Optimizing Subsea Processing for Deep and Long Step-Out Gas Fields

With ever increasing energy demands and the depletion of hydrocarbon resources, marginal fields play an important role in oil and gas exploitation. Flow assurance issues, including wax and hydrate formation, can be found in long distance tiebacks. Subsea processing, where processing equipment is installed on the seabed, can be used to solve these flow assurance issues in remote marginal fields. Subsea processing is the leading edge technology for unlocking production from reservoir under complex conditions. This paper demonstrates the opportunities in marginal field development, and analyses the implication of applying subsea processing in remote marginal fields. The marginal field case study concerns a development with an 80 km tieback, having reserves of 120 million barrels of oil and in water 3,000 m deep in the Gulf of Mexico. The technical and economic aspects of two field development options, one employing subsea separation and boosting, and the other, an electric trace heated pipe-in-pipe flowline and subsea boosting, are compared. Hydraulic analysis of three phase flow (oil, gas, and water) using state of the art simulation software (OLGA) is performed to demonstrate production fluid behavior inside the flowline. Life cycle cost, combining both economic (CAPEX and OPEX) and risk factors (RAM), are used as the selection criterion. Subsea separation with continuous hydrate inhibitor injection can prevent flowline blockage over the field life, while the electric trace heated pipe-in-pipe option may require subsea boosting to override the large pressure drop in late field life. In the analysis, subsea separation shows potential life cycle cost savings of up to 13% compared to electric trace heated pipe-in-pipe, indicating it may be the appropriate option when developing fields with these specific conditions. Improvement of subsea processing requires more compact designs for deepwater applications, which will help reduce both capital investment and intervention cost.

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18261, "Subsea Processing and Boosting - Technical Challenges and Opportunities," by R.M. Bass, Shell Intl. E&P, prepared for the 2006 Offshore Technology Conference, Houston, 1-4 May. Subsea oil-pressure boosting often enhances subsea deepwater oil developments. Currently available subsea processing and boosting solutions, global portfolio needs for subsea oil boosting, and the limitations of existing technologies in meeting these needs are described. Introduction Fig. 1 shows how subsea-processing applications have increased in recent years. Subsea processing can include the following.Subsea oil-pressure-boosting systems.Subsea oil processing.Bulk water separation.Sales-quality oil polishing.Subsea raw-seawater injection for reservoir-pressure support.Subsea gas compression.Subsea gas dewpointing and dehydration.Flow assurance.Sales-quality processing. Oil Systems Subsea oil-pressure boosting can enable ultradeepwater light-oil production, can enable deepwater heavy-oil production, can increase ultimate recovery for deepwater light oil, and may be used to reduce flow-assurance costs. In all cases, subsea boosting reduces or eliminates the back-pressure on the wells resulting from the riser hydrostatic head and the riser and flowline pressure drop caused by high viscosity. Although many reservoirs have sufficient pressure to produce to the seafloor without the use of downhole artificial lift, many ultradeepwater light-oil and deepwater heavy-oil reservoirs have pressure that is near hydrostatic pressure and cannot produce to the sea surface for more than a short period of time. Moderate-depth light-oil wells frequently are economical without artificial lift. However, as pressure declines in late life, reducing the backpressure can add significantly to ultimate recovery. Subsea oil-pressure boosting can add value to deepwater oil projects. At the time this paper was written, 10 applications were in place, and an additional five had been announced. Subsea oil-pressure boosting has been proved in water depths to approximately 3,000 ft, depending on desired boost pressure, gas content, and viscosity. Significant cost or technical challenges remain for light and heavy oil in deeper water. Bulk subsea water separation can be used to debottleneck water-processing capacity where topside debottlenecking cannot be accomplished, thus enabling additional production to an existing host. Because topside debottlenecking is possible for many situations, subsea water separation has selected applicability. Bulk subsea water separation has been used without solids-handling equipment for relatively shallow water depths and easily separated oils. Solids-handling components have been tested onshore and will be incorporated into an announced project. Water-depth limits can be extended with moderate changes in separator-vessel design. Electrostatic coalescers are being tested in topside facilities to increase separation efficiency for difficult oils. Separators for deep water remain a technical challenge. Subsea raw-seawater injection can be used to debottleneck topside facilities when additional topside injection capacity cannot be accommodated. Because topside debottlenecking is not needed for many situations, subsea raw-seawater injection has selected applicability, with two projects announced. These systems will use proven subsea injection pumps and redesigned versions of solids-filtering components that have been proved in topside application.

The Parque das Conchas (BC-10) development located in the deepwater BC-10 block offshore Brazil - comprises of relatively low-energy, low-API reservoirs (Ostra, Argonauta B-West) and one high-GOR field (Abalone) - tied back subsea 9 to 34 km to an FPSO. To enhance production and maximize recovery, an innovative subsea separation and boosting technology has been employed, consisting of a shallow well conductor that contains a caisson where liquid and gas are separated prior to transport to the surface. In the case of Ostra/Abalone, separated gas flows naturally to the FPSO via a dedicated, un-insulated gas flowline. Separated single phase fluids at the bottom of the Caisson are boosted via an electrical submersible pump (ESP) located within the caisson, and transported to the FPSO in a wet insulated flowline. The heavier B-West fluid is separated and recombined in the caisson and pumped as a multi-phase mixture. The addition of the Caisson/ESP (C-ESP) subsea separator and pumping system has significantly reshaped the flow assurance challenges and analysis processes typically applied to deepwater subsea tieback developments. For instance, several of the traditional flow assurance concerns - such as hydrate control, slug management, sand handling, and emulsion/foam tendency - will now involve a different set of design and operability requirements. Additionally, " ensuring the flow?? in the C-ESP system itself involves several unique design and operability challenges, associated with separator design and control and mitigation of separation inefficiencies. This paper describes some of the new challenges and analysis tools to be encompassed by flow assurance engineering, as this new area of subsea processing emerges in deepwater developments. The role of the flow assurance engineer will expand to include subsea " process systems engineering?? - i.e. the application and extension of traditional process engineering approaches to the design and operability of subsea separation and artificial lift systems. Introduction The Parque das Conchas development is located in block BC-10, approximately 74.5 mile South West of the coast at the city of Vitoria in Brazil in water depths about 5,900 ft. Shell is the operator with a 50% working interest, in a joint venture with Petrobras (35%) and ONGC (15%). Phase 1 of the development includes three fields - Ostra, Abalone and Argonauta B-West, each with different fluid properties. Argonauta O-North is currently in planning for development in Phase 2. Ostra and Abalone fields use the concept of subsea separation and boosting. B-West uses a novel non-separated boosting system in which the multiphase fluids from the well are separated and then recombined and boosted using a conventional ESP. The Ostra field will be produced via six horizontal wells. The oil has an API of 24 and a GOR of 274 scf/sbbl. Abalone has an API of 44 and a GOR of 3,800 scf/sbbl and behaves like a gas condensate. B-West has a heavier oil with an API of 16 and a GOR of 194 scf/sbbl. An additional challenge at B-West is the unusually high viscosity of the fluids, especially below the bubble-point.

To surpass the main challenges established by deep water, high gas-oil flowratios, flow assurance and constant increases in produced water, Petrobras is developing, within PROCAP Technology Program - Future Vision, several projects in the subsea processing area, such as: Compact Oil-Water and Gas-Liquid Separation Systems, Multiphase Pump with High Differential Pressure and Gas Compression System. The main applications of these projects are in fields with high fraction of gas and water, in fields/discoveries located far away from Production Units and to increase the reservoir recovery factor. Furthermore, the application of these technologies may have great benefits, such as: production anticipation, reduction of process system footprint on the Production Unit, decrease in CAPEX/OPEX and especially an increase of the topside oil processing capacity. This paper aims to present an overview of those technologies being developed in PROCAP - Future Vision. Also, this article shows the main motivations of these developments, the main benefits of using each technology, the technological challenges and gaps, typical application scenarios and results of the evaluations performed so far. Major petroleum companies are searching for new technical solutions that fulfill their needs of reducing both CAPEX and OPEX while increasing oil and gas production. The development of new subsea processing technologies, as stated above, will enable, and in some cases reinforce, the use of these technologies for deepwater and/or subsea to shore scenarios. Introduction Subsea processing is a key enabler for challenging field developments, and their benefits increase with water depth, flowrates and step-out. Regarding subsea separation, these advantages are maximized when employing subsea compact separation technologies. Also, subsea processing brings HSE benefits related to reduction of waste disposal to sea, an environmental contribution of subsea oil-water separation systems, and the possibility of using smaller platforms - or none at all - due to the use of processing equipment on the seabed instead of topside, reducing operational risks. In terms of compact separation technology development, Petrobras has been conducting several R&D initiatives for the last ten years. Firstly, these R&D initiatives were developed for topside and onshore applications, but always keeping on mind the subsea employment. In order to evaluate these technologies several tests have been performed. More recently, the Marlim SSAO 3-Phase Subsea Separation System is a very significative example of compact subsea technology employment, for a single producer well application. Multiphase boosting is always considered as a good alternative to develop oilfields, mainly for remote areas. Petrobras invested a lot on the development of twin screw and helicoaxial concepts for multiphase pumps, targeting applications with required differential pressures up to 60 bar. Recently, analysis has indicated that High Differential Pressure Subsea Boosting (up to 150 bar) is economically and technically attractive to various Petrobras scenarios and, because of that, many R&D efforts are being done to develop such technology.

Accumulated oil production from the Troll field offshore Norway will reach one billion barrels of oil in the spring of 2005. At 315-340 meters water depth, Troll is an oil and gas field with approximately 1,700 billions Sm3 of gas and four billion barrels of oil in place. Troll consists of two main structures, Troll East and Troll West, the latter divided into an oil and gas province. The oil is located primarily in Troll West in thin oil layers of 4-27 m. This article describes how the Troll West field has been developed from a gas field with no commercial oil to a gas and oil field with accumulated production surpassing one billion barrels of oil during the spring 2005. Introduction This article describes the multi-disciplinary success story of the Troll West oil and gas field. Originally, the Troll field's thin oil layer of 4-27 m thickness was considered to have no commercial value. The development of horizontal drilling technology combined with early testing and oil production from a floating platform (FPSO) led to the conclusion that Troll West oil could be commercially produced. The most productive part of the field is the Troll West Oil Province (TWOP) with 22–27 m oil thickness. It was first developed by the installation of five subsea clusters and the Troll B FPSO in 1995. Drilling and production performance led to further development of the even thinner oil layers (4–14 m) in the Troll West Gas Province (TWGP), and installation of the separate Troll C platform, which began producing in 1999. The Troll field is one of the largest subsea developments in the world with 107 wells currently in operation. Increased oil recovery from the thin oil layers in Troll West has been possible by gradually increasing the length of the horizontal sections and introducing multi-lateral wells to reduce cost and increase the sweep area. Advanced drilling and completion technology have been developed and implemented. Seismic and geological methods determine the location of the high-permeable sands with high accuracy. The drilling and completion operations have been significantly more efficient, resulting in a higher drainage area per invested capital. Continous production drilling with up to four floating drilling rigs has been carried out since production start in 1995. More than 30 multi-branched wells with zonal control are in operation. Five three-branched, two four-branched and one five-branched well are currently in production. Figure 1. The Troll Field is located some 80 kms west of Bergen, Norway. (available in full paper) The Troll Field The Troll field is located some 80 kilometers west of Bergen, off the coast of western Norway. The water depth is 315-340 m. The Troll field consists of Troll East, mainly covered by production license 085, and Troll West, mainly covered by production license 054, see Fig. 1. The Troll license partners are:ConocoPhillips Norge 1.62374 %Total E&P Norge AS 3.69096 %A/S Norske Shell 8.10145 %Norsk Hydro Produksjon AS 9.77914 %Statoil ASA 20.80471 %Petoro AS (Norwegian state) 56.00000 %

Subsea processing and boosting can be key enablers or optimization alternatives for challenging field developments and their benefits increase with water depth, flowrates and step-out. Petrobras has invested a lot on the development of such technologies, supported, among other pillars, on an aggressive R&D policy through its technological programs like PROCAP, and several subsea processing and boosting systems have successfully operated in Petrobras fields. Considering that, these technologies are being considered for application in potential Petrobras' scenarios including mature and green fields. This paper aims to give an overview of the systems developed and applied in Petrobras prospects during the last twenty years, such as the Vertical Annular Separation and Pumping System (VASPS), Boosting Systems with Electrical Submersible Pumps (Mudline ESP and MOBO), Subsea Multiphase Pumps, Subsea Raw Water Injection and Subsea Oil-Water Separation (SSAO). It also reports the new R&D initiatives related to subsea processing and boosting that are being developed within PROCAP - Future Vision technology program, showing the main motivations of these developments, the main benefits of using each technology, the technological challenges and typical application scenarios. Also, this paper illustrates the analysis and evaluations performed so far, for all of the new developments presented. Introduction Petrobras has developed and applied several technologies during the last 20 years, forming a very useful " toolbox" for subsea processing and boosting applications. After successful implementation of several technology-projects, on subsea boosting and processing, Petrobras and other operators have demonstrated that such technologies are definitely a very important field development tool, as predicted decades ago. In the beginning of the exploitation of oil&gas offshore fields, the main concern is related to the initial investment to construct the production units, to drill the wells and to install all the equipment necessary for the production. During this phase, there is a lack of information regarding the field, mainly about the reservoir behavior. Normally, the reservoir behavior is calibrated during the productive life of the field. Due to this, the operators usually adopt a conventional solution, not considering the use of new technologies as the first alternative. These are considered most when they are vital for a specific field development. For most fields in Campos Basin, Brazil, the main recovery mechanism for reservoirs, since the beginning of the production, is waterflooding. A typical curve of produced fluids starts with the predominance of oil, rising to the production plateau, until the water breakthrough occurs. At this point, the production presents increasing water content in the liquid stream. So, as it is necessary a massive water injection to keep the pressure of the reservoir, after a few years the watercut of the production increases a lot. Additionally to the two aspects described above, there is also a need to overcome the constraints of existing platforms. These motivations led Petrobras to start in the early 90's the development of subsea processing and boosting solutions. Technological Programs were created to support these developments. Several processing and boosting projects were installed since year 2001, when the VASPS was deployed in the Marimba Field (Campos Basin, Brazil). These projects will be described in a brief way in this paper, focusing their main technological aspects.

How do early and recent life stress shape cortisol reactivity and decision making in middle-to-older adulthood?

This paper presents an alternative form of IPR, called in this study “Gas Dynamic IPR” (GDIPR), and compares it with the performance of conventional Inflow Performance Relationships (IPR) for gas reservoirs. The main objective of the GDIPR is to provide a simple but robust IPR solution for gas wells under transient conditions for the early and late life of gas reservoirs. Conventional IPR models are often not able to capture transient effects for the late life of gas reservoirs. The GDIPR solution, on the other hand, can be used for the cases of buildup and drawdown tests (early life), and for the modeling of transient liquid loading phenomena in gas wells (late life). The GDIPR is compared to conventional IPR models in two case studies. The comparison analysis show that the conventional IPR models do not provide reliable results, while the GDIPR is in agreement with the solution from discretized reservoir models. The GDIPR technique is computationally less expensive than discretized reservoir models, and is able to capture both the transient well behavior and the steady-state solution, for early and late life of gas reservoirs.

The Laggan-Tormore gas field is a deepwater development located 125 km off the West Coast of the UK Shetland Islands, in the North Atlantic. The field consists of five subsea production wells tied back to subsea manifolds that are connected to two 18-in multiphase pipelines. In addition, two other subsea templates consisting of three subsea wells are connected to the field via a 35-km tieback. The gas field development is unique for the UK Offshore Northern Sector in that produced fluids and gas are not processed offshore. Instead, the fluids and gas are transported via the two 18-in diameter, 143-km multiphase pipelines from the offshore fields to an onshore gas plant on Shetland for processing. The multiphase pipelines are constructed from carbon steel, and therefore, to prevent corrosion an inhibitor was required. Monoethylene glycol is injected in the field at the subsea manifolds for hydrate control, and to facilitate the delivery of the corrosion inhibitor, chemical is injected in combination with the glycol. Mitigation of corrosion in the Laggan-Tormore multiphase pipelines presented several challenges. The glycol used in the field is recycled via a regeneration unit. Consequently, the corrosion inhibitor would have to withstand the high temperatures within the unit and not suffer physical degradation or a decrease in efficacy when exposed to the unit. Considering there is only one corrosion inhibitor injection location for each multiphase pipeline, the inhibitor is required to be transported the whole length of the multiphase pipeline and provide protection of its entirety. Finally, there is no corrosion monitoring in place in the subsea pipelines. Therefore, to determine if the pipelines are under corrosion control, analysis of the produced fluids to provide an indirect measurement of the corrosion rate was required, including iron counts, corrosivity measurements of the produced fluids, and corrosion inhibitor residual analysis. This paper discusses the laboratory work carried out to develop a corrosion inhibitor for this application, details its deployment and provides an overview of the ongoing monitoring performed to ensure the integrity of the multiphase pipelines.

The Poseidon project aims at developing technology for subsea multiphase development of offshore oil and gas fields. This paper shows the potential of this technology through three synthetic North Sea field examples. The investment cost may be reduced by 10-40% using multiphase technology. Realizing this technology with an unmanned wellhead platform concept or a subsea (Poseidon) concept may give neglible cost differences. The main technical areas of concern are listed and some conclusions are drawn as to the future use of multiphase technology. THE POSEIDON PROJECT The Poseidon project was started in 1984 as a cooperation between Institut Francais du Petrole (IFP), Total and Statoil. The aim of the five year project is to develop the technology for subsea development of deepwater oil and gas fields. The concept, fig. 1 includes subsea wells, subsea multiphase pumps and long distance multiphase pipelines. In this project, IFP has developed a multiphase pump. An industrial prototype of this pump will be tested in a flow-loop, outside Lyon late 1988. Total has developed the subsea station and put main emphasis on full-scale test of an electric motor for the multiphase pump. This motor was tested in 150 meters of water outside the west coast of Norway in the autumn of 1987. Statoil's part of the work has been the pipeline system. A computer program for dynamic simulation of multiphase flow has been developed and used to study slugging phenomena and transient behaviour during start-up and shut-down of the pipeline. Moreover, numerous tests have been performed to study hydrate formation in flowing media as well as corrosion and erosion in the presence of oil, gas water and sand. Special consideration has been given to corrosion under sand beds and inhibitor efficiency in the roof of pipelines carrying mainly gas. Instrumentation for reservoir monitoring and control of pump inlet conditions have been studied. Finally, Statoil has headed the field concept studies in which also personnel from Total and IFP have taken part. This paper will present some of the conclusions from these studies. CONVENTIONAL OIL AND GAS FIELD DEVELOPMENTS Fig. 2 shows the functions included in a conventional field development. To arrive at new concepts it is necessary to consider if all these functions are necessary and where the accompanying equipment should be placed. Apart from the pipelines, the main part of the equipment and therefore also the investment and operating costs are connected to well control/manifolding, separation and pumping. Well control and manifolding are always necessary. The question is therefore whether the equipment should be placed on a platform or on the sea bottom. The equipment for separation and pumping is today always placed on a platform. Platforms for water depths of 70 to 500 meters, as in the Norwegian part of the North Sea, tends to be very large constructions, fig. 3. The Gullfaks C platform, which will be installed in 220 meters of water depths late this year, will cost in the order of 18 billion NOK.

A detailed geotechnical investigation was undertaken at the Kinsale Head Gas Field in the Celtic Sea. Five-inch-diameter cores were recovered to a terminal penetration of 400 ft below the seafloor from two foundation borings drilled in a water depth of about 300 ft. Chalk extended continuously below 10-ft-thick surficial deposits of sand and gravel. Laboratory tests were conducted on the chalk samples to determine chemical and physical properties, and laboratory model techniques were developed to evaluate adhesion along a chalk-grout interface. The engineering properties of the chalk as determined from the field and laboratory study were used to develop suitable design parameters for two fixed offshore platforms recently installed in the Kinsale Head Gas Field. Graphical correlations of water content, unit dry weight, unconfined compressive strength and modulus of elasticity of the chalk are presented along with the chalk strength profiles with penetration. Chalk-grout adhesion results are discussed. The Celtic Sea chalk appears to be stronger and more dense than the English Upper Chalk and shows similarities to the chalk of Northern Ireland. Tests indicated that samples of fractured chalk softened and disintegrated rapidly when exposed to saltwater, unlike competent chalk which was unaffected by similar exposure. INTRODUCTION The constitution and properties of chalk from many regions of the British Isles are extensively documented. There is, however, an appreciable lack of information concerning chalk from the Celtic Sea area. In the fall of 1973, a detailed study was made to determine foundation conditions at two locations in the Kinsale Gas Field in the Celtic Sea (see Figure 1). The study was aimed at providing sufficient information for the design and installation of two template-type structures, requiring that two deep foundation borings (350 to 400-ft penetration) be made in the chalk. This paper presents the results of a comprehensive series of laboratory tests made to determine the geotechnical properties of chalk samples recovered from the borings. Two 8-pile platforms were recently installed successfully at the study locations. The foundation system consisted of large-diameter pipe piles driven to about 50-ft penetration with smaller-diameter pipe piles grouted into predrilled holes in the chalk below 50-ft penetration. Information concerning foundation design parameters and installation details of these piles will hopefully be published in the near future. CHALK CORING OPERATIONS The Kinsale Head Gas Field is located approximately 35 miles southeast of Cork, Ireland, as shown in Figure 1. In the area of the gas field, water depths range from 283 to 310 ft. The measured water depth at the boring locations was 295 ft, subject to tidal variations of about 13.5 ft. The seafloor is generally level, except for isolated areas of small sand waves. Shallow seismic information indicated that there were areas where unconsolidated sediments were present at the seafloor and areas where chalk outcropped at the seafloor. At the boring locations, these sediments were approximately 10 ft thick, consisting mainly of coarse sand and gravel. Beneath the surficial deposits, chalk exists continuously to below the terminal penetration of the borings.

A large number of factors influence the choice of production system for a particular oil and gas field. This paper outlines the key drivers that govern the selection process for one subset of systems-surface facilities for deepwater production- and verifies them using a comprehensive database of deepwater platforms. Regional variations-natural, industrial, political and experiential-are seen to be particularly important in the selection process. For fields benefiting from platform drilling and/or workover, the water depth and well count are key drivers. The matrix approach to system comparison presented in the paper also highlights future technology developments across a range of disciplines required for more efficient hydrocarbon production in ultra-deepwater. Both new platform types, and enhancements of existing facilities to extend their applicability, are described. Overall, subsea well systems are anticipated to find increasing application as water depths increase. Introduction Offshore oil and gas fields may be developed using a variety of production systems. The configuration of the optimum system for a particular application depends on a myriad of factors [1]. First, the selection criteria used to determine the "best" solution must be defined-these are likely to be lifecycle financial value as well as other more subjective measures. The field characteristics are important, including site, regional, global and company parameters, as are the elements of the preferred production plan to deplete the reservoir. The hardware components required to deliver the production plan have inherent advantages and limitations that must be correlated with each other and to the field and production parameters; system selection involves optimising these synergies. Potential risks associated with the system must also be recognised. However, of these many factors, only a few become the key drivers that govern the final selection decision, although these key drivers vary according to the field and production characteristics. The system selection process is greatly facilitated when the key drivers are understood. This paper describes a sequence of key drivers for facility selection in deepwater. It is presented in tabular form and justified using a database of past, current and sanctioned deepwater platforms. Anticipated innovations are also discussed briefly to appreciate how these might influence both the range of facility choices available, and the selection process. Deepwater Facilities "Deepwater" is defined in the study to be greater than 300m (nearly 1,000ft), giving a reasonable sample size of 89 facilities. This cut-off enables all compliant towers to be included, along with some important North Sea platforms. Conventional shallow water fixed platform technology is ignored even though both jackets and concrete gravity structures have been installed in water depths greater than 300m. Subsea tiebacks to existing facilities are also excluded. This leaves six proven deepwater platform types-FPSOs, semisubmersibles, spars, compliant towers, TLPs and mini-TLPs [2-4]. Here, the mini-TLP is differentiated from conventional TLPs by supporting subsea trees, with the first three mono-column TLPs being of this type. Table 1 summarises key statistics of the various facility types; a detailed comparison is presented in [1].

Earlier employment choices based on family events in earlier life have an impact up until late working life, especially in welfare regimes that encourage the breadwinner-caretaker division. We investigate types of late employment patterns and how these are associated with earlier family events. We also test whether the association between early family history and late working life varies across five welfare regimes. Using retrospective life history data from SHARELIFE, our sample consists of 10,913 women and 10,614 men aged 65 years and older. Late working life trajectories are analyzed using gender-separate sequence analyses, which are summarized into eight groups applying cluster analyses. Using average marginal and interaction effects, we explain how the association between types of late working life, coresidential partnership history and parenthood history differs by welfare states. For instance, women’s late employment is either shaped by unpaid care or paid (full- or part-time) work but not both, whereas men’s late working life is mainly shaped by full-time work. Family history in earlier life is linked to unpaid care and part-time work—an association strongest in liberal and southern welfare regimes. However, among men earlier family events are linked to full-time work. Policymakers need gender-specific strategies to integrate workers into late working life. The implementation of new policies should aim to prevent these social inequalities in early life, as employment decisions caused by family history in earlier life stages—especially for women—tend to cumulate over the life course.

Through the use of a High Integrity Pressure Protection System (HIPP$) the flare capacity of a well head platform can be reduced to the flowrate required for depressurisation. The HIPPS may also be used to reduce the are capacity of a process plant. By the use of HIPPS, the discharge of hydrocarbons or carbon dioxide due to venting/flaring is reduced. This paper describes the development of HIPPS for the Sleipner B-platform offshore Norway. A 20" multiphase pipeline is protected against overpressure by two 20" quick acting shut down valves (QW installed in series, instead ofpressure safety valves. The valves have been qualified for operation in well stream at a shut-in pressure of 336 bar, and have a closing time of 2 seconds. Each of the QSKS has independent, fail safe instrumentation circuits. A parallel rain of QSV.s has been installed due to the testing requirements. The estimated saving using HIPPS on SLB was $25 mill. The paper also discuss existing and new applications of the HIPPS. INTRODUCTION The Sleirmer Vest is a gas field, containing 33 billion Sm 3 of sales gas 29 million of code oil and; mill. tons of NGL. The development consists of two platforms, a wellhead platform (SLB), and a gas treatment platform (SLT). Platform production is 20.5 mill Sm3/Dof sales gas and 450 Sm3/hrof condensate(including NGL). Sleipner Vest will come on stream in 1996. The well head platform is connected to the treatment platform via a 20" multiphase pipeline. The Sleipner Vest interfiled pipeline has a design pressure of 160 barg, while the wellhead shut-in pressure on Sleipner B is 336 barg. It is therefore necessary to protect the pipeline against the wellhead pressure. The flowrate in the pipeline is 250 kg/s. The main scenarios for over pressure in the pipeline was considered to be hydrate formation, pigging and closing of the inlet valve on Sleipner T. A flare system designed for blocked outlet, i.e. fill flow, is Expensive at the high flow rate required (250 kg). It was therefore decided to use a HIPPS. The HIPPS on Sleipner B is shown in figure 1. PROBLEM DESCRIPTION For this paper HIPPS is defined to be a system for Over pressure protection of process equipment by utilizing dedicated shutdown valves. The HIPPS system protects the equipment against over pressure by closing down the source of the over pressure. HIPPS has been used offshore in production systems for several applications, mostly for tie-ins of new fields to existing platforms, or as a modification to platforms where the flare capacity is limiting for the oil production. A number of different valve types, instrumentation concepts, valve configuration etc. has been used. In terms of equipment, valve configuration etc. API RF'14C, ref. /1/, has traditionally been used for design of process safety systems offshore, but does not describe the application of HIPPS. Overpressure protection by the use of double shut down valves is permitted for wells, but the use of additional PSVS are still recommended by API.

The use of subsea technologies and innovative field architectures as development solutions for oil and gas fields is fast becoming a reality. In the last ten years more than half of new global oil and gas reserves have been discovered offshore, especially in deepwater. This paper shows the selection path followed systematically for the proper technical and economical solution selection, passing through concept screening and case-specific conceptual studies. A typical case study will be presented in this paper, showing the advantages to be gained in using the proposed selection exercise, including flow assurance strategies, for the development of challenging new upcoming reserves deepwater. The values presented are for a generic offshore development. The purpose is to pinpoint the limits of existing technologies, identify new subsea architectures implementing upcoming subsea processing solutions and compare and illustrate the performances of several configurations for a development in about 1000 m of water, through a case study. A problematic oil will be considered, having a density in the range of 20–30 °API, a GOR in the range of 200–400 scf/bbl, wax and hydrate formation risk. Total liquid flowrate in the example is around 50,000 bbl/d, selected in order to be out of giant project frame. Conventional loop, single production line, electrical heating, gas/liquid separation, subsea liquid or multiphase boosting are the scrutinized solutions, applied considering on site or long distance topside facilities and upward or downward production line path. The analysis reported in this paper evidences the technical feasibility and when benefits are obtainable implementing subsea processing technology on offshore oil and gas fields. The principles described could be the base to perform a multi-parameters study for real case technology selection. This paper examines the drawbacks, limitations and advantages of various field architectures and technology solutions, that may be considered for deepwater oil development. It covers the different production phases, from start-up to tail production, without forgetting flow assurance issues, typical of long satellite tie-back lengths in deep waters. INTRODUCTION In the last ten years more than half of new global oil and gas reserves were discovered offshore, especially in deepwater [1]. Usually such hydrocarbons reservoirs are located in remote areas, far from existing facilities. Traditional development solutions to exploit this kind of reserves are no longer applicable, due to both technical and economical constraints. Technologically advanced solutions are needed in order to efficiently produce oil and gas from satellite fields to overcome technical and economical difficulties. Especially for marginal fields, containing relatively small amounts of reserves in place, increasing the overall recovery factor is crucial to make the field economically sustainable. Marginal fields means too small to support the investment required for a conventional standalone development or too depth and far from existing facilities to be produced by means of conventional surface production technologies. Therefore marginal fields are more challenging to exploit in a cost-effective manner. The only way to unlock these reserves is to minimize the investment for facilities that will extract and process the hydrocarbons.