Programme For Standardization Of Subsea Equipment

Offshore oil and gas production systems are complex systems comprised of wells, flow lines, a variety of subsea and dry subsystems, production platforms and export lines. Hydraulic systems are extensively used in offshore production systems, particularly for valves control and operation. Failures in hydraulics systems may cause loss of redundancy, loss of control and well shut-in with economic losses and risks to system integrity and environment. Leaks, mostly internal, represent one of the most common failures in the hydraulic systems. The conventional approach to repair these leaks makes use of rig and/or support vessels, being time and money consuming, not mentioning the risks imposed to the system under intervention. The difficulty, risks and costs increase with water depth. In the Campos Basin, offshore Brazil, with around 500 subsea wells, in water depths range from shallow to ultra deep, leaks in hydraulic systems have a significant impact on maintenance costs. Sensitive components are down-hole safety valves, wet christmas trees valves, annulus subsurface safety valves and subsea manifolds subsystems. These aspects made the search for reliable remote or light workover solutions an important issue. A promising solution was introduced in Campos Basin in the year 2000, which makes use of a pressure-activated sealant fluid. This paper presents a case study comprised of tens of pressure-activated sealant applications, both in fixed and floating systems, carried out in Campos Basin in the last four years. The paper summarizes the operational programs, the field reports, the post-job analyses and the results achieved. The study revealed that pressure-activated sealants are a safe and economic method to repair leaks in offshore hydraulic systems. As the number of offshore oil and gas production systems, mainly the floating ones, tends to increase considerably in the near future, the knowledge acquired in Campos Basin may be useful worldwide. The main differential of this paper is a thorough and critical review, from the operator point of view, of 71 applications from 01/21/2000 to 05/16/2005.

Of the three subsea wells, drilled so far at the Oseberg field, two wells (drilled in 87/88) have a slight deviation to the true vertical, while the third well has been horizontally drilled (91) in the Gamma North Reservoir. This well will be producing gas for injection into the Oseberg Alpha Reservoir, To enable service of horizontal parts of this last drilled well, use of coiled tubing operations will be necessary. When introducing coiled tubing in operations with X-mas tree and completion/workover riser from a floater, a safety problem occurred with respect to shut in of the well, This ended up with the Subsea Well Intervention BOP (SWIB) where Ram Blow-out-preventer technology was used. Additionally, in order to ensure safe operation in case the floating rig drifting off location, an Emergency Quick Disconnect Package (EQDP) was placed on top of the SWIB. INTRODUCTION The Gamma North reservoir was developed by Norsk Hydro and its five partners*, as part of the Oseberg phase two development, and completed in October 1991. The Oseberg Field is located in blocks 30/6 and 30/9 in the Norwegian Sector of the North Sea. The Gamma North Structure, part of block 30/6, was decided to be developed with one subsea well, in order to exploit its gas reserves for reinfection into the main Oseberg reservoir. However, the nature of the structure also allowed the development of a thin oil layer, which required the drilling of a horizontal section of approximately 700 m. This means that the subsea well, located approximately 9 km. away from the Oseberg C platform as shown in Fig. 1, initially will be producing 10.000bbl/d (max) of oil through an 8" pipeline before the gas production starts. Additionally a 3" service line and an electro-hydraulic umbilical were installed connecting the Gamma North satellite to the Oseberg C platform. The philosophy for all the subsea equipment in the Oseberg Field is to be able to interchange the equipment between the various wells (two subsea wells B49 and B50 were put in operation in 1988). When completing the horizontally drilled Gamma North well, only minor wireline operations were possible, To be able to service the horizontal part of the well, use of coiled tubing operations are necessary. When this was brought forward, the equipment did not comply with the operating philosophy safetywise. The need for more sophisticated cutting mechanism to cut coiled tubing was looked for. Since the similarity between drilling operation and coiled tubing operations are striking when coming to pressure control, it was obvious to use the same well-known drilling BOP technology for coiled tubing operations. This led to the development of the SWIB, Subsea Well Intervention BOP. The new Subsea Well Intervention BOP was put on order in May 1991.

Downhole Safety Valves (DHSVs) have traditionally been viewed as essential barriers in offshore wells, particularly after high‑profile incidents and the adoption of dual‑barrier regulatory principles. In the early 2000s, however, a Brazilian deepwater operator adopted a different strategy for isolated subsea wells in the Campos Basin, opting not to install DHSVs based on quantitative risk assessments and a robust definition of "isolated well". Approximately 370 subsea wells were completed under this philosophy between 2003 and 2010. This strategy relied on field layouts designed to ensure true well isolation, supported by analyses of dropped‑object and riser‑footprint behavior. Flowlines and jumpers were intentionally designed with weak links to limit load transmission to wellhead and tree structures in the event of accidental line tension or snagging. Over more than two decades of operation, these wells experienced no major environmental events, and the absence of DHSV failures eliminated numerous heavy workovers—reducing both operational risk and greenhouse gas emissions. After the Macondo accident, a revised regulatory framework in Brazil (2016) made DHSV installation mandatory in natural flowing subsea wells. Updated quantitative studies, however, reinforced that although a DHSV does reduce certain high‑consequence risks, the incremental risk reduction in isolated wells is small compared with the substantial risk and cost of heavy workovers to replace failed valves. This led to a transition from "no‑DHSV" completions to an "install‑but‑do‑not‑replace" philosophy for isolated wells operating under modern risk‑based integrity management. Finally, the paper presents a methodology that allows us to quantitatively assessing the well integrity level (WIL) and the Incremental Cumulative Risk (ICR) caused by the failure.

This paper presents the concept and the technical solutions developed and applied to the Ormen Lange subsea production system. First, the key technical challenges related to the subsea system are presented. Thereafter the paper describes the extensive design, fabrication and testing processes undertaken in order to verify correct functionality and gain confidence in the applied solutions. Finally the paper summarizes achievements and key success factors for the project. Introduction The Ormen Lange field is located in the Norwegian Sea, approximately 100 km off the northwest coast of Norway. The field is located within a prehistoric slide area, the Storegga Slide, with water depths reaching 850 meters in the main production area. The selected development concept for Ormen Lange comprises a subsea tieback to an onshore processing plant at Nyhamna as shown in Fig. 1. Fig. 1 Ormen Lange initial subsea development (Available in full paper) The gas will be produced from up to 24 subsea wells. The well fluid will be transported to the Nyhamna plant via two 30" multiphase lines. After processing, the dry export gas is transported from the onshore plant through a new 42" pipeline via the Sleipner riser platform and further through a new 44" pipeline to the gas-receiving terminal in Easington, England. Overall project schedule. The conceptual engineering of the subsea production system was initiated in 2002. The main contracts for subsea equipment supply, umbilical fabrication and template installation were awarded between the autumn of 2003 and the summer of 2004. The main part of fabrication and testing took place during 2004/2005 with the subsea templates installed offshore in the late summer of 2005. Umbilical A and remaining subsea equipment were installed during the summer of 2006 and the first Xmas tree was installed on Template A in December 2006. Completion of the first subsea well on Template A is scheduled for spring 2007 and subsea production start-up scheduled for autumn of 2007. Subsea system configuration. Due to the large geographical extension of the Ormen Lange reservoir and the risk of reservoir segmentation, the subsea system design has a high degree of flexibility with four planned template locations. For this reason, a phased development scheme has been chosen. The phasing and location of the subsea wells will be timed to maintain plateau production as the field depletes. Initial development. The initial subsea development consists of two 8-slot production templates (A & B), located approximately 4 km apart in the main production area. Each template is tied back into the two 30" multiphase pipelines to shore. The two 30" lines are interconnected via a pipeline end termination system (PLET) as shown in Fig. 2. Two main control umbilicals link the onshore plant to the subsea production system; one is connected to template A, and the other to template B. A crossover control umbilical interconnects the two production templates, providing redundant hydraulic supply to all the subsea wells. For prevention of hydrate formation, all wells are continuously injected with monoethylene glycol (MEG) via two 6" pipelines from the onshore plant.

The physical integrity of a well is a lynchpin for any oil and gas company to achieving it's production target safely. In a deep water field with subsea wells, ensuring the physical integrity of the wells is paramount. It is given key focus because of the high value of the investment, difficultly in accessibility and the sensitivity of the surrounding environment. Subsequently, it is important that all subsea wells in a deepwater field with observed excursions outside of it's annulus limits are investigated in systematic manner to prevent any incidents or loss of containment. Field X is an offshore deep water asset in the Gulf of Guinea. The field is developed by subsea wells tied back and producing to an FPSO. It's subsea wells are drilled and completed in ca 3300 ft of water targeting hydrocarbon bearing reservoirs, with reservoir depths ranging from 7600 ftss to 10200 ftss. The wells were completed with the full capability to monitor the pressure, temperature and to control the xmas tree valves remotely from the FPSO. The maximum allowable annulus surface pressure (MAASP) and the minimum annulus pressure (minAP) limits are set for each well based on the stress modeling of the expected operating conditions during the life of the well and the casing and tubing stress and tensile limits. The MAASP, MAWOP and MinAP annulus pressure limits are part of the well and reservoir operating envelope (OE) which specify the operating points and the boundaries governing the safe production. Since the start of production in the mid 2000's, the asset team has observed that several wells exceed the set annulus pressure limits in the operating envelopes. These non-routine excursions, are detected automatically on the FPSO by the DCS and reported on the Processbook and the electronic well integrity management system portal (e-WIMS). These exceptions are an indication of a potential problem or leak within the well or a valve in the subsea xmas tree. To determine the root cause of the annulus pressure excursion or the possible leak paths/points, an annulus investigation is be conducted on the well. The annulus investigation is a workflow that starts with a preliminary risk assessment of the observed excursion. Thereafter, a systematic workflow is followed, which requires a comprehensive work program or FMS to determine the root cause of the suspected leaks. After the investigation is executed in the field, the results are analyzed and a follow-up risk assessment is held to determine the mitigating actions to manage the well safely. This paper presents the gamut of annulus problems observed in the wells in field X, the premise for executing an annulus investigation, the workflow and the results and the mitigating actions taken to minimize the risk of incident. Well integrity is an important aspect of managing an oil and gas asset. This paper demonstrates how annulus investigations are executed as a effective tool in a process to ensure the physical integrity and safety of these wells.

Wellhead and Xmas tree are the components at the surface of an oil or gas well that provide the structural and pressure-containing interface for the drilling and production equipment. During completion of the well, sometimes Electric Submersible Pumps (ESP's) are used to lift the oil from the well. Conventional ESP is deployed by attaching the ESP in line with the tubing string while the power cable is run outside of the tubing and then terminated at the wellhead tubing hanger section. A new rigless cable-deployed ESP is developed to reduce operation cost and to improve time efficiency. This new rigless cable-deployed ESP requires the ESP cable to be run cased inside the coil tubing, through the Xmas tree, and horizontally terminated at the specially designed vertical completion wellhead system. This paper focuses on the challenges, results, and lessons learned from the first prototype test of the specially designed wellhead for rigless cable-deployed ESP (rigless ESP wellhead) inside 7– completion tubing. The rigless ESP wellhead system provides hang off and vertical production flow capabilities for the rigless cable-deployed ESP. This wellhead also enables the ESP cable to be terminated below the production Xmas tree and to self-align for the horizontal surface termination for external cable interface, isolated from the production bore fluids. As the ESP is run through the Xmas tree, the self-alignment system is very crucial for the successful termination of the ESP cable. A bowl protector is also an important part of the system which protects the seal area of the wellhead while running the ESP cable through the small bore area of the wellhead. Existing coil cable-deployed ESP's in the market requires a horizontal completion Xmas tree for the production fluid to flow below the surface cable termination. Therefore large platform space is needed to accommodate the Xmas tree. The new rigless ESP wellhead system allows vertical flow of production fluid through the flow-by holes inside the wellhead around the surface cable termination. This design allows the use of standard vertical Xmas tree and does not require large horizontal space. Therefore, this system can be installed on existing platform space for upgrading current installed ESP to rigless cable-deployed ESP. Lessons learned from the first successful prototype test will be used to improve the system for future field deployments, as well as for the design of similar systems for smaller size tubing (4-1/2″). As part of the wider rigless cable-deployed ESP system, rigless ESP wellhead will reduce the time and cost for ESP deployment and workover.

Offshore operators tie successful subsea exploratory wells into field plans when possible and have used a variety of adaptation bases to complete the wells. The expense and complexity of these bases led to redesign of the subsea wellhead/- guidebase system to make completion less expensive and easier. Equipment described includes a universal 30" housing, retrievable drilling guide structures, and completion guide structures. Styles and procedures for diver/Remote Operated Vehicle-assist, diverless guideline, and diverless guidelineless installation are reviewed. In addition to achieving cost savings by reusing the retrievable drilling structures, two-stage guide structure systems described here allow custom design of the completion structure/ flowline assembly after the field development plan is finalized. INTRODUCTION (Figure 1) Subsea wellhead systems have been used for over 20 years for exploratory and development drilling. Two recent changes in operator's standard development programs have required design changes in the wellhead system to make exploratory well drilling equipment adaptable for subsea completion without large initial capital investment. The first change in common development programs has been to incorporate successful discovery wells into field development plans. In diver depths, these wells have been historically completed subsea with relatively simple adaptation bases landed over the existing guide base that include flowline connection and tree alignment provisions. Beyond diver depth, adaptation bases are complex and expensive, sometimes requiring a tubing spool adapter. This requires an additional wellhead connector and introduces a new set of seals with consequent leak path potential. The second change is to include satellite subsea completions in field development plans. When drilling a subsea well with completion a certainty, a flowline receptacle adaptation system can be incorporated in the drilling guide base. However, the well is usually drilled 6 to 12 months in advance of completion equipment manufacture. Close manufacturing tolerances and expensive test jigs are required to insure fit-up of the completion tree and flowline receptacle. Adaptation systems, whether for wells preplanned for completion, or discovery wells, also have the disadvantage of potential tree landing problems if excess cement or other debris has collected around the permanent guide structure during drilling. For these reasons, new retrievable drilling and completion guide bases were designed to simplify completing subsea wells, making the operation less expensive and more reliable. After drilling a well, the drilling base is retrieved, leaving the 30" housing ready to receive a completion base. The universal 30" housing provides a simple interface with known manufacturing tolerances. The completion base is manufactured as a part of the completion system, allowing complete fit-up testing at the factory and on the rig installing the completion equipment. Several types of retrievable drilling and completion bases have been designed allowing for diver/ROV assist and diverless guideline and guideline less drilling and completion.

Monohull based production platforms are the most widelyused floating production systems worldwide. They are proven as a reliable workhorse and have provided the industry with a commercially attractive platform for producing large and small offshore oil developments in most major offshore producing regions. The ship-shaped monohull offers low cost "real estate" for production facilities, and its integrated storage and offloading feature eliminates the oil export pipeline. To date an FPSO * has not been employed in the US Gulf of Mexico because of the extensive infrastructure of existing host platforms and pipelines on the continental shelf. However, in recent OCS lease sales, operators have acquired vast, undeveloped acreage that is increasingly remote from this infrastructure. Beyond the shelf, the potential for a low capital cost platform and elimination of, what can be a cripplingly expensive oil export trunkline, has many operators considering FPSOs to develop these remote, deepwater prospects. This paper examines and discusses major technical and regulatory issues that the industry (regulators, operators, contractors) must collectively address prior to introducing the first FPSO into the US Gulf of Mexico. * Abbreviations are explained at the end of the paper. Introduction The monohull FPSO was first used to produce the small Castellon field in the Mediterranean Sea in 1977. The system produced 20,000 bopd from a single subsea well tied-back to a turret moored converted tanker in 350 feet of water. This FPSO was the genesis of what has become the most widely employed floating production system worldwide. Over 60% of the worlds floating production platforms in use today are either converted from tankers or are purpose built monohulls. From 1977 to 1993, 24 FPSOs were installed, 17 of which were conversions. They were mostly used to develop small oil fields in areas remote from pipeline infrastructure. Large integrated oil storage capacity permited periodic shuttling of parcels of produced crude in shuttle tankers to a sales point, while enabling uninterrupted production and eliminating the need for an oil pipeline. These FPSOs proved to be reliable workhorses, that gave operators a commercial option to exploit marginal, remote oil fields. As confidence in these systems grew, along with technological advances in subsea wells and flexible risers, operators began to expand their application to progressively larger developments in increasingly deeper waters and harsher environments. Since 1994, 36 FPSOs have been installed. Of these, 15 are in the demanding North Sea and Atlantic Frontier Provinces. Petrobras has converted several VLCCs for use as FPSOs in the Campos basin in water depths upto 6000 feet. Table 1 captures the progression of FPSOs from its humble beginnings at Castellon, to the most technologically advanced FPSO recently installed in Statoils Asgard field in the Norwegian North Sea. Despite its widespread and burgeoning use, only one FPSO has been employed to develop an offshore field in US waters. That was Exxon's Offshore Storage and Treating Unit (OS&T) that operated in the Santa Barbara Channel in 500 feet of water from 1981 to 1995. A monohull FPS has never been used in the US Gulf of Mexico, one of the most prolific offshore oil and gas producing regions in the world.

This paper presents the swivel system to be used for the Lufeng Field Development. A general technical description and future perspectives for the swivel system is also provided. The Lufeng 22/1 field is located in the South China Sea. The field will be developed with Statoil's Multipurpose Shuttle Tanker (MST) as an FPSO (Ref. Fig. 1). The MST will be equipped with a compact swivel arrangement, the "Rotating Connector". The Rotating Connector for the Lufeng field is a quick disconnectable swivel system providing two off 7" (3000 psi) flow paths, transfemng electric high power to the electric driven subsea booster pumps (5 off) together with electric and hydraulic control lines for the subsea wells. The swivel arrangement is integrated on the STP buoy and located inside the STP compartment. In general, the Rotating Connector is a standardized swivel design which allows for the inclusion of several high pressure risers and umbilicals, providing the interface between the subsea wells and the Process Plant on the Vessel. The Rotating Connector is a passive system permitting the vessel to weathemane freely around the anchored Turret Shaft. The technology is innovative but simple, compact and flexible, and when this technology is combined with a FPSO, a wide range of applications becomes available. It may be adapted to different field requirements to generate a safe, standardized, cost-effective and flexible solution. Introduction Statoil Orient Inc. is presently developing the Lufeng 22/1 field in the South China Sea. The field will be developed using five subsea horizontal wells drilled and completed on a single template, which is connected to the FPSO by means of two flexible flow line risers (Ref. Fig. 2). Due to the low wellhead pressure, energy must be added to the well fluid in order to lift the fluid and maintain pressure to the inlet of the surface processing facilities. The artificial lift will be performed by individual electric driven booster pumps, integrated on each x-mas tree. In addition to the flow line risers, a control umbilical for the x-mas trees and a booster pump electric power umbilical will terminate on the FPSO turret. The FPSO is a multipurpose shuttle tanker (MST) owned by Statoil, fitted with a STP buoy/mooring and swivel arrangement. Frarno Engineering AS has been awarded the contracts of supplying the complete subsea booster pump system and the swivel system (Ref. Fig. 3). The Rotating Connector (RC) is integrated on top of the STP buoy and located inside the STP compartment. The Rotating Connector block is assembled inside the STP buoy and made up to the swivel stack. Flexible hoses connected to the swivel is directing the process fluid via isolation valves and deck bulkhead connectors to the process facilities. Rotating Connector for Lufeng The Rotating Connector (patented world-wide) for the Lufeng field development is a two-path fluid swivel, each with 7" diameter, and the design pressure is 200 bar at an operating temperature of 100°C (Ref. Fig. 43).

This paper shows the Brazilian 14 year experience (from 1977 to 1991), concerning 45 permanent installations of downhole pressure gauges, 41 installed in subsea completions in the Campos Basin, offshore Brazil. Some Brazilian and worldwide statistics regarding permanent gauges installation performance are also presented along with failure and diagnosis analysis. Petrobras Research Center has used these statistics to design a simple and reliable subsea installation, encompassing the state of the art and introducing some innovations. Applying this new design, Brazil intends to perform 65 permanent installations in subseawells (40 of them in deepwater: over 400 m / 1,312 ft of water depth) in the Campos Basin during the 90s. six out -of these 65 installations have already been performed in 1990 and 1991, including 3 very deepwater wells in the Marlim field. Reservoir and well monitoring, using downhole pressure and temperature gauges, minimizes costs by minimizing lost production and lowers accident risks through the reduction of workover operations. It also helps the production optimization through early diagnosis of formation damage, wax deposition, leaks, shut-downs, etc. The Brazilian design for permanent installations is based on simplicity, high integration among pertinent areas (operator and service companies), and on stringent feasibility studies for well choice. This design is supposed to yield large savings and increase the worldwide Mean Time To Failure (MTTF) from the current 3 years to 6 years by the end of the 90s, reaching the expected Brazilian mean time between workovers in subsea wells. INTRODUCTION Worldwid, the topic of permanent downhole sensors 1S still polemic. During an initial phase (late 70s, early 80s), the large failure rate, probably due to the introduction of the technology and the utilization of a logging cable without any type of encapsulation, created a large opposition to the installation of such systems. The statistics have shown clearly that the major part of the failures occurred inside the well. During the second phase of development of the permanent gauges technology in the mid 80s, the performance of these systems improved, but not to the point of reversing the negative feeling created by the failures of the pioneer installations. Notably, one noticed during this period the introduction of hydro acoustical transmission systems, andother innovations such as the utilization of a downhole cable protected by a nitrile encapsulation. The present phase of development of permanentgauge systems, started in 1986/1987. It is characterized by a stream of modifications such as the introduction of stainlesssteel encased cables (which guarantees the pressure integrity for the electrical connections at both ends), coupled with the utilization of metallic protectors. A bigger importance is given to the management of the project with the aim of a better interfacing of each component of the system. MUltiplexed subsea control systems are also appearing. New service companies offer permanent gauge systems, specially in the North Sea.

Subsea equipments can be considered nowadays a mature option for offshore field developments. In Brazil, since the first oil in Campos Basin, different concepts ranging from one atmosphere chambers to deepwater guidelineless x-mas trees, have been tested, contributing for this development. @The experience acquired during these years makes it possible to combine the proven systems to the new technologies being developed, for the design of subsea manifolds The main target is more etllciency and cost reduction. When choosing a manifold concept. a usual rule is applicable: the simpler the better. The maturity, confidence and reliability obtained, allow the usage of resident hydraulically actuated valves, simplifying considerably the manifold arrangement. Other contributions come from: the reduction of piping bend radius allowed by the new pigs; the increased reliability of subsea instrumentation and chokes, allowing elimination of the gas-lift-test flowline, and the development of the direct vertical connection, that turns subsea tie-ins very fast and easy operations. Combining all that with the new technology of multiphase meter (to eliminate the test flowline and even the test separator on the platform), we can achieve a cost effective solution. This paper describes the possibilities of simplifying the subsea manifolds and presents a comparison of different designs. The usage of mature technology combined with the new developments, can help the industry to make deep water developments profitable, worldwide. Introduction Aiming cost reduction, efficiency and reliable solutions for future deepwater developments, PETROBRAS has carried out a study for comparison of different manifold concepts to identify the potential more attractive ones. For a more realistic analysis, [he manifold was not studied as an isolated item, but, using a system approach, all the subsea components were considered trees - flowlines - connections - controls - manifold - export lines and umbilicals. @In this comparative study, mature technologies of subsea valves, chokes, controls and instrumentation were combined with the new developments of flowline connection systems and multiphase meters to achieve cost effective alternatives. Base Case and Technical Parameters Set-Up The base case used for this comparative work was a system composed of 8 subsea wells that produce crude oil (3000 BOPD each) during the life time of 20 years, using gas-lift as the artificial lift method. The production is commingled in a diverless guidelineless subsea manifold, located 400 m (1,312ft) away from the wellheads. The export lines (production outlet and lift gas inlet) are connected through flexible lines to the floating process unit 3.2 km (2 miles) away from the manifold, Flexible lines are also used for the subsea trees to manifoId connections. Electro-hydraulic multiplexed control system is considered.

Deepwater developments always represent a huge capital investment, and this is especially true when the field in question is instrumented with Permanent Reservoir Monitoring (PRM). These massive financial outlays demand optimum efficiency to maximize the return on investment. This means taking full advantage of the value in the large volumes of time-lapse seismic data collected. In this paper, we examine enhanced workflows and solutions for optimizing the utility of Permanent Reservoir Monitoring data in a deepwater setting. We do this by fully integrating these data into our subsurface models and decision making in a rapid, thorough, and quantitative fashion. Parque das Conchas (BC-10) represents a major milestone in the development and commercialization of Brazil’s deep water. The project consists of several distinct small-to-medium-sized fields in the Campos Basin that allow for phasing. The fields have been developed using subsea wells and manifolds, all of which are connected to a centrally located floating production, storage and offloading (FPSO) vessel, the Espirito Santo (Figure 1). The Espirito Santo FPSO, which has a processing capacity of 100,000 barrels of oil equivalent per day (BOE/d), was built by SBM in Singapore and delivered to Brazil in late 2008 being moored in around 1800 m of water. The double-hulled FPSO’s design required significant power and heat delivery systems to drive the seabed lift equipment and process the heavy crudes. This development is the first of its kind based on full subsea oil and gas separation and subsea pumping. This system uses 1500-horsepower underwater pumps – each equivalent to a Formula One engine – to drive oil and a small quantity of gas to the surface.

Brazil is entering a decisive phase in the end-of-life management of its offshore oil infrastructure. More than 90 production units are slated for retirement this decade, and the National Petroleum Agency (ANP) projects up to R $ 30 billion (≈ US $ 6 billion) in direct spending through 2025, rising to almost R $ 65 billion by 2028. At the same time, Petrobras has revised its five-year investment plan, earmarking US $ 9.9 billion for decommissioning yet exploring asset-reuse options that can postpone or re-purpose facilities. This article maps the regulatory drivers, cost structure, supply-chain gaps and emerging business models that define Brazil's decommissioning market, arguing that a combination of regulatory clarity and sustainability-linked solutions (e.g., rigs-to-reefs, offshore wind pre-lay) will unlock significant local-content opportunities while aligning with the UN Sustainable Development Goals (SDGs). The decommissioning of offshore oil and gas installations is an increasingly prominent issue worldwide as many production facilities approach the end of their productive lives. Globally, decommissioning expenditures are projected to exceed US$85 billion over the next decade, reflecting the immense scale of work required to safely retire aging infrastructure. Brazil has quickly become a major part of this global trend – it is already considered the third-largest offshore decommissioning market after the North Sea and Gulf of Mexico. Industry analyses indicate Brazil could account for roughly 10–15% of global decommissioning spending in the coming years, with forecasts of up to ~US$16 billion in offshore decommissioning projects in Brazil by 2029. This surge is attributable to the country's prolific offshore developments in past decades (particularly in the Campos Basin and early pre-salt fields) that are now maturing, combined with an evolving regulatory environment that compels and facilitates decommissioning activities. From a business perspective, the market dynamics of decommissioning in Brazil are shaped by two key drivers: (1) the sheer volume of assets due for retirement, and (2) the regulatory framework that governs and enforces decommissioning obligations. On the asset side, Petrobras – the national oil company and by far the largest offshore operator in Brazil – has announced an extensive decommissioning program under its Strategic Plan 2024–2028, signaling a systematic effort to wind down older platforms and fields. This includes plans to decommission 23 offshore platforms by 2028 (with over 40 additional units slated for decommissioning after 2028). The scope encompasses both fixed platforms and FPSOs (Floating Production, Storage and Offloading units), many of which were installed in the 1980s–2000s and have reached end-of-life or become uneconomical. Along with surface facilities, Petrobras projects the permanent abandonment of ~550 subsea wells and the removal of about 2,000 km of flowlines and pipelines associated with these fields. These figures underscore the magnitude of the decommissioning opportunity: for context, plugging 550 offshore wells in a few years represents a major P&A campaign by global standards, and 2,000 km of flexible lines to be recovered is roughly the distance from Rio de Janeiro to Natal.

This paper provides an overview of the Who Dat development. The Who Dat fieldis located in the Mississippi Canyon protraction area of the Gulf of Mexico inblocks 503, 504 and 547 and is being developed using the OPTI-EXsemisubmersible floating production system (FPS) which has a capacity of 60MBOPD and 150 MMCFD. The Who Dat discovery is primarily oil and consists of tenstacked amplitude-supported reservoirs in a salt withdrawal mini-basin. Threewells have been drilled to date penetrating over 700' of net pay in ninedistinct reservoirs ranging in depth from 12,000' to 17,000' TVD. The fieldwill be developed with twelve subsea wells (i.e. wet trees) flowing to threesubsea manifolds and subsequently to the FPS via two infield flowloops usingflexible risers. The project includes a 10" gas export line and 14" oil exportline also using flexible risers. The paper covers the exploration phase including evaluating the prospect priorto the lease sale and adjusting the delineation plan based on the discoverywell. The paper also covers the development concept selection including theevolution of the project from a long subsea tieback to a new FPS, thechallenges of utilizing an FPS that was built on a speculative basis(modifications required, regulatory approval), and contracting strategy(negotiation of an installment purchase and managing uncertainty in apost-Macondo environment). This development represents a number of firsts: first time that a privatecompany will own an FPS, first time the OPTI-EX semisubmersible FPS will beused, first time an FPS has been approved for installation post-Macondo, firsttime an FPS has been built on speculation, and first time a field has gone fromconcept selection to installation of a new FPS in less than a year. Theproject's accelerated schedule created challenges since numerous items were oncritical path, including items that are typically nowhere near criticalpath. New Seismic Shows Previous Wells were Drilled in Poor Locations. There were a number of amplitudes (bright spots on the seismic data) that werepreviously identified in the Who Dat Area. The objective section, LowerPliocene though Upper Miocene had been drilled in offset blocks MC 460/502/546. The wells were drilled in these blocks from 1985–1998 and found thin and/orpoor quality hydrocarbon bearing sands. Operators presumably assumed that theresults of these wells meant that all of the amplitudes in the area were thinand uneconomic which is the likely reason British Borneo allowed blockMississippi Canyon Block 503 (MC 503) to expire without drilling a well. Withthe release of the TGS MC Revival PSTM 3 D data set in the spring of 2004 overthis area, the poor placement of these wells and the thin pay results werebetter explained. This did not alleviate the risk of finding thin pays in otherwells but LLOG felt it could explain the poor result.

This paper deals with the Gullfaks A Subsea Production Systems: Philosophy, development plan, technical and functional descriptions and Statoil's experience to date in the various phases, including start up. The wells are connected to the Gullfaks A platform, which is a PDQ (processing, Drilling and Living Quarters) Platform. Subsea operation were accomplished. THE GULLFAKS FIELD The Gullfaks field is situated 140 km from Norwegian mainland (Figure No. 1). The field appraisal drilling showed that the reservoirs are heavily faulted with a main north-south fault through the whole field. Recoverable reserves of the Gullfaks field are assumed to be 210xI0 6 Sm3 (1,320x106 Bbls) of oil and 23X109 Sm3 (812x109 SCF) of gas. The water depth at the field varies from 13(to 220 meters. GULLFAKS A SUBSEA DEVELOPMENT PLAN – Develop reservoirs outside the efficient reach of the platform wells. Figure No. 2. – Accelerate production and improve economic returns. – Gain information and experience for future field developments. The scope of the subsea part of the GullfakS A Project has changed from: (Information available in full paper) These changes are due to increased knowledge from the drilling of the subsea wells and new reservoir simulations. The subsea wells are of a wet satellite type non-TFL (non-thru-flowline); However, wireline serviceable. The same Christmas tree is used both for production and water injection. Each well is connected to the platform with a separate Flexible flowline, a hydraulic umbilical and an electrical umbilical. The system is designed to be diverless, i.e. a11 tools required for installation and workover are non-diver assisted. The design life of the subsea production system is 10 years. The plan for the development, installation at start-up of the Gullfaks A subsea systems are shown in Figure No. 3. SATELLITE SYSTEM The main components of the satellite system as shown in Figure No. 4. They consist of:protective structureChristmas tree Systemsatellite control moduleworkover systemtools allowing for diverless installation and workover. The Gullfaks A satellite system is a new development Protective Structure The protective structure is an open frame type structure allowing ROV access. It has been designed to deflect fishing gear, with a high probability, and is piled to absorb 100 tons anchor dragging loads. A removable roof is fitted to the structure to provide overhead protection. The structure is shown in Figure No. 5. Additional protection is installed in the pull in areas after pull in and connection. Wellhead & Tubing Hanger Prior to start of drilling operations, the protective roof is removed by a guideline establishment tool. In a single run, the tool establishes guidelines to the four main guideposts and retrieves the protective roof. An 18 3/4", 10,000 psi CAMERON WS-11 weight set wellhead system is used in the subsea wells. A 5-string casing programme is used, comprising 30", 20", 16", 13 3/8" and 10 3/4" casing strings. The tubing hanger system allows the tubing hanger to be run, orientated, tested and locked in one trip.