Historically, it has been a challenge to analyze and predict water cut or water production. While predicting water production may seem less relevant as compared to oil production, produced water poses many challenges. The difficulty rises when surface facilities cannot handle the water produced and reservoir pressure declines sharply as a result of excess water production. Multiphase flowmeters (MPFMs) have in the past few decades gradually replaced the conventional approach of metering multiphase flow streams using test separators. However, MPFMs have been faced with several challenges including flow assurance problems and high bottomhole temperatures and pressures. In addition, they have a threshold below which the accuracy of the measurement of water production will be highly questionable due to design and technology limitations. As a matter of economic decisions, it is necessary to detect and estimate early and post water breakthrough trends respectively. Several models to forecast water breakthrough have been developed. Among them is the famous water cut (WC) versus cumulative production (Np) plot. This paper presents two empirical models to address the inability of MPFM to detect early water breakthrough below a threshold and to provide an alternative technique for modeling post water breakthrough. The models developed in this work predict water breakthrough using fluid volumes, bottomhole pressure and temperature. The first technique predicts early water breakthrough when the plotted function shows a deviation from a straight-line trend. In the second model, the water cut equation is modified for post water breakthrough prediction. Previous studies of water cut (WC) have focused on the production of water above the MPFMs threshold. The models derived in this paper provide accurate water cut estimates below MPMFs threshold and reliable post water breakthrough analysis.
{"title":"Holistic Approach to Estimate Water Breakthrough; A Case Study","authors":"D. Opoku, D. A. Shehri, Stephen Adjei","doi":"10.2118/198143-ms","DOIUrl":"https://doi.org/10.2118/198143-ms","url":null,"abstract":"\u0000 Historically, it has been a challenge to analyze and predict water cut or water production. While predicting water production may seem less relevant as compared to oil production, produced water poses many challenges. The difficulty rises when surface facilities cannot handle the water produced and reservoir pressure declines sharply as a result of excess water production.\u0000 Multiphase flowmeters (MPFMs) have in the past few decades gradually replaced the conventional approach of metering multiphase flow streams using test separators. However, MPFMs have been faced with several challenges including flow assurance problems and high bottomhole temperatures and pressures. In addition, they have a threshold below which the accuracy of the measurement of water production will be highly questionable due to design and technology limitations. As a matter of economic decisions, it is necessary to detect and estimate early and post water breakthrough trends respectively. Several models to forecast water breakthrough have been developed. Among them is the famous water cut (WC) versus cumulative production (Np) plot.\u0000 This paper presents two empirical models to address the inability of MPFM to detect early water breakthrough below a threshold and to provide an alternative technique for modeling post water breakthrough. The models developed in this work predict water breakthrough using fluid volumes, bottomhole pressure and temperature. The first technique predicts early water breakthrough when the plotted function shows a deviation from a straight-line trend. In the second model, the water cut equation is modified for post water breakthrough prediction.\u0000 Previous studies of water cut (WC) have focused on the production of water above the MPFMs threshold. The models derived in this paper provide accurate water cut estimates below MPMFs threshold and reliable post water breakthrough analysis.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"50 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116310932","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}
Out-Of-Sequence (OOS) Fracturing can potentially maximize reservoir contact and fracture conductivity/connectivity by creating fracture complexity via reducing the stress anisotropy. It is initiated by fracturing two "book-end" frac stages (Outside Fracs), followed by a ‘middle" stage (Centre Frac) between them. The Center Frac is theorized to utilize the reduced stress anisotropy to activate pre-existing failure surfaces oriented at various azimuths and dip angles, thereby connecting bi-wing fractures to planes of weakness (natural fractures/fissures/faults/joints/cleats) and resulting in a complex fracture network that enhances connectivity and fracture area within the Stimulated Reservoir Volume (SRV). OOS Fracturing can mitigate possible issues in treatments aiming at creating fracture complexity, including zipper frac (fracture tip interference and blunting inhibiting fracture extension), modified zipper frac (risks of well bashing and fractures growing asymmetrically opposite of the induced stress from prior stage in the adjacent well), simultaneous frac (middle clusters experiencing larger stress interference inhibiting their growth), and high-rate fracturing (risk of cluster erosion reducing the limited entry effect and premature screenout due to inconsistent diversions inside fractures). Since its inception in early 2010s, OOS Fracturing has not gained considerable attention due to previously-existing operational limitations in fracturing out-of-sequence. It is reported to have been field tested in Western Siberia in 2014 with claimed well performance success. Operational limitations of the system employed in that trial is believed to have prevented its commercial development at that time. With the advent of Multicycle Sleeves and Shift-Frac-Close operation with a single Bottom-Hole Assembly to open and close sleeves, previous operational limitations of OOS Fracturing have been resolved. OOS Fracturing has since been trialed in three formations in Western Canada (2017/2018). This work analyzes the fracture treatment pressures and well performance of these trials. Five OOS Fracturing trials in these three formations reveal that normalized 15-month/18-month production from out-of-sequence-fractured wells outperform that of sequentially-fractured offsets, with similar formation properties and treatment designs. Instantaneous Shut-In Pressures (ISIP) of Centre Frac are generally higher than that of either Outside Fracs. Breakdown pressures for Centre Fracs exhibit a mixed trend, confirming that reducing stress anisotropy could lower the breakdown gradient (based on Kirsch Equation) if rock fabric permits. Well performance and treatment pressures appear to be more sensitive to Centre Frac proppant tonnage/fluid volumes and uneven sleeve spacing. This is the first attempt in analyzing the five OOS Fracturing trials, with encouraging well performance and operational execution in conventional reservoirs where it was deployed. Despite uneven
{"title":"A Review of Preliminary Out-Of-Sequence Pinpoint Fracturing Field Trials in North America","authors":"B. Jamaloei","doi":"10.2118/198023-ms","DOIUrl":"https://doi.org/10.2118/198023-ms","url":null,"abstract":"\u0000 Out-Of-Sequence (OOS) Fracturing can potentially maximize reservoir contact and fracture conductivity/connectivity by creating fracture complexity via reducing the stress anisotropy. It is initiated by fracturing two \"book-end\" frac stages (Outside Fracs), followed by a ‘middle\" stage (Centre Frac) between them. The Center Frac is theorized to utilize the reduced stress anisotropy to activate pre-existing failure surfaces oriented at various azimuths and dip angles, thereby connecting bi-wing fractures to planes of weakness (natural fractures/fissures/faults/joints/cleats) and resulting in a complex fracture network that enhances connectivity and fracture area within the Stimulated Reservoir Volume (SRV). OOS Fracturing can mitigate possible issues in treatments aiming at creating fracture complexity, including zipper frac (fracture tip interference and blunting inhibiting fracture extension), modified zipper frac (risks of well bashing and fractures growing asymmetrically opposite of the induced stress from prior stage in the adjacent well), simultaneous frac (middle clusters experiencing larger stress interference inhibiting their growth), and high-rate fracturing (risk of cluster erosion reducing the limited entry effect and premature screenout due to inconsistent diversions inside fractures).\u0000 Since its inception in early 2010s, OOS Fracturing has not gained considerable attention due to previously-existing operational limitations in fracturing out-of-sequence. It is reported to have been field tested in Western Siberia in 2014 with claimed well performance success. Operational limitations of the system employed in that trial is believed to have prevented its commercial development at that time. With the advent of Multicycle Sleeves and Shift-Frac-Close operation with a single Bottom-Hole Assembly to open and close sleeves, previous operational limitations of OOS Fracturing have been resolved. OOS Fracturing has since been trialed in three formations in Western Canada (2017/2018). This work analyzes the fracture treatment pressures and well performance of these trials.\u0000 Five OOS Fracturing trials in these three formations reveal that normalized 15-month/18-month production from out-of-sequence-fractured wells outperform that of sequentially-fractured offsets, with similar formation properties and treatment designs. Instantaneous Shut-In Pressures (ISIP) of Centre Frac are generally higher than that of either Outside Fracs. Breakdown pressures for Centre Fracs exhibit a mixed trend, confirming that reducing stress anisotropy could lower the breakdown gradient (based on Kirsch Equation) if rock fabric permits. Well performance and treatment pressures appear to be more sensitive to Centre Frac proppant tonnage/fluid volumes and uneven sleeve spacing.\u0000 This is the first attempt in analyzing the five OOS Fracturing trials, with encouraging well performance and operational execution in conventional reservoirs where it was deployed. Despite uneven","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"46 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128064472","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
B. Gerlach, Fatima Dugonjić‐Bilić, M. Neuber, Ahmad Alkouh
Synthetic polymers in the emulsion form have been exploited for enhanced oil recovery applications especially in harsh environments for instance offshore or remote onshore locations. Polymer solutions can be prepared on-the-fly using saline make-up water like formation water or sea water. Use of an inverter surfactant accelerates the inversion of the polymer emulsion. For this study two highly efficient inverter surfactants at different price level were selected and their impact on the performance of an acrylamide-based emulsion copolymer was investigated. Polymer solutions prepared with the inverter surfactants S1 and S2 at different concentrations and conditioned by defined shear treatment were characterized by rheology, filter tests and injectivity behavior in sand packs. Significant impact of inverter surfactant on rheological properties and especially on injectivity performance is demonstrated. Viscosities of polymer solutions prepared with surfactant S1 are slightly higher (than viscosities with surfactant S2) and decrease with increasing surfactant concentration at constant polymer content. Besides, RRF values as a measure for injectivity behavior strongly decrease at ascending surfactant content. More intense conditioning leads to favorable injectivity of an otherwise plugging polymer solution. At lower concentrations surfactant S1 seems to adversely interact with the polymer and form polymer-surfactant complexes which are retained in the sand pack during injection. For surfactant S2 viscosities of polymer solutions are independent of surfactant concentration and RRF values are low even at low surfactant concentration. This surfactant ensures good injectivities over a broad range of conditions. Being the economically more favorable surfactant it adds value to polymer flooding projects.
{"title":"Best Surfactant for EOR Polymer Injectivity","authors":"B. Gerlach, Fatima Dugonjić‐Bilić, M. Neuber, Ahmad Alkouh","doi":"10.2118/198097-ms","DOIUrl":"https://doi.org/10.2118/198097-ms","url":null,"abstract":"\u0000 Synthetic polymers in the emulsion form have been exploited for enhanced oil recovery applications especially in harsh environments for instance offshore or remote onshore locations. Polymer solutions can be prepared on-the-fly using saline make-up water like formation water or sea water. Use of an inverter surfactant accelerates the inversion of the polymer emulsion. For this study two highly efficient inverter surfactants at different price level were selected and their impact on the performance of an acrylamide-based emulsion copolymer was investigated.\u0000 Polymer solutions prepared with the inverter surfactants S1 and S2 at different concentrations and conditioned by defined shear treatment were characterized by rheology, filter tests and injectivity behavior in sand packs.\u0000 Significant impact of inverter surfactant on rheological properties and especially on injectivity performance is demonstrated. Viscosities of polymer solutions prepared with surfactant S1 are slightly higher (than viscosities with surfactant S2) and decrease with increasing surfactant concentration at constant polymer content. Besides, RRF values as a measure for injectivity behavior strongly decrease at ascending surfactant content. More intense conditioning leads to favorable injectivity of an otherwise plugging polymer solution. At lower concentrations surfactant S1 seems to adversely interact with the polymer and form polymer-surfactant complexes which are retained in the sand pack during injection.\u0000 For surfactant S2 viscosities of polymer solutions are independent of surfactant concentration and RRF values are low even at low surfactant concentration. This surfactant ensures good injectivities over a broad range of conditions. Being the economically more favorable surfactant it adds value to polymer flooding projects.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130358353","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}
Tingyin He, J. Hornbrook, B. Dharanidharan, M. Al-Bahar, A. Al-Sane, Vandana Suresh, J. Hickey
The Najmah Shale, an organic-rich marl, is generally considered the primary source rock for hydrocarbons in Kuwait’s Jurassic and Cretaceous reservoirs. The purpose of this study was to estimate the original hydrocarbons in place (OHIP) and the geomechanical properties of the Najmah reservoir to aid in the design of a hydraulic fracture stimulation program in West Kuwait. An integrated petrophysical evaluation utilized conventional and sidewall core measurements, and standard and advanced open-hole logs were used to estimate net pay, porosity, oil saturation, and geomechanical properties. Formation evaluation of the Najmah Shale as a potential unconventional reservoir posed numerous challenges. These challenges included the ambiguous effects that high total organic carbon (TOC) has on conventional porosity logs and resistivity logs and the associated shale volume estimations. In this study, a probabilistic multi-mineral model was developed to more accurately assess the TOC of the rock and the associated porosity, saturation, and clay volume. Advanced well logs, including spectral gamma ray and elemental spectroscopy logs, were used to improve the mineralogical model of the complex formation. Routine core analysis, programmed pyrolysis, and X-ray diffraction (XRD) analyses were used to verify and calibrate the multi-mineral model results. Since a dual-porosity system was present in the formation, the Simandoux saturation equation was used to evaluate the fluid saturations. Anisotropic horizontal stress profiles were developed for specific wells based on analysis of dipole sonic logs, resulting in a greater regional understanding of the target interval. Based on the results of the multi-mineral modeling, the average TOC of the Najmah Shale varies from well to well throughout West Kuwait, with values as high as 14.8%. The effective porosity of the Najmah Shale ranges from 1 to 8%. Water saturation is low for these organic-rich formations. Water zones may occur above or below the organic-rich interval depending on the location. The geomechanical properties of the Najmah Shale are conducive to hydraulic fracture stimulation, by analogy to proven productive shale plays. The Sargelu interval, below the Najmah Shale, exhibits distinctly higher minimum horizontal stress gradients while the limestone above the Najmah Shale presents a weaker stress barrier. The results of the probabilistic formation evaluation of the Najmah Shale indicated that a significant volume of hydrocarbons is present in the formation. The geomechanical properties of the Najmah and adjacent units are conducive to successful hydraulic fracture stimulation. The evaluation of water-bearing zones adjacent to the target formation is critical to the investigation of the formation’s stimulation potential.
{"title":"An Integrated Study of Probabilistic Formation Evaluation and Geomechanical Analysis to Investigate the Potential of Hydraulic Fracture Stimulation in Najmah Unconventional Shale Reservoirs","authors":"Tingyin He, J. Hornbrook, B. Dharanidharan, M. Al-Bahar, A. Al-Sane, Vandana Suresh, J. Hickey","doi":"10.2118/198103-ms","DOIUrl":"https://doi.org/10.2118/198103-ms","url":null,"abstract":"\u0000 The Najmah Shale, an organic-rich marl, is generally considered the primary source rock for hydrocarbons in Kuwait’s Jurassic and Cretaceous reservoirs. The purpose of this study was to estimate the original hydrocarbons in place (OHIP) and the geomechanical properties of the Najmah reservoir to aid in the design of a hydraulic fracture stimulation program in West Kuwait.\u0000 An integrated petrophysical evaluation utilized conventional and sidewall core measurements, and standard and advanced open-hole logs were used to estimate net pay, porosity, oil saturation, and geomechanical properties. Formation evaluation of the Najmah Shale as a potential unconventional reservoir posed numerous challenges. These challenges included the ambiguous effects that high total organic carbon (TOC) has on conventional porosity logs and resistivity logs and the associated shale volume estimations. In this study, a probabilistic multi-mineral model was developed to more accurately assess the TOC of the rock and the associated porosity, saturation, and clay volume. Advanced well logs, including spectral gamma ray and elemental spectroscopy logs, were used to improve the mineralogical model of the complex formation. Routine core analysis, programmed pyrolysis, and X-ray diffraction (XRD) analyses were used to verify and calibrate the multi-mineral model results. Since a dual-porosity system was present in the formation, the Simandoux saturation equation was used to evaluate the fluid saturations. Anisotropic horizontal stress profiles were developed for specific wells based on analysis of dipole sonic logs, resulting in a greater regional understanding of the target interval.\u0000 Based on the results of the multi-mineral modeling, the average TOC of the Najmah Shale varies from well to well throughout West Kuwait, with values as high as 14.8%. The effective porosity of the Najmah Shale ranges from 1 to 8%. Water saturation is low for these organic-rich formations. Water zones may occur above or below the organic-rich interval depending on the location. The geomechanical properties of the Najmah Shale are conducive to hydraulic fracture stimulation, by analogy to proven productive shale plays. The Sargelu interval, below the Najmah Shale, exhibits distinctly higher minimum horizontal stress gradients while the limestone above the Najmah Shale presents a weaker stress barrier.\u0000 The results of the probabilistic formation evaluation of the Najmah Shale indicated that a significant volume of hydrocarbons is present in the formation. The geomechanical properties of the Najmah and adjacent units are conducive to successful hydraulic fracture stimulation. The evaluation of water-bearing zones adjacent to the target formation is critical to the investigation of the formation’s stimulation potential.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128542103","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}
Abdulaziz Alqasim, M. Sheshtawy, S. Kokal, Noureddine Benlakhdar
With maturing oil fields there is an increasing focus on improving the oil recovery factor and pushing the envelope toward a 70% target. This target is indeed very challenging and depends on a number of factors including enhanced oil recovery (EOR) methods, reservoir heterogeneities, displacement efficiency, and reservoir sweep. Other factors also play a role including vertical sweep due to flow behind the casing, well integrity issues, presence of conductive faults, or fractures. Proper surveillance performed to evaluate the injectant plume front, reservoir conformance, well connectivity, assessment of the integrity of wells, and other factors can be crucial for the success of the project and its future development. The paper discusses special downhole logging techniques including a set of conventional multiphase sensors alongside high precision temperature (HPT) and high-definition spectral noise logging (SNL-HD). It was run to provide complete assessment of the injection – production distribution and any associated well integrity issues that might impair the lateral sweep of injectants into the target layer. This will be done for an injector and producer pair near the wellbore area. The operation was carried out with a tool string that contained no mechanical parts and was not affected by downhole fluid properties. It was conducted under flowing and shut-in conditions to identify flow zones and check fracture signatures. It also provided multiphase fluid velocity profiles. The results of the survey allowed for in-depth assessment of borehole and behind casing flow, confirming lateral continuity, and provided an assessment of production-injection outside the pay zone. Results will allow for better well planning and anticipation of possible loss of well integrity that might impair production in the future. Combining the behind casing flow assessment with borehole multiphase flow distribution can be used for production optimization by sealing unwanted water contributing zones.
{"title":"Advanced Surveillance Technique for Multi-Phase Sweep Efficiency Monitoring","authors":"Abdulaziz Alqasim, M. Sheshtawy, S. Kokal, Noureddine Benlakhdar","doi":"10.2118/197985-ms","DOIUrl":"https://doi.org/10.2118/197985-ms","url":null,"abstract":"\u0000 With maturing oil fields there is an increasing focus on improving the oil recovery factor and pushing the envelope toward a 70% target. This target is indeed very challenging and depends on a number of factors including enhanced oil recovery (EOR) methods, reservoir heterogeneities, displacement efficiency, and reservoir sweep. Other factors also play a role including vertical sweep due to flow behind the casing, well integrity issues, presence of conductive faults, or fractures. Proper surveillance performed to evaluate the injectant plume front, reservoir conformance, well connectivity, assessment of the integrity of wells, and other factors can be crucial for the success of the project and its future development.\u0000 The paper discusses special downhole logging techniques including a set of conventional multiphase sensors alongside high precision temperature (HPT) and high-definition spectral noise logging (SNL-HD). It was run to provide complete assessment of the injection – production distribution and any associated well integrity issues that might impair the lateral sweep of injectants into the target layer. This will be done for an injector and producer pair near the wellbore area. The operation was carried out with a tool string that contained no mechanical parts and was not affected by downhole fluid properties. It was conducted under flowing and shut-in conditions to identify flow zones and check fracture signatures. It also provided multiphase fluid velocity profiles.\u0000 The results of the survey allowed for in-depth assessment of borehole and behind casing flow, confirming lateral continuity, and provided an assessment of production-injection outside the pay zone. Results will allow for better well planning and anticipation of possible loss of well integrity that might impair production in the future. Combining the behind casing flow assessment with borehole multiphase flow distribution can be used for production optimization by sealing unwanted water contributing zones.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"10 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126653569","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}
Forming a retrofit annular plug on controlled acid jet (CAJ) liners in horizontal wells can be challenging. Several conformance technologies have been tested with mixed results; optimal chemical placement is problematic, and results show that conventional treatments either slump or float along horizontal sections, fail to withstand the desired differential pressure, or are not achievable at low temperatures. This paper describes laboratory improvements and a large-scale yard test of a thixotropic polymer sealant (TPS). The TPS system is composed of an organically crosslinked polymer combined with optimized rheological modifiers, which enable predictable and controllable crosslinking times. This allows precise TPS placement into the horizontal or deviated wellbores to help control unwanted water or gas. Extensive laboratory testing was conducted on the TPS system to formulate the optimal rheology at low temperatures. A specialized laboratory-scaled test cell was purposely built to verify the development of the thixotropic blend at low temperatures of 35 to 40°C. After successful laboratory testing, a 520-ft long yard test was conducted to mimic a field trial. It consisted of centralized 4 1/2-in. tubing run horizontally inside a 7-in. casing. Four predrilled holes of 4-mm diameter were located midway along the tubing to represent the perforations, providing communication to the annulus of the tubing and casing. A 2.25-in. outer diameter (OD) high-pressure hose, representing coiled tubing, was placed inside the 4 1/2-in. tubing and used to deliver the TPS fluid to the perforations. The entire setup was pressure-tested to 5,000 psi and heated to 40°C using an insulated heating blanket. A high-pressure pump was used to pump and displace 6 bbl of TPS, which was sufficient to form a 300-ft annular plug. The chemical was allowed to crosslink and set for 45 hours. Results of this yard test showed that a 300-ft TPS annular plug is capable of withstanding up to 4,620-psi differential pressure. The setup was then cut at various locations, both treated and untreated, to confirm, assess, and observe TPS placement in the cross-section of the tubulars. It was observed that the TPS can flow in the smaller spaces between the tubing and the centralizer, helping ensure optimal sealing. The TPS system described here can be used to help reduce unwanted water or gas production in long horizontal wells with CAJ liners. The open annulus between the preperforated liner and the formation makes selective isolation for the presence of thief zones, high-permeability zones, or fractures extremely challenging. Left untreated, this can eventually result in a large increase in water production and eventually a reduction in the economic life of the field.
{"title":"World's Largest Yard Testing of a Thixotropic Polymer Sealant for Chemical Annular Plug Applications in Low-temperature Horizontal Wellbores","authors":"K. Matar, Y. Santin, Khan Taku, Jesper Koldig","doi":"10.2118/198085-ms","DOIUrl":"https://doi.org/10.2118/198085-ms","url":null,"abstract":"\u0000 Forming a retrofit annular plug on controlled acid jet (CAJ) liners in horizontal wells can be challenging. Several conformance technologies have been tested with mixed results; optimal chemical placement is problematic, and results show that conventional treatments either slump or float along horizontal sections, fail to withstand the desired differential pressure, or are not achievable at low temperatures.\u0000 This paper describes laboratory improvements and a large-scale yard test of a thixotropic polymer sealant (TPS). The TPS system is composed of an organically crosslinked polymer combined with optimized rheological modifiers, which enable predictable and controllable crosslinking times. This allows precise TPS placement into the horizontal or deviated wellbores to help control unwanted water or gas.\u0000 Extensive laboratory testing was conducted on the TPS system to formulate the optimal rheology at low temperatures. A specialized laboratory-scaled test cell was purposely built to verify the development of the thixotropic blend at low temperatures of 35 to 40°C.\u0000 After successful laboratory testing, a 520-ft long yard test was conducted to mimic a field trial. It consisted of centralized 4 1/2-in. tubing run horizontally inside a 7-in. casing. Four predrilled holes of 4-mm diameter were located midway along the tubing to represent the perforations, providing communication to the annulus of the tubing and casing. A 2.25-in. outer diameter (OD) high-pressure hose, representing coiled tubing, was placed inside the 4 1/2-in. tubing and used to deliver the TPS fluid to the perforations. The entire setup was pressure-tested to 5,000 psi and heated to 40°C using an insulated heating blanket. A high-pressure pump was used to pump and displace 6 bbl of TPS, which was sufficient to form a 300-ft annular plug. The chemical was allowed to crosslink and set for 45 hours.\u0000 Results of this yard test showed that a 300-ft TPS annular plug is capable of withstanding up to 4,620-psi differential pressure. The setup was then cut at various locations, both treated and untreated, to confirm, assess, and observe TPS placement in the cross-section of the tubulars. It was observed that the TPS can flow in the smaller spaces between the tubing and the centralizer, helping ensure optimal sealing.\u0000 The TPS system described here can be used to help reduce unwanted water or gas production in long horizontal wells with CAJ liners. The open annulus between the preperforated liner and the formation makes selective isolation for the presence of thief zones, high-permeability zones, or fractures extremely challenging. Left untreated, this can eventually result in a large increase in water production and eventually a reduction in the economic life of the field.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"50 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128301738","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}
Tao Chen, Qiwei Wang, F. Chang, Jairo Leal, Mauricio Espinosa
Iron sulfide (FeS) deposition is a ubiquitous phenomenon in sour oil and gas wells, especially for these producing from high temperature and high pressure reservoirs. Hydrogen sulfide (H2S) gas is highly soluble in water and readily reacts with carbon steel and dissolved iron once in contact, which leads to the formation of FeS scale. The surface deposition or bulk precipitation of FeS scale is detrimental to flow assurance, such as flow restriction, pitting corrosion and stabilized emulsion. Compared to the conventional carbonate and sulphate scales, the mitigation of iron sulfide deposition is notoriously difficult. It is essential to understand its root causes in order to develop a suitable strategy to manage the problem effectively. By combining laboratorial tests and model simulations, new progresses have been made on the FeS root cause analysis for high temperature high H2S gas wells. The iron sources were determined over different stages of well life from drilling, completion, acidizing to production. Results from this study demonstrate that the iron contributed by the sour reservoir connate water is limited and is not the major cause to FeS deposition on downhole tubular in sour gas wells. Carbon steel corrosion during production stage is one source of FeS deposition. However, the rate of iron sulfide deposition during production is minor and far less than the deposit observed in the field. Other sources of iron sulfide deposition should be further investigated. Another major source is the iron released from tubing due to acid corrosion during acidizing stimulation, which potentially leads to severe formation damage and associated deposition problems in the production tubing and equipment. In addition, the iron contamination in the drilling fluid could contribute to FeS scaling problem. This paper presents a fundamental study to understand the sources of iron for FeS deposition in high H2S sour wells producing from carbonate reservoirs. Appropriate mitigation strategies are recommended accordingly.
{"title":"Root Cause Analysis for Iron Sulfide Deposition in Sour Gas Wells","authors":"Tao Chen, Qiwei Wang, F. Chang, Jairo Leal, Mauricio Espinosa","doi":"10.2118/198187-ms","DOIUrl":"https://doi.org/10.2118/198187-ms","url":null,"abstract":"\u0000 Iron sulfide (FeS) deposition is a ubiquitous phenomenon in sour oil and gas wells, especially for these producing from high temperature and high pressure reservoirs. Hydrogen sulfide (H2S) gas is highly soluble in water and readily reacts with carbon steel and dissolved iron once in contact, which leads to the formation of FeS scale. The surface deposition or bulk precipitation of FeS scale is detrimental to flow assurance, such as flow restriction, pitting corrosion and stabilized emulsion.\u0000 Compared to the conventional carbonate and sulphate scales, the mitigation of iron sulfide deposition is notoriously difficult. It is essential to understand its root causes in order to develop a suitable strategy to manage the problem effectively.\u0000 By combining laboratorial tests and model simulations, new progresses have been made on the FeS root cause analysis for high temperature high H2S gas wells. The iron sources were determined over different stages of well life from drilling, completion, acidizing to production.\u0000 Results from this study demonstrate that the iron contributed by the sour reservoir connate water is limited and is not the major cause to FeS deposition on downhole tubular in sour gas wells. Carbon steel corrosion during production stage is one source of FeS deposition. However, the rate of iron sulfide deposition during production is minor and far less than the deposit observed in the field. Other sources of iron sulfide deposition should be further investigated.\u0000 Another major source is the iron released from tubing due to acid corrosion during acidizing stimulation, which potentially leads to severe formation damage and associated deposition problems in the production tubing and equipment. In addition, the iron contamination in the drilling fluid could contribute to FeS scaling problem.\u0000 This paper presents a fundamental study to understand the sources of iron for FeS deposition in high H2S sour wells producing from carbonate reservoirs. Appropriate mitigation strategies are recommended accordingly.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"64 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130657092","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}
Deena Tayyib, Abdulaziz Alqasim, S. Kokal, O. Huseby
Tracer technology is an efficient and effective monitoring and surveillance tool with many useful applications in the oil and gas industry. Some of these applications include improving reservoir characterization, waterflood optimization, remaining oil saturation (Sor) determination, fluid pathways, and connectivity between wells. Tracer surveys can be deployed inter-well between an injector and offset producer(s) or as push-and-pull studies in a single well. Tracers can be classified several ways. (a) Based on their functionality: partitioning and passive tracers. Partitioning tracers interact with the reservoir and thus propagate slower than passive tracers do. The time lag between the two types can be used to estimate Sor, to ultimately assess and optimize EOR operations. (b) Based on their carrying fluid: water and gas tracers. These can be used in IOR or EOR operations. All gas tracers are partitioning tracers and the most common are perfluorocarbons; they are thermally stable, environmentally friendly, have high detectability and low natural occurrence in the reservoir. On the other hand, water tracers are passive tracers and the most commonly used ones are fluorinated acids. (c) Based on radioactivity: radioactive and non-radioactive tracers. Selecting a tracer to deploy in the field depends on a number of factors including their solubility, fluid compatibility, background concentration, stability, detectability, cost, and environmental impact. This paper provides an overview of various tracer applications in the oil and gas industry. These will include the single-well tracer test (SWCT), inter-well tracer test (IWTT), nano tracers, gas tracers and radioactive tracers. Their use will be highlighted in different scenarios. Field case studies will be reviewed for all types of tracers. Lessons learnt for all the applications, including what works and what does not work, will be shared. Specific cases and examples will include the optimization of waterflood operations, remaining oil saturation determination, flow paths and connectivity between wells, and IOR/EOR applications. The current state-of-the-art will be presented and novel emerging methods will be highlighted. This paper will showcase how the tracer technology has evolved over the years and how it shows great potential as a reservoir monitoring and surveillance tool.
{"title":"Overview of Tracer Applications in Oil and Gas Industry","authors":"Deena Tayyib, Abdulaziz Alqasim, S. Kokal, O. Huseby","doi":"10.2118/198157-ms","DOIUrl":"https://doi.org/10.2118/198157-ms","url":null,"abstract":"\u0000 Tracer technology is an efficient and effective monitoring and surveillance tool with many useful applications in the oil and gas industry. Some of these applications include improving reservoir characterization, waterflood optimization, remaining oil saturation (Sor) determination, fluid pathways, and connectivity between wells. Tracer surveys can be deployed inter-well between an injector and offset producer(s) or as push-and-pull studies in a single well.\u0000 Tracers can be classified several ways. (a) Based on their functionality: partitioning and passive tracers. Partitioning tracers interact with the reservoir and thus propagate slower than passive tracers do. The time lag between the two types can be used to estimate Sor, to ultimately assess and optimize EOR operations. (b) Based on their carrying fluid: water and gas tracers. These can be used in IOR or EOR operations. All gas tracers are partitioning tracers and the most common are perfluorocarbons; they are thermally stable, environmentally friendly, have high detectability and low natural occurrence in the reservoir. On the other hand, water tracers are passive tracers and the most commonly used ones are fluorinated acids. (c) Based on radioactivity: radioactive and non-radioactive tracers. Selecting a tracer to deploy in the field depends on a number of factors including their solubility, fluid compatibility, background concentration, stability, detectability, cost, and environmental impact.\u0000 This paper provides an overview of various tracer applications in the oil and gas industry. These will include the single-well tracer test (SWCT), inter-well tracer test (IWTT), nano tracers, gas tracers and radioactive tracers. Their use will be highlighted in different scenarios. Field case studies will be reviewed for all types of tracers. Lessons learnt for all the applications, including what works and what does not work, will be shared. Specific cases and examples will include the optimization of waterflood operations, remaining oil saturation determination, flow paths and connectivity between wells, and IOR/EOR applications. The current state-of-the-art will be presented and novel emerging methods will be highlighted. This paper will showcase how the tracer technology has evolved over the years and how it shows great potential as a reservoir monitoring and surveillance tool.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"38 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132590593","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}
North Kuwait has a vision to produce about 1 million BOPD within next couple of year. As a part of this strategy, all efforts & opportunities are being synchronized to maximize the production. A serious threat to this plan was confronted by observation of Naturally occurring radioactive materials (NORM) at some of the producers, a new challenge for which the asset did not anticipate or had any plan earlier. The paper proposal covers how this threat was converted into an opportunity. A comprehensive review of the wells with NORM was done to understand the link to specific reservoir related issues or zone's mineralogy. As this kind of production problem has been faced for the first time in North Kuwait, brainstorming and technical pros & cons were investigated with internal as well as external consultants. A due diligence was conducted to existing rules & procedures within KOC and Kuwait. Case histories from different parts of the world were reviewed as to how such issues had been resolved. Measurement of NORM, accuracy & validity was also looked into, which varied from vendor to vendor. Thus the gathered knowledge was shared with all stake holder teams. As almost 30-40 MBOPD was the locked in potential, fast track actions have been taken to create a contract to manage wells suffering from NORM. After going through a fast track identification of suitable vendor, contract was awarded to one of the international vendor. Accordingly, workover rigs were made ready to handle NORM remediation operations professionally. Simultaneously, technical evaluation of the performance of wells infected with NORM was done to understand the phenomenon and the relationship with the changes in reservoir pressure / stimulation. A workover schedule was prepared and implemented to revive the shut-in production potential to the GCs, resulting in a bump in oil production for North Kuwait. As a result of the strategy adopted, deferment of oil production due to NORM, which hovered to more than 1.5 years in the past, is prevented, thus helping production target requirements for the Asset. Performance evaluation of wells indicated that there is a strong relationship of reservoir pressure and stimulation with the NORM level. NORM management requires an integrated team approach, ranging from working units to the organization level and a proactive analytical approach to understand the impact of ongoing sub-surface operations on NORM tendencies. The proper understanding and analysis done in overcoming the NORM has aided in enhancing and sustaining the production via having extended productive life for the wells.
{"title":"Turning Threat into Opportunity: NORM Management Helps to Recoup the Deferred Production from North Kuwait","authors":"N. Saleh, H. Chetri, M. Al-Mutawa","doi":"10.2118/198117-ms","DOIUrl":"https://doi.org/10.2118/198117-ms","url":null,"abstract":"\u0000 North Kuwait has a vision to produce about 1 million BOPD within next couple of year. As a part of this strategy, all efforts & opportunities are being synchronized to maximize the production. A serious threat to this plan was confronted by observation of Naturally occurring radioactive materials (NORM) at some of the producers, a new challenge for which the asset did not anticipate or had any plan earlier. The paper proposal covers how this threat was converted into an opportunity. A comprehensive review of the wells with NORM was done to understand the link to specific reservoir related issues or zone's mineralogy. As this kind of production problem has been faced for the first time in North Kuwait, brainstorming and technical pros & cons were investigated with internal as well as external consultants. A due diligence was conducted to existing rules & procedures within KOC and Kuwait. Case histories from different parts of the world were reviewed as to how such issues had been resolved. Measurement of NORM, accuracy & validity was also looked into, which varied from vendor to vendor. Thus the gathered knowledge was shared with all stake holder teams.\u0000 As almost 30-40 MBOPD was the locked in potential, fast track actions have been taken to create a contract to manage wells suffering from NORM. After going through a fast track identification of suitable vendor, contract was awarded to one of the international vendor. Accordingly, workover rigs were made ready to handle NORM remediation operations professionally. Simultaneously, technical evaluation of the performance of wells infected with NORM was done to understand the phenomenon and the relationship with the changes in reservoir pressure / stimulation. A workover schedule was prepared and implemented to revive the shut-in production potential to the GCs, resulting in a bump in oil production for North Kuwait. As a result of the strategy adopted, deferment of oil production due to NORM, which hovered to more than 1.5 years in the past, is prevented, thus helping production target requirements for the Asset. Performance evaluation of wells indicated that there is a strong relationship of reservoir pressure and stimulation with the NORM level.\u0000 NORM management requires an integrated team approach, ranging from working units to the organization level and a proactive analytical approach to understand the impact of ongoing sub-surface operations on NORM tendencies. The proper understanding and analysis done in overcoming the NORM has aided in enhancing and sustaining the production via having extended productive life for the wells.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"14 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125247146","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}
Gas injection has been widely used for enhancing oil recovery in petroleum reservoirs. One of the major challenges facing this technique is the high mobility of gas caused by its lower viscosity compared to reservoir fluids. Injecting the gas in a foam phase can solve the mobility challenge by increasing the gas apparent viscosity. Surface active agents such as surfactants are usually used to generate foams. However, the long-term stability of the surfactants is challenging. The synergistic effect of surfactants and nanoparticles may offer a novel technique to solve the foam stability issue and generate stronger foams. This study evaluates the role of nanoparticles on stabilizing surfactant foams in porous media. Anionic surfactant and surface modified silica nanoparticles were used in this assessment. Dynamic foam tests were conducted to study the foam stability and strength in porous media. The major parameter used to evaluate the foam strength in this study is the mobility reduction factor (MRF). The experiments were conducted using nitrogen gas at elevated pressure. The influence of nanoparticles on surfactant foam strength was conducted at different nanoparticles concentrations and fixed surfactant concentration. The results demonstrated that the presence of nanoparticles in surfactant solution resulted in a more stable foam compared to surfactant alone. The nanoparticles used in this study seem to enhance the foam stability by either one or two mechanisms: particle arrangement during film drainage or increasing the capillary pressure of coalescence. Based on the dynamic foam tests, higher pressure drops were reported for the mixtures of nanoparticles and surfactant compared to surfactant alone. This clearly indicated the higher resistance to gas flow caused by the foam generated using the mixture. The results also showed that as the nanoparticles concentration increased, MRF increased, too. The MRF for the sample contains only surfactant was 72. However, the addition of 0.50 and 1.00 wt% of nanoparticles to the surfactant solution resulted in higher MRF: 75 and 85, respectively. The need for generating strong foam is very important to ensure the long term stability of foam and, consequently, reducing the gas mobility in porous media. The addition of solid nanoparticles to surfactant solutions might strengthen the aqueous film between gas bubbles and, eventually, enhancing the foam stability.
{"title":"The Synergy of Surfactant and Nanoparticles: Towards Enhancing Foam Stability","authors":"Z. Alyousef, D. Schechter","doi":"10.2118/198190-ms","DOIUrl":"https://doi.org/10.2118/198190-ms","url":null,"abstract":"\u0000 Gas injection has been widely used for enhancing oil recovery in petroleum reservoirs. One of the major challenges facing this technique is the high mobility of gas caused by its lower viscosity compared to reservoir fluids. Injecting the gas in a foam phase can solve the mobility challenge by increasing the gas apparent viscosity. Surface active agents such as surfactants are usually used to generate foams. However, the long-term stability of the surfactants is challenging. The synergistic effect of surfactants and nanoparticles may offer a novel technique to solve the foam stability issue and generate stronger foams. This study evaluates the role of nanoparticles on stabilizing surfactant foams in porous media.\u0000 Anionic surfactant and surface modified silica nanoparticles were used in this assessment. Dynamic foam tests were conducted to study the foam stability and strength in porous media. The major parameter used to evaluate the foam strength in this study is the mobility reduction factor (MRF). The experiments were conducted using nitrogen gas at elevated pressure. The influence of nanoparticles on surfactant foam strength was conducted at different nanoparticles concentrations and fixed surfactant concentration.\u0000 The results demonstrated that the presence of nanoparticles in surfactant solution resulted in a more stable foam compared to surfactant alone. The nanoparticles used in this study seem to enhance the foam stability by either one or two mechanisms: particle arrangement during film drainage or increasing the capillary pressure of coalescence. Based on the dynamic foam tests, higher pressure drops were reported for the mixtures of nanoparticles and surfactant compared to surfactant alone. This clearly indicated the higher resistance to gas flow caused by the foam generated using the mixture. The results also showed that as the nanoparticles concentration increased, MRF increased, too. The MRF for the sample contains only surfactant was 72. However, the addition of 0.50 and 1.00 wt% of nanoparticles to the surfactant solution resulted in higher MRF: 75 and 85, respectively.\u0000 The need for generating strong foam is very important to ensure the long term stability of foam and, consequently, reducing the gas mobility in porous media. The addition of solid nanoparticles to surfactant solutions might strengthen the aqueous film between gas bubbles and, eventually, enhancing the foam stability.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"6 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115149774","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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