Due to the high number of wells required, drilling costs are a significant factor for coal seam gas developments. In order to improve drilling performance (and reduce associated costs) current performance should be analysed to identify areas with potential for improvement. This study makes use of a framework based on the best composite time (BCT) to assess the performance of wells drilled in Queensland, Australia in an example period in 2014-15. Data recorded by Pason electronic drilling recorders at 970 wells was made available, along with end-of-day reports for 370 of these wells. Scripts written in the Python programming language were implemented to break the 8½ in. drilling stage down into depth sections and automatically generate a best composite time model for each field in the study. Individual well data was compared to this benchmark allowing the drilling performance to be compared to other wells in the same field, and identified removable time was classified as either invisible lost time (ILT) or non-productive time (NPT). In total over 4500 hours, or approximately 49.5% of the total 8½ in. drilling time, was identified as removable time across 828 wells when compared to field specific BCTs. Causes of ILT and NPT were identified by analysing both numerical data and textual data in daily reports. There is a clear separation in key drilling parametes between the best and worst performing wells. ILT while on bottom correlated with lower recorded RPM, while ILT connecting was associated with extensive reaming and down-hole-cleaning prior to connections, and these are identified as areas which may benefit from data driven optimisation.
{"title":"Lost Time Analysis of Queensland Coal Seam Gas Drilling Data and Where Next for Improvement?","authors":"I. Rodger, A. Garnett","doi":"10.2118/192034-MS","DOIUrl":"https://doi.org/10.2118/192034-MS","url":null,"abstract":"\u0000 Due to the high number of wells required, drilling costs are a significant factor for coal seam gas developments. In order to improve drilling performance (and reduce associated costs) current performance should be analysed to identify areas with potential for improvement. This study makes use of a framework based on the best composite time (BCT) to assess the performance of wells drilled in Queensland, Australia in an example period in 2014-15.\u0000 Data recorded by Pason electronic drilling recorders at 970 wells was made available, along with end-of-day reports for 370 of these wells. Scripts written in the Python programming language were implemented to break the 8½ in. drilling stage down into depth sections and automatically generate a best composite time model for each field in the study. Individual well data was compared to this benchmark allowing the drilling performance to be compared to other wells in the same field, and identified removable time was classified as either invisible lost time (ILT) or non-productive time (NPT). In total over 4500 hours, or approximately 49.5% of the total 8½ in. drilling time, was identified as removable time across 828 wells when compared to field specific BCTs.\u0000 Causes of ILT and NPT were identified by analysing both numerical data and textual data in daily reports. There is a clear separation in key drilling parametes between the best and worst performing wells. ILT while on bottom correlated with lower recorded RPM, while ILT connecting was associated with extensive reaming and down-hole-cleaning prior to connections, and these are identified as areas which may benefit from data driven optimisation.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"73 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85944249","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The Vostochno-Messoyakhskoe field is the northernmost active continental field in the Russian Federation (Fig. 1). This field is located 250 km from the Arctic Circle, in the arctic climatic zone. Full production drilling only began in 2015 because of the field's geological complexity and lack of transportation structure. Weather conditions, such as strong winds and extremely low temperatures, can be hazardous to personnel and equipment. Additionally, this oil field has permafrost zones (400m from the surface) and low formation temperatures at the production zone. Also, because of permafrost zones, there is a high risk of thawing the wellhead formation. These conditions significantly affect which technologies can be applied during drilling and completion of the wells. Therefore, special cement designs are necessary to help reduce risks associated with low temperatures and permafrost zones in the Vostochno-Messoyakhskoe field. Production is further complicated by a gas layer at 720 to 820m true vertical depth (TVD) and high formation pore pressure. This can make the cement operations with the production casings difficult. While the TVD of the casing landing is not relatively deep, the measured depth (MD) in extended reach drilling (ERD) wells is significant (Fig. 2). ERD wells can challenge cement displacement efficiency (Sabins, 1990). Mud removal efficiency may not be enough to create a high-quality cement barrier and isolate formations from gas migration. Poor mud removal can affect future life of the wells and crude oil production. To perform remedial jobs, it is necessary to stop production for several days. Due to experience in performing remedial jobs in the Messoyakhskoe field, it is usually necessary to perform a few attempts of the remedial cementing operation to reach positive results. Therefore, the operator decided to utilize hydraulic packers to create a second barrier between the surface and production casings to help prevent gas migration to the surface, save time associated with remedial operations, and extend the life of future wells.
{"title":"Effect of Low Pumping Rate on Mud Displacement Efficiency and Pumping Pressure During Cementing of Oil Wells","authors":"Mikhail Tcibulskii, M. Akhmetov","doi":"10.2118/192107-MS","DOIUrl":"https://doi.org/10.2118/192107-MS","url":null,"abstract":"\u0000 The Vostochno-Messoyakhskoe field is the northernmost active continental field in the Russian Federation (Fig. 1). This field is located 250 km from the Arctic Circle, in the arctic climatic zone. Full production drilling only began in 2015 because of the field's geological complexity and lack of transportation structure. Weather conditions, such as strong winds and extremely low temperatures, can be hazardous to personnel and equipment. Additionally, this oil field has permafrost zones (400m from the surface) and low formation temperatures at the production zone. Also, because of permafrost zones, there is a high risk of thawing the wellhead formation. These conditions significantly affect which technologies can be applied during drilling and completion of the wells. Therefore, special cement designs are necessary to help reduce risks associated with low temperatures and permafrost zones in the Vostochno-Messoyakhskoe field.\u0000 Production is further complicated by a gas layer at 720 to 820m true vertical depth (TVD) and high formation pore pressure. This can make the cement operations with the production casings difficult. While the TVD of the casing landing is not relatively deep, the measured depth (MD) in extended reach drilling (ERD) wells is significant (Fig. 2). ERD wells can challenge cement displacement efficiency (Sabins, 1990). Mud removal efficiency may not be enough to create a high-quality cement barrier and isolate formations from gas migration. Poor mud removal can affect future life of the wells and crude oil production. To perform remedial jobs, it is necessary to stop production for several days. Due to experience in performing remedial jobs in the Messoyakhskoe field, it is usually necessary to perform a few attempts of the remedial cementing operation to reach positive results. Therefore, the operator decided to utilize hydraulic packers to create a second barrier between the surface and production casings to help prevent gas migration to the surface, save time associated with remedial operations, and extend the life of future wells.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79607735","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}
Current market conditions in the oil industry call for cost effective well intervention methods to optimize production in wells completed with Insertable Progressing Cavity Pumps (I-PCPs). Rigless rod-string conveyance of I-PCP's traditionally rely on Pump Seating Nipples (PSNs) or mechanical-set I-PCP anchoring devices in wells without PSN's. Although the installation of an I-PCP on a PSN is a reliable method, it requires a PSN to be originally installed within the production tubing, which limits the I-PCP setting depth to the location of the PSN. Rod-string conveyance of mechanical-set I- PCP anchoring devices is limited by the rod string's effectiveness to transmit the required axial loads to setting depth, which becomes increasingly challenging in extended-reach conditions. Other challenges with I-PCP installations include location of previously installed PSN's and positive anchoring to facilitate disengagement of the rotor without unseating the I-PCP for flush-by operations. An inflatable packer anchoring device has been developed to simplify rigless installation of an I-PCP without the need of a seating nipple. The device relies only on hydraulic pressure while eliminating the need for axial loads during its setting sequence. The rod string deployed inflatable packer I-PCP anchoring device incorporates inflatable packer technology in conjunction with a hydraulically-actuated slip mechanism. It is equipped with seal cups and a shearable intake sub to obtain the required pressure competence to confirm tubing integrity and enable its setting sequence while maximizing flow-through capability after it is set. The system can be retrieved by applying overpull to shear its release pins allowing the inflatable packers to deflate and the mechanical slips to retract. The first installation of this system proved its optimal functionality by successfully setting an I-PCP in 3-1/2" production tubing in a vertical well in Oman's Sadad field. The I-PCP was deployed on rod string in conjunction with the inflatable packer anchoring device to setting depth. The system was set by applying pressure with a flush-by unit pump via the tubing-rod annulus, and the well was immediately placed into production. The objective of this paper is to provide a technical explanation of this innovative and unique technology, share the lessons learned from its first installation, and discuss its potential to improve the current capabilities of I-PCP technology while reducing operational cost and optimizing PCP/I-PCP completion design.
{"title":"Inflatable Packer Anchor System Enables Rigless Installation of an Insertable Progressing Cavity Pump in South Oman","authors":"Alejandro Osorio, F. Ford, B. Montilla","doi":"10.2118/192043-ms","DOIUrl":"https://doi.org/10.2118/192043-ms","url":null,"abstract":"\u0000 Current market conditions in the oil industry call for cost effective well intervention methods to optimize production in wells completed with Insertable Progressing Cavity Pumps (I-PCPs). Rigless rod-string conveyance of I-PCP's traditionally rely on Pump Seating Nipples (PSNs) or mechanical-set I-PCP anchoring devices in wells without PSN's. Although the installation of an I-PCP on a PSN is a reliable method, it requires a PSN to be originally installed within the production tubing, which limits the I-PCP setting depth to the location of the PSN. Rod-string conveyance of mechanical-set I- PCP anchoring devices is limited by the rod string's effectiveness to transmit the required axial loads to setting depth, which becomes increasingly challenging in extended-reach conditions. Other challenges with I-PCP installations include location of previously installed PSN's and positive anchoring to facilitate disengagement of the rotor without unseating the I-PCP for flush-by operations.\u0000 An inflatable packer anchoring device has been developed to simplify rigless installation of an I-PCP without the need of a seating nipple. The device relies only on hydraulic pressure while eliminating the need for axial loads during its setting sequence. The rod string deployed inflatable packer I-PCP anchoring device incorporates inflatable packer technology in conjunction with a hydraulically-actuated slip mechanism. It is equipped with seal cups and a shearable intake sub to obtain the required pressure competence to confirm tubing integrity and enable its setting sequence while maximizing flow-through capability after it is set. The system can be retrieved by applying overpull to shear its release pins allowing the inflatable packers to deflate and the mechanical slips to retract.\u0000 The first installation of this system proved its optimal functionality by successfully setting an I-PCP in 3-1/2\" production tubing in a vertical well in Oman's Sadad field. The I-PCP was deployed on rod string in conjunction with the inflatable packer anchoring device to setting depth. The system was set by applying pressure with a flush-by unit pump via the tubing-rod annulus, and the well was immediately placed into production.\u0000 The objective of this paper is to provide a technical explanation of this innovative and unique technology, share the lessons learned from its first installation, and discuss its potential to improve the current capabilities of I-PCP technology while reducing operational cost and optimizing PCP/I-PCP completion design.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87233887","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}
A. T. Al-Hameedi, H. Alkinani, S. Dunn-Norman, R. Flori, Steven Hilgedick, A. Amer, M. Alsaba
Lost circulation costs are a significant expense in drilling oil and gas wells. Drilling anywhere in the Rumaila field, one the world's largest oilfields, requires penetrating the Dammam formation, which is notorious for lost circulation issues and thus a great source of information on lost circulation events. This paper presents a new, more precise model to predict lost circulation volumes, ECD and ROP in the Dammam formation. A larger data set, more systematic statistical approach, and a machine learning algorithm have produced statistical models that give a better prediction of the lost circulation volumes, ECD, and ROP than the previous models for events. This paper presents the new model, validates the key elements impacting lost circulation in the Dammam formation, and compares the predicted outcomes to those from the older model. The work previously in the literature provided a platform for predicting the severity of lost circulation incidents in the Dammam formation. Using the new models, the predictions closely track actual field incidents of lost circulation. When new lost circulation events were compared with predictions from the old and new models, the new model presented a much tighter prediction of events. Three equations for optimizing operations were developed from these models focusing on the elements that have the highest degree of impact. The total flow area of the nozzles was determined to be a significant factor in the ROP model indicating that nozzle size should be chosen carefully to achieve optimal ROP. Good modeling of projected lost circulation events can assist in evaluating the effectiveness of new treatments for lost circulation. The Dammam formation is a significant source of lost circulation in a major oilfield and warrants evaluation of the effectiveness of lost circulation treatments. These techniques can be applied to other fields and formations to better understand the economic impact of lost circulation and evaluate the effectiveness of various lost circulation mitigation efforts.
{"title":"Using Machine Learning to Predict Lost Circulation in the Rumaila Field, Iraq","authors":"A. T. Al-Hameedi, H. Alkinani, S. Dunn-Norman, R. Flori, Steven Hilgedick, A. Amer, M. Alsaba","doi":"10.2118/191933-MS","DOIUrl":"https://doi.org/10.2118/191933-MS","url":null,"abstract":"\u0000 Lost circulation costs are a significant expense in drilling oil and gas wells. Drilling anywhere in the Rumaila field, one the world's largest oilfields, requires penetrating the Dammam formation, which is notorious for lost circulation issues and thus a great source of information on lost circulation events.\u0000 This paper presents a new, more precise model to predict lost circulation volumes, ECD and ROP in the Dammam formation. A larger data set, more systematic statistical approach, and a machine learning algorithm have produced statistical models that give a better prediction of the lost circulation volumes, ECD, and ROP than the previous models for events. This paper presents the new model, validates the key elements impacting lost circulation in the Dammam formation, and compares the predicted outcomes to those from the older model.\u0000 The work previously in the literature provided a platform for predicting the severity of lost circulation incidents in the Dammam formation. Using the new models, the predictions closely track actual field incidents of lost circulation. When new lost circulation events were compared with predictions from the old and new models, the new model presented a much tighter prediction of events.\u0000 Three equations for optimizing operations were developed from these models focusing on the elements that have the highest degree of impact. The total flow area of the nozzles was determined to be a significant factor in the ROP model indicating that nozzle size should be chosen carefully to achieve optimal ROP.\u0000 Good modeling of projected lost circulation events can assist in evaluating the effectiveness of new treatments for lost circulation. The Dammam formation is a significant source of lost circulation in a major oilfield and warrants evaluation of the effectiveness of lost circulation treatments. These techniques can be applied to other fields and formations to better understand the economic impact of lost circulation and evaluate the effectiveness of various lost circulation mitigation efforts.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89927520","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}
Roohullah Qalandari, A. Aghajanpour, Seyedalireza Khatibi
The main purposes of employing cement in oil wells are to isolate the zones within formations, secure casing from axial loading and corrosion and improve wellbore integrity. There are plenty of nanomaterials represented in the literature which were introduced to cement in order to advance the strength and rheological properties of cement slurry. The objective of this study is to propose a novel nanomaterial which can upgrade the mechanical and rheological properties of cement. The smaller the size of Nano-particles, the higher surface area and hence higher efficiency they possess to advance particular properties of the support material. Bio-templating has been offered as an approach to reduce the size of utilized nanoparticles. In this study, Nanosilica particles were synthesized and functionalized using modified sol-gel method. Bio-templating was then implemented through crosslinking of the procured Nanosilica with soluble egg protein using glutaraldehyde. In order to investigate the effect of bio-templated Nanosilica on cement slurry, synthesized Nanosilica was added to cement and rheological and mechanical experiments were conducted. To validate the performed bio-templating, ATR-FTIR spectrum was acquired which confirmed successful crosslinking between the functionalized Nanosilica and SEP. Furthermore, experimental tests were conducted to evaluate the effect of bio-templated Nanosilica on mechanical and rheological properties of neat cement. The results were then compared to inclusion of commercial Nanosilica in cement. Through the rheological studies, it was found that the modified Nanosilica has acted as dispersant in cementitious system by decreasing the plastic viscosity of cement and maintaining the density. It was also obtained that novel bio-templated Nanosilica has significantly increased uniaxial compressive strength of cementitious system by 16.59% upon addition of only 0.25 wt.%. It was due to its pozzolanic reaction in cement and its pore filling effect where the porosity of cementitious system was decreased. The proposed synthesized Nanosilica demonstrates superior results than commercial Nanosilica which shows its remarkable efficiency in cement strength reinforcement and rheological properties improvement. The research study has successfully proposed a novel method to utilize biomaterial waste in the process of synthesizing Nanosilica particles which is not only environmental friendly but also yields in phenomenal rheological and mechanical properties of Class G cement.
{"title":"A Novel Nanosilica-Based Solution for Enhancing Mechanical and Rheological Properties of Oil Well Cement","authors":"Roohullah Qalandari, A. Aghajanpour, Seyedalireza Khatibi","doi":"10.2118/192031-MS","DOIUrl":"https://doi.org/10.2118/192031-MS","url":null,"abstract":"\u0000 The main purposes of employing cement in oil wells are to isolate the zones within formations, secure casing from axial loading and corrosion and improve wellbore integrity. There are plenty of nanomaterials represented in the literature which were introduced to cement in order to advance the strength and rheological properties of cement slurry. The objective of this study is to propose a novel nanomaterial which can upgrade the mechanical and rheological properties of cement. The smaller the size of Nano-particles, the higher surface area and hence higher efficiency they possess to advance particular properties of the support material. Bio-templating has been offered as an approach to reduce the size of utilized nanoparticles. In this study, Nanosilica particles were synthesized and functionalized using modified sol-gel method. Bio-templating was then implemented through crosslinking of the procured Nanosilica with soluble egg protein using glutaraldehyde. In order to investigate the effect of bio-templated Nanosilica on cement slurry, synthesized Nanosilica was added to cement and rheological and mechanical experiments were conducted. To validate the performed bio-templating, ATR-FTIR spectrum was acquired which confirmed successful crosslinking between the functionalized Nanosilica and SEP. Furthermore, experimental tests were conducted to evaluate the effect of bio-templated Nanosilica on mechanical and rheological properties of neat cement. The results were then compared to inclusion of commercial Nanosilica in cement. Through the rheological studies, it was found that the modified Nanosilica has acted as dispersant in cementitious system by decreasing the plastic viscosity of cement and maintaining the density. It was also obtained that novel bio-templated Nanosilica has significantly increased uniaxial compressive strength of cementitious system by 16.59% upon addition of only 0.25 wt.%. It was due to its pozzolanic reaction in cement and its pore filling effect where the porosity of cementitious system was decreased. The proposed synthesized Nanosilica demonstrates superior results than commercial Nanosilica which shows its remarkable efficiency in cement strength reinforcement and rheological properties improvement. The research study has successfully proposed a novel method to utilize biomaterial waste in the process of synthesizing Nanosilica particles which is not only environmental friendly but also yields in phenomenal rheological and mechanical properties of Class G cement.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"174 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77944191","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}
Shusheng Guo, Yongde Gao, Ming Chen, Peng Liu, Yanyan Chen, Lei Zhang, Zheyuan Huang
D block in the South China Sea is challenging to drill due to both high temperature and high pressure (HTHP) concerns. Well D2 is a wild-cat exploration well in this HTHP area. The target formation is HTHP and the safe mud window is narrow. To drill safely, it is required to predict target zone depth accurately and monitor pore pressure ahead of bit while drilling. Seismic-While-Drilling (SWD) technology was evaluated and applied for the first time in the D2 well of the South China Sea. In this well, with the checkshot data and seisimic waveforms from SWD, an integrated solution was provided, including updates of the time-depth relationship, depth prediction for the high-pressure problem formations, pore pressure monitoring and updated prediction ahead of the bit. All results were updated in real-time while drilling, helping to optimize the mud weight in a tight mud window scenario and to determine the final target depth of the open hole section and the casing depth. The real-time and memory waveforms were processed and the resultant corridor stack was compared with surface seismic section for marker correlation. The predicted depth of the high pressure zone estimated from the SWD udpates was within 3 meters of the actual depth from drilling data. Pore pressure and fracture gradient were also estimated in real-time with SWD data and the results were found to be consistent with the pore pressure measurement from wireline formation tester, obtained post drilling. By using the real-time target zone depth prediction and abnormal high pore pressure predictions based on SWD data, the D2 well was successfully completed without severe drilling issues. The casing was set to the proper depth which formed a solid foundation for the safe drilling of the next openhole section. This case study is the first application of SWD in the sediments of the South China sea, especially within an HTHP environment. The results clearly show the effecacy of SWD in this specific geological environment.
{"title":"The First Application of Seismic While Drilling Technology in HTHP Offshore Exploration Well of South China Sea","authors":"Shusheng Guo, Yongde Gao, Ming Chen, Peng Liu, Yanyan Chen, Lei Zhang, Zheyuan Huang","doi":"10.2118/192120-MS","DOIUrl":"https://doi.org/10.2118/192120-MS","url":null,"abstract":"\u0000 D block in the South China Sea is challenging to drill due to both high temperature and high pressure (HTHP) concerns. Well D2 is a wild-cat exploration well in this HTHP area. The target formation is HTHP and the safe mud window is narrow. To drill safely, it is required to predict target zone depth accurately and monitor pore pressure ahead of bit while drilling.\u0000 Seismic-While-Drilling (SWD) technology was evaluated and applied for the first time in the D2 well of the South China Sea. In this well, with the checkshot data and seisimic waveforms from SWD, an integrated solution was provided, including updates of the time-depth relationship, depth prediction for the high-pressure problem formations, pore pressure monitoring and updated prediction ahead of the bit. All results were updated in real-time while drilling, helping to optimize the mud weight in a tight mud window scenario and to determine the final target depth of the open hole section and the casing depth.\u0000 The real-time and memory waveforms were processed and the resultant corridor stack was compared with surface seismic section for marker correlation. The predicted depth of the high pressure zone estimated from the SWD udpates was within 3 meters of the actual depth from drilling data.\u0000 Pore pressure and fracture gradient were also estimated in real-time with SWD data and the results were found to be consistent with the pore pressure measurement from wireline formation tester, obtained post drilling. By using the real-time target zone depth prediction and abnormal high pore pressure predictions based on SWD data, the D2 well was successfully completed without severe drilling issues. The casing was set to the proper depth which formed a solid foundation for the safe drilling of the next openhole section.\u0000 This case study is the first application of SWD in the sediments of the South China sea, especially within an HTHP environment. The results clearly show the effecacy of SWD in this specific geological environment.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73082962","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In the search for energy, new technologies bring added benefits. These new technologies are driven by the need to be more environmentally conscious, reduce costs, increase reliability, reach farther and deeper, and provide more and better data to more effectively manage wells and equipment. With these new technologies, the industry is making a steady transition toward electrification and digitalization of the well completion. Electrification of completion equipment has occurred at a steady pace for several years, but the pace has quickened as the reliability of equipment has improved and the benefits of additional data have been realized. Within the last few years, the first completions with all-electric Christmas trees (XT) were run. Because all-electric tubing retrievable downhole safety valves were not yet available, these were not true all-electric completions. These first wells required the XTs to be installed with hydraulically operated downhole safety valves, making these mixed-technology completions. Recently, an all-electric tubing retrievable downhole safety valve was developed, qualified, and field tested. The introduction of the all-electric tubing retrievable downhole safety valve will bring the benefits of an all-electric completion to the oil industry. All-electric tubing retrievable downhole safety valves, also known as electric surface-controlled subsurface safety valves (ESCSSV), build upon field proven technology, but offer the added benefits that an electrically operated tool can provide while performing the same critical function as the traditional hydraulic downhole safety valve. This paper describes the development and deployment of the ESCSSV; it includes discussions about the qualification program of the valve and valve systems, integration with the all-electric subsea XT and control system, and installation in the well.
{"title":"Innovative All-Electric Tubing Retrievable Downhole Safety Valve","authors":"B. Scott, Joseph Chakkungal Joseph, Ian Penman","doi":"10.2118/191913-MS","DOIUrl":"https://doi.org/10.2118/191913-MS","url":null,"abstract":"\u0000 In the search for energy, new technologies bring added benefits. These new technologies are driven by the need to be more environmentally conscious, reduce costs, increase reliability, reach farther and deeper, and provide more and better data to more effectively manage wells and equipment. With these new technologies, the industry is making a steady transition toward electrification and digitalization of the well completion. Electrification of completion equipment has occurred at a steady pace for several years, but the pace has quickened as the reliability of equipment has improved and the benefits of additional data have been realized. Within the last few years, the first completions with all-electric Christmas trees (XT) were run. Because all-electric tubing retrievable downhole safety valves were not yet available, these were not true all-electric completions. These first wells required the XTs to be installed with hydraulically operated downhole safety valves, making these mixed-technology completions. Recently, an all-electric tubing retrievable downhole safety valve was developed, qualified, and field tested. The introduction of the all-electric tubing retrievable downhole safety valve will bring the benefits of an all-electric completion to the oil industry.\u0000 All-electric tubing retrievable downhole safety valves, also known as electric surface-controlled subsurface safety valves (ESCSSV), build upon field proven technology, but offer the added benefits that an electrically operated tool can provide while performing the same critical function as the traditional hydraulic downhole safety valve.\u0000 This paper describes the development and deployment of the ESCSSV; it includes discussions about the qualification program of the valve and valve systems, integration with the all-electric subsea XT and control system, and installation in the well.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75588766","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}
Tiurma Theresa Sibarani, M. Ziauddin, H. Nasr-El-Din, Ahmed S. Zakaria
This study investigates the performance of viscoelastic surfactant (VES)-based HCl stimulation fluids as a function of carbonate rock type and quantifies the response of the acid to different pore-structures. A pore-structure evaluation during stimulation design could lead to a successful field treatment. Coreflood tests were conducted using several types of limestone cores with permeabilities ranging from 2.5 to 155 md. Intergranular pores were dominant in the Indiana limestone and Austin chalk samples investigated, whereas moldic pores were dominant in the Pink desert, Edwards yellow, Winterset, and Edwards white cores. Tracer experiments characterized the pore structure in each carbonate sample, and the tracer fluid was injected at 5 cm3/min and 75°F into the cores with dimensions of 6 in. length and 1.5 in. diameter. The tracer effluent data was used to measure accessible porosity (flowing fraction) for each core sample. After the tracer, the VES acid was injected at rates from 1 to 10 cm3/min and 150°F to determine pore volume to breakthrough (PVbt). The wormhole patterns were analyzed using computed tomography (CT) scan images, and the pattern complexity was examined by fractal dimension analysis. A better pore connectivity showed for Indiana limestone compared to Edwards yellow, Winterset limestone, and Edwards white. The flowing fractions were 1, 0.86, 0.61, and 0.53 for Indiana limestone, Edwards yellow, Winterset limestone, and Edwards white, respectively. The PVbt of Indiana limestone ranged from 0.62 to 0.92. Cores with lower pore connectivity, such as Edwards yellow, had PVbt ranging from 0.52 to 0.81, Winterset limestone from 0.34 to 0.49, and Edwards white from 0.21 to 0.36. These results revealed that higher flowing fractions are required with a higher PVbt. Rocks that have the same dominant pore-structures usually exhibit similar wormhole behavior. Prior to this study, the performance of VES fluids had only been studied on carbonate rocks with well-connected intergranular porosity. The results of this study show that porosity distribution of the rock affects the response to acids.
{"title":"The Impact of Pore Structure on Carbonate Stimulation Treatment Using VES-Based HCl","authors":"Tiurma Theresa Sibarani, M. Ziauddin, H. Nasr-El-Din, Ahmed S. Zakaria","doi":"10.2118/192066-MS","DOIUrl":"https://doi.org/10.2118/192066-MS","url":null,"abstract":"\u0000 This study investigates the performance of viscoelastic surfactant (VES)-based HCl stimulation fluids as a function of carbonate rock type and quantifies the response of the acid to different pore-structures. A pore-structure evaluation during stimulation design could lead to a successful field treatment.\u0000 Coreflood tests were conducted using several types of limestone cores with permeabilities ranging from 2.5 to 155 md. Intergranular pores were dominant in the Indiana limestone and Austin chalk samples investigated, whereas moldic pores were dominant in the Pink desert, Edwards yellow, Winterset, and Edwards white cores. Tracer experiments characterized the pore structure in each carbonate sample, and the tracer fluid was injected at 5 cm3/min and 75°F into the cores with dimensions of 6 in. length and 1.5 in. diameter. The tracer effluent data was used to measure accessible porosity (flowing fraction) for each core sample. After the tracer, the VES acid was injected at rates from 1 to 10 cm3/min and 150°F to determine pore volume to breakthrough (PVbt). The wormhole patterns were analyzed using computed tomography (CT) scan images, and the pattern complexity was examined by fractal dimension analysis.\u0000 A better pore connectivity showed for Indiana limestone compared to Edwards yellow, Winterset limestone, and Edwards white. The flowing fractions were 1, 0.86, 0.61, and 0.53 for Indiana limestone, Edwards yellow, Winterset limestone, and Edwards white, respectively. The PVbt of Indiana limestone ranged from 0.62 to 0.92. Cores with lower pore connectivity, such as Edwards yellow, had PVbt ranging from 0.52 to 0.81, Winterset limestone from 0.34 to 0.49, and Edwards white from 0.21 to 0.36. These results revealed that higher flowing fractions are required with a higher PVbt. Rocks that have the same dominant pore-structures usually exhibit similar wormhole behavior.\u0000 Prior to this study, the performance of VES fluids had only been studied on carbonate rocks with well-connected intergranular porosity. The results of this study show that porosity distribution of the rock affects the response to acids.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90050615","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}
V. Lafitte, M. Panga, Nirupama A Vaidya, Max Nikolaev, P. Enkababian, L. K. Teng, Haiyan Zhao
Water production is a major concern for oil companies because it involves not only a high cost for handling the water on surface, but also issues related to scale and corrosion in tubulars, and an overall decrease of hydrocarbon production. Finding the right solutions for each case is a challenge because there is no one solution that fits all. Chemical treatments for water shutoff are cheaper than mechanical treatments and can offer more targeted and customized design, but they often come with higher operational risks. A new water control system based on a single particulate additive was extensively evaluated under laboratory conditions and then successfully implemented in the field. The fluid is easy to prepare using traditional field mixers and does not need curing after it is pumped into the formation, thus saving time and cost compared to most conventional water shutoff systems. The fluid was evaluated in the laboratory with a wide range of formation permeabilities and injection conditions using the fluid loss apparatus, permeameter, and formation response tester. The viscosity and stability of the fluid in different water salinity and concentrations were also investigated. Overall, it was found that the new fluid system was very efficient in shutting-off formations greater than 50 md up to a few darcies. Those results were consistent with the nature of the plugging mechanism, which relies on physical pore plugging alone. The system could be further tuned depending on the formation permeability. In the presence of oil saturation, the penetration of the particulate system was found limited as compared to a single-phase, water-saturated core.
{"title":"A Particulate Gel Based System for Water Shut-Off Applications","authors":"V. Lafitte, M. Panga, Nirupama A Vaidya, Max Nikolaev, P. Enkababian, L. K. Teng, Haiyan Zhao","doi":"10.2118/191982-MS","DOIUrl":"https://doi.org/10.2118/191982-MS","url":null,"abstract":"\u0000 Water production is a major concern for oil companies because it involves not only a high cost for handling the water on surface, but also issues related to scale and corrosion in tubulars, and an overall decrease of hydrocarbon production. Finding the right solutions for each case is a challenge because there is no one solution that fits all. Chemical treatments for water shutoff are cheaper than mechanical treatments and can offer more targeted and customized design, but they often come with higher operational risks.\u0000 A new water control system based on a single particulate additive was extensively evaluated under laboratory conditions and then successfully implemented in the field. The fluid is easy to prepare using traditional field mixers and does not need curing after it is pumped into the formation, thus saving time and cost compared to most conventional water shutoff systems. The fluid was evaluated in the laboratory with a wide range of formation permeabilities and injection conditions using the fluid loss apparatus, permeameter, and formation response tester. The viscosity and stability of the fluid in different water salinity and concentrations were also investigated.\u0000 Overall, it was found that the new fluid system was very efficient in shutting-off formations greater than 50 md up to a few darcies. Those results were consistent with the nature of the plugging mechanism, which relies on physical pore plugging alone. The system could be further tuned depending on the formation permeability. In the presence of oil saturation, the penetration of the particulate system was found limited as compared to a single-phase, water-saturated core.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"24 23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88699860","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. Viljoen, Vikram Sharma, S. Mazumder, A. Rajora, E. Córdova, Keith Wilson, M. Thompson
Solids production in coal seam gas wells have been a large contributor to down-hole completion failure in the Surat Basin, Australia. Since 2016, solids production has become an important focal point for well quality improvement for the Surat Basin operator and has focused its efforts on trying to a) understand the mechanism of pump failure related to solids, b) quantifying the origin of the solids, c) understanding where they come from geologically and d) developing best practices to optimise well designs and operating practices. This study has focused on improving drilling, completion and post-completion activities to reduce operating costs and maximise gas production. The implementation of formal procedural workflows and management of key performance indicators have formed the fundamentals for managing the delivery of quality wells through metrics such as interburden isolation, and thus reducing the risk of well impairment. Sourcing of additional equipment such as shorter slotted casing joints has increased the material limits for interburden isolation. The development of casing tally software has drastically reduced the risk of manual calculation errors and improved completions accuracy and efficiency. Solid samples have been taken from production water, completion tubing and well sumps. The samples from production water indicate that the average particle size is reduced with a reduction in fluid velocities. This inefficiency to remove the larger particles sizes coincides with a reduction in pump run-life due to settling of these solids in the tubing. An increase in periodic pump shut downs has also resulted in increased pump failure related to solids accumulation. Therefore, the optimisation of pump sizes and tubing designs plays a very important role in effective solids removal and increasing pump run-life. The average mineral composition of the solids samples may suggest that the majority of samples originate from the lower Juandah and upper Taroom formations. Further testing will be required to refine any hypothesis of solid origins and related strategies for more targeted isolation. A higher solids production correlates well with an increase in interburden exposure. The variable trends may indicate that some areas are more prone to solids production due to geological differences. Solids quantities do not demonstrate any noticeable trends over time for vertical wells but do increase over time for deviated wells. In some cases, solids quantities increase at ascending rates; this may suggest that the swellable packers are not creating effective seals and the well is washing away behind the packers and subsequently increasing the surface area of the wellbore. Through the reduction of exposed interburden, the potential risk of well impairment has been significantly reduced. Further work will be required to understand the effective use of swellable packers in deviated wells and possible strategies to overcome their shortcomings. Drilling bot
{"title":"Interburden Isolation & Slotted Liner Placement as Solids Control Measure to Improve Well Performance by Reducing Operating Costs and Maximising Gas Production","authors":"R. Viljoen, Vikram Sharma, S. Mazumder, A. Rajora, E. Córdova, Keith Wilson, M. Thompson","doi":"10.2118/192102-MS","DOIUrl":"https://doi.org/10.2118/192102-MS","url":null,"abstract":"\u0000 Solids production in coal seam gas wells have been a large contributor to down-hole completion failure in the Surat Basin, Australia. Since 2016, solids production has become an important focal point for well quality improvement for the Surat Basin operator and has focused its efforts on trying to a) understand the mechanism of pump failure related to solids, b) quantifying the origin of the solids, c) understanding where they come from geologically and d) developing best practices to optimise well designs and operating practices. This study has focused on improving drilling, completion and post-completion activities to reduce operating costs and maximise gas production. The implementation of formal procedural workflows and management of key performance indicators have formed the fundamentals for managing the delivery of quality wells through metrics such as interburden isolation, and thus reducing the risk of well impairment. Sourcing of additional equipment such as shorter slotted casing joints has increased the material limits for interburden isolation. The development of casing tally software has drastically reduced the risk of manual calculation errors and improved completions accuracy and efficiency. Solid samples have been taken from production water, completion tubing and well sumps. The samples from production water indicate that the average particle size is reduced with a reduction in fluid velocities. This inefficiency to remove the larger particles sizes coincides with a reduction in pump run-life due to settling of these solids in the tubing. An increase in periodic pump shut downs has also resulted in increased pump failure related to solids accumulation. Therefore, the optimisation of pump sizes and tubing designs plays a very important role in effective solids removal and increasing pump run-life. The average mineral composition of the solids samples may suggest that the majority of samples originate from the lower Juandah and upper Taroom formations. Further testing will be required to refine any hypothesis of solid origins and related strategies for more targeted isolation. A higher solids production correlates well with an increase in interburden exposure. The variable trends may indicate that some areas are more prone to solids production due to geological differences. Solids quantities do not demonstrate any noticeable trends over time for vertical wells but do increase over time for deviated wells. In some cases, solids quantities increase at ascending rates; this may suggest that the swellable packers are not creating effective seals and the well is washing away behind the packers and subsequently increasing the surface area of the wellbore. Through the reduction of exposed interburden, the potential risk of well impairment has been significantly reduced. Further work will be required to understand the effective use of swellable packers in deviated wells and possible strategies to overcome their shortcomings. Drilling bot","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"49 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77134871","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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