Qishuai Yin, Jin Yang, Bo Zhou, M. Luo, Wentuo Li, Yi Huang, T. Sun, Xinxin Hou, W. Xiaodong, Junxiang Wang
The South China YQ Basin with 15 trillion cubic meters natural gas is typical of ultra high temperature-high pressure (ultra-HTHP) with the highest bottomhole temperature (BHT) at 249°C, the maximum bottomhole pressure (BHP) at 142MPa and the extremely narrow pressure window. Therefore, there are kinds of technical challenges during drilling there. In recent years, the managed pressure drilling (MPD) has been successfully applied in the basin with risks and well cost reduced instead. The operational designs of MPD consist of three parts: the precise calculation of drilling fluid equivalent circulating density (ECD), the optimization of operational parameters and the well control. The first part includes four models: the wellbore temperature field model, the drilling fluid equivalent static density (ESD) model, the drilling fluid rheological property model and the effects of cuttings concentration on ECD. The second part is the determination of the two key operational parameters: the mud weight (MW) and the surface backpressure (SBP). The third part is the plans of three cases: downhole accidents, equipment failures and termination conditions of MPD. The first part includes four steps: establish the instantaneous wellbore temperature model based on the convection and thermal conductivity theory by dividing the wellbore into five areas; establish the ESD model by considering the elastic compression effect of HP and thermal expansion effect of HT; establish the drilling fluid rheological property model based on the Herschel-Buckley model by considering the effect of ultra-HTHP on dynamic shear force, consistency coefficient and liquidity index; consider the effects of cuttings concentration on ECD based on the solid-liquid two-phase flow. The ECD model is established based on above models. The second part includes two steps: determine the MW based on the critical pressure constraint principle by the operational window simulation of different well depth and fluid volume; determine the SBP of pump-on and pump-off by considering the rated operating pressure of the equipment, the calculated pressure loss and the 0~1MPa higher BHP than formation pressure. The third part includes three steps: make the emergency measures against downhole accidents by well control matrix; make the emergency measures against the failure of equipment such as rotating control device (RCD); determine the MPD termination conditions such as drilling big cracks. The MPD is successfully applied to X gas field featuring offshore ultra-HTHP. The casing structure is optimized from 7-8 layers to 5 layers and the well is drilled in the micro pressure window of 0.01~0.02sg without accidents. Additionally, the non-productive time (NPT) decreases by 60% and the well cost is obviously reduced. Generally, the MPD yields time and cost savings for tomorrow's market.
{"title":"Operational Designs and Applications of MPD in Offshore Ultra-HTHP Exploration Wells","authors":"Qishuai Yin, Jin Yang, Bo Zhou, M. Luo, Wentuo Li, Yi Huang, T. Sun, Xinxin Hou, W. Xiaodong, Junxiang Wang","doi":"10.2118/191060-MS","DOIUrl":"https://doi.org/10.2118/191060-MS","url":null,"abstract":"\u0000 The South China YQ Basin with 15 trillion cubic meters natural gas is typical of ultra high temperature-high pressure (ultra-HTHP) with the highest bottomhole temperature (BHT) at 249°C, the maximum bottomhole pressure (BHP) at 142MPa and the extremely narrow pressure window. Therefore, there are kinds of technical challenges during drilling there. In recent years, the managed pressure drilling (MPD) has been successfully applied in the basin with risks and well cost reduced instead.\u0000 The operational designs of MPD consist of three parts: the precise calculation of drilling fluid equivalent circulating density (ECD), the optimization of operational parameters and the well control. The first part includes four models: the wellbore temperature field model, the drilling fluid equivalent static density (ESD) model, the drilling fluid rheological property model and the effects of cuttings concentration on ECD. The second part is the determination of the two key operational parameters: the mud weight (MW) and the surface backpressure (SBP). The third part is the plans of three cases: downhole accidents, equipment failures and termination conditions of MPD.\u0000 The first part includes four steps: establish the instantaneous wellbore temperature model based on the convection and thermal conductivity theory by dividing the wellbore into five areas; establish the ESD model by considering the elastic compression effect of HP and thermal expansion effect of HT; establish the drilling fluid rheological property model based on the Herschel-Buckley model by considering the effect of ultra-HTHP on dynamic shear force, consistency coefficient and liquidity index; consider the effects of cuttings concentration on ECD based on the solid-liquid two-phase flow. The ECD model is established based on above models. The second part includes two steps: determine the MW based on the critical pressure constraint principle by the operational window simulation of different well depth and fluid volume; determine the SBP of pump-on and pump-off by considering the rated operating pressure of the equipment, the calculated pressure loss and the 0~1MPa higher BHP than formation pressure. The third part includes three steps: make the emergency measures against downhole accidents by well control matrix; make the emergency measures against the failure of equipment such as rotating control device (RCD); determine the MPD termination conditions such as drilling big cracks.\u0000 The MPD is successfully applied to X gas field featuring offshore ultra-HTHP. The casing structure is optimized from 7-8 layers to 5 layers and the well is drilled in the micro pressure window of 0.01~0.02sg without accidents. Additionally, the non-productive time (NPT) decreases by 60% and the well cost is obviously reduced. Generally, the MPD yields time and cost savings for tomorrow's market.","PeriodicalId":133825,"journal":{"name":"Day 3 Wed, August 29, 2018","volume":"11 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131548729","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}
R. Bautista, Vanessa Gonzalez, A. Hawy, Alaa Al Zarafi, Adil Al Busaidi, Ruikun Liu, Ali Al Shidhani, Mahesh S. Picha, H. Rashdi
As in most of the Sultanate of Oman fields, faulted Shuaiba fields contain formations that are extremely faulted and folded. These conditions are a result of the extensive and complex tectonic activities that broke the rock into many structurally deformed blocks. Several studies have been conducted to identify the best drilling and geosteering methods to use in the area. An additional challenge in faulted Shuaiba fields is the bounding of the target reservoir by two dense and sticky layers with similar gamma ray, resistivity, and density. With such reservoir character, differentiating between the top and bottom to make the correct geosteering decision is a real challenge when using conventional logging-while-drilling and standard drilling technologies. A deep-directional boundary mapping tool enabled determining the borehole position inside the steeply dipping carbonate reservoir. Based on the mapping tool's directional measurements, the trajectory was adjusted to avoid exiting the reservoir from the top or bottom, thus continuously keeping the borehole within the reservoir sweet spot. A hybrid rotary steerable system (RSS) tool enabled achieving high doglegs over a short distance in response to the steep and sudden formation dip changes. If a sidetrack was found to be necessary, the hybrid RSS provided the ability to perform an openhole sidetrack in the same string to as deep as 897 m from the 7-in. liner shoe. At the same time, well design, bottomhole assembly (BHA) design and drilling parameters and envelopes were optimized, allowing new historical field records to be achieved in such challenging drilling environment, specifically, the a faulted Shuaiba fields, and in nearby Qarn Alam cluster fields. Due to the difficulty in mapping the reservoir boundary in faulted Shuaiba fields, the operator's geological model was determined to be insufficient. With the high-resistivity contrast in faulted Shuaiba fields, the deep-directional boundary mapping tool enabled the geosteering engineer to detect the top and bottom of the reservoir to a distance up to 2.5-m true vertical depth (TVD). The ability to detect the top and bottom of the reservoir provided reasonable time to react to any sudden changes in the formation. Introducing the directional boundary mapping tool made it possible to update the geological model based on the data obtained from the tool. During the prejob modeling, the well placement team, drilling team, and the operator's reservoir management team jointly set the geosteering objectives and assessed the risk of sidetracking the well, selected the appropriate BHA, and determined if the well would be drilled in the flank zone area. Drilling in the flank zone area was important due to the highly faulted area and sudden formation dip changes. Due to having a better understanding of the true vertical depth (TVD) and azimuth of the faulted Shuaiba reservoirs and being able to update the structural model based on the results and bounda
{"title":"Geosteering and Drilling Challenges in a Faulted Reservoir Northern Oman","authors":"R. Bautista, Vanessa Gonzalez, A. Hawy, Alaa Al Zarafi, Adil Al Busaidi, Ruikun Liu, Ali Al Shidhani, Mahesh S. Picha, H. Rashdi","doi":"10.2118/191002-MS","DOIUrl":"https://doi.org/10.2118/191002-MS","url":null,"abstract":"\u0000 As in most of the Sultanate of Oman fields, faulted Shuaiba fields contain formations that are extremely faulted and folded. These conditions are a result of the extensive and complex tectonic activities that broke the rock into many structurally deformed blocks. Several studies have been conducted to identify the best drilling and geosteering methods to use in the area. An additional challenge in faulted Shuaiba fields is the bounding of the target reservoir by two dense and sticky layers with similar gamma ray, resistivity, and density. With such reservoir character, differentiating between the top and bottom to make the correct geosteering decision is a real challenge when using conventional logging-while-drilling and standard drilling technologies.\u0000 A deep-directional boundary mapping tool enabled determining the borehole position inside the steeply dipping carbonate reservoir. Based on the mapping tool's directional measurements, the trajectory was adjusted to avoid exiting the reservoir from the top or bottom, thus continuously keeping the borehole within the reservoir sweet spot. A hybrid rotary steerable system (RSS) tool enabled achieving high doglegs over a short distance in response to the steep and sudden formation dip changes. If a sidetrack was found to be necessary, the hybrid RSS provided the ability to perform an openhole sidetrack in the same string to as deep as 897 m from the 7-in. liner shoe. At the same time, well design, bottomhole assembly (BHA) design and drilling parameters and envelopes were optimized, allowing new historical field records to be achieved in such challenging drilling environment, specifically, the a faulted Shuaiba fields, and in nearby Qarn Alam cluster fields.\u0000 Due to the difficulty in mapping the reservoir boundary in faulted Shuaiba fields, the operator's geological model was determined to be insufficient. With the high-resistivity contrast in faulted Shuaiba fields, the deep-directional boundary mapping tool enabled the geosteering engineer to detect the top and bottom of the reservoir to a distance up to 2.5-m true vertical depth (TVD). The ability to detect the top and bottom of the reservoir provided reasonable time to react to any sudden changes in the formation. Introducing the directional boundary mapping tool made it possible to update the geological model based on the data obtained from the tool.\u0000 During the prejob modeling, the well placement team, drilling team, and the operator's reservoir management team jointly set the geosteering objectives and assessed the risk of sidetracking the well, selected the appropriate BHA, and determined if the well would be drilled in the flank zone area. Drilling in the flank zone area was important due to the highly faulted area and sudden formation dip changes.\u0000 Due to having a better understanding of the true vertical depth (TVD) and azimuth of the faulted Shuaiba reservoirs and being able to update the structural model based on the results and bounda","PeriodicalId":133825,"journal":{"name":"Day 3 Wed, August 29, 2018","volume":"11 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129927383","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}
Chemical diverter systems, such as relative permeability modifiers (RPMs), can significantly reduce effective permeability, mainly to aqueous-based fluids (e.g., acids), where the fluid enters into the interval being treated. Graded salt is a granular solid used at all temperatures that has a wide particle-size distribution (PSD) for bridging and sealing to provide effective diversion of treating fluids. This combined with an RPM fluid can help divert the entire interval during a matrix-acid stimulation. This paper discusses a review of wells treated, with excellent results, using such a chemical and bridging diversion system (CBDS) in different fields in the southern region of Mexico. If a formation has zones containing a large number of open, natural fractures, the resulting tendency is for treatment fluids to flow into the zone(s) with the highest effective permeability or the least amount of damage instead of creating a uniform distribution over the entire interval, as is necessary. An important characteristic for a diverter product is creating a temporary skin effect during the injection of the treatment that leaves no permanent damage or that can later be removed or dissolved. The focus of this study was on gathering more detailed information for the selection of the diverter, treatment design, and operational procedures. Additionally, the learning curve is presented associated with the challenge of stimulating a specific zone within a complex mechanical wellbore and selecting the correct candidate for applying a schedule of mechanical diversions and acid stimulations. Laboratory study data are included to illustrate how the diverting process physically manifests, which is used to substantiate the field designs. Understanding how chemical diverters interact with the formation rock and fluid is fundamental to selecting the proper product for a specific treatment application.
{"title":"Optimized Diversion System Applied in Stimulation Treatments in a Highly Naturally Fractured Carbonate Formation: Successful Case Histories","authors":"C. Ramirez, K. Campos, A. Gonzalez","doi":"10.2118/191026-MS","DOIUrl":"https://doi.org/10.2118/191026-MS","url":null,"abstract":"\u0000 Chemical diverter systems, such as relative permeability modifiers (RPMs), can significantly reduce effective permeability, mainly to aqueous-based fluids (e.g., acids), where the fluid enters into the interval being treated. Graded salt is a granular solid used at all temperatures that has a wide particle-size distribution (PSD) for bridging and sealing to provide effective diversion of treating fluids. This combined with an RPM fluid can help divert the entire interval during a matrix-acid stimulation. This paper discusses a review of wells treated, with excellent results, using such a chemical and bridging diversion system (CBDS) in different fields in the southern region of Mexico.\u0000 If a formation has zones containing a large number of open, natural fractures, the resulting tendency is for treatment fluids to flow into the zone(s) with the highest effective permeability or the least amount of damage instead of creating a uniform distribution over the entire interval, as is necessary. An important characteristic for a diverter product is creating a temporary skin effect during the injection of the treatment that leaves no permanent damage or that can later be removed or dissolved.\u0000 The focus of this study was on gathering more detailed information for the selection of the diverter, treatment design, and operational procedures. Additionally, the learning curve is presented associated with the challenge of stimulating a specific zone within a complex mechanical wellbore and selecting the correct candidate for applying a schedule of mechanical diversions and acid stimulations.\u0000 Laboratory study data are included to illustrate how the diverting process physically manifests, which is used to substantiate the field designs. Understanding how chemical diverters interact with the formation rock and fluid is fundamental to selecting the proper product for a specific treatment application.","PeriodicalId":133825,"journal":{"name":"Day 3 Wed, August 29, 2018","volume":"32 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124881726","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}
Ruxin Zhang, B. Hou, Yijin Zeng, Jian Zhou, Qingyang Li
Traditional hydraulic fracturing requires lots of water and sand resulting in short fracture length and small SRV with a low production. However, a new waterless fracturing, called Liquefied Petroleum Gas (LPG) fracturing, is applied to stimulate shale formation effectively. In order to figure out the mechanism of fracture initiation and propagation in LPG fracturing, four large-scale true tri-axial fracturing simulation experiments have been conducted on shale outcrops. Meanwhile, the effects of engineering factors, pump rate and fluid viscosity, on fracture propagation behavior in the shale formation are discussed. The experimental results indicate that LPG fracturing not only activates discontinuities to form a complex fracture network, but also enhances induced fracture length to form a large SRV. Induced fractures have two initiation points, open-hole section and stress concentration point of wellbore wall, and have three main propagation behaviors, crossing, shear and arrest, dilation and crossing in shale formation. A low viscosity fracturing fluid activates discontinuities resulting in complex fractures, whereas, a high viscosity fluid would like to create some main fractures without opening discontinuities. Moreover, a high pump rate offers more energy for induced fractures to cross the discontinuities resulting in a long fracture length and large SRV. In addition, the anisotropic of shale formation and the existence of discontinuities cause signals attenuation, which increases the arrival time, resulting in location deviation of acoustic emission (AE) events in the AE monitoring. The pressure-time-energy curve, however, shows that the fracture initiation is earlier than the sample ruptured. That is, the initiation pressure is smaller than the ruptured pressure. The experiments conducted in this paper prove that the LPG fracturing indeed has some advantages than traditional hydraulic fracturing, such as long fracture length and large SRV. And then, the research results provide the theoretical basis for the LPG fracturing operation in shale formation.
{"title":"Investigation on Hydraulic Fracture Initiation and Propagation with LPG Fracturing in Shale Formation based on True Tri-Axial Laboratory Experiments","authors":"Ruxin Zhang, B. Hou, Yijin Zeng, Jian Zhou, Qingyang Li","doi":"10.2118/191107-MS","DOIUrl":"https://doi.org/10.2118/191107-MS","url":null,"abstract":"\u0000 Traditional hydraulic fracturing requires lots of water and sand resulting in short fracture length and small SRV with a low production. However, a new waterless fracturing, called Liquefied Petroleum Gas (LPG) fracturing, is applied to stimulate shale formation effectively.\u0000 In order to figure out the mechanism of fracture initiation and propagation in LPG fracturing, four large-scale true tri-axial fracturing simulation experiments have been conducted on shale outcrops. Meanwhile, the effects of engineering factors, pump rate and fluid viscosity, on fracture propagation behavior in the shale formation are discussed.\u0000 The experimental results indicate that LPG fracturing not only activates discontinuities to form a complex fracture network, but also enhances induced fracture length to form a large SRV. Induced fractures have two initiation points, open-hole section and stress concentration point of wellbore wall, and have three main propagation behaviors, crossing, shear and arrest, dilation and crossing in shale formation. A low viscosity fracturing fluid activates discontinuities resulting in complex fractures, whereas, a high viscosity fluid would like to create some main fractures without opening discontinuities. Moreover, a high pump rate offers more energy for induced fractures to cross the discontinuities resulting in a long fracture length and large SRV. In addition, the anisotropic of shale formation and the existence of discontinuities cause signals attenuation, which increases the arrival time, resulting in location deviation of acoustic emission (AE) events in the AE monitoring. The pressure-time-energy curve, however, shows that the fracture initiation is earlier than the sample ruptured. That is, the initiation pressure is smaller than the ruptured pressure.\u0000 The experiments conducted in this paper prove that the LPG fracturing indeed has some advantages than traditional hydraulic fracturing, such as long fracture length and large SRV. And then, the research results provide the theoretical basis for the LPG fracturing operation in shale formation.","PeriodicalId":133825,"journal":{"name":"Day 3 Wed, August 29, 2018","volume":"240 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123742646","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}
Reawat Wattanasuwankorn, Tuanangkoon Daohmareeyor, Kritsana Kritsanaphak, I. Pathmanathan, Jorge Bohorquez
Approximately 3,762 m of coiled tubing (CT) became stuck downhole in a live, offshore high-pressure well. The CT parted after fatigue limitations were exceeded. This paper discusses a snubbing operation that was conducted to fish the parted CT. To ensure flawless execution the following was employed: Successful job design, operational planning, and execution. A complex engineered solution to improve the fishing operation and clean up debris. Introduction of well control applications (hot tapping) to help minimize risk of pressure becoming trapped in the CT. Multiple successful trials. A unique job design was introduced and executed according to plan. Careful engineering, study, and yard trials supported the actual operation. The crew's technical expertise helped improve safety and enhanced efficiency. Significant underbalance skill and fishing proficiency helped make the fishing operation successful. The operator and service company improved their understanding and operational competence by fully communicating with all parties involved. The operator was able to remove parted CT and perform plug and abandonment (P&A) operations in this live, high-pressure offshore well with no incidents or spills. The successful engineering and testing during this campaign are discussed.
{"title":"Successful Snubbing Application Performed Underbalanced Fishing of Parted Coiled Tubing in Live High-Pressure Well: Offshore Vietnam","authors":"Reawat Wattanasuwankorn, Tuanangkoon Daohmareeyor, Kritsana Kritsanaphak, I. Pathmanathan, Jorge Bohorquez","doi":"10.2118/191013-MS","DOIUrl":"https://doi.org/10.2118/191013-MS","url":null,"abstract":"Approximately 3,762 m of coiled tubing (CT) became stuck downhole in a live, offshore high-pressure well. The CT parted after fatigue limitations were exceeded. This paper discusses a snubbing operation that was conducted to fish the parted CT. To ensure flawless execution the following was employed: Successful job design, operational planning, and execution. A complex engineered solution to improve the fishing operation and clean up debris. Introduction of well control applications (hot tapping) to help minimize risk of pressure becoming trapped in the CT. Multiple successful trials. A unique job design was introduced and executed according to plan. Careful engineering, study, and yard trials supported the actual operation. The crew's technical expertise helped improve safety and enhanced efficiency. Significant underbalance skill and fishing proficiency helped make the fishing operation successful. The operator and service company improved their understanding and operational competence by fully communicating with all parties involved. The operator was able to remove parted CT and perform plug and abandonment (P&A) operations in this live, high-pressure offshore well with no incidents or spills. The successful engineering and testing during this campaign are discussed.","PeriodicalId":133825,"journal":{"name":"Day 3 Wed, August 29, 2018","volume":"13 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134454229","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}
An operator recently launched a "water-shutoff" polymer development project for an onshore injector well in a brownfield operation in Thailand. To effectively improve water flooding performance in this field, shutting off a water thief zone was a prerequisite. Several conservative expanding tubing pads placed in the upper zones restricted access to the lower zone perforations or placement of another tubing pad in the lower zones; therefore, operational planning and strict laboratory testing were performed. This included setting-time testing using an actual chemical blend in batch mode, which closely simulated bottomhole conditions. The process required shutting off the upper zone to facilitate water injection into the lower zone, employing coiled tubing (CT). The design consisted of a shut-off treatment with a lost-circulation material (LCM) to help ensure wellbore fluid placement and shutoff in the high-permeability water thief zone at the designated positions, and to ensure that the pressure response could be monitored from the surface. The shut-off operation was performed as planned, and CT was used for cleanup after placement. Water-production monitoring has shown that the shut-off polymer is one of the best solutions for this field in terms of safety, economics, and operation. As a result of well testing, after the thief zone shut-off treatment, water injectivitywas decreased by approximately 97%, demonstrating the effectiveness of the technique in terms of safety, economics, and operation. A long-term monitoring program was established to evaluate the polymer’s seal-off performance for development of future field strategies. Such an operation could help increase oil recovery by 5 to 10% of oil in place. This technique does not require mechanically sealing off the perforations, making it more feasible for future well interventions and enabling a greater injection rate for chemical EOR where desired.
{"title":"First-Time Implementation of Water Management Technology to Improve Water Flooding Performance in a Multi-Restriction Injector Well: Brownfield Redevelopment, Onshore Thailand","authors":"Prasen Thawatthukool, Wararit Toempromraj, Pipat Lilaprathuang, Chasin Kaewwetchawong, Deephrom Weeramethachai, T. Kiatrabile, Supakorn Krisadasima, Reawat Wattanasuwankorn, Tuanangkoon Daohmareeyor, Arweephan Kangsadarn, Kritsana Kritsanaphak, I. Pathmanathan","doi":"10.2118/190972-MS","DOIUrl":"https://doi.org/10.2118/190972-MS","url":null,"abstract":"\u0000 An operator recently launched a \"water-shutoff\" polymer development project for an onshore injector well in a brownfield operation in Thailand. To effectively improve water flooding performance in this field, shutting off a water thief zone was a prerequisite.\u0000 Several conservative expanding tubing pads placed in the upper zones restricted access to the lower zone perforations or placement of another tubing pad in the lower zones; therefore, operational planning and strict laboratory testing were performed. This included setting-time testing using an actual chemical blend in batch mode, which closely simulated bottomhole conditions. The process required shutting off the upper zone to facilitate water injection into the lower zone, employing coiled tubing (CT). The design consisted of a shut-off treatment with a lost-circulation material (LCM) to help ensure wellbore fluid placement and shutoff in the high-permeability water thief zone at the designated positions, and to ensure that the pressure response could be monitored from the surface.\u0000 The shut-off operation was performed as planned, and CT was used for cleanup after placement. Water-production monitoring has shown that the shut-off polymer is one of the best solutions for this field in terms of safety, economics, and operation. As a result of well testing, after the thief zone shut-off treatment, water injectivitywas decreased by approximately 97%, demonstrating the effectiveness of the technique in terms of safety, economics, and operation. A long-term monitoring program was established to evaluate the polymer’s seal-off performance for development of future field strategies. Such an operation could help increase oil recovery by 5 to 10% of oil in place.\u0000 This technique does not require mechanically sealing off the perforations, making it more feasible for future well interventions and enabling a greater injection rate for chemical EOR where desired.","PeriodicalId":133825,"journal":{"name":"Day 3 Wed, August 29, 2018","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123241661","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}
Abdulrahman Bin Omar, Abdullah A. Al Moajil, Sajjad Aldarweesh, Abdullah Al-Rustum
This paper represents a study of the application of nano-surfactant in the acid stimulation and EOR operations. The performance of the novel surfactant was compared with commercial alcohol ethoxylate surfactants. Different acidizing additives were added to the surfactants under study to evaluate their behavior using surface tension measurements. A negative behavior of the nano-surfactant with corrosion inhibitor, H2S scavenger, and iron control and reducing agents were observed. Regardless of the effect of these additives on the surfactant performance, the nano-surfactant still provides a better performance overall compared to commercial alcohol ethoxylate surfactants. Interfacial tension experiment of the nano-surfactant with condensate samples was performed giving an average IFT of 8 dynes/cm at 160 °F.
{"title":"Evaluation of Novel Surfactant for Acid Stimulation and EOR Treatments","authors":"Abdulrahman Bin Omar, Abdullah A. Al Moajil, Sajjad Aldarweesh, Abdullah Al-Rustum","doi":"10.2118/191115-MS","DOIUrl":"https://doi.org/10.2118/191115-MS","url":null,"abstract":"\u0000 This paper represents a study of the application of nano-surfactant in the acid stimulation and EOR operations. The performance of the novel surfactant was compared with commercial alcohol ethoxylate surfactants. Different acidizing additives were added to the surfactants under study to evaluate their behavior using surface tension measurements. A negative behavior of the nano-surfactant with corrosion inhibitor, H2S scavenger, and iron control and reducing agents were observed. Regardless of the effect of these additives on the surfactant performance, the nano-surfactant still provides a better performance overall compared to commercial alcohol ethoxylate surfactants. Interfacial tension experiment of the nano-surfactant with condensate samples was performed giving an average IFT of 8 dynes/cm at 160 °F.","PeriodicalId":133825,"journal":{"name":"Day 3 Wed, August 29, 2018","volume":"101 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124793418","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}
Wararit Toempromraj, Deephrom Weeramethachai, T. Kiatrabile, Thakerngchai Sangvaree, Apiwat Nadoon, Suwin Sompopsart, R. Duncan, L. Mai-Cao, Richard Havalda, P. Havalda
The Sirikit Field, a mature onshore field operated by PTTEP in northern Thailand, derives production from sandstone reservoirs. While production from many of the shallow pays have been well-developed and optimized, comparatively few of the deeper and tighter sands have been similarly produced. Various methodologies have been trialed to enhance production from these tight sands and an examination of results will be presented in the context of geology, engineering and economics. This field, like most in the world, was produced initially by primary recovery (natural flow and various artificial lift mechanisms). Later in the development phase, secondary recovery (waterflooding) was implemented in the Sirikit Main area with the aim of improving production from the shallower, higher permeability, reservoirs. The deeper, lower permeability, sands have not undergone secondary recovery. It is foreseen that the vast majority of STOIIP can be extracted from these tight sands and will ultimately be the future of Sirikit long term production. Several secondary recovery methods were evaluated. Waterflooding was ruled out as an option due to poor reservoir properties which were not favorable for flooding displacement as well as a high injection pressure requirement. The focus then became well stimulation as the main strategy to enhance production from these tight reservoirs. Initial well stimulation technology was the use of larger size perforation guns for the low porosity sands in order to improve reservoir penetration and overcome damage zones. Analysis after field trials showed that the deep penetration perforations had insignificant production improvement. Consequently, solid-propellant technology, which is capable of creating near wellbore fractures, was field trialed. Two types of solid-propellant were tested: "regressive" burning propellant and "progressive" burning propellant. The "regressive" burning propellant results were inconclusive; however, the "progressive" burning propellant results showed clear improvements in production. Moreover, in order to create deeper fractures, "hydraulic fracturing", which requires higher investment, was tested in parallel to the smaller scale investment perforation guns and solid-propellant; however, the results were no better than the "progressive" burning propellant. Consequently, the "progressive" burning propellant provided the positive results at the best economics. Different well stimulation technologies may be appropriate for varying geologic, engineering and economic conditions. For tight or damaged reservoirs, progressively burning propellant may prove to be the most efficient and cost effective technology for secondary recovery.
{"title":"Effective Secondary Recovery Stimulation Using Solid Propellant Technology for Tight Sand Development in Sirikit Oil Field, Thailand","authors":"Wararit Toempromraj, Deephrom Weeramethachai, T. Kiatrabile, Thakerngchai Sangvaree, Apiwat Nadoon, Suwin Sompopsart, R. Duncan, L. Mai-Cao, Richard Havalda, P. Havalda","doi":"10.2118/191007-ms","DOIUrl":"https://doi.org/10.2118/191007-ms","url":null,"abstract":"\u0000 The Sirikit Field, a mature onshore field operated by PTTEP in northern Thailand, derives production from sandstone reservoirs. While production from many of the shallow pays have been well-developed and optimized, comparatively few of the deeper and tighter sands have been similarly produced. Various methodologies have been trialed to enhance production from these tight sands and an examination of results will be presented in the context of geology, engineering and economics. This field, like most in the world, was produced initially by primary recovery (natural flow and various artificial lift mechanisms). Later in the development phase, secondary recovery (waterflooding) was implemented in the Sirikit Main area with the aim of improving production from the shallower, higher permeability, reservoirs. The deeper, lower permeability, sands have not undergone secondary recovery. It is foreseen that the vast majority of STOIIP can be extracted from these tight sands and will ultimately be the future of Sirikit long term production.\u0000 Several secondary recovery methods were evaluated. Waterflooding was ruled out as an option due to poor reservoir properties which were not favorable for flooding displacement as well as a high injection pressure requirement. The focus then became well stimulation as the main strategy to enhance production from these tight reservoirs. Initial well stimulation technology was the use of larger size perforation guns for the low porosity sands in order to improve reservoir penetration and overcome damage zones. Analysis after field trials showed that the deep penetration perforations had insignificant production improvement. Consequently, solid-propellant technology, which is capable of creating near wellbore fractures, was field trialed. Two types of solid-propellant were tested: \"regressive\" burning propellant and \"progressive\" burning propellant. The \"regressive\" burning propellant results were inconclusive; however, the \"progressive\" burning propellant results showed clear improvements in production. Moreover, in order to create deeper fractures, \"hydraulic fracturing\", which requires higher investment, was tested in parallel to the smaller scale investment perforation guns and solid-propellant; however, the results were no better than the \"progressive\" burning propellant. Consequently, the \"progressive\" burning propellant provided the positive results at the best economics.\u0000 Different well stimulation technologies may be appropriate for varying geologic, engineering and economic conditions. For tight or damaged reservoirs, progressively burning propellant may prove to be the most efficient and cost effective technology for secondary recovery.","PeriodicalId":133825,"journal":{"name":"Day 3 Wed, August 29, 2018","volume":"32 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131770990","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}
Hussain Bahman, F. Ali, Saud M. Al-Haddad, Dalal A Muzaffar
Channel sand reservoirs very rarely have layer cake geometries and are generally characterized by sand bodies/lenses with limited horizontal and vertical continuity. Significant lateral changes occur in reservoir thickness as well as reservoir properties and lenses are often stacked at different stratigraphic levels. The reservoir sands in the greater Burgan field show similar variations both structurally and stratigraphically. Navigating a wellbore in such complex channel sand reservoir requires precision geo-steering technology with two major requirements: Detecting reservoir boundaries with dip information for structural steering. Mapping multiple layers above and below the target layer for stratigraphic positioning. Detecting reservoir boundaries with information on layer dip and anisotropy can immensely help to forward plan trajectory as per formation changes and this require a good knowledge and study about the seismic data and offset wells information. 3D seismic data immensely help in placement of all kinds of wells, especially designing and fine-tuning a meticulous trajectory for Deviated and horizontal wells. Attributes made with seismic cube data, namely Structure and coherency volume, can image major to minor faults, which are generally viewed on slices of major formation tops. There are various other attributes like Impedance, Vp/Vs, Porosity and sand probability map, which can indicate possibility of sweeter part of reservoir. Depth of various major formation tops are predicted quite accurately within the limit of seismic resolution from Velocity model or Depth-Migrated seismic volume. These depth predictions immensely help in designing trajectory and landing the well in the actual desired zone of reservoir at the desired angle. During Geo-steering also, in spite of all the tools of drilling contractor at their disposal, the seismic data help to guide the drillers to steer in the right direction, if drilling team is out of track from the good part of reservoir. Overlaying such a well in the seismic section directly gives the predicted depth throughout the well trajectory, which helps to design the Deviation survey parameters. The paper will explain a special attribute called Ant-trak, which not only shows the major faults, but also very minor faults and sometimes, fine geological features, which cannot be seen in seismic section or slices. This attribute is taken on Burgan-Third sand top surface. All the major NW-SE faults can be seen. Over and above, some minor faults are also seen in it. PSTM seismic data and the other structural attribute which able to show together, faults very clearly. Such a blended surface gives an enhanced display of faults in the area of study including very minor ones, which help to design the survey. By using different Seismic Volume and Surface Attribute analysis, we mark the major faults trend and extracted many structural features in the study area. We try to deal with different attribute paramete
{"title":"Successful Impact of 3D Seismic Attributes in Planning and Drilling Directional Wells in Clastic Reservoir of Greater Burgan Field in Kuwait","authors":"Hussain Bahman, F. Ali, Saud M. Al-Haddad, Dalal A Muzaffar","doi":"10.2118/190988-MS","DOIUrl":"https://doi.org/10.2118/190988-MS","url":null,"abstract":"\u0000 Channel sand reservoirs very rarely have layer cake geometries and are generally characterized by sand bodies/lenses with limited horizontal and vertical continuity. Significant lateral changes occur in reservoir thickness as well as reservoir properties and lenses are often stacked at different stratigraphic levels. The reservoir sands in the greater Burgan field show similar variations both structurally and stratigraphically. Navigating a wellbore in such complex channel sand reservoir requires precision geo-steering technology with two major requirements: Detecting reservoir boundaries with dip information for structural steering. Mapping multiple layers above and below the target layer for stratigraphic positioning. Detecting reservoir boundaries with information on layer dip and anisotropy can immensely help to forward plan trajectory as per formation changes and this require a good knowledge and study about the seismic data and offset wells information.\u0000 3D seismic data immensely help in placement of all kinds of wells, especially designing and fine-tuning a meticulous trajectory for Deviated and horizontal wells. Attributes made with seismic cube data, namely Structure and coherency volume, can image major to minor faults, which are generally viewed on slices of major formation tops. There are various other attributes like Impedance, Vp/Vs, Porosity and sand probability map, which can indicate possibility of sweeter part of reservoir. Depth of various major formation tops are predicted quite accurately within the limit of seismic resolution from Velocity model or Depth-Migrated seismic volume. These depth predictions immensely help in designing trajectory and landing the well in the actual desired zone of reservoir at the desired angle. During Geo-steering also, in spite of all the tools of drilling contractor at their disposal, the seismic data help to guide the drillers to steer in the right direction, if drilling team is out of track from the good part of reservoir.\u0000 Overlaying such a well in the seismic section directly gives the predicted depth throughout the well trajectory, which helps to design the Deviation survey parameters. The paper will explain a special attribute called Ant-trak, which not only shows the major faults, but also very minor faults and sometimes, fine geological features, which cannot be seen in seismic section or slices. This attribute is taken on Burgan-Third sand top surface. All the major NW-SE faults can be seen. Over and above, some minor faults are also seen in it. PSTM seismic data and the other structural attribute which able to show together, faults very clearly. Such a blended surface gives an enhanced display of faults in the area of study including very minor ones, which help to design the survey.\u0000 By using different Seismic Volume and Surface Attribute analysis, we mark the major faults trend and extracted many structural features in the study area. We try to deal with different attribute paramete","PeriodicalId":133825,"journal":{"name":"Day 3 Wed, August 29, 2018","volume":"25 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131648527","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}
C. Ndokwu, Nico Foekema, Victor Okowi, O. Olagundoye, N. Umoren, A. Delpeint, O. Ndefo, A. Agbejule, O. Jeje
Geological and geophysical uncertainties account for most of the challenges encountered during the placement or geosteering of high-angle and horizontal wells in deepwater environments. Structural uncertainties could result from the targeted subsurface structure that is folded, undulating and faulted. Lateral discontinuity of sand bodies, lateral variations in sand thickness, multiple beds, and formation heterogeneities are some of the more common sedimentological uncertainties. Geophysical uncertainties include the vertical depth of the seismic data and seismic reservoir characterization. These uncertainties make increasing the likelihood of success during geosteering not only dependent on the integration of geologic and seismic reservoir characterization techniques, but also on the application of a robust reservoir navigation scheme. In this paper, we present a case study of the geosteering of a horizontal producer well in a complex reservoir in the deep offshore Niger Delta. The reservoir consists of highly faulted channelized turbidites. The lateral discontinuity of sand bodies and the variations in sand thickness have been calibrated by other producer wells in the field. For efficient geosteering, geological and geophysical well planning was complemented by the availability of scenario modeling, a suitable drilling strategy, the availability of fit-for-purpose drilling and formation evaluation tools, robust software, and a multidisciplinary team with the right mix of experience for effective reservoir navigation. An extra-deep reading azimuthal propagation tool was used, and the inversion was performed with Multi-Component While Drilling (MCWD) software that utilized an algorithm to perform real-time processing of any combination of the deep and extra-deep logging-while-drilling (LWD) resistivity measurements, both coaxial and azimuthal [Sviridov et al., 2014]. The case study primarily reviews the geological and geophysical strategies employed during the geosteering, examines the role the extra-deep azimuthal resistivity inversion modeling and borehole imaging played in understanding the nature of the reservoir and checking the effect of formation anisotropy on depth of detection. The study highlights some peculiarities of the depositional environment of the area and shows the benefits of having extra-deep azimuthal propagation resistivity tools in the bottom hole assembly.
{"title":"Geosteering in a Complex Deepwater Reservoir in the Niger Delta","authors":"C. Ndokwu, Nico Foekema, Victor Okowi, O. Olagundoye, N. Umoren, A. Delpeint, O. Ndefo, A. Agbejule, O. Jeje","doi":"10.2118/190993-MS","DOIUrl":"https://doi.org/10.2118/190993-MS","url":null,"abstract":"\u0000 Geological and geophysical uncertainties account for most of the challenges encountered during the placement or geosteering of high-angle and horizontal wells in deepwater environments. Structural uncertainties could result from the targeted subsurface structure that is folded, undulating and faulted. Lateral discontinuity of sand bodies, lateral variations in sand thickness, multiple beds, and formation heterogeneities are some of the more common sedimentological uncertainties. Geophysical uncertainties include the vertical depth of the seismic data and seismic reservoir characterization. These uncertainties make increasing the likelihood of success during geosteering not only dependent on the integration of geologic and seismic reservoir characterization techniques, but also on the application of a robust reservoir navigation scheme.\u0000 In this paper, we present a case study of the geosteering of a horizontal producer well in a complex reservoir in the deep offshore Niger Delta. The reservoir consists of highly faulted channelized turbidites. The lateral discontinuity of sand bodies and the variations in sand thickness have been calibrated by other producer wells in the field. For efficient geosteering, geological and geophysical well planning was complemented by the availability of scenario modeling, a suitable drilling strategy, the availability of fit-for-purpose drilling and formation evaluation tools, robust software, and a multidisciplinary team with the right mix of experience for effective reservoir navigation. An extra-deep reading azimuthal propagation tool was used, and the inversion was performed with Multi-Component While Drilling (MCWD) software that utilized an algorithm to perform real-time processing of any combination of the deep and extra-deep logging-while-drilling (LWD) resistivity measurements, both coaxial and azimuthal [Sviridov et al., 2014].\u0000 The case study primarily reviews the geological and geophysical strategies employed during the geosteering, examines the role the extra-deep azimuthal resistivity inversion modeling and borehole imaging played in understanding the nature of the reservoir and checking the effect of formation anisotropy on depth of detection. The study highlights some peculiarities of the depositional environment of the area and shows the benefits of having extra-deep azimuthal propagation resistivity tools in the bottom hole assembly.","PeriodicalId":133825,"journal":{"name":"Day 3 Wed, August 29, 2018","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122484248","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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