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Keywords: subsea production system
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Proceedings Papers
Publisher: Offshore Technology Conference
Paper presented at the Offshore Technology Conference, May 6–9, 2019
Paper Number: OTC-29639-MS
... the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright. Abstract Subsea production systems...
Abstract
Subsea production systems and processes are generally conducted using hydraulic and more recently electro-hydraulic controls. These systems have become complex and expensive to deploy, especially with increasing length of tie-backs, more deepwater installations and challenging environments. Electrically powered and controlled equipment has become the standard for onshore and topsides equipment. Developing a subsea electric control unit that is modular and easily packaged is integral to leveraging the benefits of electric monitoring and control into subsea production systems and processes, as well as many other intervention applications such as subsea chemical storage and injection. In addition to simplifying and reducing costs of these systems, the unit will be able to discern an end component's health and status providing an opportunity to adjust or modify the operation in-situ, and in some instances real-time as well as provide other benefits. New analytical techniques powered by advanced analytics and artificial intelligence (AI) are being developed to examine in greater detail the controlled equipment's operational status, infer its current state of health and even predict future performance and maintenance/repair needs. As more and more data are collected and analyzed, the predictability and accuracy of the analysis and prediction improves. Coupling the newly developed all electric subsea controller unit described in this paper with advanced data analytics will lower operator costs and risks in subsea systems. the system presented herein has been designed as a simple, rugged and reliable piece of equipment based on years of experience with API RP 17H Class 2 torque equipment and variable speed subsea pumps. It utilizes serial communications with position limiting and has a closed loop speed/position control, torque control, and real-time torque limiting. The profiling feature helps establish valve and pump status, functionality and health monitoring. The tool is ideally suited for subsea application to 10,000 fsw for any application requiring up to 250 ft.-lbs. with position and variable speed control. Leveraging learnings from the nuclear industry and their regulators, this ‘spring-less’ unit includes an option for a ‘smart battery’ (Lithium ion) back-up for specified fail-safe positioning and monitoring. Technical specifications were driven by operator customers. A full set of Functional Design Specs (FDS) were developed as well as an Inspection and Test Quality Plan (ITP). Where practical, acceptance criteria were leveraged from API, ASME and other industry guidance. A full-scale prototype unit has been built, tested and qualified with over 1 million cycles. The unit enables collecting sensed operating data from one or more end devices and one or more control end points, calculating and performing analytics, and reporting health and status of the one or more end devices and one or more control end points. It is currently being utilized on a common industry subsea ball valve, integrated into a subsea chemical storage and injection system as well as a drive for a variable speed subsea chemical injection pump. Regulator authorities in the U.S. have been included in the qualification witnessing.
Proceedings Papers
Publisher: Offshore Technology Conference
Paper presented at the Offshore Technology Conference, April 30–May 3, 2007
Paper Number: OTC-18819-MS
... performance propelled a major operator to select an all-electric subsea production system for a multiwell development in the North Sea. This paper describes the process, decision criteria and strategic impetus that led to the selection of the all-electric subsea production system for this application and...
Abstract
Abstract Operators are continually seeking improved reliability, availability and performance in subsea control systems due to the ever increasing cost of failure from downtime and intervention. Enhancements in functionality including more rapid response and improved condition monitoring of equipment are greatly desired. And, the increased focus on environmental concerns due to venting and leakage of control fluids to sea, coupled with the high carrying costs of control fluids in general, are forcing operators to look for cleaner, more economical alternatives to meet ever restricting standards. Resulting from these and other deficiencies, hydraulic control systems for subsea production have come under increased scrutiny. The advantages and benefits provided by all-electric systems over conventional, hydraulic based systems for subsea application have been rigorously evaluated by many operators and have demonstrated dramatically positive results. Due to the rapid development and advances in electric controls technologies, operators now have a viable alternative. The desire to realize improvements in equipment reliability, system availability, operational functionality and environmental performance propelled a major operator to select an all-electric subsea production system for a multiwell development in the North Sea. This paper describes the process, decision criteria and strategic impetus that led to the selection of the all-electric subsea production system for this application and outlines the desired objectives for the implementation of the all-electric technology. Figure 1 - All-Electric Deepwater Subsea SpoolTree System (available in full paper) Introduction Over the past decade, substantial gains have been realized in reliability and functionality of electro-hydraulic multiplexed (EHMUX) control systems for subsea production. These systems are the culmination of advanced hydraulic controls technology dating back to the early days of subsea systems. Since the 1960s, the evolution of control systems technology has proceeded from direct hydraulic to piloted and sequenced systems to provide improved response time and allow for long distance tiebacks. Today, most subsea developments make use of EHMUX control. This is essentially a subsea computer/communication system of hydraulic directional control valves (DCVs). These electrically actuated valves allow stored pressure within subsea accumulators to be routed to individual hydraulic lines and onward to actuated gate valves and chokes on subsea production equipment. Despite the many advantages provided by EHMUX systems, there is a general industry recognition of persistent weaknesses related to susceptibility of fluid cleanliness, materials compatibility, hydrostatic effects in deeper water and limitations for long distance tieback. The higher cost of deepwater and remote, long offset, subsea developments has focused much attention by operators on improving the reliability of subsea systems in general, and control systems in particular. Many subsea reliability assessments conducted by operators, in association with specialist academic and reliability consultants identified that a significant portion of reliability problems are attributable to the failure of hydraulic components. Reliability issues persistently occur during installation and in operations associated with high pressure/high fluid volume hydraulic systems. The positive results from reliability studies initiated significant technology development investigations to explore potential advantages and benefits of all-electric subsea controls capability.
Proceedings Papers
Publisher: Offshore Technology Conference
Paper presented at the Offshore Technology Conference, May 5–8, 1997
Paper Number: OTC-8453-MS
... paper reviews Statoil's and KOS's experience and ongoing work with subsea production systems, and address strategic activities taken to cover needs related to the development of smaller fields in the coming five year period. The paper focuses on the preparations which Statoil and KOS/FMC have undertaken...
Abstract
Abstract Today, Statoil has a number of subsea wells in production, has several ongoing projects, and has a number of promising prospects where the use of subsea wells will be essential for an economical sound development. These fields range from the development of the Norwegian Asgard and Gullfaks Satellite fields which include a large number of wells, complex reservoirs, and have a long field life, to small international fields like the Lufeng (offshore China) and Connemara (offshore Ireland) fields which include few wells, have a short field life, amd are very marginal developments. The paper reviews Statoil's and KOS's experience and ongoing work with subsea production systems, and address strategic activities taken to cover needs related to the development of smaller fields in the coming five year period. The paper focuses on the preparations which Statoil and KOS/FMC have undertaken to enable fast-track field developments. Essential in this is to remove the delivery of the subsea Xmas trees and other long lead items from the critical line of a field development. Flexibility and standardisation are key issues and the paper outlines how Statoil and KOS/FMC have focused on these when establishing low cost building blocks for international fast-track developments. The paper decribes how building blocks have been developed; both for the marginal subsea developments where low expenditure and risk are more important than maximising system availability, and for subsea developments with enough recoverable reserves to allow oil production to be optimised and the recovery factor to be maximised to a larger extent. The paper concludes that it is essential to undertake the preparatory work which is outlined in this paper in order to be able to improve cost efficiency and further reduce cost per barrel produced. Introduction Statoil has completed or placed equipment orders for about 150 subsea wells since Statoil completed its first subsea well on the Gullfaks field 11 years ago. Most of these wells are located in Norwegian waters. The use of subsea wells as the primary method of producing hydrocarbons has had its final breakthrough on the Norwegian shelf through the large developments Asgard/ Gullfaks Satellites (Operator Statoil) and Troll Oil (Operator Norsk Hydro). Here it has been essential to maximise oil recovery from complex reservoirs. There will be an increasing need for a cost efficient method to develop smaller, very often marginal fields which typically has a short field life and recoverable reserves in the order of 5 - 15 million Sm 3 in the future. These smaller fields may be marginal for different reasons, but common for them all could be the method of development and the need to find internationally competitive solutions. The simple conclusion is that standardisation to international suppliers standard products and establishment of a close relationship with a few key contractors through frame contracts could give both fit for purpose low cost equipment and arrangements for short delivery times which would enable fast-tract developments. Definition of Subsea Systems and Cost Driving Factors Review of Statoil field development experience. KOS/FMC has become Statoil's main supplier of subsea production stations.
Proceedings Papers
Publisher: Offshore Technology Conference
Paper presented at the Offshore Technology Conference, May 1–4, 1995
Paper Number: OTC-7866-MS
... ABSTRACT This paper describes recent subsea production system experience, with focus on cost reduction trends which are expected to continue throughout the remainder of the decade. First, the system configuration trend from large, heavy, multi- well integrated drilling template and production...
Abstract
ABSTRACT This paper describes recent subsea production system experience, with focus on cost reduction trends which are expected to continue throughout the remainder of the decade. First, the system configuration trend from large, heavy, multi- well integrated drilling template and production/injection manifold systems to small, lightweight, "minitemplate" systems or clustered well manifolds with individual satellite wells is addressed. Second, several equipment technology trends are addressed including towed flowline bundles with integral manifolds, development of improved reservoir management/data acquisition tools, subsea pressure boosting to extend the reach of subsea systems, emergence of the rental tool market and "tool pools", "horizontal" trees for certain applications, and standardization of subsea components and interfaces. This paper concludes that subsea production systems have successfully demonstrated their overall reliability, and have established a proven track record over the past thirty years of field experience. System configuration and equipment technology trends in the nineties are now improving the profitability and capability of subsea production systems. Subsea production system examples are cited along with generic costs to illustrate the effectiveness of these cost reduction trends. SYSTEM CONFIGURATION TREND Introduction The first "modern" subsea production systems, pioneered in the early 1960's, were developed with single satellite wells and trees tied back to host facilities with individual flowlines and control umbilicals. Many of these trees were extensions of existing land and platform tree designs, and were"marinized" for use underwater; however, several of these trees incorporated technology specifically designed for subsea applications. Flowlines and umbilicals were connected to the subsea trees with extensive use of air and saturation diving techniques. Although these pioneering subsea production systems were successful in their own right, their applicability was somewhat limited. Individual satellite well flowline and umbilical costs would be prohibitive for multi-well developments with relatively long distances back to the host facilities. In addition, technology at that time would not allow for deepwater subsea developments beyond diver depth limitations. In an effort to minimize the flowline and umbilical costs, a shift in system design philosophy emerged in the late sixties/eady seventies to commingle the produced fluids by way of subsea manifolding, as well as to distribute hydraulic and electric power/signals with subsea controls distribution trunking. In addition, designs were developed for diverless pull-in and connection of subsea flowlines and umbilicals, so that subsea production systems would be applicable for Potential deepwater developments. Figure 1 illustrates the flowline and umbilical cost difference between a generic satellite well system with individual flowlines and umbilicals, versus a manifolded subsea production system for a typical North Sea development 10 km from the host facility. Large, Heavy Integrated Template/Manifold Systems The very first integrated drilling template and production/injection manifold system was Exxon?s Submerged Production System (SPS), which was installed in the Gulf of Mexico in 1974. Because the SPS was a pilot test for future deepwater applications, all underwater operations were designed for diverless intervention, even though it was located in only 52m of water. Diverless operations included flowline and umbilical pull-in and connection, as well as insert valve.
Proceedings Papers
Publisher: Offshore Technology Conference
Paper presented at the Offshore Technology Conference, May 3–6, 1993
Paper Number: OTC-7241-MS
... ABSTRACT For many years, suppliers and operators have debated the issue of standardization in subsea production systems and questioned the need for the wide design variation seen. The standardization efforts has always been defeated by governmental and environmental requirements for different...
Abstract
ABSTRACT For many years, suppliers and operators have debated the issue of standardization in subsea production systems and questioned the need for the wide design variation seen. The standardization efforts has always been defeated by governmental and environmental requirements for different producing areas, by advancing technology and by customer/supplier preferences. The obvious advantages of standardization, as for instance, the use of proven technology, reduced engineering, reduced development risk, planning and project management hours and reduced project lead time has been the subject for discussion over a long period of time, however it has never been attempted in real life projects. The contemporary development of three major subsea fields in the North Sea under EPC contracts, has given the opportunity to standardize equipment between the different concepts and configurations. The fields are: Draugen Subsea Facilities Statjord Satellite Project (SSP) Heidrun Subsea Water Injection System This paper summarizes the practical experience gained during this work, including the effect of standardization, and the related challenges seen during execution of the project. INTRODUCTION The award of the EPC contracts to Kongsberg Offshore a.s (KOS) and FMC, UK offered the opportunity to standardize between the following field configuration: 5 slot template for water injection 4 slot template for production and water Injection. Single satellites The staggered timing of the contracts as shown below, made it possible to gain experience from one project and implement the experience into the next project. Standardization can in general be achieved on various level: international Within Operators Within Suppliers The opportunity of standardization from a Supplier is all based on the contract form, i.e. the Total System Supply concept - the EPC concept. Regardless of required subsea architecture and field layout, a degree of standardization can be achieved between any concept, provided the contract form allows it and the Supplier has sufficient strength to realize it. The following success factors for standardization can be related to the contract: Suppliers are given the opportunity to review, comment and familiarize with the specifications during pre engineering stage prior to invitation to bid. This stage is the only stage when open discussions between Suppliers and Operators can take place. The specifications are functional and not formulated as detail design requirements. Only interfaces to other contracts should be governed by specify design requirements. Detail design requirements in general are cost-driving. Operator supplied equipment should be minimized. These are is general not optimized for the field development and new equipment have to be designed for integration of these items. Another set of success factors can be linked to the EPC supplier: Control over technology used. This implies design authority and the ability to understand operational limitations of components and the ability to adjust these.
Proceedings Papers
Publisher: Offshore Technology Conference
Paper presented at the Offshore Technology Conference, May 5–8, 1986
Paper Number: OTC-5242-MS
...aTe 5242 API Offshore Standards Activities: Subsea Production Systems by B.C. Carlson, Shell Offshore Inc., and J.M. Spanhel, American Petroleum Inst. Copyright 1986 OffshoreTechnorogy Conference .. - - - . _. This paper was presenled at the 18th Annual OIC in Houston, Texas, May 5-8;-1 ggG:-itie...
Abstract
ABSTRACT Oil industry activity in offshore areas has led to increasing application of subsea production systems. The American Petroleum Institute has formed a new standardization committee to prepare standards for these systems. The first standard, which is currently being finalized, is a Recommended Practice for Design and Operation of Subsea Production Systems. It covers well foundations, wellheads and trees; pipelines and end connections; controls, control lines and control fluids; templates and manifolds; production risers; operations; and quality assurance, materials and corrosion. Other standards in preparation are a Recommended Practice For Flexible Pipe and a Specification For Subsea Wellheads and Trees. INTRODUCTION A new API Committee on Standardization of Subsea Production Systems was formed in September 1984 to prepare standards and serve as an industry focal point for questions concerning subsea production systems. This was in response to a general feeling within the industry that standardization work in this area was needed. Starting with the first installation in 1960, there have been 334 1 subsea well completions through 1984. Nearly one-half (162) have been made during the 1980-84 period. This accelerating activity along with the extensive experience gained to date makes this work timely. At the present time there are no API standards covering subsea production systems. API Spec 6A 2 no longer contains any information about subsea wellhead equipment. The initial work of the new committee has been the preparation of a Recommended Practice For Design and Operation of Subsea Production Systems. The RP was developed by eight task groups composed of over 60 people representing oil companies, manufacturers, service companies, consultants, and a regulatory agency. As of the writing of this paper (mid January 1986) a composite draft of the RP was being assembled for transmittal to some 50 organizations for review and comment before finalizing the document for publication in late 1986. Recently, work was begun on the preparation of a Recommended Practice For Flexible Pipe and a Specification For Subsea Wellheads and Trees. RP: Design & Operation of Subsea Production Systems This Recommended Practice provides guidelines for the design, installation, operation, repair and abandonment of subsea production systems. It encompasses all system elements (Figure 1), including well foundations, wellheads and trees; pipelines and end connections; controls, control lines and control fluids; templates and manifolds; production risers; operations; and quality assurance, materials and corrosion. The material covering this wide range of equipment and operations is being included in one document to emphasize inter-relationships and the need to consider subsea production installations as systems. The RP consists of the sections discussed in the following paragraphs. Well Completion Equipment This section describes equipment and reviews functional and design considerations for the use of subsea wellhead equipment; tubing hangers and trees; and completions on mud1ine suspension equipment. Wellhead equipment includes guidebases, housings, casing hangers, annulus packoff assemblies, bore protectors, wear bushings and running and retrieving tools. Tubing hanger equipment includes both parallel and concentric bore hangers and mechanical and hydraulic running tools. Tree equipment includes connectors, extension subs, valves, TFL components, tree cap and running tools.