Q oilfield is a typical fluvial reservoir, which is located in the middle of Bohai Bay. Lower member of Ming (Nm) formation and upper member of Guantao (Ng) formation of Neogene are the main oil-bearing strata, with buried depth -950m ~ -1430m, and developed fluvial sedimentary sandstone reservoir. The lower member of Minghuazhen formation developed meandering river deposit, and sandbody was mainly composed of complex meandering. Guantao formation developed braided river deposit. Each oil group has a good vertical superposition, which shows high porosity and high permeability (average 3000mD), but the oil viscosity of each oil group is quite different (from 22mPa s~260mPa s).
{"title":"Successfully Increasing Production of a Mature Offshore Heavy Oil Reservoir by Water Flooding Conformance","authors":"Yifan He, Xianbo Luo, Hongfu Shi","doi":"10.4043/29612-MS","DOIUrl":"https://doi.org/10.4043/29612-MS","url":null,"abstract":"\u0000 Q oilfield is a typical fluvial reservoir, which is located in the middle of Bohai Bay. Lower member of Ming (Nm) formation and upper member of Guantao (Ng) formation of Neogene are the main oil-bearing strata, with buried depth -950m ~ -1430m, and developed fluvial sedimentary sandstone reservoir. The lower member of Minghuazhen formation developed meandering river deposit, and sandbody was mainly composed of complex meandering. Guantao formation developed braided river deposit. Each oil group has a good vertical superposition, which shows high porosity and high permeability (average 3000mD), but the oil viscosity of each oil group is quite different (from 22mPa s~260mPa 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":"80521575","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}
Arill Småland Hagland, Ross Cooper, Mike Clarke, Svein Hausberg, Jostein Tvedt, Audun Tovslid
In 2016 the Subsea Integration Alliance (SIA) was awarded the industry's first deepwater integrated subsea engineering, procurement, construction, installation, and commissioning (EPCIC) multiphase boosting system contract. The scope of the contract called for the supply and installation of a subsea multiphase boosting system in the Dalmatian Field in the Gulf of Mexico and represents the world's longest deepwater subsea boosting tieback. Several studies were conducted to look at increased oil recovery (IOR), with subsea boosting yielding the best economic benefits and lowest overall risk profile. The subsea boosting system has now been installed and has significantly improved the operator's ultimate recovery. The Dalmatian Field was developed in deepwater Gulf of Mexico by Murphy and partners and commenced production in April 2014. The field was developed as a subsea tieback in water depths of approximately 6,000 ft, with a record tieback distance of 22 mi to the Petronius Field compliant tower platform in shallower waters of approximately 1,800 ft. The challenge of increased recovery in subsea fields has driven the advancement of subsea processing technologies, especially in the subsea boosting domain. The successful operation of subsea multiphase boosting systems on a global scale, coupled with the significant added value these systems generate, has driven technological advances in terms of higher differential pressures and longer step-outs. The subsea boosting system was installed in October 2018 and significantly improving the operator's ultimate recovery. Working in close collaboration with the operating company, the SIA has demonstrated that this type of project execution, also referred to as a supplier-led-solution (SLS), can be an effective way to accelerate project completion, reduce schedule and installation risk, and improve overall project economics. This project was completed in a very short execution time of less than 23 months from contract award to pump startup. This was achieved using mature technology in combination with a novel integrated contract model. In addition, a front-end engineering design (FEED) study was performed to define the project scope that included integrated asset modeling to fully explore the potential of the system that enabled the project to be sanctioned. The Dalmatian subsea boosting system represents a game changer in the subsea processing domain because it is an important leap forward in the efforts to improve recovery and enable long deepwater tiebacks. For field developments in remote, deep, and hostile locations, this technology represents a key enabler. This paper explains the application of the subsea boosting system in the Dalmatian Field and discusses how the Alliance's SLS approach to project delivery using fit-for-purpose solutions based on existing design ensured a seamless delivery and installation of a deepwater boosting system for the operator.
{"title":"Dalmatian Subsea Boosting: Project Execution and Early Operational Experience from the First High-Boost Multiphase Boosting System Deployed in the Gulf of Mexico","authors":"Arill Småland Hagland, Ross Cooper, Mike Clarke, Svein Hausberg, Jostein Tvedt, Audun Tovslid","doi":"10.4043/29540-MS","DOIUrl":"https://doi.org/10.4043/29540-MS","url":null,"abstract":"\u0000 In 2016 the Subsea Integration Alliance (SIA) was awarded the industry's first deepwater integrated subsea engineering, procurement, construction, installation, and commissioning (EPCIC) multiphase boosting system contract. The scope of the contract called for the supply and installation of a subsea multiphase boosting system in the Dalmatian Field in the Gulf of Mexico and represents the world's longest deepwater subsea boosting tieback. Several studies were conducted to look at increased oil recovery (IOR), with subsea boosting yielding the best economic benefits and lowest overall risk profile. The subsea boosting system has now been installed and has significantly improved the operator's ultimate recovery.\u0000 The Dalmatian Field was developed in deepwater Gulf of Mexico by Murphy and partners and commenced production in April 2014. The field was developed as a subsea tieback in water depths of approximately 6,000 ft, with a record tieback distance of 22 mi to the Petronius Field compliant tower platform in shallower waters of approximately 1,800 ft.\u0000 The challenge of increased recovery in subsea fields has driven the advancement of subsea processing technologies, especially in the subsea boosting domain. The successful operation of subsea multiphase boosting systems on a global scale, coupled with the significant added value these systems generate, has driven technological advances in terms of higher differential pressures and longer step-outs.\u0000 The subsea boosting system was installed in October 2018 and significantly improving the operator's ultimate recovery. Working in close collaboration with the operating company, the SIA has demonstrated that this type of project execution, also referred to as a supplier-led-solution (SLS), can be an effective way to accelerate project completion, reduce schedule and installation risk, and improve overall project economics.\u0000 This project was completed in a very short execution time of less than 23 months from contract award to pump startup. This was achieved using mature technology in combination with a novel integrated contract model. In addition, a front-end engineering design (FEED) study was performed to define the project scope that included integrated asset modeling to fully explore the potential of the system that enabled the project to be sanctioned.\u0000 The Dalmatian subsea boosting system represents a game changer in the subsea processing domain because it is an important leap forward in the efforts to improve recovery and enable long deepwater tiebacks. For field developments in remote, deep, and hostile locations, this technology represents a key enabler.\u0000 This paper explains the application of the subsea boosting system in the Dalmatian Field and discusses how the Alliance's SLS approach to project delivery using fit-for-purpose solutions based on existing design ensured a seamless delivery and installation of a deepwater boosting system for the operator.","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":"90190582","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}
Most drilling operations in deep water are performed in Dynamic Positioning (DP) mode. In harsh environments and shallow water conditions, thruster assisted position mooring configurations are often the preferred choice as the mooring lines provide an extra help to counteract the environmental loads. Drilling operations, both in pure DP or thruster-assisted position mooring modes, are limited by the ability of the vessel to maintain position and heading within the required accuracy. In addition, the motion in heave, roll and pitch must be within predefined limits. These limits vary between the type of operation to be performed. For example, reconnecting the low marine riser package has much stricter motion limitations compared to logging or drilling through riser operations. All these operations need to be carefully planned; and having estimate in advance of the vessel motion and station-keeping performance could be of vital importance, also considering planned maintenance. The aim of this paper is to share experiences in planning DP drilling operations by using cloud-based time-domain simulations performed with a digital twin of a semi-submersible drilling rig. A digital twin is a virtual representation of an asset, used from early design through building and operations, maintained and easily accessible throughout its lifecycle. A digital twin can replicate many aspects of the asset; in the case of planning DP drilling operations, our digital twin includes time-domain models for running simulations and predicting the vessel motion.
{"title":"Digital Twin for Drilling Operations – Towards Cloud-Based Operational Planning","authors":"L. Pivano, D. Nguyen, K. Ludvigsen","doi":"10.4043/29316-MS","DOIUrl":"https://doi.org/10.4043/29316-MS","url":null,"abstract":"\u0000 Most drilling operations in deep water are performed in Dynamic Positioning (DP) mode. In harsh environments and shallow water conditions, thruster assisted position mooring configurations are often the preferred choice as the mooring lines provide an extra help to counteract the environmental loads. Drilling operations, both in pure DP or thruster-assisted position mooring modes, are limited by the ability of the vessel to maintain position and heading within the required accuracy. In addition, the motion in heave, roll and pitch must be within predefined limits. These limits vary between the type of operation to be performed. For example, reconnecting the low marine riser package has much stricter motion limitations compared to logging or drilling through riser operations. All these operations need to be carefully planned; and having estimate in advance of the vessel motion and station-keeping performance could be of vital importance, also considering planned maintenance.\u0000 The aim of this paper is to share experiences in planning DP drilling operations by using cloud-based time-domain simulations performed with a digital twin of a semi-submersible drilling rig. A digital twin is a virtual representation of an asset, used from early design through building and operations, maintained and easily accessible throughout its lifecycle. A digital twin can replicate many aspects of the asset; in the case of planning DP drilling operations, our digital twin includes time-domain models for running simulations and predicting the vessel motion.","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":"74799629","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Gas hydrates are naturally-occurring crystalline inclusion compounds. They comprise compressed molecules of gas (usually methane) that are ‘lodged’ within a solid lattice of water molecules. For this reason, the gas molecules are called ‘guests’ and the water molecules are called ‘hosts’. Gas hydrates form where there are sources of water and methane under favorable thermodynamic conditions of relatively high pressure and low temperature. Objective of the study is to evaluate Petrophysical Properties from drilled well of NGHP expedition 2 for Gas Hydrate. To identify different hydrate formation and estimation of hydrate saturation. The Work flow to estimate Petrophysical properties is guided by the high resistivity, low transit time and low density. It includes evaluation of different overlays and cross plots of wells like picket plot to firm up different parameters. Porosity is measured by density log, water saturation using Archie's equation; gas hydrate saturation using DMR method and its validation for the results obtained from Pressure core. Electrical resistivity and acoustic travel time mainly used to identify potential Gas Hydrate zones with overlay technique from density porosity and acoustic travel time and other density porosity with total NMR porosity, along with resistivity log are used for identifying potential Gas Hydrate zones in this study. Porosity estimated from density log is used for calculation Hydrate saturation. Gas Hydrate saturation is estimated using standard Archie's equation and Density Magnetic Resonance (DMR) method. Wherever NMR log data is good, saturation estimated from both are in good agreement. Log derived Gas Hydrate saturation are compared and validated with Gas Hydrate saturation obtained from pressure cores. Very good Gas Hydrate saturated zones are observed above BSR in 21 wells in the range of 40-90%. Out of these 21 wells, 16 wells are also having Gas Hydrate saturation in the range of 30-50%. Good Gas Hydrate saturation wells are mainly in area B and C in KG deep water Basin. This study will be very useful in preparation of Geological model for estimation of Gas Hydrate reservesaccurately. This study will also help in NGHP-3 for identifying suitable sites to carry out pilot production testing of Gas Hydrates.
{"title":"Petrophysical Evaluation of Gas-Hydrate Formations in National Gas Hydrates Programme Expedition 02 in India","authors":"Sikha Rani Mondal, K. Chopra","doi":"10.4043/29614-MS","DOIUrl":"https://doi.org/10.4043/29614-MS","url":null,"abstract":"\u0000 Gas hydrates are naturally-occurring crystalline inclusion compounds. They comprise compressed molecules of gas (usually methane) that are ‘lodged’ within a solid lattice of water molecules. For this reason, the gas molecules are called ‘guests’ and the water molecules are called ‘hosts’. Gas hydrates form where there are sources of water and methane under favorable thermodynamic conditions of relatively high pressure and low temperature.\u0000 Objective of the study is to evaluate Petrophysical Properties from drilled well of NGHP expedition 2 for Gas Hydrate. To identify different hydrate formation and estimation of hydrate saturation.\u0000 The Work flow to estimate Petrophysical properties is guided by the high resistivity, low transit time and low density. It includes evaluation of different overlays and cross plots of wells like picket plot to firm up different parameters. Porosity is measured by density log, water saturation using Archie's equation; gas hydrate saturation using DMR method and its validation for the results obtained from Pressure core.\u0000 Electrical resistivity and acoustic travel time mainly used to identify potential Gas Hydrate zones with overlay technique from density porosity and acoustic travel time and other density porosity with total NMR porosity, along with resistivity log are used for identifying potential Gas Hydrate zones in this study. Porosity estimated from density log is used for calculation Hydrate saturation. Gas Hydrate saturation is estimated using standard Archie's equation and Density Magnetic Resonance (DMR) method. Wherever NMR log data is good, saturation estimated from both are in good agreement. Log derived Gas Hydrate saturation are compared and validated with Gas Hydrate saturation obtained from pressure cores. Very good Gas Hydrate saturated zones are observed above BSR in 21 wells in the range of 40-90%. Out of these 21 wells, 16 wells are also having Gas Hydrate saturation in the range of 30-50%. Good Gas Hydrate saturation wells are mainly in area B and C in KG deep water Basin. This study will be very useful in preparation of Geological model for estimation of Gas Hydrate reservesaccurately. This study will also help in NGHP-3 for identifying suitable sites to carry out pilot production testing of Gas Hydrates.","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":"90933494","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}
S. Guzman, M. Taboada, Albino Pombo, R. Martín, Ana Bezunartea, Andy Knights-Cooper, J. Moreu
This paper describes the conceptual design and estimates the CAPEX breakdown of a novel floater type for offshore wind turbines: the Reduced-Draft Spar (RDS). This floater, which resembles a GBS although it is in essence a spar, has excellent seakeeping at a reduced draft. Aiming at reducing the CAPEX, the RDS design allows the installation of the wind turbine at the manufacturing site. Furthermore, no auxiliary means are required to provide stability during towing and in-place installation (mooring and electric hook-up, and ballasting to the operational draft). It also promotes the use of structural concrete and cost-effective high-density ballast for its construction. In addition, the whole concept benefits from the implementation of an Active Ballast System (ABS) to compensate the mean tilt angle while operating. An extensive model test campaign was carried out in summer 2018 at INTA-CEHIPAR model basin to validate the concept. The tests scope was focused on calibrating a state-of-the-art numerical hydrodynamic model for further stages of development. An 8MW RDS model, with a scale factor of 1:50 and a 3-line spread mooring system, was tested in Transport and Installation (T&I), operational and survival conditions to assess the concept feasibility. The ABS was simulated using pre-calibrated counteracting weights. Stability during T&I was also checked. In addition, the unit CAPEX was estimated and compared to equivalent semi and spar units made of steel. The RDS can operate at intermediate water depths (60 to 80 m, where spars cannot) and deep waters, and also avoids the use of expensive auxiliary means for T&I. The results from the model tests confirm a dynamic behavior of the RDS similar to that of classic spars, which is beneficial for the offshore WT. Regarding the CAPEX, estimations indicate relevant savings compared to classic spars or semis. Although it is a large massive unit, the use of concrete combined with heavy ballast makes the concept feasible. Due to the ABS, the required platform's size is smaller and the fatigue life of the WT components increases. Furthermore, an adequate ABS control system increases the net energy production since the energy consumption is negligible compared to the extra generated power. The use of civil construction manufacturing technologies such as floating docks and assemble of pre-manufactured parts leads to major CAPEX savings. The US coast has a huge offshore wind energy resource at water depths greater than 60m, where the RDS floating concept has a promising future. The concept could be used as well in the Offshore Oil& Gas.
{"title":"The Reduced-Draft Spar: A Novel Cost-Effective Concept for Floating Offshore Wind Turbines","authors":"S. Guzman, M. Taboada, Albino Pombo, R. Martín, Ana Bezunartea, Andy Knights-Cooper, J. Moreu","doi":"10.4043/29495-MS","DOIUrl":"https://doi.org/10.4043/29495-MS","url":null,"abstract":"\u0000 This paper describes the conceptual design and estimates the CAPEX breakdown of a novel floater type for offshore wind turbines: the Reduced-Draft Spar (RDS). This floater, which resembles a GBS although it is in essence a spar, has excellent seakeeping at a reduced draft.\u0000 Aiming at reducing the CAPEX, the RDS design allows the installation of the wind turbine at the manufacturing site. Furthermore, no auxiliary means are required to provide stability during towing and in-place installation (mooring and electric hook-up, and ballasting to the operational draft). It also promotes the use of structural concrete and cost-effective high-density ballast for its construction. In addition, the whole concept benefits from the implementation of an Active Ballast System (ABS) to compensate the mean tilt angle while operating.\u0000 An extensive model test campaign was carried out in summer 2018 at INTA-CEHIPAR model basin to validate the concept. The tests scope was focused on calibrating a state-of-the-art numerical hydrodynamic model for further stages of development. An 8MW RDS model, with a scale factor of 1:50 and a 3-line spread mooring system, was tested in Transport and Installation (T&I), operational and survival conditions to assess the concept feasibility. The ABS was simulated using pre-calibrated counteracting weights. Stability during T&I was also checked.\u0000 In addition, the unit CAPEX was estimated and compared to equivalent semi and spar units made of steel. The RDS can operate at intermediate water depths (60 to 80 m, where spars cannot) and deep waters, and also avoids the use of expensive auxiliary means for T&I. The results from the model tests confirm a dynamic behavior of the RDS similar to that of classic spars, which is beneficial for the offshore WT. Regarding the CAPEX, estimations indicate relevant savings compared to classic spars or semis.\u0000 Although it is a large massive unit, the use of concrete combined with heavy ballast makes the concept feasible. Due to the ABS, the required platform's size is smaller and the fatigue life of the WT components increases. Furthermore, an adequate ABS control system increases the net energy production since the energy consumption is negligible compared to the extra generated power. The use of civil construction manufacturing technologies such as floating docks and assemble of pre-manufactured parts leads to major CAPEX savings.\u0000 The US coast has a huge offshore wind energy resource at water depths greater than 60m, where the RDS floating concept has a promising future. The concept could be used as well in the Offshore Oil& Gas.","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":"91336241","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. Dimbour, Loic Ferron, Eric Luquiau, Benoît Laflotte
Offshore floating LNG can offer an optimum CAPEX solution either for the development of large or stranded gas fields, including full processing functions, or as an enabler to oil production while monetizating associated gas. The offshore LNG mega-module solution was developed to meet the challenge of producing competitive LNG offshore, leading to the next generation of floating LNG facilities. This paper decribes the offshore LNG mega-module innovative solution of which the features are patent pending. The design features are highlighted, then the specifics of combining topsides with hull are presented, followed by the installation particulars. Finally, perspectives and savings in using this solution are presented.
{"title":"Offshore LNG Mega-Module Solution","authors":"J. Dimbour, Loic Ferron, Eric Luquiau, Benoît Laflotte","doi":"10.4043/29633-MS","DOIUrl":"https://doi.org/10.4043/29633-MS","url":null,"abstract":"\u0000 Offshore floating LNG can offer an optimum CAPEX solution either for the development of large or stranded gas fields, including full processing functions, or as an enabler to oil production while monetizating associated gas.\u0000 The offshore LNG mega-module solution was developed to meet the challenge of producing competitive LNG offshore, leading to the next generation of floating LNG facilities.\u0000 This paper decribes the offshore LNG mega-module innovative solution of which the features are patent pending. The design features are highlighted, then the specifics of combining topsides with hull are presented, followed by the installation particulars. Finally, perspectives and savings in using this solution are presented.","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":"86806528","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}
Hongfu Shi, Wei Zhang, Xiaodong Han, Haochuan Ling, Chaojie Kong
A new regional integrated development pattern is proposed by Bohai Oilfield Bureau, based on the existing development and production system and engineering facilities, and combined with the distribution characteristics of underground oil and gas resources in Bohai oilfields, and according to the principles of ‘overall planning, unified layout, stage promotion and subarea implementation'. Through the integration and rational allocation of exploration and development, reservoir and engineering, development and production, the overall planning of underground resources and ground engineering is carried out, and a perfect regional development pattern is gradually formed. Based on reducing the threshold of oilfield development through resources sharing and accelerating the construction of new oilfield, the reservoir potential is fully released, and the efficient development of regional oil and gas is realized.
{"title":"Risks Minimization and Results Improvement in Offshore Projects","authors":"Hongfu Shi, Wei Zhang, Xiaodong Han, Haochuan Ling, Chaojie Kong","doi":"10.4043/29325-MS","DOIUrl":"https://doi.org/10.4043/29325-MS","url":null,"abstract":"\u0000 A new regional integrated development pattern is proposed by Bohai Oilfield Bureau, based on the existing development and production system and engineering facilities, and combined with the distribution characteristics of underground oil and gas resources in Bohai oilfields, and according to the principles of ‘overall planning, unified layout, stage promotion and subarea implementation'. Through the integration and rational allocation of exploration and development, reservoir and engineering, development and production, the overall planning of underground resources and ground engineering is carried out, and a perfect regional development pattern is gradually formed. Based on reducing the threshold of oilfield development through resources sharing and accelerating the construction of new oilfield, the reservoir potential is fully released, and the efficient development of regional oil and gas is realized.","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":"76203807","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}
M. Oliveira, Monica Alevatto, T. P. Sampaio, P. Dias
In Brazil oilfield scenario, there are large, clearly identified brownfield sites, many of which with high additional oil production potential. The lifting costs and conventional breakeven price per barrel associated with an existing producing field offshore, even those in decline and requiring some recompletion & workover jobs, are – in many situations - less investiment demanding than brand new greenfield development. The formation of water in oil (W/O) emulsions is ubiquitous in oilfield production. As the water commingled in crude increases, the emulsions' stability and viscosity also increase, thence generating flow restrictions due to higher friction losses. The subsea demulsifier injection has proven to be an interesting alternative to overcome this flowing constraint in mature wells, thus maximizing the productive capacity of existing brownfields. This paper presents some results and challenges faced to implement the routine of subsea demulsifier injection, from the development of testing protocols to come up with a tailor-made chemical solution, to the hurdles associated to chemical injection through subsea umbilical- and gas lift-lines.
{"title":"Subsea Demulsifier Injection to Enhance Crude Oil Production in Offshore Brownfields - A Success Case","authors":"M. Oliveira, Monica Alevatto, T. P. Sampaio, P. Dias","doi":"10.4043/29535-MS","DOIUrl":"https://doi.org/10.4043/29535-MS","url":null,"abstract":"\u0000 In Brazil oilfield scenario, there are large, clearly identified brownfield sites, many of which with high additional oil production potential. The lifting costs and conventional breakeven price per barrel associated with an existing producing field offshore, even those in decline and requiring some recompletion & workover jobs, are – in many situations - less investiment demanding than brand new greenfield development.\u0000 The formation of water in oil (W/O) emulsions is ubiquitous in oilfield production. As the water commingled in crude increases, the emulsions' stability and viscosity also increase, thence generating flow restrictions due to higher friction losses. The subsea demulsifier injection has proven to be an interesting alternative to overcome this flowing constraint in mature wells, thus maximizing the productive capacity of existing brownfields. This paper presents some results and challenges faced to implement the routine of subsea demulsifier injection, from the development of testing protocols to come up with a tailor-made chemical solution, to the hurdles associated to chemical injection through subsea umbilical- and gas lift-lines.","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":"76258837","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
B. Grove, R. DeHart, J. McGregor, Haggerty Dennis, C. Christopher
Multiple perforation laboratory programs have been conducted during recent years to support high-pressure/high-temperature (HP/HT) and ultrahigh-pressure (UHP) oil and gas field developments at various offshore locations globally. This paper highlights six such projects that supported activities within the Asia-Pacific, North Sea, and US Gulf of Mexico (GOM) (both Miocene and Lower Tertiary) regions. Each program was designed and conducted in collaboration with an operator and field operations personnel to help reduce potential risks, improve operational efficiency, and optimize well performance across a variety of challenging environments. Laboratory experiments were based on API RP 19B Sections 2 and 4, with test conditions customized to match specific downhole environments of interest (rock and fluid properties, stress, pressure, temperature, and flow scenarios). Matching downhole conditions at the laboratory proved important because this yields results that can be quite different from those obtained at surface (or scaled) test conditions. Reliable estimations of field perforation skin, sanding propensity, and the effectiveness of subsequent stimulation operations depend on realistic perforation and flow data obtained at relevant downhole conditions. The overriding goal for test design is to create and expose the laboratory perforation in an environment that matches its field counterpart as closely as possible. Beyond obtaining accurate flow data for skin and/or sanding propensity determination, post-test diagnostics, such as computed tomography (CT) and optical techniques, provide additional essential insight into the characteristics of the perforation tunnel, core interior, and the hole through the casing and cement. Results from these various programs were used to confirm or, in some cases, guide the field perforating strategy.
近年来，为了支持全球不同海上地区的高压/高温(HP/HT)和超高压(UHP)油气田开发，开展了多个射孔实验室项目。本文重点介绍了六个此类项目，这些项目支持亚太、北海和美国墨西哥湾(中新世和下第三纪)地区的活动。每个方案都是与作业者和现场作业人员合作设计和实施的，以帮助降低潜在风险，提高作业效率，并在各种具有挑战性的环境中优化井的性能。实验室实验基于API RP 19B section 2和section 4，并根据特定的井下环境(岩石和流体性质、应力、压力、温度和流动场景)定制了测试条件。与实验室的井下条件相匹配非常重要，因为其结果可能与在地面(或规模)测试条件下获得的结果大不相同。对现场射孔表皮、出砂倾向以及后续增产作业有效性的可靠估计，取决于在相关井下条件下获得的实际射孔和流动数据。测试设计的首要目标是在尽可能接近现场的环境中创建和暴露实验室射孔。除了获得准确的流量数据以确定表皮和/或磨砂倾向外，测试后的诊断，如计算机断层扫描(CT)和光学技术，还提供了对射孔隧道、岩心内部以及穿过套管和水泥的井眼特征的额外基本洞察。这些不同方案的结果用于确认或在某些情况下指导现场射孔策略。
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R. Gilbert, Yunhan Huang, K. Stokoe, S. Wang, J. Munson, Jonas Bauer, R. Hosseini, Ahmed Hussien, H. Fadaifard, Daniel P. O'Connell
The conventional design methods for laterally loaded offshore foundations in sand, API RP 2GEO (2014) and DNV (2018), were not developed for wind turbine monopiles that experience lateral loads imposing relatively small lateral displacements in service. This paper presents the results of research to evaluate the suitability of existing guidance for the design of laterally loaded monopiles at small displacements and to provide recommendations for improving design methods for monopile foundations. The research included applying existing techniques to measure the non-linear stiffness of sand at small shear strains, utilizing a three-dimensional finite element method (3-D FEM) model that incorporates the non-linear stiffness of sand to predict the lateral response of a monopile, testing the proposed approach with foundation model tests in the laboratory, and applying the proposed approach to the lateral load tests conducted on Mustang Island in 1966 that provided the original basis for current design methods. The following major conclusions are drawn from this research: Model tests and field tests consistently show that the conventional p-y curves from current design practice tend to underestimate the initial stiffness for laterally loaded piles and fail to capture the non-linearity of the stiffness at small lateral displacements. A 3-D FEM model that incorporates a constitutive model to characterize the small-strain properties of sand, including the maximum shear stiffness at very small strains and the relationships between shear stiffness and both shear strain and effective confining stress, is capable of predicting the response of laterally loaded piles both at model and field scales. These conclusions lead to the following recommendations for the design of laterally loaded monopiles in sand: Exercise caution in using conventional p-y curves for sand to predict the performance of offshore wind turbine monopiles in service. The conventional p-y curves used in current design practice do not adequately predict the stiffness and non-linearity of laterally loaded piles at the small lateral displacements relevant for offshore wind turbine monopiles in service. Measure directly or empirically establish the in-situ maximum ("small-strain") shear modulus, the relationship between shear modulus and shear strain, and the relationship between shear modulus and effective confining pressure. These small-strain properties are needed to predict the stiffness and non-linearity of laterally loaded piles at small lateral displacements. Establish improved p-y curves to be used in design directly from 3-D FEM analyses using representative properties of the sand in-situ at small strains.
API RP 2GEO(2014)和DNV(2018)这两种传统的砂中横向加载海上基础设计方法，并没有针对在使用过程中经历横向载荷施加相对较小横向位移的风力涡轮机单桩开发。本文对现有的小位移单桩横向荷载设计指南的适用性进行了评价，并对改进单桩基础设计方法提出了建议。研究包括应用现有技术测量小剪切应变下砂土的非线性刚度，利用包含砂土非线性刚度的三维有限元方法(3-D FEM)模型来预测单桩的横向响应，并在实验室中通过基础模型测试测试所提出的方法。并将所建议的方法应用于1966年在野马岛进行的横向荷载试验，该试验为当前的设计方法提供了原始基础。研究得出以下主要结论:模型试验和现场试验一致表明，目前设计实践中传统的p-y曲线往往低估了侧向荷载桩的初始刚度，不能反映小侧向位移时刚度的非线性。三维有限元模型结合本构模型来表征砂的小应变特性，包括极小应变下的最大剪切刚度以及剪切刚度与剪切应变和有效围应力之间的关系，能够在模型和现场尺度上预测侧向加载桩的响应。这些结论对砂土中横向加载单桩的设计提出了以下建议:在使用常规的砂土p-y曲线来预测海上风力涡轮机单桩的性能时要谨慎。目前设计实践中使用的传统p-y曲线不能充分预测与海上风电单机桩相关的小侧向位移处的横向荷载桩的刚度和非线性。直接测量或经验建立原位最大(“小应变”)剪切模量、剪切模量与剪切应变的关系、剪切模量与有效围压的关系。需要这些小应变特性来预测小侧向位移下水平荷载桩的刚度和非线性。利用小应变下现场砂土的代表性特性，通过三维有限元分析建立改进的p-y曲线，直接用于设计。
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