervised ANN has the ability to predict lost circulation with an overall R-squared of 0.925 for induced fractures formations. This is a very good estimation that will help the drilling personnel prepare remedies before entering the losses zone as well as adjusting the key drilling parameters to avoid or at least mitigate losses as a proactive approach. This ANN can be used globally for any induced fractures formations that are suffering from the lost circulation problem to estimate mud losses. As the demand for energy increases, the drilling process is becoming more challenging. Thus, more advanced tools such as ANNs are required to better tackle these problems. The ANN built in this paper can be adapted to commercial software that predicts lost circulation for any induced fractures formations globally.
{"title":"Prediction of Lost Circulation Prior to Drilling for Induced Fractures Formations Using Artificial Neural Networks","authors":"H. Alkinani, A. T. Al-Hameedi, S. Dunn-Norman, M. Alkhamis, R. A. Mutar","doi":"10.2118/195197-MS","DOIUrl":"https://doi.org/10.2118/195197-MS","url":null,"abstract":"\u0000 Lost circulation is a complicated problem to be predicted with conventional statistical tools. As the drilling environment is getting more complicated nowadays, more advanced techniques such as artificial neural networks (ANNs) are required to help to estimate mud losses prior to drilling. The aim of this work is to estimate mud losses for induced fractures formations prior to drilling to assist the drilling personnel in preparing remedies for this problem prior to entering the losses zone. Once the severity of losses is known, the key drilling parameters can be adjusted to avoid or at least mitigate losses as a proactive approach.\u0000 Lost circulation data were extracted from over 1500 wells drilled worldwide. The data were divided into three sets; training, validation, and testing datasets. 60% of the data are used for training, 20% for validation, and 20% for testing. Any ANN consists of the following layers, the input layer, hidden layer(s), and the output layer. A determination of the optimum number of hidden layers and the number of neurons in each hidden layer is required to have the best estimation, this is done using the mean square of error (MSE). A supervised ANNs was created for induced fractures formations. A decision was made to have one hidden layer in the network with ten neurons in the hidden layer. Since there are many training algorithms to choose from, it was necessary to choose the best algorithm for this specific data set. Ten different training algorithms were tested, the Levenberg-Marquardt (LM) algorithm was chosen since it gave the lowest MSE and it had the highest R-squared. The final results showed that the supervised ANN has the ability to predict lost circulation with an overall R-squared of 0.925 for induced fractures formations. This is a very good estimation that will help the drilling personnel prepare remedies before entering the losses zone as well as adjusting the key drilling parameters to avoid or at least mitigate losses as a proactive approach. This ANN can be used globally for any induced fractures formations that are suffering from the lost circulation problem to estimate mud losses.\u0000 As the demand for energy increases, the drilling process is becoming more challenging. Thus, more advanced tools such as ANNs are required to better tackle these problems. The ANN built in this paper can be adapted to commercial software that predicts lost circulation for any induced fractures formations globally.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"61 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88134718","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}
P. Sengupta, N. Katre, A. Suman, Barnali Das, A. S. Pawar, S. Deshpande
In any onshore gas installation, bath-heaters and high pressure separators are provided as standard surface facilities to take production from high pressure wells having hydrate forming tendency. Medium pressure separators are also provided to take production from medium pressure gas wells. The paper deliberates on an optimized surface installation for handling high pressure well fluids with possibilities of hydrate formation. The study has been carried out through steady state multiphase simulation considering pressure & production profile of the wells, consumer requirement and flow assurance i.e. hydrate formation. An optimized process scheme and production strategy is presented for early production from both high pressure and medium pressure gas wells in a single separator and without any bath heater. Based on well test data, well completion data and pressure profile, simulation studies are carried out in steady-state multiphase flow simulation software to look into possibility of hydrate formation in the flow lines or in process piping. Flow from wells having high well-head pressures in the range of 120 to 165 kg/cm2g (ksc) are simulated by varying the separator pressure, flow line size & length and choke arrangement. Flow simulations are carried out for different choke combinations and flow line arrangements to keep well fluid temperature above hydrate formation temperature in the entire flow path from well head to separators. It was established from simulations that flow from the well having highest production as well as highest well head pressure of 165 ksc can be taken by operating the separator at 33 ksc and adopting a multi-choke arrangement along the flow line without any possibility of hydrate formation in the system. The multi-choke arrangement consists of putting chokes including well head choke at well site, at installation inlet and the final choke at installation inlet manifold. The arrangement also envisages additional small length of flow line as buried portion near installation inlet to take advantage of heat gain from soil. From 2nd year onwards of the profile period, it is observed that with reduction in well head pressure to 132 ksc as per profile, the well can be produced by operating the separator at lower pressure without any hydrate formation. For rest of the wells, only multi-choke arrangement is found to be sufficient to prevent hydrate problem while operating the separator at even lower pressure throughout the profile period. It is also observed that higher production can be taken from the wells from 2nd year onwards on account of operating the separator at lower pressure. The optimized scheme has marked deviation from the earlier proposed standard scheme with substantial reduction in number of equipment and consequent reduction in CAPEX & OPEX. This novel process scheme and production strategy eliminate the need for investment in both high pressure separator and hydrate mitigation measures like heat tracing, me
{"title":"Conceptualization of Optimized Surface Facilities for a Proposed Gas Installation - A Case Study","authors":"P. Sengupta, N. Katre, A. Suman, Barnali Das, A. S. Pawar, S. Deshpande","doi":"10.2118/194609-MS","DOIUrl":"https://doi.org/10.2118/194609-MS","url":null,"abstract":"\u0000 In any onshore gas installation, bath-heaters and high pressure separators are provided as standard surface facilities to take production from high pressure wells having hydrate forming tendency. Medium pressure separators are also provided to take production from medium pressure gas wells. The paper deliberates on an optimized surface installation for handling high pressure well fluids with possibilities of hydrate formation. The study has been carried out through steady state multiphase simulation considering pressure & production profile of the wells, consumer requirement and flow assurance i.e. hydrate formation. An optimized process scheme and production strategy is presented for early production from both high pressure and medium pressure gas wells in a single separator and without any bath heater.\u0000 Based on well test data, well completion data and pressure profile, simulation studies are carried out in steady-state multiphase flow simulation software to look into possibility of hydrate formation in the flow lines or in process piping. Flow from wells having high well-head pressures in the range of 120 to 165 kg/cm2g (ksc) are simulated by varying the separator pressure, flow line size & length and choke arrangement. Flow simulations are carried out for different choke combinations and flow line arrangements to keep well fluid temperature above hydrate formation temperature in the entire flow path from well head to separators.\u0000 It was established from simulations that flow from the well having highest production as well as highest well head pressure of 165 ksc can be taken by operating the separator at 33 ksc and adopting a multi-choke arrangement along the flow line without any possibility of hydrate formation in the system. The multi-choke arrangement consists of putting chokes including well head choke at well site, at installation inlet and the final choke at installation inlet manifold. The arrangement also envisages additional small length of flow line as buried portion near installation inlet to take advantage of heat gain from soil. From 2nd year onwards of the profile period, it is observed that with reduction in well head pressure to 132 ksc as per profile, the well can be produced by operating the separator at lower pressure without any hydrate formation. For rest of the wells, only multi-choke arrangement is found to be sufficient to prevent hydrate problem while operating the separator at even lower pressure throughout the profile period. It is also observed that higher production can be taken from the wells from 2nd year onwards on account of operating the separator at lower pressure.\u0000 The optimized scheme has marked deviation from the earlier proposed standard scheme with substantial reduction in number of equipment and consequent reduction in CAPEX & OPEX. This novel process scheme and production strategy eliminate the need for investment in both high pressure separator and hydrate mitigation measures like heat tracing, me","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87647627","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}
Sagar Nauduri, M. Parker, A. Nabiyev, Eddy Sampley, L. Kirstein, Jason M. Morris, Matthew R. Wilkinson, Jason E. Buckner
A novel drilling solution, ‘Constant Bottomhole Pressure (CBHP) Managed Pressure Drilling (MPD) assisted Casing Drilling operation', was designed, planned and successfully executed for different operators on multiple directional wells in North America. These wells were otherwise not drillable either conventionally or with CBHP MPD using conventional drillpipe-BHA; and over the last few decades several operators tried and failed to reach the Target Depth (TD) on multiple occasions when drilling some of these formations. One operator drilled in formations prone to severe faulting/fracturing and with very high permeability, while a different operator drilled through multiple weak zones interbedded with over-pressured and highly conductive regions. Both scenarios resulted in similar issues with fluid displacement, tripping/surge and swab, kicks and losses, running casing and cementing. The generic CBHP MPD solution with a conventional drillpipe-BHA even with ‘Anchor Point' CBHP MPD and its variations was not successful in either of these scenarios in drilling to the TD. As demonstrated using case histories, the success in these projects was a result of combining two technologies – ‘CBHP MPD' and ‘Casing Drilling'. Pre-planning, understanding formation constraints, training, and having knowledgeable and experienced people involved, enabled safe and successful execution of CBHP MPD assisted Casing Drilling on these projects and helped CBHP MPD develop and reach new horizons.
{"title":"CBHP MPD Assisted Casing Drilling: A Novel MPD Solution Combining Two Drilling Technologies, Planned and Executed on Otherwise Not Drillable Multiple Directional Wells in North America","authors":"Sagar Nauduri, M. Parker, A. Nabiyev, Eddy Sampley, L. Kirstein, Jason M. Morris, Matthew R. Wilkinson, Jason E. Buckner","doi":"10.2118/194534-MS","DOIUrl":"https://doi.org/10.2118/194534-MS","url":null,"abstract":"\u0000 A novel drilling solution, ‘Constant Bottomhole Pressure (CBHP) Managed Pressure Drilling (MPD) assisted Casing Drilling operation', was designed, planned and successfully executed for different operators on multiple directional wells in North America. These wells were otherwise not drillable either conventionally or with CBHP MPD using conventional drillpipe-BHA; and over the last few decades several operators tried and failed to reach the Target Depth (TD) on multiple occasions when drilling some of these formations.\u0000 One operator drilled in formations prone to severe faulting/fracturing and with very high permeability, while a different operator drilled through multiple weak zones interbedded with over-pressured and highly conductive regions. Both scenarios resulted in similar issues with fluid displacement, tripping/surge and swab, kicks and losses, running casing and cementing. The generic CBHP MPD solution with a conventional drillpipe-BHA even with ‘Anchor Point' CBHP MPD and its variations was not successful in either of these scenarios in drilling to the TD.\u0000 As demonstrated using case histories, the success in these projects was a result of combining two technologies – ‘CBHP MPD' and ‘Casing Drilling'. Pre-planning, understanding formation constraints, training, and having knowledgeable and experienced people involved, enabled safe and successful execution of CBHP MPD assisted Casing Drilling on these projects and helped CBHP MPD develop and reach new horizons.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88832857","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}
Fatehgarh reservoirs in Aishwariya field, located in Barmer Basin of Rajasthan India, have very high CO2 content in reservoir fluid. A procedure was developed earlier to model the impact of reservoir CO2 on waterflood, polymer flood and ASP flood (Mishra and Pandey 2017, 2018) in this field. Another observation is that in such a system with very high amount of CO2, produced gas rate does not follow conventional trend. Conventionally, gas is dissolved in oil and produced gas is the gas released out from the oil. However, in a system like Aishwariya with very high amount of CO2 in dissolved gas, produced gas is the cumulative of gas released out from both liquid streams i.e., oil and water. Interestingly, gas can continue to produce even after no more oil is being produced from the system. A live oil coreflood was carried out to generate produced gas rate profile under Aishwariya reservoir conditions. The objective of this work was to validate the modelling procedure developed to predict the produced gas rate in such a system with very high amount of CO2 in reservoir fluid. A live oil coreflood experiment was carried out using 12 inches long Bentheimer core under Aishwariya reservoir pressure and temperature conditions. After saturating the core with live oil, the core was water flooded with brine for ~3.7 pore volumes. Produced gas volume was measured at different times so as to generate gas production profile. Two different simulation techniques were used to simulate the experiment and match the gas production profile. First technique was using a compositional simulator with EOS based PVT while the other technique was using an "advanced processes simulator" modeling the component distributions based on partitioning coefficients. Both methods could successfully capture the production of gas from both liquid streams; oil and water and a reasonable match for the produced gas could be obtained. The approach developed to simulate impact of CO2 on different aqueous based flooding processes in Aishwariya field was validated by matching the coreflood experiment carried out under actual Aishwariya reservoir conditions. It helped to confirm confidence in performance prediction of aqueous based flooding mechanisms planned in Aishwariya field despite the presence of significant amount of CO2. The paper presents history match of unconventional produced gas profile of a coreflood carried out under Aishwariya field conditions with very high amount of dissolved CO2. The proposed method can be applied to estimate produced gas rate in other fields with very high amount of CO2 in reservoir fluid.
{"title":"Validation of Produced Gas Rate Modelling in an Oil Reservoir with Very High CO2 Through Matching of Live Oil Coreflood","authors":"S. Mishra, A. Pandey","doi":"10.2118/194604-MS","DOIUrl":"https://doi.org/10.2118/194604-MS","url":null,"abstract":"\u0000 Fatehgarh reservoirs in Aishwariya field, located in Barmer Basin of Rajasthan India, have very high CO2 content in reservoir fluid. A procedure was developed earlier to model the impact of reservoir CO2 on waterflood, polymer flood and ASP flood (Mishra and Pandey 2017, 2018) in this field. Another observation is that in such a system with very high amount of CO2, produced gas rate does not follow conventional trend. Conventionally, gas is dissolved in oil and produced gas is the gas released out from the oil. However, in a system like Aishwariya with very high amount of CO2 in dissolved gas, produced gas is the cumulative of gas released out from both liquid streams i.e., oil and water. Interestingly, gas can continue to produce even after no more oil is being produced from the system. A live oil coreflood was carried out to generate produced gas rate profile under Aishwariya reservoir conditions.\u0000 The objective of this work was to validate the modelling procedure developed to predict the produced gas rate in such a system with very high amount of CO2 in reservoir fluid.\u0000 A live oil coreflood experiment was carried out using 12 inches long Bentheimer core under Aishwariya reservoir pressure and temperature conditions. After saturating the core with live oil, the core was water flooded with brine for ~3.7 pore volumes. Produced gas volume was measured at different times so as to generate gas production profile.\u0000 Two different simulation techniques were used to simulate the experiment and match the gas production profile. First technique was using a compositional simulator with EOS based PVT while the other technique was using an \"advanced processes simulator\" modeling the component distributions based on partitioning coefficients. Both methods could successfully capture the production of gas from both liquid streams; oil and water and a reasonable match for the produced gas could be obtained.\u0000 The approach developed to simulate impact of CO2 on different aqueous based flooding processes in Aishwariya field was validated by matching the coreflood experiment carried out under actual Aishwariya reservoir conditions. It helped to confirm confidence in performance prediction of aqueous based flooding mechanisms planned in Aishwariya field despite the presence of significant amount of CO2.\u0000 The paper presents history match of unconventional produced gas profile of a coreflood carried out under Aishwariya field conditions with very high amount of dissolved CO2. The proposed method can be applied to estimate produced gas rate in other fields with very high amount of CO2 in reservoir fluid.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78386683","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}
M. Gupta, J. Sukanandan, V. Singh, R. Bansal, A. S. Pawar, B. Deuri
This paper discusses a case study of one of the onshore field of ONGC where while processing well fluid, frequent surge has been observed leading to shutdown of the SDVs creating severe operational problems and loss of production. It was imperative to find out the problematic wells/lines located in clusters which contribute for surge formation and mitigation approach with minimum modifications. A transient complex network of sixty five wells flowing with a different lift mode such as intermittent gas lift, continuous gas lift etc were developed in a dynamic multiphase flow simulator OLGA. Time cycle of each well were introduced for intermittent lift wells. Simulation study reveals pulsating transient trends of liquid flow, pressure which was matched with the real time data of the plant and hence confirms the accuracy of the model. After verifying the results, different scenarios were created to determine the causes of surge formation. After finding the cause, a low cost approach was considered for surge mitigations. An integrated rigorous simulation was carried out in OLGA, by feeding more than 12,000 data points to obtain model match. Several scenarios were also created such as optimization of lift gas quantity, optimization of elevation and size. Trend obtained after each scenario was pulsating behaviour and it matched with the real time data appearing in the SCADA system of the field. After rigorous simulation with each scenario, it was established that the cause of surge forming wells/pipelines. Once the root cause of surge has been confirmed then quantum of liquid generated due to surge was determined. Adequacy checks of the existing separators were carried out to estimate the handling capacity of the existing separators at prevalent operating condition. After adequacy check it was found that existing separators cannot handle the surge generated in that time interval leading to cross the high-high safety level, resulting closure of shut down valve (SDV). After establishment of root cause of the surge, a low cost solution with small modification in pipelines and control system/valves was adopted to arrest the surges. It was first of its kind simulation carried out for a huge network of wells/ pipelines by feeding more than 12,000 data to analyze the surge formation cause and capture its dynamism owing to wide array of suspected causes. This will help to address the challenges of efficiently reviewing the entire pipeline network while designing new well pad/GGS and will also help to arrest surge by adopting a low cost solution wherever such situation arises.
{"title":"A Case Study on Identification & Mitigation of Surges in a Cluster of Composite Well Flow Line Network","authors":"M. Gupta, J. Sukanandan, V. Singh, R. Bansal, A. S. Pawar, B. Deuri","doi":"10.2118/194597-MS","DOIUrl":"https://doi.org/10.2118/194597-MS","url":null,"abstract":"\u0000 This paper discusses a case study of one of the onshore field of ONGC where while processing well fluid, frequent surge has been observed leading to shutdown of the SDVs creating severe operational problems and loss of production. It was imperative to find out the problematic wells/lines located in clusters which contribute for surge formation and mitigation approach with minimum modifications.\u0000 A transient complex network of sixty five wells flowing with a different lift mode such as intermittent gas lift, continuous gas lift etc were developed in a dynamic multiphase flow simulator OLGA. Time cycle of each well were introduced for intermittent lift wells. Simulation study reveals pulsating transient trends of liquid flow, pressure which was matched with the real time data of the plant and hence confirms the accuracy of the model. After verifying the results, different scenarios were created to determine the causes of surge formation. After finding the cause, a low cost approach was considered for surge mitigations.\u0000 An integrated rigorous simulation was carried out in OLGA, by feeding more than 12,000 data points to obtain model match. Several scenarios were also created such as optimization of lift gas quantity, optimization of elevation and size. Trend obtained after each scenario was pulsating behaviour and it matched with the real time data appearing in the SCADA system of the field. After rigorous simulation with each scenario, it was established that the cause of surge forming wells/pipelines. Once the root cause of surge has been confirmed then quantum of liquid generated due to surge was determined. Adequacy checks of the existing separators were carried out to estimate the handling capacity of the existing separators at prevalent operating condition. After adequacy check it was found that existing separators cannot handle the surge generated in that time interval leading to cross the high-high safety level, resulting closure of shut down valve (SDV). After establishment of root cause of the surge, a low cost solution with small modification in pipelines and control system/valves was adopted to arrest the surges. It was first of its kind simulation carried out for a huge network of wells/ pipelines by feeding more than 12,000 data to analyze the surge formation cause and capture its dynamism owing to wide array of suspected causes. This will help to address the challenges of efficiently reviewing the entire pipeline network while designing new well pad/GGS and will also help to arrest surge by adopting a low cost solution wherever such situation arises.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"224 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83661024","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. Mishra, R. Meena, Sujit Mitra, K. Saha, Vilas Pandurangji Dhakate, O. Prakash, Raman R. K. Singh
India is the fastest growing major economy and third largest CO2 emitter in the world. Keeping cognizance of country's energy requirement and commitment to climate change, embarking upon technologies having minimal carbon footprint is the need of the hour. Carbon capture, utilization and storage (CCUS) is one such technology which offers dual benefits of carbon sequestration & enhancing oil production from mature oils fields. This paper outlines ONGC's efforts in bringing nation's first CO2-EOR project. In view of non-availability of natural CO2 sources in India, usage of anthropogenic CO2 captured from thermal power plants was conceptualised. Based upon CO2 source-sink matching exercise and favourable reservoir & fluid parameters, two oil fields were screened. Technical feasibility of CO2-EOR was first ascertained in laboratory by determination of minimum miscibility pressure (MMP) of CO2 through slim tube experiments. Encouraged by laboratory results, full field compositional simulation studies along with fluid characterization inputs from PVT simulator were carried out. The MMP were found to be in range 190-250 Ksc, which is below the initial reservoir pressures of the targeted reservoirs. The proposed scheme entails drilling of around 70-80 wells inclusive of both producers & injectors and has the potential to yield an incremental recovery between 10-14 %. A sensitivity analysis based upon purity of CO2 and its adverse effect on MMP was carried out in terms of reduced oil recoveries. Since, this shall be a CCUS project, CO2 from the produced stream has to be separated, compressed and reinjected in a closed loop system. Around 5-8 MMT of CO2 will be sequestrated through Structural, Solubility and Residual trapping mechanisms as modelled in compositional simulator. IFT reduction & decrease in Sor (Residual oil saturation) as result of swelling, miscibility of CO2 with native oil were also modelled in simulator. Being first of its kind project in India, there are many inherent challenges to the CCUS project. At the source end, capturing CO2 from flue gas stream and its compression & transportation is a cost and energy intensive process. At the Sink end, CO2 being acidic and corrosive gas will need retrofit modifications in terms of special corrosion resistant metallurgy for existing processing facilities. The learning curve from this endeavour shall create knowledge base to further expand deployment of CCUS in India, bringing a large portfolio of reservoirs under the ambit of CO2-EOR. Success of CCUS in India will not only increase domestic oil production but also cater to address the National INDC of reducing emission intensity of GDP by 33-35 percent by 2030 as per Paris agreement.
{"title":"Planning India's First CO2-EOR Project as Carbon Capture Utilization & Storage: A Step Towards Sustainable Growth","authors":"G. Mishra, R. Meena, Sujit Mitra, K. Saha, Vilas Pandurangji Dhakate, O. Prakash, Raman R. K. Singh","doi":"10.2118/194629-MS","DOIUrl":"https://doi.org/10.2118/194629-MS","url":null,"abstract":"\u0000 India is the fastest growing major economy and third largest CO2 emitter in the world. Keeping cognizance of country's energy requirement and commitment to climate change, embarking upon technologies having minimal carbon footprint is the need of the hour. Carbon capture, utilization and storage (CCUS) is one such technology which offers dual benefits of carbon sequestration & enhancing oil production from mature oils fields. This paper outlines ONGC's efforts in bringing nation's first CO2-EOR project.\u0000 In view of non-availability of natural CO2 sources in India, usage of anthropogenic CO2 captured from thermal power plants was conceptualised. Based upon CO2 source-sink matching exercise and favourable reservoir & fluid parameters, two oil fields were screened. Technical feasibility of CO2-EOR was first ascertained in laboratory by determination of minimum miscibility pressure (MMP) of CO2 through slim tube experiments. Encouraged by laboratory results, full field compositional simulation studies along with fluid characterization inputs from PVT simulator were carried out.\u0000 The MMP were found to be in range 190-250 Ksc, which is below the initial reservoir pressures of the targeted reservoirs. The proposed scheme entails drilling of around 70-80 wells inclusive of both producers & injectors and has the potential to yield an incremental recovery between 10-14 %. A sensitivity analysis based upon purity of CO2 and its adverse effect on MMP was carried out in terms of reduced oil recoveries. Since, this shall be a CCUS project, CO2 from the produced stream has to be separated, compressed and reinjected in a closed loop system. Around 5-8 MMT of CO2 will be sequestrated through Structural, Solubility and Residual trapping mechanisms as modelled in compositional simulator. IFT reduction & decrease in Sor (Residual oil saturation) as result of swelling, miscibility of CO2 with native oil were also modelled in simulator. Being first of its kind project in India, there are many inherent challenges to the CCUS project. At the source end, capturing CO2 from flue gas stream and its compression & transportation is a cost and energy intensive process. At the Sink end, CO2 being acidic and corrosive gas will need retrofit modifications in terms of special corrosion resistant metallurgy for existing processing facilities.\u0000 The learning curve from this endeavour shall create knowledge base to further expand deployment of CCUS in India, bringing a large portfolio of reservoirs under the ambit of CO2-EOR. Success of CCUS in India will not only increase domestic oil production but also cater to address the National INDC of reducing emission intensity of GDP by 33-35 percent by 2030 as per Paris agreement.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82077186","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 effects of horizontal well geometry remain debatable in most production modeling works. Most of recent reports fail to mention the effects of well geometries, especially in severe slugging cases. This study presents a qualitative comparison between different well geometries and their impacts in production performance of horizontal wells. The study utilizes a transient multiphase simulator to mimic the production from a horizontal well over a 12-hour period. The well has a 2-7/8″ ID tubing with TVD of approximately 5000 ft and MD of 10000 ft and maximum inclination angle of 10º within the horizontal section. The trajectories of horizontal section in the well include 5 cases, 5 undulations, hump (one undulation upward), sump (one undulation downward), toe-up and toe-down. These configurations are the representative examples of horizontal wells. A reservoir with a given deliverability equation and several perforation stages is used to provide well inflow. The impacts of reservoir deliverability, GOR, pressure and temperature are studied for all well geometries. The simulation results offer some valuable insights into the effects of well trajectory on production performance, including borehole pressure profile, liquid holdup, gas and liquid rate variations with time, and cumulative gas and liquid production. At high production rates, severe slugging is not observed, and thus, the well geometry effects are minimized with a consistent production at the surface. However, toe-up configuration exhibits a slightly better performance than the others. As the productivity and pressure reduces throughout the life of a well, the impacts of well trajectories become clearer. The presence of severe slugs and blockage of perforations near the toes causes a noticeable drop in production. During severe slugging, the pressure profile reveals longer fluctuation cycles, resulting in extreme separator flooding issues. The slugging frequencies are compared among different well geometries. Toe-down case exhibits lower slugging severity. As a result, toe-down well produces the highest cumulative liquid and gas rates. The presence of liquid blockage is observed in lateral and curvature sections. The toe-up and hump configurations exhibit the most severe slugs with minimum cumulative gas and liquid productions. The differences in productions among well trajectories exceed 30% under different well configurations. With the augmented growth of production from unconventional reservoirs, horizontal well technology has grown in oil and gas industry, yet study of well geometry in production system remains to be limited. This study is a unique effort to optimize well configuration and perforation placement in order to alleviate multiphase flow problems in the wellbore. Providing the practical potential on simulation works, this study provides a predictive guidline to connect well geometry selection and production optimization.
{"title":"Transient Multiphase Analysis of Well Trajectory Effects in Production of Horizontal Unconventional Wells","authors":"Ngoc Tran, H. Karami","doi":"10.2118/195230-MS","DOIUrl":"https://doi.org/10.2118/195230-MS","url":null,"abstract":"\u0000 The effects of horizontal well geometry remain debatable in most production modeling works. Most of recent reports fail to mention the effects of well geometries, especially in severe slugging cases. This study presents a qualitative comparison between different well geometries and their impacts in production performance of horizontal wells.\u0000 The study utilizes a transient multiphase simulator to mimic the production from a horizontal well over a 12-hour period. The well has a 2-7/8″ ID tubing with TVD of approximately 5000 ft and MD of 10000 ft and maximum inclination angle of 10º within the horizontal section. The trajectories of horizontal section in the well include 5 cases, 5 undulations, hump (one undulation upward), sump (one undulation downward), toe-up and toe-down. These configurations are the representative examples of horizontal wells. A reservoir with a given deliverability equation and several perforation stages is used to provide well inflow. The impacts of reservoir deliverability, GOR, pressure and temperature are studied for all well geometries.\u0000 The simulation results offer some valuable insights into the effects of well trajectory on production performance, including borehole pressure profile, liquid holdup, gas and liquid rate variations with time, and cumulative gas and liquid production. At high production rates, severe slugging is not observed, and thus, the well geometry effects are minimized with a consistent production at the surface. However, toe-up configuration exhibits a slightly better performance than the others.\u0000 As the productivity and pressure reduces throughout the life of a well, the impacts of well trajectories become clearer. The presence of severe slugs and blockage of perforations near the toes causes a noticeable drop in production. During severe slugging, the pressure profile reveals longer fluctuation cycles, resulting in extreme separator flooding issues. The slugging frequencies are compared among different well geometries. Toe-down case exhibits lower slugging severity. As a result, toe-down well produces the highest cumulative liquid and gas rates. The presence of liquid blockage is observed in lateral and curvature sections. The toe-up and hump configurations exhibit the most severe slugs with minimum cumulative gas and liquid productions. The differences in productions among well trajectories exceed 30% under different well configurations.\u0000 With the augmented growth of production from unconventional reservoirs, horizontal well technology has grown in oil and gas industry, yet study of well geometry in production system remains to be limited. This study is a unique effort to optimize well configuration and perforation placement in order to alleviate multiphase flow problems in the wellbore. Providing the practical potential on simulation works, this study provides a predictive guidline to connect well geometry selection and production optimization.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82452104","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}
Cement sheath is a critical barrier for maintaining well integrity. Formation of micro-annulus due to volume shrinkage and/or pressure/temperature changes is the major challenge in achieving good hydraulic seal. Expansion of cement after the placement is a promising solution to this problem. Expanding cement can potentially close micro-annulus and further achieve pre-stress condition because of the confinement. Primary aim of this paper is to investigate mechanical integrity of different pre-stressed cement system under loading condition. To achieve the objectives, finite element modelling approach was employed. Three dimensional computer models consisting of liner, cement sheath, and casing were developed. Pre-stress condition was generated by modelling contact interference at the cement-casing interface. Three cement (ductile, moderately ductile, and brittle) were considered for simulation cases. Wellbore and annulus pressure were applied. Resultant, radial, hoop, and maximum shear stresses were investigated at the cement-pipe interface to assess mechanical integrity. For comparison purpose, similar simulations were conducted using cement sheath without pre-stress and cement system representing uniform volume shrinkage and presence micro-annulus. For constant wellbore pressure, the radial stresses observed in all three types of cement system were practically similar and decreased as pre-stress was increased. Hoop stress also reduced with increase in compressive pre-load. However, their absolute values were distinct for different cement types. These results indicate that cement system with compressive pre-load can notably reduce the risk of radial crack failure by providing compensatory compressive stress. However, on the contrary, the maximum shear stress developed at cement-pipe interface, increased because of pre-load. This can compromise the mechanical integrity by reducing the safety margin on shear failure. Thus, the selection of expansive cement should be made after carefully weighing reduced risk of radial failure/debonding against the increased risks of shear failure. This paper provides novel information on expanding cement from the perspective of mechanical stresses and integrity. Modelling approach discussed in this work, can be used to estimate amount of pre-stress required for a selected cement system under anticipated wellbore loads.
{"title":"Assessing Mechanical Integrity of Expanding Cement","authors":"Harshkumar Patel, S. Salehi, C. Teodoriu","doi":"10.2118/195225-MS","DOIUrl":"https://doi.org/10.2118/195225-MS","url":null,"abstract":"\u0000 Cement sheath is a critical barrier for maintaining well integrity. Formation of micro-annulus due to volume shrinkage and/or pressure/temperature changes is the major challenge in achieving good hydraulic seal. Expansion of cement after the placement is a promising solution to this problem. Expanding cement can potentially close micro-annulus and further achieve pre-stress condition because of the confinement. Primary aim of this paper is to investigate mechanical integrity of different pre-stressed cement system under loading condition.\u0000 To achieve the objectives, finite element modelling approach was employed. Three dimensional computer models consisting of liner, cement sheath, and casing were developed. Pre-stress condition was generated by modelling contact interference at the cement-casing interface. Three cement (ductile, moderately ductile, and brittle) were considered for simulation cases. Wellbore and annulus pressure were applied. Resultant, radial, hoop, and maximum shear stresses were investigated at the cement-pipe interface to assess mechanical integrity. For comparison purpose, similar simulations were conducted using cement sheath without pre-stress and cement system representing uniform volume shrinkage and presence micro-annulus.\u0000 For constant wellbore pressure, the radial stresses observed in all three types of cement system were practically similar and decreased as pre-stress was increased. Hoop stress also reduced with increase in compressive pre-load. However, their absolute values were distinct for different cement types. These results indicate that cement system with compressive pre-load can notably reduce the risk of radial crack failure by providing compensatory compressive stress. However, on the contrary, the maximum shear stress developed at cement-pipe interface, increased because of pre-load. This can compromise the mechanical integrity by reducing the safety margin on shear failure. Thus, the selection of expansive cement should be made after carefully weighing reduced risk of radial failure/debonding against the increased risks of shear failure.\u0000 This paper provides novel information on expanding cement from the perspective of mechanical stresses and integrity. Modelling approach discussed in this work, can be used to estimate amount of pre-stress required for a selected cement system under anticipated wellbore loads.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"80 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87101403","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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