Ahmed A. Al Sulaiman, Krinis Dimitrios, D. A. Shehri
The surface choke has been utilized in the oil industry to control withdrawal rates per well and to optimize production especially after water breakthrough. However, as found out from this study, applying undue restrictions in horizontal wellbores intersecting high permeability features can have an adverse impact on well performance and unnecessarily lock oil potential. This paper investigates the effect of surface choke on water cut and flow contribution along horizontal wellbores that encountered natural fractures and high permeability streaks (Super-Ks). The study considered different down-hole completions; open-hole and cased-hole. The investigation was carried out using Multi Phase Flow Meter (MPFM) measurements at different choke sizes in addition to production logs (FSI), wellbore simulation modeling, and real-time data. Instant data monitoring was instrumental in insuring stabilization of sub-surface static pressure while performing many rate tests at different choke sizes. Moreover, it flagged the role of rate stabilization on water cut behavior and rate data quality. The presence of conductive fractures and Super-Ks substantially influences the flow profile and water cut of horizontal wellbores. These features create high permeability conduits along wellbores such that they dominate production and may cause some matrix sections to contribute little or nothing as observed on FSI profiles. The effect of fractures on production from less permeable sections in the wellbore was investigated at different operating rates using horizontal wellbore simulation modeling. Both MPFM measurements and FSI logs showed that water cut from horizontal wells, affected by fractures and/or Super-Ks, can decrease if they're flowed at higher rates. Upon reviewing and analyzing data from numerous FSI logs, the study has been able to relate the water cut and surface choking to the well productivity index (PI). Consistently, wells with PI more than twice the averaged matrix PI were found to always perform better at bigger choke sizes. By choke relaxation, the water cut decreased by up to 22% while increasing oil production. Wellbore modeling also suggested that the influence of a fracture on flow contribution from remaining sections in the wellbore can be minimized if the well is operated at higher rates. Restrictive surface chokes were found to disproportionately affect lower permeability sections compared to conductive fractures or Super-Ks which in most cases were invaded by water after water breakthrough. Relaxing these surface chokes allowed more contribution of dry oil from the lower permeability sections, hence the increase in overall oil production and drop in water cut in the affected wells.
{"title":"Influence of Surface Choke on Water Cut and Flow Profile in Horizontal Wellbores Intersecting Fractures and Super-Ks","authors":"Ahmed A. Al Sulaiman, Krinis Dimitrios, D. A. Shehri","doi":"10.2118/194960-MS","DOIUrl":"https://doi.org/10.2118/194960-MS","url":null,"abstract":"\u0000 The surface choke has been utilized in the oil industry to control withdrawal rates per well and to optimize production especially after water breakthrough. However, as found out from this study, applying undue restrictions in horizontal wellbores intersecting high permeability features can have an adverse impact on well performance and unnecessarily lock oil potential.\u0000 This paper investigates the effect of surface choke on water cut and flow contribution along horizontal wellbores that encountered natural fractures and high permeability streaks (Super-Ks). The study considered different down-hole completions; open-hole and cased-hole. The investigation was carried out using Multi Phase Flow Meter (MPFM) measurements at different choke sizes in addition to production logs (FSI), wellbore simulation modeling, and real-time data. Instant data monitoring was instrumental in insuring stabilization of sub-surface static pressure while performing many rate tests at different choke sizes. Moreover, it flagged the role of rate stabilization on water cut behavior and rate data quality.\u0000 The presence of conductive fractures and Super-Ks substantially influences the flow profile and water cut of horizontal wellbores. These features create high permeability conduits along wellbores such that they dominate production and may cause some matrix sections to contribute little or nothing as observed on FSI profiles. The effect of fractures on production from less permeable sections in the wellbore was investigated at different operating rates using horizontal wellbore simulation modeling.\u0000 Both MPFM measurements and FSI logs showed that water cut from horizontal wells, affected by fractures and/or Super-Ks, can decrease if they're flowed at higher rates. Upon reviewing and analyzing data from numerous FSI logs, the study has been able to relate the water cut and surface choking to the well productivity index (PI). Consistently, wells with PI more than twice the averaged matrix PI were found to always perform better at bigger choke sizes. By choke relaxation, the water cut decreased by up to 22% while increasing oil production. Wellbore modeling also suggested that the influence of a fracture on flow contribution from remaining sections in the wellbore can be minimized if the well is operated at higher rates. Restrictive surface chokes were found to disproportionately affect lower permeability sections compared to conductive fractures or Super-Ks which in most cases were invaded by water after water breakthrough. Relaxing these surface chokes allowed more contribution of dry oil from the lower permeability sections, hence the increase in overall oil production and drop in water cut in the affected wells.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 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":"75875599","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}
Water flooding has been widely used as secondary oil recovery method in the clastic reservoirs in PDO. Field development plan of this field requires water injection under matrix injection conditions. The field consists of stacked Gharif sand stone reservoirs with variable degree of depletion. Increased injection volumes at economical rate, could induce hydraulic fracturing where it is very important to manage fracture growth and reducing risk for out of zone injection. The success of water flood development depends on an optimal injection pressure, which requires knowledge of formation fracture pressures and geomechanical rock properties. Efficient geomechanical analysis and workflow integrating data from well tests, field performance, water injection history and monitoring data was implemented for this study to provide guidance on optimum water injection pressure. Field stress tests, such as Leak off Tests (LOT) and micro fracs were analyzed to derive the fracture pressures. Gharif formation in these stacked reservoir formations have been significantly depleted hence a reduction in fracture pressure was required to be assessed. Depletion stress path coefficient, which is the ratio of change of fracture pressure and reservoir depletion, was derived based on historic field data. Data from well tests, field water injection performance was used for Modified Hall plot analysis and other diagnostic plots to provide better insight on active water injection operating conditions (fracture, matrix and plugging). Finally, for injector operating above the fracture pressure, Produced Water Re-Injection (PWRI) model was used to simulate expected fracture dimensions, and quantify the out of zone injection risk. Results of this study indicate that the decrease in fracture pressure in Gharif formations is about 60% of the change in pore pressure (depletion). Qualitative and quantitative analyses were able to characterize the operating injection conditions (matrix vs. fractured) for active injectors. Interpreted fracture pressure from Gharif water injector diagnostic plots demonstrates good alignment with the measured fracture pressure from field tests. The results reveal that most of the water injector wells, particularly in the depleted formations are operating above fracturing pressure. Predicted fracture dimensions form the PWRI model calibrates well with the field monitoring data. Outcome of this study provided fracture pressure estimate for Gharif formation with depletion and provide guidance on optimum water injection pressure to improve waterflood management. Stress path chart provide continuous improvement and quick decision for water flood operation. Results quantified the induced fracturing to mitigate the risk of out of zone injection and/or loss of sweep efficiency. Additionally, the results provide continuous critical input for fracture gradient for drilling and cement design for wells through depleted stacked reservoirs in other field within
{"title":"Geomechanical Integration Maximizes the Value For Waterflood Developments in the Sultanate of Oman","authors":"Ruqaiya Al Zadjali, S. Mahajan","doi":"10.2118/194730-MS","DOIUrl":"https://doi.org/10.2118/194730-MS","url":null,"abstract":"\u0000 Water flooding has been widely used as secondary oil recovery method in the clastic reservoirs in PDO. Field development plan of this field requires water injection under matrix injection conditions. The field consists of stacked Gharif sand stone reservoirs with variable degree of depletion. Increased injection volumes at economical rate, could induce hydraulic fracturing where it is very important to manage fracture growth and reducing risk for out of zone injection. The success of water flood development depends on an optimal injection pressure, which requires knowledge of formation fracture pressures and geomechanical rock properties.\u0000 Efficient geomechanical analysis and workflow integrating data from well tests, field performance, water injection history and monitoring data was implemented for this study to provide guidance on optimum water injection pressure. Field stress tests, such as Leak off Tests (LOT) and micro fracs were analyzed to derive the fracture pressures. Gharif formation in these stacked reservoir formations have been significantly depleted hence a reduction in fracture pressure was required to be assessed. Depletion stress path coefficient, which is the ratio of change of fracture pressure and reservoir depletion, was derived based on historic field data. Data from well tests, field water injection performance was used for Modified Hall plot analysis and other diagnostic plots to provide better insight on active water injection operating conditions (fracture, matrix and plugging). Finally, for injector operating above the fracture pressure, Produced Water Re-Injection (PWRI) model was used to simulate expected fracture dimensions, and quantify the out of zone injection risk.\u0000 Results of this study indicate that the decrease in fracture pressure in Gharif formations is about 60% of the change in pore pressure (depletion). Qualitative and quantitative analyses were able to characterize the operating injection conditions (matrix vs. fractured) for active injectors. Interpreted fracture pressure from Gharif water injector diagnostic plots demonstrates good alignment with the measured fracture pressure from field tests. The results reveal that most of the water injector wells, particularly in the depleted formations are operating above fracturing pressure. Predicted fracture dimensions form the PWRI model calibrates well with the field monitoring data.\u0000 Outcome of this study provided fracture pressure estimate for Gharif formation with depletion and provide guidance on optimum water injection pressure to improve waterflood management. Stress path chart provide continuous improvement and quick decision for water flood operation. Results quantified the induced fracturing to mitigate the risk of out of zone injection and/or loss of sweep efficiency.\u0000 Additionally, the results provide continuous critical input for fracture gradient for drilling and cement design for wells through depleted stacked reservoirs in other field within ","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 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":"81778043","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}
Polymer flooding has been identified as the next phase of developing two heavy oil fields located in the South of the Sultanate of Oman. The fields are supported with a strong bottom aquifer drive that results in large amount of water production due to the adverse mobility. In order to prove the concept of polymer sweep, a field trial was designed and conducted successfully in the field. Moreover, due to the challenges associated to handling back produced polymer number of tests were conducted to assess the impact of polymer on facilitates. Development of the field will take place in a phased manner in order to reduce the capex exposure, maximize the utilization of the existing facility and managing project risks while contributing to the overall production. Dynamic modeling of both fields showed that polymer development is feasible. The modeling work was supported by a field trial that was designed to prove: polymer sweep performance, injectivity, as well as polymer losses to the strong water aquifer. This trial was monitored with detailed surveillance program including pressure, injection/production rates, viscosity and water quality, which concluded incremental oil gain from the process. In parallel, a number of laboratory and field tests were performed to assess the impact of polymer on the surface facilities such as the heater, separation tanks and the growth of the reed beds - wet planets- in the field. Sustained incremental oil gain was clearly observed from polymer injection in the field trial. Injectivity could not be maintained as planned, due to a combination of polymer, biological and water quality issues. Later tests including biocide injection and QA/QC of polymer batches as well as some well stimulation did show improved injectivity profiles. Demulsifier tests mitigated the risk of creating stable emulsions. Laboratory tests indicated no heater fouling observed below 150°C. Short and long term investigation into the impact of water- contaminated polymer on plants in the wet lands was positive with the plants showing no necrosis. This was tested up to back produce polymer concentration levels of 500 ppm. Which is achievable given the excessive amount of water received at the facility allowing the dilution of back produced polymer to the required level. This helped in making the project more economically attractive as it results in a saving of around 30% from the overall project Capex. The modeling exercise proposed drilling of around 200 polymer injectors across both fields, but in order to manage costs and further reduce project risks an optimised phased development approach was evaluated. Both Analytical and modeling approach were used to identify the phasing strategy. The phasing strategy will start with the most attractive to least attractive areas allowing for appraisal these areas prior to committing to their development. The key enabler for phasing of this development is by standardizing and replicating the development.
{"title":"Optimizing Field Scale Polymer Development in Strong Aquifer Fields in the South of the Sultanate of Oman","authors":"Reham Jabri, R. Mjeni, M. Gharbi, A. Alkindi","doi":"10.2118/195055-MS","DOIUrl":"https://doi.org/10.2118/195055-MS","url":null,"abstract":"\u0000 Polymer flooding has been identified as the next phase of developing two heavy oil fields located in the South of the Sultanate of Oman. The fields are supported with a strong bottom aquifer drive that results in large amount of water production due to the adverse mobility. In order to prove the concept of polymer sweep, a field trial was designed and conducted successfully in the field. Moreover, due to the challenges associated to handling back produced polymer number of tests were conducted to assess the impact of polymer on facilitates. Development of the field will take place in a phased manner in order to reduce the capex exposure, maximize the utilization of the existing facility and managing project risks while contributing to the overall production.\u0000 Dynamic modeling of both fields showed that polymer development is feasible. The modeling work was supported by a field trial that was designed to prove: polymer sweep performance, injectivity, as well as polymer losses to the strong water aquifer. This trial was monitored with detailed surveillance program including pressure, injection/production rates, viscosity and water quality, which concluded incremental oil gain from the process. In parallel, a number of laboratory and field tests were performed to assess the impact of polymer on the surface facilities such as the heater, separation tanks and the growth of the reed beds - wet planets- in the field.\u0000 Sustained incremental oil gain was clearly observed from polymer injection in the field trial. Injectivity could not be maintained as planned, due to a combination of polymer, biological and water quality issues. Later tests including biocide injection and QA/QC of polymer batches as well as some well stimulation did show improved injectivity profiles. Demulsifier tests mitigated the risk of creating stable emulsions. Laboratory tests indicated no heater fouling observed below 150°C. Short and long term investigation into the impact of water- contaminated polymer on plants in the wet lands was positive with the plants showing no necrosis. This was tested up to back produce polymer concentration levels of 500 ppm. Which is achievable given the excessive amount of water received at the facility allowing the dilution of back produced polymer to the required level. This helped in making the project more economically attractive as it results in a saving of around 30% from the overall project Capex.\u0000 The modeling exercise proposed drilling of around 200 polymer injectors across both fields, but in order to manage costs and further reduce project risks an optimised phased development approach was evaluated. Both Analytical and modeling approach were used to identify the phasing strategy. The phasing strategy will start with the most attractive to least attractive areas allowing for appraisal these areas prior to committing to their development. The key enabler for phasing of this development is by standardizing and replicating the development. ","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73133184","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}
In this paper we carry out a full field Reservoir calibration and optimisation scenario, coupling molecular interactions and ensemble based optimisation techniques. We use the friction theory model to estimate the viscosity, taking into account the molecular interactions and integrating the results in Reservoir simulation using the equation of state. Model calibration is achieved with the Ensemble Smoother with Multiple Data Assimilation (ES-MDA). Further, we then optimise the calibrated model, focusing on Enhanced Oil recovery technique, with steam injection, utilising the Ensemble based Production Optimisation method (EnOPT). The Hydrocarbons viscosity was estimated using the friction theory, which utilises the attraction and repulsion parameters in a Van Der Waals type equation of state and the concept behind Amontons Coulomb friction laws. The molecular interactions are taken into account in understanding the fluid viscosity behaviour. The link is signified between the molecular interactions and their effect on the velocity between the hydrocarbon fluid layers that are responsible for the resistance to flow. The uncertainty in the estimated viscosity could be narrowed by using Bayesian statistic techniques to match the chosen reservoir parameters with the mean historical data using the Ensemble Smoother with Multiple Data Assimilation (ES-MDA). The Enhanced Oil Recovery technique was chosen to be steam injection in order to reduce the oil viscosity by raising the reservoir temperature without maximising the overall cost. The Net Present Value (NPV) was maximised by using an ensemble based optimisation technique (EnOPT), where the controls of steam injection temperature and two producers bottom hole pressure were the adjusted parameters. The viscosity of a heavy oil required additional recovery techniques to increase the driving force for the production. The heavy oil viscosity decreases with increasing temperature due to the increase in kinetic energy of the molecules that weakens the attraction force and the increases in repulsion between them. The initial mean NPV of the generated 100 realisations of the chosen adjusted parameters was found to be approximately $1,500,000. The mean NPV of the realisations after optimisation was found to be $3,440,056. This increase in NPV was due to the increase in oil production rate, the main parameter influencing the increase in NPV was the cost and amount of oil produced, bearing in mind the water treatment and steam cost. The novelty in this study is a coupling of molecular scale simulation (friction theory) with Reservoir Simulation (by means of the Peng-Robinson Equation of state), which estimates the main physical parameters of reservoir systems and also adequately accounts for the intermolecular forces. We also calibrate the synthetic reservoir model with the ES-MDA infused with EnOPT for realistic model production optimisation.
在本文中，我们进行了一个完整的油藏校准和优化场景，耦合分子相互作用和基于集成的优化技术。我们使用摩擦理论模型来估计粘度，考虑了分子间的相互作用，并用状态方程对油藏模拟结果进行积分。采用多数据同化集成平滑器(ES-MDA)实现模型标定。此外，我们利用基于集成的生产优化方法(EnOPT)优化校准模型，重点关注蒸汽注入提高采收率技术。碳氢化合物的粘度是使用摩擦理论来估计的，该理论利用了范德华状态方程中的吸引力和排斥力参数以及Amontons Coulomb摩擦定律背后的概念。在理解流体粘度行为时考虑了分子间的相互作用。分子间的相互作用及其对造成流动阻力的烃类流体层间速度的影响之间存在联系。利用贝叶斯统计技术，利用ES-MDA (Ensemble smooth with Multiple data Assimilation)将所选储层参数与平均历史数据进行匹配，可以缩小估计粘度的不确定性。为了在不提高总成本的情况下通过提高储层温度来降低油粘度，选择了蒸汽注入技术来提高采收率。净现值(NPV)通过使用基于集成的优化技术(EnOPT)实现了最大化，其中控制注汽温度和两个生产商井底压力是调整后的参数。稠油的粘度需要额外的采收率技术来增加生产的驱动力。稠油粘度随着温度的升高而降低，这是由于分子的动能增加，分子间的引力减弱，斥力增加。选定的调整参数所产生的100种实现的初始平均净现值约为1 500 000美元。优化后实现的平均净现值为3,440,056美元。NPV的增加是由于采油速度的提高，影响NPV增加的主要参数是成本和采油量，同时考虑到水处理和蒸汽成本。本研究的新颖之处是将分子尺度模拟(摩擦理论)与储层模拟(通过Peng-Robinson状态方程)相结合，估计了储层系统的主要物理参数，并充分考虑了分子间的作用力。我们还使用注入EnOPT的ES-MDA来校准合成油藏模型，以实现实际模型的生产优化。
{"title":"A Coupled Viscosity Estimation and Reservoir Simulation for Ensemble Based Production Optimisation","authors":"Bashayer Almaraghi, Clement Etienam, R. Villegas","doi":"10.2118/194751-MS","DOIUrl":"https://doi.org/10.2118/194751-MS","url":null,"abstract":"\u0000 In this paper we carry out a full field Reservoir calibration and optimisation scenario, coupling molecular interactions and ensemble based optimisation techniques. We use the friction theory model to estimate the viscosity, taking into account the molecular interactions and integrating the results in Reservoir simulation using the equation of state. Model calibration is achieved with the Ensemble Smoother with Multiple Data Assimilation (ES-MDA).\u0000 Further, we then optimise the calibrated model, focusing on Enhanced Oil recovery technique, with steam injection, utilising the Ensemble based Production Optimisation method (EnOPT). The Hydrocarbons viscosity was estimated using the friction theory, which utilises the attraction and repulsion parameters in a Van Der Waals type equation of state and the concept behind Amontons Coulomb friction laws. The molecular interactions are taken into account in understanding the fluid viscosity behaviour. The link is signified between the molecular interactions and their effect on the velocity between the hydrocarbon fluid layers that are responsible for the resistance to flow. The uncertainty in the estimated viscosity could be narrowed by using Bayesian statistic techniques to match the chosen reservoir parameters with the mean historical data using the Ensemble Smoother with Multiple Data Assimilation (ES-MDA).\u0000 The Enhanced Oil Recovery technique was chosen to be steam injection in order to reduce the oil viscosity by raising the reservoir temperature without maximising the overall cost. The Net Present Value (NPV) was maximised by using an ensemble based optimisation technique (EnOPT), where the controls of steam injection temperature and two producers bottom hole pressure were the adjusted parameters.\u0000 The viscosity of a heavy oil required additional recovery techniques to increase the driving force for the production. The heavy oil viscosity decreases with increasing temperature due to the increase in kinetic energy of the molecules that weakens the attraction force and the increases in repulsion between them. The initial mean NPV of the generated 100 realisations of the chosen adjusted parameters was found to be approximately $1,500,000.\u0000 The mean NPV of the realisations after optimisation was found to be $3,440,056. This increase in NPV was due to the increase in oil production rate, the main parameter influencing the increase in NPV was the cost and amount of oil produced, bearing in mind the water treatment and steam cost. The novelty in this study is a coupling of molecular scale simulation (friction theory) with Reservoir Simulation (by means of the Peng-Robinson Equation of state), which estimates the main physical parameters of reservoir systems and also adequately accounts for the intermolecular forces. We also calibrate the synthetic reservoir model with the ES-MDA infused with EnOPT for realistic model production optimisation.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76599513","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}
Well testing is an essential tool to estimate reserves and forecast production. The assessment depends on the analytical solution of the continuity and diffusivity equations which results in average reservoir properties. The key challenge is to acquire real-time data of pressure pulse signatures as they propagate and reach the boundaries. A potential solution is to use a permanent downhole pressure gauge or an array of distributed pressure sensors (DPS) placed at each hydraulic fracture cluster to characterize the flow. This work presents the elements of an innovative analytical model that uses this data to derive formation properties, visualize averaged flow dynamics, and evaluate the Stimulated Reservoir Volume (SRV). The real-time distributed pressure data, together with flow rate history, provides information that can be used to characterize the flow and estimate the boundary effect of hydraulic fractures and fissures. First, the numerically generated synthetic data is analyzed at each cluster to eliminate pressure drops due to friction. Next, analytical solutions of the continuity equation as well as trilinear models are used to invert reservoir properties to verify the proposed model. Based on the results, an advance statistical analysis is used to characterize the contribution of each variable to the flow rate. The numerical results suggest that there are key variables to identify different flow regimes. Numerical simulations are used to gauge the accuracy of the analytical model at predicting reservoir properties and flow patterns. Statistical analysis evinces that there are key parameters of the formation, fractures, and fissures that control the well productivity. The numerical analysis showed that for every reservoir type there are different combination of fracture parameters that can optimize the flow. Moreover, the results describe a method to obtain hydraulic fracture properties around each pressure sensor (DPS) and forecast their productivity. Finally, statistical learning was investigated as a potential solution to derive reservoir properties, including hydraulic and natural fractures, using the pressure pulse signature data without the need of inversion. The results show that there are key parameters that determine flow patterns. The importance of the accurate recognition and analysis of the multiple linear flow regimes at each cluster is in the potential to estimate the size of the SRV around hydraulic fractures during the transient life of the well. Moreover, this paper explains the procedure used for analyzing the change in the flow rate to obtain reservoir properties.
{"title":"Distributed Pressure Sensing for Production Data Analysis","authors":"Wisam J. Assiri, Ilkay Uzun, E. Ozkan","doi":"10.2118/194799-MS","DOIUrl":"https://doi.org/10.2118/194799-MS","url":null,"abstract":"\u0000 Well testing is an essential tool to estimate reserves and forecast production. The assessment depends on the analytical solution of the continuity and diffusivity equations which results in average reservoir properties. The key challenge is to acquire real-time data of pressure pulse signatures as they propagate and reach the boundaries. A potential solution is to use a permanent downhole pressure gauge or an array of distributed pressure sensors (DPS) placed at each hydraulic fracture cluster to characterize the flow. This work presents the elements of an innovative analytical model that uses this data to derive formation properties, visualize averaged flow dynamics, and evaluate the Stimulated Reservoir Volume (SRV).\u0000 The real-time distributed pressure data, together with flow rate history, provides information that can be used to characterize the flow and estimate the boundary effect of hydraulic fractures and fissures. First, the numerically generated synthetic data is analyzed at each cluster to eliminate pressure drops due to friction. Next, analytical solutions of the continuity equation as well as trilinear models are used to invert reservoir properties to verify the proposed model. Based on the results, an advance statistical analysis is used to characterize the contribution of each variable to the flow rate.\u0000 The numerical results suggest that there are key variables to identify different flow regimes. Numerical simulations are used to gauge the accuracy of the analytical model at predicting reservoir properties and flow patterns. Statistical analysis evinces that there are key parameters of the formation, fractures, and fissures that control the well productivity. The numerical analysis showed that for every reservoir type there are different combination of fracture parameters that can optimize the flow. Moreover, the results describe a method to obtain hydraulic fracture properties around each pressure sensor (DPS) and forecast their productivity. Finally, statistical learning was investigated as a potential solution to derive reservoir properties, including hydraulic and natural fractures, using the pressure pulse signature data without the need of inversion.\u0000 The results show that there are key parameters that determine flow patterns. The importance of the accurate recognition and analysis of the multiple linear flow regimes at each cluster is in the potential to estimate the size of the SRV around hydraulic fractures during the transient life of the well. Moreover, this paper explains the procedure used for analyzing the change in the flow rate to obtain reservoir properties.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77052264","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}
Steve Smith, H. Khairy, Chinwenwa Emma-Ebere, M. Ismail
Supercharged pressures exist when drilling fluid losses (spurt, dynamic and static) invade the near well-bore region and creates a ‘supercharged’ pressure zone that is higher than the reservoir pressure but lower than the wellbore hydrostatic pressure. Due to the overbalanced hydrostatic pressure the fluid invades but cannot be disbursed because of the low mobility of the rock. This creates a near well-bore region with pore pressures between hydrostatic (wellbore) and reservoir pressure. This typically occurs in low mobility formations where the dispersion of the invaded drilling fluids is not efficient. Determining true reservoir pore pressure in these conditions is difficult for formation pressure testing tools (FPT's) which measure elevated pressures above true reservoir pressure in these conditions. Analyzing the change in measured pressures from repeated tests using FPT's may help estimate the true formation pressure. One characteristic indication of supercharging is successive pressure build-up tests (after small drawdown volumes) that stabilize at lower pressures with each subsequent test as more supercharging fluid is removed from the near well-bore region. The successive decrease in build-up pressure as a function of volume can provide information on the dynamic pressure environment in the near wellbore zone and the reservoir pressures further from the wellbore. Plotting the pressure drop as a function of fluid volume removed from the formation and fitting an exponential decay curve to the data provides an estimate of the reservoir pressure. The curve is optimized using a regression algorithm to find a best match. Because one of the unknown variables is the desired formation pressure, a range of formation pressures are evaluated and a χ-squared error function is minimized, thus approximating the true reservoir pressure. Numerical simulation models with known formation pressures were set-up with a static supercharged near well-bore environment and various pressure tests were conducted. Analysis was performed on a number of tests to optimize the regression algorithm. The optimized regression provided an indication of the reservoir pressure within 2% of the simulated value. Real data examples were also analyzed with good results. This analysis technique provides a novel empirical method for estimating reservoir pressures in supercharged environments by investigating the change in build-up pressures in successive tests. The analysis can be accomplished with pressure measurement data from standard FPT's. Furthermore, the individual pressure tests do not need to stabilize because the change in pressure is used nor do the pressure tests need to measure the true reservoir pressure because it is determined by a regression analysis.
{"title":"Novel Empirical Approach to Supercharged Pressure Test Analysis","authors":"Steve Smith, H. Khairy, Chinwenwa Emma-Ebere, M. Ismail","doi":"10.2118/194887-MS","DOIUrl":"https://doi.org/10.2118/194887-MS","url":null,"abstract":"\u0000 \u0000 \u0000 Supercharged pressures exist when drilling fluid losses (spurt, dynamic and static) invade the near well-bore region and creates a ‘supercharged’ pressure zone that is higher than the reservoir pressure but lower than the wellbore hydrostatic pressure. Due to the overbalanced hydrostatic pressure the fluid invades but cannot be disbursed because of the low mobility of the rock. This creates a near well-bore region with pore pressures between hydrostatic (wellbore) and reservoir pressure. This typically occurs in low mobility formations where the dispersion of the invaded drilling fluids is not efficient. Determining true reservoir pore pressure in these conditions is difficult for formation pressure testing tools (FPT's) which measure elevated pressures above true reservoir pressure in these conditions. Analyzing the change in measured pressures from repeated tests using FPT's may help estimate the true formation pressure.\u0000 \u0000 \u0000 \u0000 One characteristic indication of supercharging is successive pressure build-up tests (after small drawdown volumes) that stabilize at lower pressures with each subsequent test as more supercharging fluid is removed from the near well-bore region. The successive decrease in build-up pressure as a function of volume can provide information on the dynamic pressure environment in the near wellbore zone and the reservoir pressures further from the wellbore. Plotting the pressure drop as a function of fluid volume removed from the formation and fitting an exponential decay curve to the data provides an estimate of the reservoir pressure. The curve is optimized using a regression algorithm to find a best match. Because one of the unknown variables is the desired formation pressure, a range of formation pressures are evaluated and a χ-squared error function is minimized, thus approximating the true reservoir pressure.\u0000 \u0000 \u0000 \u0000 Numerical simulation models with known formation pressures were set-up with a static supercharged near well-bore environment and various pressure tests were conducted. Analysis was performed on a number of tests to optimize the regression algorithm. The optimized regression provided an indication of the reservoir pressure within 2% of the simulated value. Real data examples were also analyzed with good results.\u0000 \u0000 \u0000 \u0000 This analysis technique provides a novel empirical method for estimating reservoir pressures in supercharged environments by investigating the change in build-up pressures in successive tests. The analysis can be accomplished with pressure measurement data from standard FPT's. Furthermore, the individual pressure tests do not need to stabilize because the change in pressure is used nor do the pressure tests need to measure the true reservoir pressure because it is determined by a regression analysis.\u0000","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"226 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76114581","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}
Reinaldo Jose Angulo Yznaga, L. Quintero, Ehab Negm, P. Laer
Flowback of wells after hydraulic fracturing has always been under debate because the future performance of fractured hydraulic wells depends on the operational procedure applied during the flowback. Unconventional reservoirs have become increasingly important hydrocarbon resources to develop and produce for the oil and gas industry, and the best cost-efficient approach to develop and produce unconventional reservoirs is by drilling and completion of horizontal multi-stage hydraulic fractured wells. Hence the complexity of the phenomenology seen during the flowback of this type of wells has increased substantially. The complexity of the phenomenology is the result of the change on the range of fluid and fluid-rock properties. The permeability of unconventional reservoirs is typically in the range of nano to low micro darcies. This implies that the forces acting on the fluid flow through the medium are extremely magnified. This paper is aimed at describing the phenomenology during early fluid flow in unconventional wells, and its relevance during the design, planning, and execution of well flowback. The work considers actual data and information of flowback in unconventional wells from the available literature, as well as our own experiences. The authors use this available data and information to describe the physical phenomena that occurs in unconventional wells, especially in the early stages of production testing. The paper describes a theoretical approach that explains the fluid behaviour seen during multi-stage hydraulic fractured unconventional wells. Finally, the flowback is characterized based on the phenomenology, and its description provides an approach to an improved design of well flow management. The characterization of the phenomenology during flowback allows us to identify six stages of fluid flow in unconventional wells during the early flow process. Each stage has been identified considering the acting forces, fluid flow, and implications during the flowback. After such description, flowback design is explained based on the phenomenology characterization. Finally, the authors provide a comparison of the design and the actual behaviour for the early stages of flowback. This work introduces an approach based on the characterization of the phenomenology associated to multi-stage hydraulic fractured unconventional wells that have been successfully applied in flowback operations. A comparison between theoretical designs and actual cases confirms the value of the methodology.
{"title":"Phenomenology During Flowback in Unconventional Wells","authors":"Reinaldo Jose Angulo Yznaga, L. Quintero, Ehab Negm, P. Laer","doi":"10.2118/194986-MS","DOIUrl":"https://doi.org/10.2118/194986-MS","url":null,"abstract":"\u0000 Flowback of wells after hydraulic fracturing has always been under debate because the future performance of fractured hydraulic wells depends on the operational procedure applied during the flowback. Unconventional reservoirs have become increasingly important hydrocarbon resources to develop and produce for the oil and gas industry, and the best cost-efficient approach to develop and produce unconventional reservoirs is by drilling and completion of horizontal multi-stage hydraulic fractured wells. Hence the complexity of the phenomenology seen during the flowback of this type of wells has increased substantially. The complexity of the phenomenology is the result of the change on the range of fluid and fluid-rock properties. The permeability of unconventional reservoirs is typically in the range of nano to low micro darcies. This implies that the forces acting on the fluid flow through the medium are extremely magnified. This paper is aimed at describing the phenomenology during early fluid flow in unconventional wells, and its relevance during the design, planning, and execution of well flowback.\u0000 The work considers actual data and information of flowback in unconventional wells from the available literature, as well as our own experiences. The authors use this available data and information to describe the physical phenomena that occurs in unconventional wells, especially in the early stages of production testing. The paper describes a theoretical approach that explains the fluid behaviour seen during multi-stage hydraulic fractured unconventional wells. Finally, the flowback is characterized based on the phenomenology, and its description provides an approach to an improved design of well flow management.\u0000 The characterization of the phenomenology during flowback allows us to identify six stages of fluid flow in unconventional wells during the early flow process. Each stage has been identified considering the acting forces, fluid flow, and implications during the flowback. After such description, flowback design is explained based on the phenomenology characterization. Finally, the authors provide a comparison of the design and the actual behaviour for the early stages of flowback.\u0000 This work introduces an approach based on the characterization of the phenomenology associated to multi-stage hydraulic fractured unconventional wells that have been successfully applied in flowback operations. A comparison between theoretical designs and actual cases confirms the value of the methodology.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"213 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74329498","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}
Drilling Fluids rheological properties play a vital role in controlling the success of the drilling operation. Rheological parameters such as effective (or apparent) viscosity, yield point (YP), gel strength, and plastic viscosity (PV) are very important for rig hydraulic calculations and hole cleaning efficiency. The water-based drilling fluid (WBDF) consists of a mixture of different solids and polymers which are used to optimize the rheological properties. Starch is a resistance-solid additive which is used mainly to control the filtration properties and at the same time to increase the viscosity of the drilling fluid. The main goal of this research is to evaluate the effect of using micronized starch (1 μm) on the rheological and filtration properties of water-based drilling fluid. Field emission scanning electron microscope (FESEM) was used to evaluate the starch at different particle size. Rheological properties for the drilling fluid with different starch sizes were measured at ambient condition using Fan VG rheometer while the high-pressure high-temperature (HPHT) filter press was used to conduct the filtration experiment at 200°F. It was noted that micronized starch (1 μm) had a vital effect on the rheological and filtration properties of WBDF. The PV of the WBDF with micronized starch was increased by 158% while the YP was increased by 125% as compared with the starch of conventional size (60 μm). The apparent viscosity (AV) was increased by 137% after reducing the starch sized to 1 μm. Adding the micronized starch for the WBDF resulted in flat rheology behavior where there is no increase in the gel strength between 10 seconds and 10 minutes. The filter cake thickness was reduced by 63% while the cumulative filtrate volume was decreased by 52% when 1 μm starch is used. This study introduced a new drilling fluid formulation that contains a micronized starch as an additive, which will help the drilling engineers to avoid many drilling issues especially the formation damage by forming an ideal filter cake.
{"title":"Assessing the Effect of Micronized Starch on Rheological and Filtration Properties of Water-Based Drilling Fluid","authors":"S. Elkatatny","doi":"10.2118/194965-MS","DOIUrl":"https://doi.org/10.2118/194965-MS","url":null,"abstract":"\u0000 Drilling Fluids rheological properties play a vital role in controlling the success of the drilling operation. Rheological parameters such as effective (or apparent) viscosity, yield point (YP), gel strength, and plastic viscosity (PV) are very important for rig hydraulic calculations and hole cleaning efficiency. The water-based drilling fluid (WBDF) consists of a mixture of different solids and polymers which are used to optimize the rheological properties. Starch is a resistance-solid additive which is used mainly to control the filtration properties and at the same time to increase the viscosity of the drilling fluid.\u0000 The main goal of this research is to evaluate the effect of using micronized starch (1 μm) on the rheological and filtration properties of water-based drilling fluid. Field emission scanning electron microscope (FESEM) was used to evaluate the starch at different particle size. Rheological properties for the drilling fluid with different starch sizes were measured at ambient condition using Fan VG rheometer while the high-pressure high-temperature (HPHT) filter press was used to conduct the filtration experiment at 200°F.\u0000 It was noted that micronized starch (1 μm) had a vital effect on the rheological and filtration properties of WBDF. The PV of the WBDF with micronized starch was increased by 158% while the YP was increased by 125% as compared with the starch of conventional size (60 μm). The apparent viscosity (AV) was increased by 137% after reducing the starch sized to 1 μm. Adding the micronized starch for the WBDF resulted in flat rheology behavior where there is no increase in the gel strength between 10 seconds and 10 minutes. The filter cake thickness was reduced by 63% while the cumulative filtrate volume was decreased by 52% when 1 μm starch is used.\u0000 This study introduced a new drilling fluid formulation that contains a micronized starch as an additive, which will help the drilling engineers to avoid many drilling issues especially the formation damage by forming an ideal filter cake.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"422 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84929190","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. Yassin, O. Abdullatif, M. Makkawi, Ibrahim M. Yousif, M. Osman
Well exposed Jurassic outcrops belt in central Saudi Arabia provides good outcrop analogs which can be utilized to capture the high resolution facies types and architecture that might help to fill the inter-wells gap in the subsurface. This study is focused on the characterization and modeling the facies types, body geometries deposited in geomorphic elements of carbonate ramp system and the distribution of the reservoir properties on it. Three-dimensional models for the different facies-body geometries were conducted to provide accurate stochastic representation. This study was conducted at a selected Jurassic outcrop reservoir analog that exposed around Riyadh area. The Mesozoic carbonate strata of central Saudi Arabia are interpreted to have been deposited in ramp systems and exposed in hundreds of kilometers in the strike and dip direction of palaeoshoreline. The study integrates detailed sedimentological and stratigraphic analysis from outcrop strata to capture facies-body geometries and their petrophysical properties on the ramp system. Nine lithofacies were interpreted from the stratigraphic sections. Spatially, the porosity and permeability show different ranges of heterogeneity from micro to meso and macro scales. Laterally, the reservoir properties show steady variations in contrast with the abrupt change vertically. This variation seems to be related to the sedimentary structure, grain size, and degree of cementation. Different pore types were recognized in the studied intervals, which include fracture, intraparticle, moldic and intercrystalline porosities. Several 3D facies models were constructed using sedimentological and stratigraphic data that collected from the field. These models express the complex and heterogeneous relationship between facies-body geometries in the outcrop precisely. Integration of these data to subsurface equivalent reservoirs will provide qualitative and quantitative information useful for understanding and predicting reservoir quality and architecture in carbonate ramps.
{"title":"Characterization and Modeling of the Geo-Body Geometries and the Reservoir Properties: An Outcrop Analog Study of Jurassic Carbonate Reservoirs in Central Saudi Arabia","authors":"M. Yassin, O. Abdullatif, M. Makkawi, Ibrahim M. Yousif, M. Osman","doi":"10.2118/194697-MS","DOIUrl":"https://doi.org/10.2118/194697-MS","url":null,"abstract":"\u0000 Well exposed Jurassic outcrops belt in central Saudi Arabia provides good outcrop analogs which can be utilized to capture the high resolution facies types and architecture that might help to fill the inter-wells gap in the subsurface. This study is focused on the characterization and modeling the facies types, body geometries deposited in geomorphic elements of carbonate ramp system and the distribution of the reservoir properties on it. Three-dimensional models for the different facies-body geometries were conducted to provide accurate stochastic representation. This study was conducted at a selected Jurassic outcrop reservoir analog that exposed around Riyadh area. The Mesozoic carbonate strata of central Saudi Arabia are interpreted to have been deposited in ramp systems and exposed in hundreds of kilometers in the strike and dip direction of palaeoshoreline. The study integrates detailed sedimentological and stratigraphic analysis from outcrop strata to capture facies-body geometries and their petrophysical properties on the ramp system. Nine lithofacies were interpreted from the stratigraphic sections. Spatially, the porosity and permeability show different ranges of heterogeneity from micro to meso and macro scales. Laterally, the reservoir properties show steady variations in contrast with the abrupt change vertically. This variation seems to be related to the sedimentary structure, grain size, and degree of cementation. Different pore types were recognized in the studied intervals, which include fracture, intraparticle, moldic and intercrystalline porosities. Several 3D facies models were constructed using sedimentological and stratigraphic data that collected from the field. These models express the complex and heterogeneous relationship between facies-body geometries in the outcrop precisely. Integration of these data to subsurface equivalent reservoirs will provide qualitative and quantitative information useful for understanding and predicting reservoir quality and architecture in carbonate ramps.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73564738","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}
E. Sayapov, A. Nunez, Masoud Al Salmi, Ibrahim Al Farei, H. Gheilani, Ahmed Benchekor, A. Al-Shanfari
Multistage frac completion (MFC) has been playing a significant role in modern oilfield industry being one of the key tools making development of low permeable formations economical. Commonly, it is applied in horizontal wells that are drilled to compensate for reduced drainage radius of these wells due to a lack of formation conductivity. This technique is evolving, there are quite a few inventions introduced every year that make MFC easier, more economical and that allow the operators to control and precisely evaluate both the treatment itself and performance of the created fractures. However, due to its nature and initial focus on horizontal wells, it did not become very popular in vertical wells. One of the reasons for it is its limited formation access since the sleeves that are providing the access are short and cannot cover the entire net pay. What historically more common in vertical wells are either conventional "plug and perf" approach or its modifications, whereas intervals are perforated with either coiled tubing and sand-blasting perforation or wireline guns, while isolation of the zones is achieved by setting frac plugs, sand plugs or frac packers depending on pumping conduits. In Petroleum Development Oman, some of these vertical wells were stimulated via multistage frac completion. In central part of the Sultanate of Oman, a deep tight gas field is developed using hydraulic fracture stimulation technique since the formation conductivity is low and the near wellbore damage after drilling is making it even worse. Normally, between 6 and 13 frac intervals are stimulated in each well. Majority of wells are completed vertically with pay zones separated with strong shale layers that restrict fracture height development. Since plug & perf has been the main technique used in this field, there are multiple well interventions during hydraulic fracture operations that consume time, money and delay the well delivery. Moreover, the depletion of the field and its main productive zones make well intervention activities much more challenging whereas the risks of getting coiled tubing string or even wireline tools stuck in wellbore are high due to immediate losses faced after opening those low pressurized zones having as low as 8,000 KPa formation pressure, which can be 5-7 times less than hydrostatic pressures in the wellbore depending on depths and fluid s used. At the same time, with downhole temperatures ranging from 135 to 150 deg C and fracturing pressures reaching around 145,000 KPa bottomhole (~21,000 psi), differential pressures across the target zones can reach enormous levels of 15,000-20,000psi. Conditions in general become very risky, making it extremely difficult to source the right tools and equipment from what is available on the market. Another challenge associated with depletion of this field is an effective deliquification of the wells after stimulation treatments to allow them to effectively get rid of frac fluids and be abl
{"title":"Advantages of Multistage Frac Completion in Vertical Depleted Gas Wells and Lessons Learned","authors":"E. Sayapov, A. Nunez, Masoud Al Salmi, Ibrahim Al Farei, H. Gheilani, Ahmed Benchekor, A. Al-Shanfari","doi":"10.2118/194871-MS","DOIUrl":"https://doi.org/10.2118/194871-MS","url":null,"abstract":"\u0000 Multistage frac completion (MFC) has been playing a significant role in modern oilfield industry being one of the key tools making development of low permeable formations economical. Commonly, it is applied in horizontal wells that are drilled to compensate for reduced drainage radius of these wells due to a lack of formation conductivity. This technique is evolving, there are quite a few inventions introduced every year that make MFC easier, more economical and that allow the operators to control and precisely evaluate both the treatment itself and performance of the created fractures. However, due to its nature and initial focus on horizontal wells, it did not become very popular in vertical wells. One of the reasons for it is its limited formation access since the sleeves that are providing the access are short and cannot cover the entire net pay. What historically more common in vertical wells are either conventional \"plug and perf\" approach or its modifications, whereas intervals are perforated with either coiled tubing and sand-blasting perforation or wireline guns, while isolation of the zones is achieved by setting frac plugs, sand plugs or frac packers depending on pumping conduits. In Petroleum Development Oman, some of these vertical wells were stimulated via multistage frac completion.\u0000 In central part of the Sultanate of Oman, a deep tight gas field is developed using hydraulic fracture stimulation technique since the formation conductivity is low and the near wellbore damage after drilling is making it even worse. Normally, between 6 and 13 frac intervals are stimulated in each well. Majority of wells are completed vertically with pay zones separated with strong shale layers that restrict fracture height development. Since plug & perf has been the main technique used in this field, there are multiple well interventions during hydraulic fracture operations that consume time, money and delay the well delivery. Moreover, the depletion of the field and its main productive zones make well intervention activities much more challenging whereas the risks of getting coiled tubing string or even wireline tools stuck in wellbore are high due to immediate losses faced after opening those low pressurized zones having as low as 8,000 KPa formation pressure, which can be 5-7 times less than hydrostatic pressures in the wellbore depending on depths and fluid s used. At the same time, with downhole temperatures ranging from 135 to 150 deg C and fracturing pressures reaching around 145,000 KPa bottomhole (~21,000 psi), differential pressures across the target zones can reach enormous levels of 15,000-20,000psi. Conditions in general become very risky, making it extremely difficult to source the right tools and equipment from what is available on the market. Another challenge associated with depletion of this field is an effective deliquification of the wells after stimulation treatments to allow them to effectively get rid of frac fluids and be abl","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"183 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74646528","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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