This paper presents an innovative concept to run Electrical Submersible Pumps (ESP) and upper completion utilizing dual derrick drillship rigs in deep water wells. The availability of a second deck to assemble, test and rack long assemblies brings the possibility to conduct a safer, efficient and reliable operation. The experience in Brazil running complex completions and high horsepower ESPs shows how important is to implement initiatives to reduce rig time. The main objective of the new process is to have every completion tool readily available in the drilling deck, requiring minimum time to connect it to the completion string. In the standard process, the tool sits in the pipe deck until completion string reaches its set position and only then the equipment is brought into the rig floor to be serviced and made up to the completion string. The methodology to assemble ESP and completion tools offline in the auxiliary derrick was developed in partnership with the operator, the service company, and the drilling rig contractor. The offline preparation concept was considered as part of the completion design phase analyzing every step of the upper completion run, looking for efficiency improvement and reduced total rig time. The modern automated pipe handling system was used to manipulate the long and heavy assemblies from the auxiliary deck to the racking system and from the racking system to the main deck without any safety concern, and with minimal human intervention. Eight deep-water operations were completed in Brazil using the new concept and the results brought important rig time reduction in the upper completion running time. The tools that were part of the completion included DHSV, permanent downhole gauges, chemical injection valves, 1600 HP ESP system and tubing test valves. The new process allows the team to service equipment without the usual operation rush reducing installation related failure therefore increasing equipment reliability. The methodology presented on this paper contributes to oil industry as a field-proven reference for offshore ESP and completion deployment technique reducing HSE exposure and total well construction cost. This is particularly important for deep and ultra-deepwater projects which are associated with high intervention costs. Dual derrick rigs were designed with focus to improve drilling operations and after the new process development, the modern robotized machinery empowers ESP and completion activities with improved efficiencies.
{"title":"ESP and Completion Deployment using Dual Derrick Drill Ship Rigs","authors":"D. Lemos, J. Marins, R. D. Lima","doi":"10.2118/206309-ms","DOIUrl":"https://doi.org/10.2118/206309-ms","url":null,"abstract":"\u0000 This paper presents an innovative concept to run Electrical Submersible Pumps (ESP) and upper completion utilizing dual derrick drillship rigs in deep water wells. The availability of a second deck to assemble, test and rack long assemblies brings the possibility to conduct a safer, efficient and reliable operation. The experience in Brazil running complex completions and high horsepower ESPs shows how important is to implement initiatives to reduce rig time. The main objective of the new process is to have every completion tool readily available in the drilling deck, requiring minimum time to connect it to the completion string. In the standard process, the tool sits in the pipe deck until completion string reaches its set position and only then the equipment is brought into the rig floor to be serviced and made up to the completion string. The methodology to assemble ESP and completion tools offline in the auxiliary derrick was developed in partnership with the operator, the service company, and the drilling rig contractor.\u0000 The offline preparation concept was considered as part of the completion design phase analyzing every step of the upper completion run, looking for efficiency improvement and reduced total rig time.\u0000 The modern automated pipe handling system was used to manipulate the long and heavy assemblies from the auxiliary deck to the racking system and from the racking system to the main deck without any safety concern, and with minimal human intervention.\u0000 Eight deep-water operations were completed in Brazil using the new concept and the results brought important rig time reduction in the upper completion running time. The tools that were part of the completion included DHSV, permanent downhole gauges, chemical injection valves, 1600 HP ESP system and tubing test valves. The new process allows the team to service equipment without the usual operation rush reducing installation related failure therefore increasing equipment reliability.\u0000 The methodology presented on this paper contributes to oil industry as a field-proven reference for offshore ESP and completion deployment technique reducing HSE exposure and total well construction cost. This is particularly important for deep and ultra-deepwater projects which are associated with high intervention costs. Dual derrick rigs were designed with focus to improve drilling operations and after the new process development, the modern robotized machinery empowers ESP and completion activities with improved efficiencies.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"83 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80647907","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. Machado, Paola Andrea de Sales Bastos, Danny Daniel Socorro Royero, E. Medvedovski
Components and tubulars in down-hole applications for oil and gas production must withstand severe wear (e.g. erosion, abrasion, rod wear) and corrosion environments. These challenges can be addressed through boronizing of steels achieved employing chemical vapour deposition-based process. This process permits protection of the entire working surfaces of production tubulars up to 12m in length, as well as various sizes of complex shaped components. The performance of these tubulars and components have been evaluated in abrasion, erosion, and corrosion conditions simulating the environment and service conditions experienced in down-hole oil and gas production. Harsh service conditions are very common in the oil industry and the combination of abrasion, friction-induced wear, erosion, and corrosion environments can be quite normal in wells producing with the assistance of artificial lift methods. The boronized steel products demonstrated significantly higher performance in terms of material loss when exposed to harsh operating conditions granting a significant extension of the component service life in wear and corrosion environments. As opposed to many coating technologies, the boronizing process provides high integrity finished products without spalling or delamination on the working surface and minimal dimensional changes. Successful application of tubulars and components with the iron boride protective layer in oil and gas production will be discussed and presented.
{"title":"Corrosion and Wear Resistant Boronizing for Tubulars and Components Used Down-Hole","authors":"R. Machado, Paola Andrea de Sales Bastos, Danny Daniel Socorro Royero, E. Medvedovski","doi":"10.2118/206074-ms","DOIUrl":"https://doi.org/10.2118/206074-ms","url":null,"abstract":"\u0000 Components and tubulars in down-hole applications for oil and gas production must withstand severe wear (e.g. erosion, abrasion, rod wear) and corrosion environments. These challenges can be addressed through boronizing of steels achieved employing chemical vapour deposition-based process. This process permits protection of the entire working surfaces of production tubulars up to 12m in length, as well as various sizes of complex shaped components. The performance of these tubulars and components have been evaluated in abrasion, erosion, and corrosion conditions simulating the environment and service conditions experienced in down-hole oil and gas production. Harsh service conditions are very common in the oil industry and the combination of abrasion, friction-induced wear, erosion, and corrosion environments can be quite normal in wells producing with the assistance of artificial lift methods. The boronized steel products demonstrated significantly higher performance in terms of material loss when exposed to harsh operating conditions granting a significant extension of the component service life in wear and corrosion environments. As opposed to many coating technologies, the boronizing process provides high integrity finished products without spalling or delamination on the working surface and minimal dimensional changes. Successful application of tubulars and components with the iron boride protective layer in oil and gas production will be discussed and presented.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81925841","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}
Barzan Ahmed, F. A. Khoshnaw, Mustansar Raza, Hossam A. Elmoneim, Kamil Shehzad, Mustafa Sarbast, Omar El Zanaty, Serwer Yousif
A case study is presented detailing the methodology used to perform the clean-out operation in a water disposal well of Khurmala Field, Kurdistan Region of Iraq. Untreated disposed water caused scaling and plugging in perforated liner and in the open hole that eventually ceased injection. Multiple attempts and investments were made in recent years to resume access to the injection zone using high-pressure hydro-jetting tools coupled with acid treatments. However, these attempts yielded futile efforts. Before proceeding with the decision of workover, it was decided to go for one final attempt to regain wellbore access using Fluidic Oscillator (SFO). Fluidic Oscillator (SFO) having pulsing, cavitation and helix jetting action was used in combination with a train of fluids consisting of diesel, 28% HCl and gel. The clean out was performed in stages of 10m, to clean the fill from 1091m to 1170m. Since the well bore was initially isolated from the injection zone, the cleanout was conducted with non-nitrified fluids. As the cleanout progressed and access to the liner and open hole was regained, the circulation of insoluble fill to surface required a lighter carrying fluid. Nitrification, volume of the fluids, batch cycling, and ROP were designed considering the downhole dynamic changes expected during each stage of the operation. The combination of SFO, the thorough selection of treatment fluids and the accurate downhole hydraulics simulations pertaining to different stages of the operation offered an effective solution and regained the connectivity between the wellbore and the injection zone. The injection rate of water increased from 0 bpm at 700 psi to 15 bpm at 200 psi. Throughout this operation, the SFO helix, cavitation, and acoustic pulse (alike) jetting proved to be more effective than other single acting rotating jetting tools. Also, Environmental impact was reduced by eliminating the need for a rig workover operation. The matching of the injection pressure when the well was first completed and the post job value indicated that the complete zone was exposed and scale deposits were removed from the critical matrix or bypassed. SFO has an effective jetting near wellbore region, while the kinetic energy transferred via fluid makes the impact stronger in the deeper region. Internal mechanism of the tool allows it to handle high pumping rate and pressures, external finishing offer multi-port orientation of outflow that allows targeting the fill in desired directions. Presently the SFO used in the case study is the only technology that has pulse, cavitation, and helix jetting structure. Also, since the tool does not require redressing, it proves to be an efficient, safe and cost effective alternative
{"title":"Adaptation of Technologies Making Clean out Operations Environment Friendly and Cost Effective - Converting Failure into Success Using New Type of Fluidic Oscillator","authors":"Barzan Ahmed, F. A. Khoshnaw, Mustansar Raza, Hossam A. Elmoneim, Kamil Shehzad, Mustafa Sarbast, Omar El Zanaty, Serwer Yousif","doi":"10.2118/206099-ms","DOIUrl":"https://doi.org/10.2118/206099-ms","url":null,"abstract":"\u0000 A case study is presented detailing the methodology used to perform the clean-out operation in a water disposal well of Khurmala Field, Kurdistan Region of Iraq. Untreated disposed water caused scaling and plugging in perforated liner and in the open hole that eventually ceased injection. Multiple attempts and investments were made in recent years to resume access to the injection zone using high-pressure hydro-jetting tools coupled with acid treatments. However, these attempts yielded futile efforts. Before proceeding with the decision of workover, it was decided to go for one final attempt to regain wellbore access using Fluidic Oscillator (SFO).\u0000 Fluidic Oscillator (SFO) having pulsing, cavitation and helix jetting action was used in combination with a train of fluids consisting of diesel, 28% HCl and gel. The clean out was performed in stages of 10m, to clean the fill from 1091m to 1170m. Since the well bore was initially isolated from the injection zone, the cleanout was conducted with non-nitrified fluids. As the cleanout progressed and access to the liner and open hole was regained, the circulation of insoluble fill to surface required a lighter carrying fluid. Nitrification, volume of the fluids, batch cycling, and ROP were designed considering the downhole dynamic changes expected during each stage of the operation.\u0000 The combination of SFO, the thorough selection of treatment fluids and the accurate downhole hydraulics simulations pertaining to different stages of the operation offered an effective solution and regained the connectivity between the wellbore and the injection zone. The injection rate of water increased from 0 bpm at 700 psi to 15 bpm at 200 psi. Throughout this operation, the SFO helix, cavitation, and acoustic pulse (alike) jetting proved to be more effective than other single acting rotating jetting tools. Also, Environmental impact was reduced by eliminating the need for a rig workover operation. The matching of the injection pressure when the well was first completed and the post job value indicated that the complete zone was exposed and scale deposits were removed from the critical matrix or bypassed.\u0000 SFO has an effective jetting near wellbore region, while the kinetic energy transferred via fluid makes the impact stronger in the deeper region. Internal mechanism of the tool allows it to handle high pumping rate and pressures, external finishing offer multi-port orientation of outflow that allows targeting the fill in desired directions. Presently the SFO used in the case study is the only technology that has pulse, cavitation, and helix jetting structure. Also, since the tool does not require redressing, it proves to be an efficient, safe and cost effective alternative","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"182 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80360372","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 Shale and Tight, the term "Parent-Child effect" refers to the impact the depleted area and corresponding stress changes originated by the production of a previously drilled well, the "parent", has over the generated hydraulic fracture geometry, conforming initial drainage area and consequent production performance of a new neighbor well, called "child". Such effect might be considered analogous to the no flow boundary created when the drainage areas of two wells meet at a certain distance from them in conventional reservoirs; but, unconventional developments exhibit higher exposure to a more impactful version of this phenomena, given their characteristic tighter well spacing and the effect pressure depletion of the nearby area by the neighbor well has over the child well's hydraulic fracture development. Due to the importance the Parent-Child effect has for unconventional developments, this study aims first to generally characterize this effect and then quantify its expected specific project impact based on real field data from the Vaca Muerta formation. To do so, we developed a methodology where fracture and reservoir simulation were applied for calibrating a base model using field observed data such as microseismic, tracers, daily production data and well head pressure measurements. The calibrated model was then coupled with a geomechanical reservoir simulator and used to predict pressure and stress tensor profiles across different depletion times. On these different resulting scenarios, child wells were hydraulically fractured with varying well spacing and completion designs. Finally, the Expected Ultimate Recovery (EUR) impact versus well spacing and the parent´s production time were built for different child´s completion design alternatives, analyzed and contrasted against previously field observed data. Results obtained from the characterization work suggests the parent child effect is generated by a combination of initial drainage area changes and stress magnitude and direction changes, which are both dependent of the pressure depletion from the parent well. Furthermore, the results show how the well spacing and parent's production timing, as well as parent's and child's completion design, significantly affect the magnitude of the expected parent child effect impact over the child's EUR.
{"title":"Closing the Gap in Characterizing the Parent Child Effect for Unconventional Reservoirs - A Case of Study in Vaca Muerta Shale Formation","authors":"A. Lerza, Sergio Cuervo, Sahil Malhotra","doi":"10.2118/206001-ms","DOIUrl":"https://doi.org/10.2118/206001-ms","url":null,"abstract":"\u0000 In Shale and Tight, the term \"Parent-Child effect\" refers to the impact the depleted area and corresponding stress changes originated by the production of a previously drilled well, the \"parent\", has over the generated hydraulic fracture geometry, conforming initial drainage area and consequent production performance of a new neighbor well, called \"child\". Such effect might be considered analogous to the no flow boundary created when the drainage areas of two wells meet at a certain distance from them in conventional reservoirs; but, unconventional developments exhibit higher exposure to a more impactful version of this phenomena, given their characteristic tighter well spacing and the effect pressure depletion of the nearby area by the neighbor well has over the child well's hydraulic fracture development.\u0000 Due to the importance the Parent-Child effect has for unconventional developments, this study aims first to generally characterize this effect and then quantify its expected specific project impact based on real field data from the Vaca Muerta formation.\u0000 To do so, we developed a methodology where fracture and reservoir simulation were applied for calibrating a base model using field observed data such as microseismic, tracers, daily production data and well head pressure measurements. The calibrated model was then coupled with a geomechanical reservoir simulator and used to predict pressure and stress tensor profiles across different depletion times. On these different resulting scenarios, child wells were hydraulically fractured with varying well spacing and completion designs. Finally, the Expected Ultimate Recovery (EUR) impact versus well spacing and the parent´s production time were built for different child´s completion design alternatives, analyzed and contrasted against previously field observed data.\u0000 Results obtained from the characterization work suggests the parent child effect is generated by a combination of initial drainage area changes and stress magnitude and direction changes, which are both dependent of the pressure depletion from the parent well. Furthermore, the results show how the well spacing and parent's production timing, as well as parent's and child's completion design, significantly affect the magnitude of the expected parent child effect impact over the child's EUR.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"79 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76033503","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}
Nadir Husein, Vishwajit Upadhye, Igor Novikov, A. Drobot, V. Bolshakov, A. Buyanov, Vladimir Alekseevich Doronin
This paper deals with the case of using the production surveillance inflow tracer-based method in one of multi-lateral wells located in West Siberia. Tracer systems were placed in the well during the well construction by horizontal side tracking, and multi-stage hydraulic fracturing (MSHF) was performed, with the parent borehole remaining in operation. This technology allows developing the reservoir drainage area with a lateral hole and bringing the oil reserves remaining in the parent borehole into production, which results in an increased well productivity and improved oil recovery rate. Tracer systems are placed into the parent borehole within a downhole sub installed into the well completion. Polymer-coated proppant pack was injected during multi-stage hydraulic fracturing to deliver the tracers to the side track lateral. Dynamic production profiling was done to aid into more efficient development of complex and heterogeneous reservoirs and improve of the productive reservoir sweep ratio during the construction of multilateral wells, which enabled us to address several key problems: Providing tools for waterflood diagnostics in multilateral wells and finding an easy water shut- off method for a certain interval Assessing the efficiency of multi-stage hydraulic fracturing and elaborating the optimal treatment design Selecting the optimal mode of the multilateral well operation to prevent premature flooding in one or more laterals Evaluating whether well construction was performed efficiently, and a higher production was achieved by side tracking. Currently, the proposed first-of-its-kind solution enables the operator to obtain a set of data that can help not only significantly improve the wells productivity and increase the oil recovery rate, but also lead to a considerable economic savings in capital expenditure.
{"title":"Experience of Using Continuous Production Surveillance Techniques in Multilateral Wells","authors":"Nadir Husein, Vishwajit Upadhye, Igor Novikov, A. Drobot, V. Bolshakov, A. Buyanov, Vladimir Alekseevich Doronin","doi":"10.2118/205908-ms","DOIUrl":"https://doi.org/10.2118/205908-ms","url":null,"abstract":"\u0000 This paper deals with the case of using the production surveillance inflow tracer-based method in one of multi-lateral wells located in West Siberia.\u0000 Tracer systems were placed in the well during the well construction by horizontal side tracking, and multi-stage hydraulic fracturing (MSHF) was performed, with the parent borehole remaining in operation. This technology allows developing the reservoir drainage area with a lateral hole and bringing the oil reserves remaining in the parent borehole into production, which results in an increased well productivity and improved oil recovery rate.\u0000 Tracer systems are placed into the parent borehole within a downhole sub installed into the well completion. Polymer-coated proppant pack was injected during multi-stage hydraulic fracturing to deliver the tracers to the side track lateral.\u0000 Dynamic production profiling was done to aid into more efficient development of complex and heterogeneous reservoirs and improve of the productive reservoir sweep ratio during the construction of multilateral wells, which enabled us to address several key problems:\u0000 Providing tools for waterflood diagnostics in multilateral wells and finding an easy water shut- off method for a certain interval Assessing the efficiency of multi-stage hydraulic fracturing and elaborating the optimal treatment design Selecting the optimal mode of the multilateral well operation to prevent premature flooding in one or more laterals Evaluating whether well construction was performed efficiently, and a higher production was achieved by side tracking.\u0000 Currently, the proposed first-of-its-kind solution enables the operator to obtain a set of data that can help not only significantly improve the wells productivity and increase the oil recovery rate, but also lead to a considerable economic savings in capital expenditure.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77586006","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 fly-in-fly-out personnel on the oil platform are exposed to extreme climatic and geographic and production factors, and also remain in group isolation conditions, which makes demands on the body of the fly-in-fly-out worker that often exceed its reserves. This excludes the possibility of full psychological adaptation to these conditions and causes the emergence of specialist's unfavorable functional states, which lead to a decrease in the mental health level, productivity and professional performance. The worker's labor tasks of various professions differ in physical and physiological stress, as well as in the degree of harmful production factors action. The goal is to identify the psychological adaptability of the offshore ice-resistant oil and gas production platform fly-in-fly-out employees in the Caspian Sea. The study was conducted on the offshore ice-resistant platform in the Caspian Sea (April 2019), 50 employees took part in it (fly-in duration - 14 days fly-out period – 14 days). Research methods are questionnaire, psychological and psychophysiological testing. By psychological adaptation we understand a personality traits system necessary for the productive performance of our leading activities. Due to the fact that fly-in-fly-out oil and gas workers are affected by climate, production and socio-psychological factors, we will study psychological adaptability through subjective criteria: indicators of regulatory processes, subjective control, socio-psychological adaptation, as well as personal characteristics, and objective criteria: functional state level (working capacity, job stress and other). The psychological adaptability peculiarities were revealed among employees with an optimal and reduced level of functional reserves and working capacity. The oil and gas production platform employees are distinguished by a high level of self-regulation, which is expressed in the ability to form a self-regulation style that allows them to compensate for the personal influence, characterological characteristics that impede the goal achievement. Among the regulatory processes, a high expression level is observed in planning and modeling. The employees have a need for conscious planning of activities, the plans in this case are realistic, detailed, hierarchical, effective and stable, the goals of the activity are put forward independently. They are able to identify significant conditions for achieving goals both in the current situation and in the long-term future, which is manifested in the adequacy of the action programs to the action plans, the results correspondence obtained to the adopted goals. Programming, evaluation of results, independence and flexibility are developed among employees at an average level. The workers are characterized by an average subjective control level. They believe that most of the important events in their life are the result of their own actions, that they can control them, and feel their own responsibility f
{"title":"Psychological Adaptation Peculiarities of the Offshore Ice-Resistant Oil and Gas Production Platform Workers in the Caspian Sea","authors":"Y. Korneeva, N. Simonova","doi":"10.2118/205956-ms","DOIUrl":"https://doi.org/10.2118/205956-ms","url":null,"abstract":"\u0000 The fly-in-fly-out personnel on the oil platform are exposed to extreme climatic and geographic and production factors, and also remain in group isolation conditions, which makes demands on the body of the fly-in-fly-out worker that often exceed its reserves. This excludes the possibility of full psychological adaptation to these conditions and causes the emergence of specialist's unfavorable functional states, which lead to a decrease in the mental health level, productivity and professional performance. The worker's labor tasks of various professions differ in physical and physiological stress, as well as in the degree of harmful production factors action. The goal is to identify the psychological adaptability of the offshore ice-resistant oil and gas production platform fly-in-fly-out employees in the Caspian Sea. The study was conducted on the offshore ice-resistant platform in the Caspian Sea (April 2019), 50 employees took part in it (fly-in duration - 14 days fly-out period – 14 days). Research methods are questionnaire, psychological and psychophysiological testing. By psychological adaptation we understand a personality traits system necessary for the productive performance of our leading activities. Due to the fact that fly-in-fly-out oil and gas workers are affected by climate, production and socio-psychological factors, we will study psychological adaptability through subjective criteria: indicators of regulatory processes, subjective control, socio-psychological adaptation, as well as personal characteristics, and objective criteria: functional state level (working capacity, job stress and other). The psychological adaptability peculiarities were revealed among employees with an optimal and reduced level of functional reserves and working capacity. The oil and gas production platform employees are distinguished by a high level of self-regulation, which is expressed in the ability to form a self-regulation style that allows them to compensate for the personal influence, characterological characteristics that impede the goal achievement. Among the regulatory processes, a high expression level is observed in planning and modeling. The employees have a need for conscious planning of activities, the plans in this case are realistic, detailed, hierarchical, effective and stable, the goals of the activity are put forward independently. They are able to identify significant conditions for achieving goals both in the current situation and in the long-term future, which is manifested in the adequacy of the action programs to the action plans, the results correspondence obtained to the adopted goals. Programming, evaluation of results, independence and flexibility are developed among employees at an average level. The workers are characterized by an average subjective control level. They believe that most of the important events in their life are the result of their own actions, that they can control them, and feel their own responsibility f","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79221380","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}
Yu. D. Maksimov, M. Khasanov, Aleksander Blyablyas, S. Vershinin, E. Ognev, R. Starostenko
Gazprom Neft Science and Technology Center tailors various system engineering methods and other practices to the agenda of oil and gas industry. Resulting consistent approaches will produce a sort of work book enabling management of complex projects throughout the Upstream perimeter. Value-Driven Engineering is a strategic approach to system engineering that optimizes several disciplines within a single model. For example, complex project components are broken down into simpler elements, making it easier to find responsible action officers. Planning is broken down into phases that make it easier to meet the assigned deadlines. It allows you to fragmentize the end product at the design and management phase with a view to edit the product's configuration during the work. Essentially, the VDE approach best resembles a step-by-step guide to putting together a construction made up of multiple elements: without this guide, building the elements into one piece is a much harder job. System engineering is being successfully employed by NASA and aircraft industry today. The approach helps bring together numerous correlated technologies in spacecraft and aircraft building. In the oil industry, BP and Shell are the pioneers in using VDE. Seeking to tailor the system engineering approaches to the applied problems of Gazprom Neft, the Company engineers deliver work in several stages. Stage one is a look back study of projects that covers all the aspects of oil production, from seismic survey to field operation. To build the optimal concept, a project team studies special literature and existing practices in related sectors, essentially among foreign counterparts. The Company has already analyzed the existing research breakthroughs, best practices and digital tools. Even though VDE will chiefly focus on the development of new reservoirs, its individual practices may be successfully utilized at existing assets. Oil and gas production system is growing more complex every day because of the number of control elements and uncertainties that the oil and gas Company has to face at the early stages of planning a future asset. Development of each product, from concept to final implementation, involves a number of lifecycle stages; the sequence of these stages and the necessary toolkit for each stage is identified by the area of expertise known as system engineering. System engineering works perfectly if a certain product or system has existing equivalents, but engineers today may have to handle their tasks in absence of equivalent solutions, which necessitates engagement of creative competences. Development of such competences and inventive problem solving are in the focus of the area of expertise known as creative problem solving that relies on the TRIZ methods (TRIZ = theory of inventive problem solving). Technology intelligence is the area of expertise that focuses on aggregation of experience and employment of solutions from related industries or even from fu
{"title":"A Revolutionary Approach to Meeting Technological Challenges","authors":"Yu. D. Maksimov, M. Khasanov, Aleksander Blyablyas, S. Vershinin, E. Ognev, R. Starostenko","doi":"10.2118/206210-ms","DOIUrl":"https://doi.org/10.2118/206210-ms","url":null,"abstract":"\u0000 Gazprom Neft Science and Technology Center tailors various system engineering methods and other practices to the agenda of oil and gas industry. Resulting consistent approaches will produce a sort of work book enabling management of complex projects throughout the Upstream perimeter.\u0000 Value-Driven Engineering is a strategic approach to system engineering that optimizes several disciplines within a single model. For example, complex project components are broken down into simpler elements, making it easier to find responsible action officers. Planning is broken down into phases that make it easier to meet the assigned deadlines. It allows you to fragmentize the end product at the design and management phase with a view to edit the product's configuration during the work. Essentially, the VDE approach best resembles a step-by-step guide to putting together a construction made up of multiple elements: without this guide, building the elements into one piece is a much harder job.\u0000 System engineering is being successfully employed by NASA and aircraft industry today. The approach helps bring together numerous correlated technologies in spacecraft and aircraft building. In the oil industry, BP and Shell are the pioneers in using VDE. Seeking to tailor the system engineering approaches to the applied problems of Gazprom Neft, the Company engineers deliver work in several stages. Stage one is a look back study of projects that covers all the aspects of oil production, from seismic survey to field operation. To build the optimal concept, a project team studies special literature and existing practices in related sectors, essentially among foreign counterparts. The Company has already analyzed the existing research breakthroughs, best practices and digital tools.\u0000 Even though VDE will chiefly focus on the development of new reservoirs, its individual practices may be successfully utilized at existing assets.\u0000 Oil and gas production system is growing more complex every day because of the number of control elements and uncertainties that the oil and gas Company has to face at the early stages of planning a future asset. Development of each product, from concept to final implementation, involves a number of lifecycle stages; the sequence of these stages and the necessary toolkit for each stage is identified by the area of expertise known as system engineering. System engineering works perfectly if a certain product or system has existing equivalents, but engineers today may have to handle their tasks in absence of equivalent solutions, which necessitates engagement of creative competences. Development of such competences and inventive problem solving are in the focus of the area of expertise known as creative problem solving that relies on the TRIZ methods (TRIZ = theory of inventive problem solving). Technology intelligence is the area of expertise that focuses on aggregation of experience and employment of solutions from related industries or even from fu","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75663894","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}
Hamad Al-Rashidi, M. Hussein, Abdulaziz Erhamah, Satinder Malik, A. Al-Hajri, Dwane Almeida, N. Salehi, G. Omonte, A. Zaitoun
Large reserves of High-Viscous Oil in Kuwait calls for Improved Oil Recovery scenarios. In Kuwait unconsolidated sandstone formations, the sandstone intervals represent extensive reservoir intervals of sand separated by laterally extensive non-reservoir intervals that comprise finer-grained, argillaceous sands, silts and muds. The reservoir is shallow with high permeability (above 1000 mD) and under bottom aquifer pressure support. Due to strong viscosity contrast between oil and water, after breakthrough, the water cut rises quickly resulting in strong loss of production efficiency. Mitigating water production is thus mandatory to improve production conditions. The candidate wells have 2 to 3 open intervals in different rock facies with comingle production. The total perforated length is between 38 and 48 ft. Production is through PCP at a rate of around 300 bpd and BS&W is between 71 and 87%. The technology applied utilizes pre-gelled size-controlled product (SMG Microgels) having RPM properties, i.e. inducing a strong drop of relative permeability to water without affecting oil relative permeability. The size is chosen to selectively treat the high-permeability water producing zones while preserving the lower-permeability oil zones. The chemical can also withstand downhole harsh conditions such as salinity of around 170,000ppm and presence of 2% H2S. The treatment consisted of bullhead injection of 300 bbls of pre-gelled chemical through tubing. The first results seem very favourable, sincefor two wells, the water cut has dropped from 80 to 40% with almost same gross production rate. The incremental oil is more than 100 bopd. The third well did not show marked change after WSO treatment. The wells are under continuous monitoring to assess long-term performance. Such result, if confirmed, may lead to high possibilities for the improvement of heavy-oil reservoir production under aquifer support by mitigating water production with simple chemical bullhead injection.
{"title":"Mitigating Water Production from High Viscosity Oil Wells in Unconsolidated Sandstone Formations","authors":"Hamad Al-Rashidi, M. Hussein, Abdulaziz Erhamah, Satinder Malik, A. Al-Hajri, Dwane Almeida, N. Salehi, G. Omonte, A. Zaitoun","doi":"10.2118/206333-ms","DOIUrl":"https://doi.org/10.2118/206333-ms","url":null,"abstract":"\u0000 Large reserves of High-Viscous Oil in Kuwait calls for Improved Oil Recovery scenarios. In Kuwait unconsolidated sandstone formations, the sandstone intervals represent extensive reservoir intervals of sand separated by laterally extensive non-reservoir intervals that comprise finer-grained, argillaceous sands, silts and muds. The reservoir is shallow with high permeability (above 1000 mD) and under bottom aquifer pressure support. Due to strong viscosity contrast between oil and water, after breakthrough, the water cut rises quickly resulting in strong loss of production efficiency. Mitigating water production is thus mandatory to improve production conditions.\u0000 The candidate wells have 2 to 3 open intervals in different rock facies with comingle production. The total perforated length is between 38 and 48 ft. Production is through PCP at a rate of around 300 bpd and BS&W is between 71 and 87%.\u0000 The technology applied utilizes pre-gelled size-controlled product (SMG Microgels) having RPM properties, i.e. inducing a strong drop of relative permeability to water without affecting oil relative permeability. The size is chosen to selectively treat the high-permeability water producing zones while preserving the lower-permeability oil zones. The chemical can also withstand downhole harsh conditions such as salinity of around 170,000ppm and presence of 2% H2S.\u0000 The treatment consisted of bullhead injection of 300 bbls of pre-gelled chemical through tubing. The first results seem very favourable, sincefor two wells, the water cut has dropped from 80 to 40% with almost same gross production rate. The incremental oil is more than 100 bopd. The third well did not show marked change after WSO treatment. The wells are under continuous monitoring to assess long-term performance.\u0000 Such result, if confirmed, may lead to high possibilities for the improvement of heavy-oil reservoir production under aquifer support by mitigating water production with simple chemical bullhead injection.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88823848","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}
Bruno D. Roussennac, G. V. van Essen, B.-R. de Zwart, Claus von Winterfeld, E. Hernandez, Rob Harris, N. Al Sultan, B. Al Otaibi, A. Kidd, G. Kostin
Infill drilling is a proved strategy to improve hydrocarbon recovery from reservoirs to increase production and maximize field value. Infill drilling projects address the following questions: 1) Where should the wells be drilled? 2) What should be their optimum trajectories? 3) What are the realistic ranges of incremental production of the infill wells? Answering these questions is important yet challenging as it requires the evaluation of multiple scenarios which is laborious and time intensive. This study presents an integrated workflow that allows the optimization of drilling locations using an automated approach that comprises cutting-edge optimization algorithms coupled to reservoir simulation. This workflow concurrently evaluates multiple scenarios until they are narrowed down to an optimum range according to pre-set objectives and honoring pre-established well design constraints. The simultaneous nature of the workflow makes it possible to differentiate between acceleration and real incremental recovery linked to proposed locations. In addition, the technology enables the optimization of all the elements that are relevant to the selection of drilling candidates, such as location, trajectory, inclination, and perforation interval. The well location optimization workflow was applied to a real carbonate large field; heavily faulted; with a well count of +400 active wells and subject to waterflooding. Hence the need for an automated way of finding new optimal drilling locations enabling testing of many locations. Also due to the significant full field model size; sector modelling capability was used such that the optimization, i.e. running many scenarios; could be carried out across smaller scale models within a reasonable time frame. Using powerful hardware and a fully parallelized simulation engine were also important elements in allowing the efficient evaluation of ranges of possible solutions while getting deeper insights into the field and wells responses. As a result of the study, 8 out of the original 9 well locations were moved to more optimal locations. The proposed optimized locations generate an incremental oil recovery increase of more than 70% compared to the original location (pre-optimization). In addition, the project was completed within 2 weeks of equivalent computational time which is a significant acceleration compared to a manual approach of running optimization on a full field model and it is significantly more straight forward than the conventional location selection process. The novelty of the project is introduced by customized python scripts. These scripts allow to achieve practical ways for placing the well locations to explore the solution space and at the same time, honor well design constraints, such as maximum well length, maximum step-out from the surface well-pad, and well perforation interval. Such in-built flexibility combined with automation and highly advanced optimization algorithms helped to achieve
{"title":"Streamlining the Well Location Optimization Process - An Automated Approach Applied to a Large Onshore Carbonate Field","authors":"Bruno D. Roussennac, G. V. van Essen, B.-R. de Zwart, Claus von Winterfeld, E. Hernandez, Rob Harris, N. Al Sultan, B. Al Otaibi, A. Kidd, G. Kostin","doi":"10.2118/205913-ms","DOIUrl":"https://doi.org/10.2118/205913-ms","url":null,"abstract":"\u0000 Infill drilling is a proved strategy to improve hydrocarbon recovery from reservoirs to increase production and maximize field value. Infill drilling projects address the following questions: 1) Where should the wells be drilled? 2) What should be their optimum trajectories? 3) What are the realistic ranges of incremental production of the infill wells? Answering these questions is important yet challenging as it requires the evaluation of multiple scenarios which is laborious and time intensive.\u0000 This study presents an integrated workflow that allows the optimization of drilling locations using an automated approach that comprises cutting-edge optimization algorithms coupled to reservoir simulation. This workflow concurrently evaluates multiple scenarios until they are narrowed down to an optimum range according to pre-set objectives and honoring pre-established well design constraints. The simultaneous nature of the workflow makes it possible to differentiate between acceleration and real incremental recovery linked to proposed locations. In addition, the technology enables the optimization of all the elements that are relevant to the selection of drilling candidates, such as location, trajectory, inclination, and perforation interval.\u0000 The well location optimization workflow was applied to a real carbonate large field; heavily faulted; with a well count of +400 active wells and subject to waterflooding. Hence the need for an automated way of finding new optimal drilling locations enabling testing of many locations. Also due to the significant full field model size; sector modelling capability was used such that the optimization, i.e. running many scenarios; could be carried out across smaller scale models within a reasonable time frame. Using powerful hardware and a fully parallelized simulation engine were also important elements in allowing the efficient evaluation of ranges of possible solutions while getting deeper insights into the field and wells responses. As a result of the study, 8 out of the original 9 well locations were moved to more optimal locations. The proposed optimized locations generate an incremental oil recovery increase of more than 70% compared to the original location (pre-optimization). In addition, the project was completed within 2 weeks of equivalent computational time which is a significant acceleration compared to a manual approach of running optimization on a full field model and it is significantly more straight forward than the conventional location selection process.\u0000 The novelty of the project is introduced by customized python scripts. These scripts allow to achieve practical ways for placing the well locations to explore the solution space and at the same time, honor well design constraints, such as maximum well length, maximum step-out from the surface well-pad, and well perforation interval. Such in-built flexibility combined with automation and highly advanced optimization algorithms helped to achieve ","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"294 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77025648","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}
Maged Alaa Taha, Eissa Shokier, A. Attia, A. Yahia, K. Mansour
In retrograde gas condensate reservoirs, condensate blockage is a major reservoir damage problem, where liquid is dropped-out of natural gas, below dew-point pressure. Despite that most of this liquid will not produce due to not reaching the critical saturation, natural gas will be blocked by the accumulated liquid and will also not produce. This work investigates the effects of gas injection (such as methane, carbon-dioxide, and nitrogen) and steam at high temperatures on one of the Egyptian retrograde gas condensate reservoirs. Several gas injection scenarios that comprise different combination of gas injection temperature, enthalpy, injection gas types (CO2, N2, and CH4), and injection-rates were carried out. The results indicated that all conventional and thermal gas injection scenarios do not increase the cumulative gas production more than the depletion case. The non-thermal gas injection scenarios increased the cumulative condensate production by 8.6%. However, thermal CO2 injection increased the condensate production cumulative by 28.9%. It was observed that thermal gas injection does not vaporize condensate It was observed that thermal gas injection does not vaporize condensate more than conventional injection that have the same reservoir pressure trend. However, thermal injection mainly improves the condensate mobility. Appropriately, thermal injection in retrograde reservoirs, is mostly applicable for depleted reservoirs when the largest amount of non-producible liquid is already dropped out. Finally, this research studied executing thermal gas injection in retrograde gas condensate reservoirs, operationally, by considering the following items: carbon dioxide recovery unit, compressors, storage-tanks, anti-corrosion pipe-lines and tubing-strings, and corrosion-inhibitors along with downhole gas heaters.
{"title":"Enhancing Hydrocarbon Production Through Thermal Gas Injection from a Retrograde as Condensate Reservoir in the Western Desert in Egypt","authors":"Maged Alaa Taha, Eissa Shokier, A. Attia, A. Yahia, K. Mansour","doi":"10.2118/206190-ms","DOIUrl":"https://doi.org/10.2118/206190-ms","url":null,"abstract":"\u0000 In retrograde gas condensate reservoirs, condensate blockage is a major reservoir damage problem, where liquid is dropped-out of natural gas, below dew-point pressure. Despite that most of this liquid will not produce due to not reaching the critical saturation, natural gas will be blocked by the accumulated liquid and will also not produce.\u0000 This work investigates the effects of gas injection (such as methane, carbon-dioxide, and nitrogen) and steam at high temperatures on one of the Egyptian retrograde gas condensate reservoirs. Several gas injection scenarios that comprise different combination of gas injection temperature, enthalpy, injection gas types (CO2, N2, and CH4), and injection-rates were carried out.\u0000 The results indicated that all conventional and thermal gas injection scenarios do not increase the cumulative gas production more than the depletion case. The non-thermal gas injection scenarios increased the cumulative condensate production by 8.6%. However, thermal CO2 injection increased the condensate production cumulative by 28.9%.\u0000 It was observed that thermal gas injection does not vaporize condensate It was observed that thermal gas injection does not vaporize condensate more than conventional injection that have the same reservoir pressure trend. However, thermal injection mainly improves the condensate mobility. Appropriately, thermal injection in retrograde reservoirs, is mostly applicable for depleted reservoirs when the largest amount of non-producible liquid is already dropped out. Finally, this research studied executing thermal gas injection in retrograde gas condensate reservoirs, operationally, by considering the following items: carbon dioxide recovery unit, compressors, storage-tanks, anti-corrosion pipe-lines and tubing-strings, and corrosion-inhibitors along with downhole gas heaters.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"131 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85360203","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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