Gulf of Mexico Deepwater Platform Decommissioning

A study was conducted in November 2000 for the United States Department of Interior, Minerals Management Service (MMS) to identify and review state-of-the-art technologies for removing large offshore platforms located in deep water. Platforms emphasized on in this report were located in the Pacific Outer Continental Shelf Region (POCSR); comparisons were made to similar Gulf of Mexico platforms. For this study, deepwater platforms were defined as those with jacket weights exceeding 10,000 short tons located in water depths exceeding 400 feet. Three POCSR platforms (Hidalgo, Gail and Harmony) were selected to encompass the range of decommissioning conditions and to provide a thorough review of issues related to removing deepwater offshore structures. The water depths considered range from 430 feet to 1,198 feet. Specific areas of technology reviewed included lifting, transportation, disposal, and explosive and non-explosive severing techniques. The three removal methods evaluated (using the best technology currently available) were Complete Removal, Partial Removal (reefing in place) and Remote Reefing (reefing off site). Decommissioning cost estimates were prepared for the selected platforms and removal methods, including an evaluation of cost sensitivity (risk) issues and the cost of alternative technologies. Also assessed were environmental and human safety risks for current and evolving decommissioning technology. Specific recommendations were provided for industry and federal/state support for future developments. Introduction The overall goal of the MMS study was to determine and examine the issues relevant to decommissioning deepwater platforms and to quantify them in the context of economics, risk, and available technology. The following specific goals were achieved in this study:Develop decommissioning plans for selected POCSR deepwater platforms using the best technology currently available.Prepare decommissioning cost estimates for selected platforms and cases, including an evaluation of cost sensitivity (risk) issues and the cost of alternative technologies (i.e., explosive versus non-explosive severing methods).Assess environmental and human safety risks for current and evolving decommissioning technology.Provide a review of the state-of-the-art in decommissioning technology for: lifting, transportation, and disposal; explosive and non-explosive severing techniques.Prepare specific recommendations for industry and federal/state support for future developments. Scope of Work. The scope of work for the study consisted of selecting platforms to be evaluated; selecting and evaluating removal technology; developing decommissioning plans and cost estimates; analyzing safety and environmental issues; and reviewing and describing other removal technologies, their current development status, and prospects. Project Issues Offshore platform decommissioning is a challenge under any circumstances in terms of planning and executing the work in an environmentally sensitive, safe, and economical way. Regarding large deepwater platforms in the POCSR, this is particularly true. Among the issues that must be faced are: Lack of Local Infrastructure. There are currently no derrick barges of significant capacity or other types of major marine construction equipment based on the West Coast, and none are likely to be in the foreseeable future. Additionally, there are currently no onshore facilities in California (or Mexico) capable of accepting jackets or topsides of these sizes, even in small pieces.

The hurricane metocean conditions presently contained in the 21st edition of API RP2A are in the process of being revised, to account for both the effects of recent major hurricanes as well as changes in understanding regarding the occurrence of severe hurricanes that has taken place since the RP2A conditions were last updated in 1993. This paper contains information on the process used to develop new hurricane metocean conditions, including the hurricane hindcast information used as the basis for the conditions and the statistical methodology used to analyze the data. A summary of the present draft version of the new conditions is also included. The new conditions, when accepted by API, will eventually be published as part of a separate stand-alone API recommended practice on metocean conditions which can then in turn be referenced by other API recommended practices covering offshore structures and operations, such as those addressing shallow-water fixed platforms, jackups, deepwater platforms, and floating MODUs. New draft hurricane metocean conditions are provided for four regions spanning the northern Gulf of Mexico from southern Florida to southern Texas, for all water depths 7.5 m and deeper. The new conditions between 86.5o and 90o W are significantly higher than the conditions currently contained in RP2A, due to the recent severe storms, most notably Opal (1995), Ivan (2004), and Katrina (2005); however, the new conditions in the other three regions are similar to those currently in RP2A. The new conditions are based on the hurricane record from 1950 to the 2005. Unlike common practice in previous hurricane metocean studies, storms before 1950 were excluded from the statistical analysis because the quantity and quality of data available for those storms is considered too uncertain. The division into four regions recognizes the geographical variability of hurricane conditions across the Gulf of Mexico and is an improvement over the uniform conditions described in RP2A. However, a site-specific metocean study is the only way to more thoroughly account for regional variability in developing design and operational metocean criteria for major development projects. Introduction The arrival of major hurricanes Ivan, Katrina, and Rita, three of the most severe storms on record in the Gulf of Mexico, within two hurricane seasons (2004 and 2005), caused massive interruptions in the production of oil and gas in the Gulf of Mexico due to damage to facilities. Given the impact of these storms, and changes that have occurred in the understanding of hurricane conditions in the Gulf of Mexico since 1993 (the year the conditions in API RP2A were last updated), it was decided by the API Hurricane Evaluation and Assessment Team (HEAT) that the hurricane metocean conditions presently contained in the 21st edition of API RP2A (1) should be re-evaluated and, if necessary, revised. An API Task Group, composed of the authors of this paper, was formed to develop new hurricane conditions. It was also decided that the new hurricane conditions would not be included in API RP2A but would be included in a stand-alone API recommended practice document on metocean conditions, which could then in turn be referenced by other API recommended practices.

A large number of dry tree concept's have been proposed to the offshore industry over the last few years for application in deepwater fields in the Gulf of Mexico, West Africa and Brazil. Looking into the details of these concepts, they all to a varying degree apply new and unproven technology that will increase project risk when brought to first use. PGS Offshore Technology has over the last 3 years developed the Dry Tree Semi or DTS, which limits the cost and risk aspects of unproven technology by using a standard semi-submersible hull with top-tensioned risers suspended by large volume buoyancy cans. A Norwegian patent has been awarded, and US and international patents are pending for the riser support system developed for the DTS, which comprises a light weight truss tower placed in the centre of the hull. Conventional sliding or roller bearings provide lateral support to the buoyancy cans inside the riser support tower. The DTS concept avoids the disadvantage of dry tree concepts with riser tensioners, which rapidly loose payload capacity in deep water because of the increasing weights of the riser system. Compared to SPAR alternatives, the DTS has a substantially better steel weight to payload ratio. Also, installation costs are considerably reduced since offshore lifting and mating operations are not required. At the OTC 2000 (ref. /1/), a DTS platform concept for West Africa was presented. This paper presents a DTS platform concept, primarily for use in the Gulf of Mexico, but also suitable for deepwater applications offshore Brazil. Introduction During the last two decades there has been a general trend towards higher oil recovery factors, and platform based or dry completed wells have a distinct advantage over subsea developments in this respect. There are a number of reasons for this, including amongst others, pressure drop in flowlines and limits on completion size, but even more importantly the cost and risk of performing subsea interventions. The latter reduces in practice the frequency of the whole range of recovery-enhancing measures such as logging, testing, reallocation, stimulation, recompletion etc. The CAPEX costs for current platform designs with dry well completions increase however dramatically in deep water. The cost balance often tips the scale towards an FPSO and subsea development rather than the current dry completion unit alternatives, which are mainly TLP or mini-TLP in medium to deep water and Spar type platform in deep to ultra deep waters. The most prolific deepwater exploration areas are currently West Africa, Brazil and Gulf of Mexico, ranging from benign to moderately harsh environments. The motivation for the DTS (Dry Tree Semi) development during the last 3 years has been to significantly reduce the cost of dry tree solutions for these main markets, starting with West Africa, which was subject for a paper presented at the OTC 2000 (ref. /1/). Subsequently, work has continued to extend the DTS application to Brazil and Gulf of Mexico (GoM).

Production techniques and designs have been developed to take full advantage of the unique dynamic characteristics of a Tension Leg Platform (TLP). The application of the information presented in this paper could be used to economically develop deep water reservoirs considered to be marginal if conventional fixed platforms were used. Data obtained in this development program indicates that the production risers can remain connected under all environmental conditions that the TLP would experience. Included are graphs, specialized hardware designs, sketches of special operating techniques and TLP performance data. INTRODUCTION For many years, the petroleum industry has developed offshore production from fixed platforms. Initially these platforms were installed in shallow water (<100'). Over the years, fixed platforms have been used in ever increasing water depth and have established a history of proven performance. In 1977, Shell Oil Company began installation of the Cognac platform offshore Louisiana in 1025 feet of water. Deep water fixed platforms are expensive. Only large and prolific reservoirs can be considered for development using a fixed platform in deep water. Development of comparatively small reservoirs or those located in water depths beyond the economic limit of a fixed platform require alternate production concepts. One alternative that has been considered is a completely submerged seafloor production station. In 1972 the Shell-Lockheed production system was installed on a well in the Gulf of Mexico at a water depth of 375 feet. A second alternative which takes advantage of readily available semi-submersible drilling platforms and much proven equipment and techniques is the floating platform production system. The first such installation is Sedco-Hamilton's Floating Production Facility (FPF) on the Argyll Field in the North Sea. The system has been operating for approximately three years. A sub sea manifold receives prediction from four satellite sub sea wells where individual production risers transmit the flow up to the platform. After processing in onboard separators, the product is transferred through a ten (10") inch central riser back to the seafloor manifold. A Single Point Mooring (SPM) system and tankers are used to deliver the crude to shore facilities. The production and transfer risers are supported from the platform by riser tensioners which accommodate a maximum rig heave of ten (10') feet. Prudent operation of such a conventionally moored facility requires that the wells be shut-in, and that the risers be purged of oil and retrieved well in advance of weather which would impede such operations. The result is downtime and a less cost-effective program. Also, when production is resumed, flow rates are often lower. The Tension Leg Platform production system offers potential for improved production efficiency because the platform does not heave, roll, or pitch in response to wave motion. The absence of heave not only simplifies the riser design and tensioning, but also permits the risers to remain connected during all weather conditions.

An estimate of wave heights is needed for risk and venture analysis, for platform design, and for operational planning. Very little reliable data on hurricane waves have been available for a number of years. The present hindcast system uses a moving, two-dimensional wind field to generates and propagate waves to a location of interest. The propagate waves to a location of interest. The wind-wave model is based on work reported in the literature by Wilson. Wave Program I uses a synoptic wind field based on measurements or observations. Wave Program II generates its own wind field based on the track, the time history of the radius to maximum Winds, and the barometric pressure of the storm. Wave Program III also pressure of the storm. Wave Program III also generates its own wind fields, but the storm is moved along a predetermined path. The results of all three hindcast methods have been compared with data gathered from Hurricane Carla. Other hurricanes have also been studied and each of the programs gives comparable results. Introduction The most critical environmental factor in deepwater platform design is the selection of wave heights to which the platform will be subjected. Regardless of the design theory, wave loading contributes a major portion of the environmental force on a deep-water platform. To date there has been little sound historical evidence of the magnitude of wave heights that could occur in the Gulf of Mexico. To overcome this problem the offshore oil industry has sought an answer by two related methods. The first method consists of several measuring programs to gather both wave force and wave height information. Since reliable measuring techniques have existed for only a short time, the second method consists of developing techniques to predict historical waves that probably occurred in the Gulf of Mexico. The purpose of this paper is to document Shell's efforts in hindcasting paper is to document Shell's efforts in hindcasting waves for hurricanes that have passed through the Gulf since 1900. In order to hindcast waves, it was necessary to find a mathematical simulation model that would generate waves from a moving wind field. Such wind fields may be taken from synoptic charts or developed from empirical equations based on hurricane data such as radius to maximum winds, central pressure, and forward speed.

Recent population expansion of Gray Snapper, Lutjanus griseus, in the northern Gulf of Mexico is driving increasing catch in the recreational fishery in Texas. We assessed long—term trends in distribution and abundance of Gray Snapper in Texas using fishery—dependent and fishery—independent data collected by the Texas Parks and Wildlife Department in the years 1980 — 2019. Boosted regression trees (BRT) were used to evaluate factors (water quality, season, depth, bay and inlet distance) driving Gray Snapper presence in fishery—independent samples of juveniles (seines) and subadults (gill nets) found in estuaries. Estuarine Gray Snapper were subsequently sampled from gill nets, and otolith age and gonad development were evaluated microscopically to assess patterns of age, growth, and maturity. Increasing Gray Snapper abundance in Texas was coupled with expansion of the population age structure in comparisons before and after 1993. Gray Snapper juveniles and subadults encountered in Texas estuaries are generally associated with lower bays and offshore passes, and are more common in the late summer/early fall. Comparison of size (total length in mm) of recreational catch inshore versus offshore suggests that mature adults recruit to offshore habitats around 409 mm TL, or around 3 years old, which is approximately coincident with the onset of sexual maturity. Increasing abundance coupled with an expanding age structure of Gray Snapper in Texas have co—occurred with increasing winter temperatures over time. Population expansion could be facilitated by management measures that improve overwinter survival of juveniles and subadults in estuaries prior to offshore recruitment.

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].

The U.S. Minerals Management Service is responsible for ensuring that offshore oil and gas exploration, development, production, and transportation occur in an environmentally sound manner. This paper outlines some environmental concerns associated with deepwater activities that are being addressed by the Bureau and industry. The policy, strategy and implementation of environmental reviews for prelease and postlease deepwater activity are outlined, along with a description of planned and ongoing research to address information needs. Opportunities for cooperative efforts among the stakeholders in offshore development are increasing and are essential to address important technical needs and regulatory requirements. Introduction Deepwater exploration and development in the Gulf of Mexico hold great promise for the United States in terms of both energy and economic benefits. To realize this potential, industry and regulators must meet the substantial challenge of maintaining environmental quality and protection during offshore operations. The advance into deep water is evidenced by industry's response to recent Gulf of Mexico Outer Continental Shelf lease sales. In March 1997, a lease sale in the central Gulf brought in a record number of bids, over half of which were located in water depths greater than 800 m. Five months later, another record-breaking lease sale in the western Gulf showed similar results, with over 75 percent of all tracts receiving bids in similar water depths. Likewise, exploration and development operations are rapidly moving into deep water, with over 1,300 active leases currently located in more than 1,500 m of water. There are currently over 30 deepwater rigs drilling in the Gulf in water depths greater than 300 m, including two drilling in over 1,500 m. The U.S. Minerals Management service (MMS) is responsible for ensuring that offshore oil and gas exploration, development, production, and transportation occur in an environmentally sound manner. The MMS's number one priority is ensuring that industry's excellent environmental and safety record is maintained as this new frontier is explored and developed. Our approach has been to work cooperatively with industry to gain understanding of this new environment and the technological challenges it poses. We recognize that a serious accident in deep water may undermine the public's confidence in the program, which could delay or jeopardize significant potential benefits. (I) Environmental Concerns/Information Needs The following outlines some of the major issues and information needs associated with deepwater activities. The issues address both localized effects to deep ocean habitats and impacts to coastal environments and economies. Socioeconomic Effects of Deepwater Activity on Ports and Coastal Support Facilities. Social and economic impacts of energy development are often the first felt and most strongly experienced of any impacts. While the Gulf of Mexico has been experiencing social and economic impacts of offshore oil and gas development activities since the mid-1950's, there are some differences in deepwater development that are beginning to be felt. Historically, the effects of offshore activities have been fairly diffused among Gulf coastal communities that serviced the offshore industry in one way or another. However, deepwater activities will have different service requirements, such as larger deeper supply boats.

E&P Notes (April 2022)

The Gulf of Mexico (GOM) is one of the world’s most prolific hydrocarbon basins, with more than 80 years of development since the first offshore drilling began. GOM is the primary source of the United States (U.S.) offshore oil and natural gas production. According to data published by the United States EIA, approximately 15% of the U.S. domestic oil production came from offshore oil and natural gas fields in federal waters, with over 99% of that production coming from the Gulf of Mexico over the most recent year of data available at the time of this paper’s publishing (Q4 2022-Q3 2023) [1]. Nonetheless, GOM reservoirs have complex depositional settings. Reservoir heterogeneity, stacked pay system, reservoir compartmentalization, high-temp and pressure are some of the common challenges seen in these fields. The use of conventional completion design in vertical wells with commingled production form multiple zones has led to multiple operational challenges. In this paper, we explore the use of intelligent completions in the deepwater GOM as a solution to this problem. Specifically, we will show how intelligent completions have allowed for increased production, reduction in operating expenses, enhanced overall reservoir recovery and improved safety and environmental performance. A case study of intelligent completions in GOM is with sliding sleeves that are hydraulically controlled from the production facility. In this paper we will be focusing on one of these deepwater oil fields located in the northern GOM. The field is comprised of a subsalt reservoir with best-in-class Pliocene age sands (main target reservoir). These conventional sands have good porosities and permeabilities up to 1 Darcy. The target producing reservoir sands are comprised of multiple, stacked, turbidite sands. This has led to the standard field development in this area to be vertical wells with commingled production from multiple zones. The field has been producing back to a deepwater facility for more than 5 years through multiple subsea wells. Initial production was over 10,000 barrels of oil per day (bopd) per well. The producing reservoirs are supported with strong aquifer drive and leads to rapidly increasing water rates in wells post water breakthrough. Riser base gas lift is utilized in all producing risers to help optimize production.

An overall conceptual design development of a deep sea FPSO suitable for the Gulf of Mexico area is described. The oil storage capacity was determined after the market screening by analyzing the answers to questionnaires submitted to potential field operators. The locations of turret, accommodation, topsides, flare boom and offloading equipment have been studied carefully before selecting the final location on the general arrangements. The basic drawings of general arrangements, lines, mid-ship section, accommodation layout and outfitting systems are developed. The basic hydrostatic calculations, stability, motions, mooring, structural and riser analyses are also carried out. The model tests are carried out at 2-dimensional wave flume for roll motion and wave model basin for global performances. In order to reduce the roll motion, a box-like mid-ship section is adopted with projected bilge keels. The model tests confirmed the expected good motion performances. A turret moored, one million barrels storage capacity, double hull FPSO is found to be most suitable in the Gulf of Mexico. Introduction The Gulf of Mexico was the last offshore oil field area not open for FPSOs. The absence of FPSOs from the GoM is partly due to the well-developed production and pipeline infrastructure. Another reason is the relative prevalence of gas developments in the GoM. As production enters deeper water and far away from any export infrastructure, the demand for FPSOs gets stronger. The final threshold to open the GoM for FPSOs was a safety confirmation. MMS (the Minerals Management Services) have expressed concerns about FPSO deployment, which have focused on the performance of offloading operations and the vessels' survivability during hurricanes in the GoM. According to the EIS (Environmental Impact Statement) recently issued by MMS, potential sitespecific impacts are essentially the same as with other deepwater development and production systems. The FPSO has been widely used as a most competitive production system concept in other offshore fields where infrastructure is not sufficient, or where the fields are marginal. As the water depth for offshore fields increases, more offshore operators have selected the FPSO concept. Considering the size of the oil reservoirs in the GoM, FPSOs will be widely adopted by the main operators. On December 31st 2001 the MMS announced its decision to allow the industry to propose using FPSOs in the central and western Gulf of Mexico. This paper presents an overall conceptual design development of a deep sea FPSO suitable for the Gulf of Mexico area. The locations of turret, accommodation, topsides, flare boom and offloading equipment have been studied carefully before selecting the final location on the general arrangements. Environmental conditions in the Gulf of Mexico, such as hurricanes, ultra-deep water depth and loop currents, required special consideration in the dimensioning and arrangements.

Chapter 5 - Wading into Deepwater

The response effort executed by Shell staff, contractors and governmental agencies to return the Shell operated crude oil infrastructure to service after Hurricane Ivan was truly a monumental accomplishment. The unusual and unprecedented circumstances encountered as a result of the storm cannot be compared to any other event that has been encountered by Shell Pipeline in the Gulf of Mexico (GOM). As a result of Hurricane Ivan, the Shell crude oil systems in the eastern GOM region were completely disabled. The crude oil infrastructure transports production from Nakika, Petronius, Ram-Powell, Main Pass (MP) 289, the MP 252 Complex, and Horn Mountain fields, along with other production facilities in the eastern GOM. The force of Ivan also impacted pump stations, delivery terminals, and pipelines along the entire system, which is used to transport over 400,000 barrels per day. Overview of the Response Effort The hurricane struck the northern GOM on September 17, 2004. It traveled in a northerly direction through the GOM and directly impacted Nakika, Ram-Powell, and Horn Mountain production facilities. Shell's pipeline infrastructure is the major link in the Mississippi Delta area that connects these assets to the Louisiana refineries and onshore distribution network. These pipelines are routed primarily on the eastern side of the Mississippi River. The lines were decimated by mudslides, displaced debris and currents that resulted in risers being severed from platforms, pipeline crossings being damaged, pipelines being displaced in mudslide areas, pipelines being fully severed, pipelines being impacted by mooring lines from drill rigs that broke free of their anchors during the storm, and debris landing over pipelines. The associated pump stations and delivery terminals along the Mississippi River were also completely inundated by water and debris rendering them inoperable. As a part of the response effort, oil cleanup crews were mobilized to contain and pickup oil that was threatening the Delta coastline. The list above highlights the aftermath that provided the incredible challenge the Ivan Response and Repair Team now faced. Due to the severity of damage to pipeline systems owned by Shell and others, creative solutions were required to contain leaking oil, repair the affected systems, and return service to production facilities as soon as possible. As an example, an abandoned third party subsea connection and associated pipeline was connected between the Shell infrastructure and a competing system in less than two weeks. This allowed significant production to be returned to service a full six weeks before the competing system was repaired. Another challenge was the containment of oil from an offshore leak site in the Main Pass 69 area, which is also located near the Delta Wildlife Refuge Area. The team designed and constructed a containment structure that was placed over the pipeline's leak source under water, which allowed recovery of oil from the pipeline without allowing it to reach the surface. A quick and well executed response from the Ivan Team kept impact to a minimum. Multiple work crews and vessels were dispatched to perform the repair work simultaneously.

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.

During the last few years autonomous underwater vehicle (AUV) technology has evolved from concept demonstrators towards commercial products. The driving forces are the move for energy exploitation towards deeper waters, naval applications and the Internet driven need for more intercontinental underwater communication cables. Other applications emerging for the future would be within environmental research and monitoring and deepwater exploration. Deepwater developments beyond the continental shelf would require the same level of survey data quality and intervention access as established for shallow water. The potential for cost savings is two folds. Firstly, there is a reduction in the survey cost it self and secondly there is a considerable cost saving by avoiding over design of subsea installations due to lack of sufficient documentation of the field. In this scenario, there is an increasing understanding that underwater robotics and in particular AUVs would play an important role in future survey and subsea engineering work. The AUV as a free swimming underwater survey sensor carrier has several advantages compared to cable controlled ROVs and deep towed systems. The paper focusses on the HUGIN AUV concept and field results from the North Sea and Gulf of Mexico.