Xiaoming Ye, Pengfei Wang, Junfei Li, Jianmin Yang, Feifei Miao, Ting Li, Xinlei Shi
The third Member of Dongying Formation reservoir in CFD oilfield is steep slope fan-delta deposits; it was penetrated by 6 wells, each well belongs to different fan body. 143 meters oil reservoir was found in well 1, the lithologic combination are complex pebbly sandstone and sandstone with undeveloped interlayer. The reservoir feature is low porosity and low permeability, large thickness with quick lateral variance, and strong internal heterogeneity, which made reservoir characterization challenging. Firstly, high resolution sequence stratigraphic framework of the third Member of Dongying Formation reservoir was established by using of core, log and seismic data, guided by sequence stratigraphy and sedimentology. Then, microfacies classification scheme was determined by actual data and the depositional model. The spatial distribution regularity of fan delta and its microfacies was researched by seismic sedimentology attribute slice and sedimentary numerical simulation. Combined with rock composition features, physical properties, diagenetic characteristics, etc., reservoir classification evaluation was researched. Lastly, a geological model was established for quantitative prediction of the 3d distribution and physical distribution of each reservoir type. The third Member of Dongying Formation reservoir of well 1 block was divided into Lowstand Systems Tract and Transgressive Systems Tract, subdivided into six subsequence sets and 11 subsequences. Good reservoir was mainly distributed in the upper subsequences of Transgressive Systems Tract. Through fine seismic explanation, the plane distribution of each subsequence was determined. The fan delta was divided into six microfacies, including main channel, sheetflood sand beach, braided channel, overflow sand beach, sheet sand and lacustrine mudstone. Middle-fine sandstone and well sorted pebbly coarse sandstone in braided channel and main channel are good reservoir. Based on seismic sedimentology, different strata slicing schemes were used to extract seismic attributes for spatial distribution prediction of good reservoir. Together with sedimentary numerical simulation, the planar distribution and vertical evolution of fan delta and its microfacies were researched, then fan delta sedimentary model of good reservoir developed and Transgressive Systems Tract was established. Based on the study above, the reservoir was divided into four types with different physical characteristics. Then reservoir distribution and physical property distribution of all types were quantitatively predicted by geological modeling. Lastly, a more accurate geological model was provided for oilfield development plan design. Geological model of CFD oilfield was established by comprehensive application of sequence stratigraphy, seismic sedimentology and sedimentary numerical simulation. The modeling method adequately simulated the reservoir heterogeneity and fluid flow characteristics of complex fan delta reservoir with
{"title":"Reservoir Modeling of Fan Delta with Sparse Wells: A Case from CFD Oilfield in Shijiutuo Uplift, Bohai Bay Basin","authors":"Xiaoming Ye, Pengfei Wang, Junfei Li, Jianmin Yang, Feifei Miao, Ting Li, Xinlei Shi","doi":"10.4043/29417-MS","DOIUrl":"https://doi.org/10.4043/29417-MS","url":null,"abstract":"\u0000 The third Member of Dongying Formation reservoir in CFD oilfield is steep slope fan-delta deposits; it was penetrated by 6 wells, each well belongs to different fan body. 143 meters oil reservoir was found in well 1, the lithologic combination are complex pebbly sandstone and sandstone with undeveloped interlayer. The reservoir feature is low porosity and low permeability, large thickness with quick lateral variance, and strong internal heterogeneity, which made reservoir characterization challenging.\u0000 Firstly, high resolution sequence stratigraphic framework of the third Member of Dongying Formation reservoir was established by using of core, log and seismic data, guided by sequence stratigraphy and sedimentology. Then, microfacies classification scheme was determined by actual data and the depositional model. The spatial distribution regularity of fan delta and its microfacies was researched by seismic sedimentology attribute slice and sedimentary numerical simulation. Combined with rock composition features, physical properties, diagenetic characteristics, etc., reservoir classification evaluation was researched. Lastly, a geological model was established for quantitative prediction of the 3d distribution and physical distribution of each reservoir type.\u0000 The third Member of Dongying Formation reservoir of well 1 block was divided into Lowstand Systems Tract and Transgressive Systems Tract, subdivided into six subsequence sets and 11 subsequences. Good reservoir was mainly distributed in the upper subsequences of Transgressive Systems Tract. Through fine seismic explanation, the plane distribution of each subsequence was determined. The fan delta was divided into six microfacies, including main channel, sheetflood sand beach, braided channel, overflow sand beach, sheet sand and lacustrine mudstone. Middle-fine sandstone and well sorted pebbly coarse sandstone in braided channel and main channel are good reservoir. Based on seismic sedimentology, different strata slicing schemes were used to extract seismic attributes for spatial distribution prediction of good reservoir. Together with sedimentary numerical simulation, the planar distribution and vertical evolution of fan delta and its microfacies were researched, then fan delta sedimentary model of good reservoir developed and Transgressive Systems Tract was established. Based on the study above, the reservoir was divided into four types with different physical characteristics. Then reservoir distribution and physical property distribution of all types were quantitatively predicted by geological modeling. Lastly, a more accurate geological model was provided for oilfield development plan design.\u0000 Geological model of CFD oilfield was established by comprehensive application of sequence stratigraphy, seismic sedimentology and sedimentary numerical simulation. The modeling method adequately simulated the reservoir heterogeneity and fluid flow characteristics of complex fan delta reservoir with ","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84425695","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}
Offshore gas treatment faces constraints for space and weight limits. This paper will present an innovative concept of using only membranesto remove multiple contaminants, reduce weight, space and cost on offshore installations and becoming an enabler for gas monetization. Membrane separation is a cost effective way to remove CO2 from natural gas. The typical offshore membrane treatment package usually consists of a relatively complex pre-treatment step followed by a simple membrane system to remove CO2. The solution using only membranes for gas treatment consists of: a first stage of poly (ether ether ketone) or PEEK membranes, resistant to the main impurities in natural gas, able to remove H2S, heavy hydrocarbons and water, thus essentially replacing the pre-treatment for offshore CO2 removal membrane packages a second stage of poly-imide membranes with high CO2 / CH4 selectivity for CO2 removal The membrane-only solution can be applied for treatment of large volumes of gas for pipeline specification to remove CO2 and other contaminants. Key benefits are simplicity of operation, compactness of footprint, weight reduction and a reduction in or elimination of adsorbent media replacements. Topside weight and cost reduction can increase gas treatment capacity and flexibility and are an enabler for gas monetization. Due to their resistance to impurities PEEK membranes can also be used to treat flared gas for valorization through gas-to-power applications, thus reducing flaring. For gas-to-power applications, the gas will undergo some basic conditioning (such as hydrocarbons dew point, BTU adjustment, H2S removal) by a compact membrane unit to be used for power generation on the offshore platform.
{"title":"Streamlined Natural Gas Treatment by Membranes Only","authors":"Udo Dengel, S. Karode, Yong Ding","doi":"10.4043/29489-MS","DOIUrl":"https://doi.org/10.4043/29489-MS","url":null,"abstract":"\u0000 Offshore gas treatment faces constraints for space and weight limits. This paper will present an innovative concept of using only membranesto remove multiple contaminants, reduce weight, space and cost on offshore installations and becoming an enabler for gas monetization.\u0000 Membrane separation is a cost effective way to remove CO2 from natural gas. The typical offshore membrane treatment package usually consists of a relatively complex pre-treatment step followed by a simple membrane system to remove CO2.\u0000 The solution using only membranes for gas treatment consists of:\u0000 a first stage of poly (ether ether ketone) or PEEK membranes, resistant to the main impurities in natural gas, able to remove H2S, heavy hydrocarbons and water, thus essentially replacing the pre-treatment for offshore CO2 removal membrane packages\u0000 a second stage of poly-imide membranes with high CO2 / CH4 selectivity for CO2 removal\u0000 The membrane-only solution can be applied for treatment of large volumes of gas for pipeline specification to remove CO2 and other contaminants. Key benefits are simplicity of operation, compactness of footprint, weight reduction and a reduction in or elimination of adsorbent media replacements. Topside weight and cost reduction can increase gas treatment capacity and flexibility and are an enabler for gas monetization.\u0000 Due to their resistance to impurities PEEK membranes can also be used to treat flared gas for valorization through gas-to-power applications, thus reducing flaring. For gas-to-power applications, the gas will undergo some basic conditioning (such as hydrocarbons dew point, BTU adjustment, H2S removal) by a compact membrane unit to be used for power generation on the offshore platform.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88091842","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 objective of this paper is to help the various stakeholders involved in offshore wind projects identify and overcome the challenges of financing offshore wind projects. It will present key considerations for debt and equity financing during the development (i.e., early stage), construction, and operational project phases. Additionally, the paper will outline the benefits of adopting a joint go-to-market approach that combines equipment, services, and financing solutions into a single bundled package. Where applicable, the strategies/conclusions outlined in this paper will be validated using real-world case studies, which serve as a benchmark for how projects can be structured to secure high levels of funding. Funding remains a key challenge for offshore wind projects due to the quantum of capital required and often complex contractual structures. This complexity stems from the large number of contracting parties involved, and the resulting "interface risk". With utilities less willing to finance projects on balance sheet (i.e., via equity or corporate-level debt), and increasingly partnering alongside co-investors – such as equipment manufacturers and institutional investors—tailoring projects for the project finance market has become increasingly important. Expert financiers can help bring confidence to lenders by acting as a peer within a bank syndicate. In the case of an original equipment manufacturer (OEM) or solution provider, providing financial support in the form of debt or equity capital to the project highlights how the company has so called "skin in the game", providing the necessary vote of confidence to enable the utilization of newer technologies and consequently reduce capital costs. As many real-world projects have demonstrated, doing so helps to reduce the overall risk profile of the project – ultimately increasing its bankability and improving the likelihood of securing the level of funding required for construction.
{"title":"Overcoming the Challenges of Financing Offshore Wind Projects","authors":"Pedro Azevedo, Steffen Grosse","doi":"10.4043/29366-MS","DOIUrl":"https://doi.org/10.4043/29366-MS","url":null,"abstract":"The objective of this paper is to help the various stakeholders involved in offshore wind projects identify and overcome the challenges of financing offshore wind projects. It will present key considerations for debt and equity financing during the development (i.e., early stage), construction, and operational project phases. Additionally, the paper will outline the benefits of adopting a joint go-to-market approach that combines equipment, services, and financing solutions into a single bundled package. Where applicable, the strategies/conclusions outlined in this paper will be validated using real-world case studies, which serve as a benchmark for how projects can be structured to secure high levels of funding.\u0000 Funding remains a key challenge for offshore wind projects due to the quantum of capital required and often complex contractual structures. This complexity stems from the large number of contracting parties involved, and the resulting \"interface risk\".\u0000 With utilities less willing to finance projects on balance sheet (i.e., via equity or corporate-level debt), and increasingly partnering alongside co-investors – such as equipment manufacturers and institutional investors—tailoring projects for the project finance market has become increasingly important.\u0000 Expert financiers can help bring confidence to lenders by acting as a peer within a bank syndicate. In the case of an original equipment manufacturer (OEM) or solution provider, providing financial support in the form of debt or equity capital to the project highlights how the company has so called \"skin in the game\", providing the necessary vote of confidence to enable the utilization of newer technologies and consequently reduce capital costs. As many real-world projects have demonstrated, doing so helps to reduce the overall risk profile of the project – ultimately increasing its bankability and improving the likelihood of securing the level of funding required for construction.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84200043","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}
Erik Oswald, C. Yeilding, Carlos Portela, Tim Duncan, Liz Schwarze, Christie Golden, Julie Wilson, S. Khurana
The deepwater basins of the Americas have been among the most active and successful with discovered resources to date of over 100 billion boe. Some of the world’s most prolific hydrocarbon basins are located along the Americas margins. Considerable undiscovered potential remains, and prospects can be multi-billion barrels of oil in size. This paper will focus on deepwater hot spots in East Coast Canada, Gulf of Mexico, the Equatorial and Atlantic Margins, and Colombia. This paper will explore the factors that have contributed to building a successful deepwater sector – from access to exploration, from development to production. It highlights some of the common challenges operators face across the region, and best practice by governments and industry in handling these issues for sustainability in a highly cyclical oil and gas business. And, finally, this paper will set the stage for a panel discussion scheduled for 9.30am to 12.00pm, Wednesday, May 8, 2019 at the Offshore Technology Conference (OTC). The panelists are oil company executives representing independents, integrated oil companies and national oil companies along with service providers as follows: Erik Oswald, VP Americas, ExxonMobil ExplorationCindy Yeilding, Senior VP, BP AmericasCarlos Portela, President, Ecopetrol AmericaTim Duncan, CEO, Talos EnergyLiz Schwarze, VP Global Exploration, ChevronChris Golden, Senior VP, EquinorJulie Wilson, Director, Wood MackenzieSandeep Khurana, Senior Manager, Granherne
{"title":"Coming to Americas","authors":"Erik Oswald, C. Yeilding, Carlos Portela, Tim Duncan, Liz Schwarze, Christie Golden, Julie Wilson, S. Khurana","doi":"10.4043/29675-MS","DOIUrl":"https://doi.org/10.4043/29675-MS","url":null,"abstract":"\u0000 The deepwater basins of the Americas have been among the most active and successful with discovered resources to date of over 100 billion boe. Some of the world’s most prolific hydrocarbon basins are located along the Americas margins. Considerable undiscovered potential remains, and prospects can be multi-billion barrels of oil in size. This paper will focus on deepwater hot spots in East Coast Canada, Gulf of Mexico, the Equatorial and Atlantic Margins, and Colombia.\u0000 This paper will explore the factors that have contributed to building a successful deepwater sector – from access to exploration, from development to production. It highlights some of the common challenges operators face across the region, and best practice by governments and industry in handling these issues for sustainability in a highly cyclical oil and gas business.\u0000 And, finally, this paper will set the stage for a panel discussion scheduled for 9.30am to 12.00pm, Wednesday, May 8, 2019 at the Offshore Technology Conference (OTC). The panelists are oil company executives representing independents, integrated oil companies and national oil companies along with service providers as follows: Erik Oswald, VP Americas, ExxonMobil ExplorationCindy Yeilding, Senior VP, BP AmericasCarlos Portela, President, Ecopetrol AmericaTim Duncan, CEO, Talos EnergyLiz Schwarze, VP Global Exploration, ChevronChris Golden, Senior VP, EquinorJulie Wilson, Director, Wood MackenzieSandeep Khurana, Senior Manager, Granherne","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90551034","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 Subsea Oil and Gas industry is quickly moving toward deeper waters, complex, challenging, and dynamic working environments, while requiring the highest level of safety. Tasks that have been historically undertaken by workers in shallow waters are now performed by Remotely Operated underwater Vehicles (ROV) at water depths that humans cannot survive. ROV's are being used for intervention (Work-class ROV's, WROV) and for surveillance on drilling and production systems and pipeline. ROVs inherently have several limitations including requirement of a large operating crew, a need of a dynamically positioned surface vessel, tether management, and high cost mobilization and demobilization. Autonomous Underwater Vehicles (AUV) are now emerging with new capabilities and technologies that could make them more efficient and more cost effective than ROVs. New paradigms in shape, autonomy, sensing and communication and physical capabilities are needed to make AUVs the tool of choice for deepwater industry. An ideation and roadmapping workshop on the Development of AUVs for Subsea Applications was held at Rice Uni-versity that (i) generated a consensus from Oil & Gas operators, service providers, technology developers and providers, academics and policy makers of the anticipated needs and wishes for AUV technology in10 years, (ii) identified gaps between current status and future needs, and (iii) developed a roadmap of specific technical needs, gaps and solutions, and identified how and when those gaps might be closed.
{"title":"An Ideation and Roadmapping Workshop on the Development of AUVs for Oil & Gas Subsea Applications","authors":"F. Ghorbel, S. Kapusta, John Allen","doi":"10.4043/29671-MS","DOIUrl":"https://doi.org/10.4043/29671-MS","url":null,"abstract":"\u0000 The Subsea Oil and Gas industry is quickly moving toward deeper waters, complex, challenging, and dynamic working environments, while requiring the highest level of safety. Tasks that have been historically undertaken by workers in shallow waters are now performed by Remotely Operated underwater Vehicles (ROV) at water depths that humans cannot survive. ROV's are being used for intervention (Work-class ROV's, WROV) and for surveillance on drilling and production systems and pipeline. ROVs inherently have several limitations including requirement of a large operating crew, a need of a dynamically positioned surface vessel, tether management, and high cost mobilization and demobilization. Autonomous Underwater Vehicles (AUV) are now emerging with new capabilities and technologies that could make them more efficient and more cost effective than ROVs. New paradigms in shape, autonomy, sensing and communication and physical capabilities are needed to make AUVs the tool of choice for deepwater industry. An ideation and roadmapping workshop on the Development of AUVs for Subsea Applications was held at Rice Uni-versity that (i) generated a consensus from Oil & Gas operators, service providers, technology developers and providers, academics and policy makers of the anticipated needs and wishes for AUV technology in10 years, (ii) identified gaps between current status and future needs, and (iii) developed a roadmap of specific technical needs, gaps and solutions, and identified how and when those gaps might be closed.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77461393","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}
As per EIA, 40% of the world reserves are sour. This has imposed significant challenges and economic burden to monetize ultra-sour gas fields with H2S levels much higher than 5 mol% in the raw gas. Currently most of the ultra-sour gas fields are monetized by using conventional treating technologies like amine solvent process followed a Claus based process to produce sulfur, Sulfur recovery unit and Tail gas treatment unit, SRU-TGTU. This process is extremely capital and operating cost prohibitive as standalone processes. Also, the overall Sulfur production requires a local demand to address overall sulfur disposal cost. With growing number of fields with higher than 5-36% H2S, ultra-sour fields, it’s difficult for operators to maintain healthy production profits while producing such large quantity of sulfur. With ultra-sour gas production, it has many Health Safety and Environmental (HSE) challenges. A new gas treating technology approach is developed to address ultra-sour fields. The approach is using hybrid process by using state of the art H2S removal membranes to do bulk separation of H2S upstream followed by small amine and Claus plant. This is ideal solution where unique membranes have ability to withstand high H2S environment without altering its performance. These membranes will separate H2S enriched stream which is ideal for reinjection or potentially used for Enhanced Oil Recovery (EOR). The membranes retain maximum hydrocarbons in the high-pressure product gas which very valuable in gas production. Low pressure H2S rich stream is water dry and can be reinjected directly. These membranes will also address CO2 capture along with H2S removal. Using combination of unique membrane technology with smaller amine and Claus plant will reduce the overall CAPEX and OPEX requirement for a given project budget. Membranes are much safer and does not have any emission issues. This will allow plants to be much more HSE safe. Having lower CAPEX and overall lower total cost of ownership (TCO) will allow operators to monetize ultra-sour gas fields and provide better return on investment compared to standalone large sulfur plants.
{"title":"High H2S Gas Field Monetization: A Novel Approach","authors":"A. Jariwala","doi":"10.4043/29370-MS","DOIUrl":"https://doi.org/10.4043/29370-MS","url":null,"abstract":"\u0000 \u0000 \u0000 As per EIA, 40% of the world reserves are sour. This has imposed significant challenges and economic burden to monetize ultra-sour gas fields with H2S levels much higher than 5 mol% in the raw gas. Currently most of the ultra-sour gas fields are monetized by using conventional treating technologies like amine solvent process followed a Claus based process to produce sulfur, Sulfur recovery unit and Tail gas treatment unit, SRU-TGTU. This process is extremely capital and operating cost prohibitive as standalone processes. Also, the overall Sulfur production requires a local demand to address overall sulfur disposal cost. With growing number of fields with higher than 5-36% H2S, ultra-sour fields, it’s difficult for operators to maintain healthy production profits while producing such large quantity of sulfur. With ultra-sour gas production, it has many Health Safety and Environmental (HSE) challenges.\u0000 \u0000 \u0000 \u0000 A new gas treating technology approach is developed to address ultra-sour fields. The approach is using hybrid process by using state of the art H2S removal membranes to do bulk separation of H2S upstream followed by small amine and Claus plant. This is ideal solution where unique membranes have ability to withstand high H2S environment without altering its performance. These membranes will separate H2S enriched stream which is ideal for reinjection or potentially used for Enhanced Oil Recovery (EOR). The membranes retain maximum hydrocarbons in the high-pressure product gas which very valuable in gas production. Low pressure H2S rich stream is water dry and can be reinjected directly. These membranes will also address CO2 capture along with H2S removal.\u0000 \u0000 \u0000 \u0000 Using combination of unique membrane technology with smaller amine and Claus plant will reduce the overall CAPEX and OPEX requirement for a given project budget. Membranes are much safer and does not have any emission issues. This will allow plants to be much more HSE safe. Having lower CAPEX and overall lower total cost of ownership (TCO) will allow operators to monetize ultra-sour gas fields and provide better return on investment compared to standalone large sulfur plants.\u0000","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77256399","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}
There are still few subsea water removal systems, but looking at deeper offshore scenario the conventional topside water removal and treatment configuration is not acceptable, either from the economic or technical point of view. Increasing water cuts penalizes field revenue outcome along its productive life. The paper will demonstrate on several business cases that the best way to reduce these penalties is to get rid of water as soon as possible with subsea solutions. We start discussing the economics of a subsea primary separation station. In this focus, some examples based on hypothetical production curves show the gains in terms of increased total volume of recoverable oil that can be obtained with the approach of using a subsea water removal system, compared to conventional topside produced water management system. Some sensitivity on the influence of the parameter hypothetical values used in the analysis is also presented and they show that this trend is indisputable. It can also be concluded that these advantages increase with increasing water depth. The main conclusion of the paper is that the traditional all topside water management system, although being one business case for a field development, it is not the best configuration and it leads to lower net present value (NPV) for the whole project, since some oil is left behind due to increasing water cuts, and subsea water removal improves NPV of the project. Then it is discussed the question on why, being this the case, not much Operators consider this alternative configuration for production development. On this focus, the paper also discusses the main concerns regarding a subsea processing installation, from the point of view of operation, maintenance and reliability – justifiable concerns that have to be addressed by subsea system suppliers. Finally, it is presented the optimized concept of configuration for subsea water removal, treatment and re-injection system, whose first version was already object of an OTC presentation in 2015 (OTC-25934-MS), and since then it has been further developed and optimized through Joint Industry Projects with Operators. It is shown that this system is conceptually designed in order to increase robustness regarding a wide diversity of field conditions and production issues, requiring low maintenance. This analysis is made comparing SpoolSep concept with the alternative solutions already installed worldwide. No direct discussion on the losses implied by adopting a conservative "all topside approach" for green field development project (or even a revamp for a brown field) is easily found on literature. This paper addresses these losses and highlights the benefits of taking subsea water removal into account when studying a production development project either during green fields development planning or brown fields revamping planning. Of course, these benefits should be balanced against any sound concerns on subsea processing. Subsea Equipment and S
{"title":"Subsea Separation: The Way to Go for Increasing Water Production and NPV Optimization","authors":"Carlos Alberto Capela Moraes, S. Shaiek","doi":"10.4043/29527-MS","DOIUrl":"https://doi.org/10.4043/29527-MS","url":null,"abstract":"\u0000 There are still few subsea water removal systems, but looking at deeper offshore scenario the conventional topside water removal and treatment configuration is not acceptable, either from the economic or technical point of view. Increasing water cuts penalizes field revenue outcome along its productive life. The paper will demonstrate on several business cases that the best way to reduce these penalties is to get rid of water as soon as possible with subsea solutions.\u0000 We start discussing the economics of a subsea primary separation station. In this focus, some examples based on hypothetical production curves show the gains in terms of increased total volume of recoverable oil that can be obtained with the approach of using a subsea water removal system, compared to conventional topside produced water management system. Some sensitivity on the influence of the parameter hypothetical values used in the analysis is also presented and they show that this trend is indisputable. It can also be concluded that these advantages increase with increasing water depth.\u0000 The main conclusion of the paper is that the traditional all topside water management system, although being one business case for a field development, it is not the best configuration and it leads to lower net present value (NPV) for the whole project, since some oil is left behind due to increasing water cuts, and subsea water removal improves NPV of the project. Then it is discussed the question on why, being this the case, not much Operators consider this alternative configuration for production development. On this focus, the paper also discusses the main concerns regarding a subsea processing installation, from the point of view of operation, maintenance and reliability – justifiable concerns that have to be addressed by subsea system suppliers. Finally, it is presented the optimized concept of configuration for subsea water removal, treatment and re-injection system, whose first version was already object of an OTC presentation in 2015 (OTC-25934-MS), and since then it has been further developed and optimized through Joint Industry Projects with Operators. It is shown that this system is conceptually designed in order to increase robustness regarding a wide diversity of field conditions and production issues, requiring low maintenance. This analysis is made comparing SpoolSep concept with the alternative solutions already installed worldwide.\u0000 No direct discussion on the losses implied by adopting a conservative \"all topside approach\" for green field development project (or even a revamp for a brown field) is easily found on literature. This paper addresses these losses and highlights the benefits of taking subsea water removal into account when studying a production development project either during green fields development planning or brown fields revamping planning. Of course, these benefits should be balanced against any sound concerns on subsea processing. Subsea Equipment and S","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90408846","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}
Digitalization involves the use of digital technologies to improve, or create new, business processes that drive operational efficiencies. Moreover, the concept of data democratization allows the fruition of digitalization; the data sources, data processes, and content, to be leveraged and scaled enterprise wide. Visualization and self-service analytics platforms allow all levels of business more autonomous ability to analyze and communicate data driven solutions to decision makers and those responsible for implementation. Driving toward digital transformation, modern digitalization strategies include aspects of data democratization. Data content is shared across the enterprise. Entire organizations have access to the raw data sources and data processes in addition to the produced report or visualization itself. This data democratization is the key to reducing replicated work, removing silos, and developing a social network for leveraging the hard data efforts of one business entity for efficient use in another. Results, observations, and conclusions, as well as solution specifics, will be presented with a series of use cases within the offshore drilling industry. These use cases are: Digitalization of Rig Activity Performance KPIs using data enablement platforms to build the first version of an interactive Performance Dashboard. Democratized results of this exercise allowed user defined performance measures to be developed specific to proposed customer well specs. These performance measures were quickly analyzed and presented in contract tenders. Digitalizing downtime events and maintenance history reports using data enabling visualization and self-service analytics platforms for flexible and efficient analysis identifying Reliability Improvement Initiatives and Maintenance Optimization opportunities in support of a company's Failure Reporting, Analysis, and Corrective Action System processes. Digitalizing the Cost of Quality KPIs for use in Vendor Scorecards using easily filterable reports and automated distribution of daily updates.
{"title":"Digitalization and Data Democratization in Offshore Drilling","authors":"Randy Thomas Yoder","doi":"10.4043/29381-MS","DOIUrl":"https://doi.org/10.4043/29381-MS","url":null,"abstract":"\u0000 Digitalization involves the use of digital technologies to improve, or create new, business processes that drive operational efficiencies. Moreover, the concept of data democratization allows the fruition of digitalization; the data sources, data processes, and content, to be leveraged and scaled enterprise wide.\u0000 Visualization and self-service analytics platforms allow all levels of business more autonomous ability to analyze and communicate data driven solutions to decision makers and those responsible for implementation.\u0000 Driving toward digital transformation, modern digitalization strategies include aspects of data democratization. Data content is shared across the enterprise. Entire organizations have access to the raw data sources and data processes in addition to the produced report or visualization itself. This data democratization is the key to reducing replicated work, removing silos, and developing a social network for leveraging the hard data efforts of one business entity for efficient use in another.\u0000 Results, observations, and conclusions, as well as solution specifics, will be presented with a series of use cases within the offshore drilling industry.\u0000 These use cases are:\u0000 Digitalization of Rig Activity Performance KPIs using data enablement platforms to build the first version of an interactive Performance Dashboard. Democratized results of this exercise allowed user defined performance measures to be developed specific to proposed customer well specs. These performance measures were quickly analyzed and presented in contract tenders. Digitalizing downtime events and maintenance history reports using data enabling visualization and self-service analytics platforms for flexible and efficient analysis identifying Reliability Improvement Initiatives and Maintenance Optimization opportunities in support of a company's Failure Reporting, Analysis, and Corrective Action System processes. Digitalizing the Cost of Quality KPIs for use in Vendor Scorecards using easily filterable reports and automated distribution of daily updates.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81517517","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}
J. Schicks, E. Spangenberg, Ronny Giese, M. Luzi-Helbing, M. Priegnitz, K. Heeschen, B. Strauch, J. Schrötter, J. Kück, Martin Töpfer, J. Klump, J. Thaler, Sven Abendroth
At the GFZ German Research Centre for Geosciences we have developed a safe and efficient method which allows for the decomposition of gas hydrates by the supply of heat inside the reservoir. The heat is generated in situ by a catalytic combustion of methane in a counter-current heat-exchange reactor. The reactor that Rudy Rogers, Professor Emeritus in Chemical Engineering at Mississippi State University, referred to as the "Schicks Combustor" is placed in a borehole in such way that the hot reaction zone is situated in the area of the hydrate layer. The counter-current heat-exchange reactor developed at GFZ generates heat via a flameless catalytic oxidation of methane at a noble metal catalyst. The system is closed i.e. there is no contact of the reactants, catalyst and environment. For safety reasons, methane and air are fed separately through a tube-in-tube arrangement into the mixing chamber. Due to its cooling effect and for safety reasons air instead of pure oxygen is used. From the mixing chamber the gas mixture arrives in defined quantities on the catalyst bed, where methane and oxygen are converted into carbon dioxide and water. The hot product gases release their heat via an aluminum foam to the outer wall of the reactor and then to the environment. Simultaneously, the incoming gases are preheated. The reaction runs stable and autonomous between 673 and 823 K. The counter-current heat-exchange reactor was designed as a lab reactor and a borehole tool. The lab reactor was tested in a reservoir simulator to investigate the heat transfer into gas hydrate bearing sediments. Therefore methane hydrate was generated in the LArge Reservoir Simulator (LARS), an autoclave with a volume of 425 L. In a test with 80% hydrate saturation, the reservoir simulator warmed up within 12 hours after the ignition of the catalyst to such an extent that the temperature of the complete sample was above the dissociation temperature of the previously formed methane hydrate which dissociated completely and methane could therefore be produced. During this test, only 15% of the produced CH4 was consumed to generate the energy needed for the thermal dissociation of the hydrates. The experience with the laboratory reactor served as basis for the design of a borehole tool which is suitable for the application in natural gas hydrate reservoirs. The borehole tool has a total length of 5120 mm, an outer diameter of 90 mm and weighs ca. 100 kg. First results from field tests at the continental deep drilling site KTB in Windischeschenbach, Germany, confirm that the borehole tool reliably produces heat at depth.
{"title":"A Counter-Current Heat-Exchange Reactor for the Thermal Stimulation of Gas Hydrate and Petroleum Reservoirs","authors":"J. Schicks, E. Spangenberg, Ronny Giese, M. Luzi-Helbing, M. Priegnitz, K. Heeschen, B. Strauch, J. Schrötter, J. Kück, Martin Töpfer, J. Klump, J. Thaler, Sven Abendroth","doi":"10.4043/29296-MS","DOIUrl":"https://doi.org/10.4043/29296-MS","url":null,"abstract":"\u0000 At the GFZ German Research Centre for Geosciences we have developed a safe and efficient method which allows for the decomposition of gas hydrates by the supply of heat inside the reservoir. The heat is generated in situ by a catalytic combustion of methane in a counter-current heat-exchange reactor. The reactor that Rudy Rogers, Professor Emeritus in Chemical Engineering at Mississippi State University, referred to as the \"Schicks Combustor\" is placed in a borehole in such way that the hot reaction zone is situated in the area of the hydrate layer.\u0000 The counter-current heat-exchange reactor developed at GFZ generates heat via a flameless catalytic oxidation of methane at a noble metal catalyst. The system is closed i.e. there is no contact of the reactants, catalyst and environment. For safety reasons, methane and air are fed separately through a tube-in-tube arrangement into the mixing chamber. Due to its cooling effect and for safety reasons air instead of pure oxygen is used. From the mixing chamber the gas mixture arrives in defined quantities on the catalyst bed, where methane and oxygen are converted into carbon dioxide and water. The hot product gases release their heat via an aluminum foam to the outer wall of the reactor and then to the environment. Simultaneously, the incoming gases are preheated. The reaction runs stable and autonomous between 673 and 823 K.\u0000 The counter-current heat-exchange reactor was designed as a lab reactor and a borehole tool. The lab reactor was tested in a reservoir simulator to investigate the heat transfer into gas hydrate bearing sediments. Therefore methane hydrate was generated in the LArge Reservoir Simulator (LARS), an autoclave with a volume of 425 L. In a test with 80% hydrate saturation, the reservoir simulator warmed up within 12 hours after the ignition of the catalyst to such an extent that the temperature of the complete sample was above the dissociation temperature of the previously formed methane hydrate which dissociated completely and methane could therefore be produced. During this test, only 15% of the produced CH4 was consumed to generate the energy needed for the thermal dissociation of the hydrates. The experience with the laboratory reactor served as basis for the design of a borehole tool which is suitable for the application in natural gas hydrate reservoirs. The borehole tool has a total length of 5120 mm, an outer diameter of 90 mm and weighs ca. 100 kg. First results from field tests at the continental deep drilling site KTB in Windischeschenbach, Germany, confirm that the borehole tool reliably produces heat at depth.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88403124","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}
John Olav Fløisand, B. Torkildsen, Joakim Almqvist, Hans Fredrik Lindøen-Kjellnes
The world's energy demand is continuously increasing, and natural gas will play a vital role in covering the future need for energy as part of a shift toward a cleaner carbon fuel mix. Offshore reserves constitute a considerable part of the world's recoverable gas. Accordingly, viable development of these reserves is instrumental for future socially responsible energy production and meeting the commitments of the Paris agreement. The competitive marketplace for natural gas is challenging the subsea project economics now more than ever. This is driving the innovation for field enabling subsea technology solutions, targeting reduced capital and operational costs while increasing recovery of reserves compared with conventional offshore extraction. In 2015, the world's first subsea multiphase gas compression system was installed offshore Norway. The system comprises two-off 5-MW machines configurable for serial or parallel compression. This system has now gained considerable and valuable operational experience. One of the most noticeable learnings from the field operation is the way the multiphase compressor has been utilized to unlock abandoned liquid reserves. In addition to the gas produced, a cyclic production of more than 5,000 bbl/d has been documented. Operation of the system has also shown how the subsea compressors regulates the wells’ backpressure and thus constitutes an effective pressure filter toward topside. This allows the operators to be more flexible with well operation without disturbing topside pressures. To effectively produce and improve ultimate recovery in large offshore gas fields, the next-step requirements for volumetric flow capacity and drawdown pressure become substantial for multiphase compressors. Accordingly, this also applies to the required shaft power. State-of-the-art computer modeling and aerodynamic testing has been applied to improve the compressor design and throughput capacity. The differential pressure capability of the multiphase compressor has, up until now, been limited by the ultimate load capability of the axial thrust bearing. A thrust-balancing solution is now being included, and detailed design work is ongoing as part of a larger technology collaboration with major operators. Enhancements of the motor technology to larger outputs is part of this program as well. Combined, these improvements are fundamental for the ongoing qualification of the 8 MW and later 12 MW multiphase compressors while adding flexibility to the associated system design. Shifting focus from compressor to system is a key factor to ensure the life-of-field return on investment. As tieback and power rating increases, minimizing the power system cost and complexity can entail rethinking of the compressor topology. This further justifies this focus shift in terms of field development planning. Ensuring an effective fit and compatibility with the subsea power system key units currently in qualification with world-leading powerhou
{"title":"Bringing Forward the Next-Generation Multiphase Compressor","authors":"John Olav Fløisand, B. Torkildsen, Joakim Almqvist, Hans Fredrik Lindøen-Kjellnes","doi":"10.4043/29391-MS","DOIUrl":"https://doi.org/10.4043/29391-MS","url":null,"abstract":"\u0000 The world's energy demand is continuously increasing, and natural gas will play a vital role in covering the future need for energy as part of a shift toward a cleaner carbon fuel mix. Offshore reserves constitute a considerable part of the world's recoverable gas. Accordingly, viable development of these reserves is instrumental for future socially responsible energy production and meeting the commitments of the Paris agreement.\u0000 The competitive marketplace for natural gas is challenging the subsea project economics now more than ever. This is driving the innovation for field enabling subsea technology solutions, targeting reduced capital and operational costs while increasing recovery of reserves compared with conventional offshore extraction.\u0000 In 2015, the world's first subsea multiphase gas compression system was installed offshore Norway. The system comprises two-off 5-MW machines configurable for serial or parallel compression. This system has now gained considerable and valuable operational experience. One of the most noticeable learnings from the field operation is the way the multiphase compressor has been utilized to unlock abandoned liquid reserves. In addition to the gas produced, a cyclic production of more than 5,000 bbl/d has been documented. Operation of the system has also shown how the subsea compressors regulates the wells’ backpressure and thus constitutes an effective pressure filter toward topside. This allows the operators to be more flexible with well operation without disturbing topside pressures.\u0000 To effectively produce and improve ultimate recovery in large offshore gas fields, the next-step requirements for volumetric flow capacity and drawdown pressure become substantial for multiphase compressors. Accordingly, this also applies to the required shaft power. State-of-the-art computer modeling and aerodynamic testing has been applied to improve the compressor design and throughput capacity. The differential pressure capability of the multiphase compressor has, up until now, been limited by the ultimate load capability of the axial thrust bearing. A thrust-balancing solution is now being included, and detailed design work is ongoing as part of a larger technology collaboration with major operators. Enhancements of the motor technology to larger outputs is part of this program as well. Combined, these improvements are fundamental for the ongoing qualification of the 8 MW and later 12 MW multiphase compressors while adding flexibility to the associated system design.\u0000 Shifting focus from compressor to system is a key factor to ensure the life-of-field return on investment. As tieback and power rating increases, minimizing the power system cost and complexity can entail rethinking of the compressor topology. This further justifies this focus shift in terms of field development planning. Ensuring an effective fit and compatibility with the subsea power system key units currently in qualification with world-leading powerhou","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89075204","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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