Riserless, Remotely Operated Technology Enables 10,000-ft Intervention Without Rig

This paper describes an operational subsea wireline system that is self-contained and flexible and offers a safe, economical, and proven method for riserless re-entry into any subsea well. The system discussed here was developed over a number of years and has been used to carry out a comprehensive range of wireline tasks from floating vessels in the North Sea. Although generally deployed from a diving support vessel (DSV), the system has been successfully used from a drilling rig to conduct wireline operations in a well, simultaneously with workover operations in an adjacent well, on a subsea template.

Heave motion of supporting ships deeply affect the normally operating, safely launching and recovering of remotely operated vehicles when the sea state becomes rough. A heave compensation system can uncouple the heave movement between supporting ships and remotely operated vehicles. An active heave compensation system which includes a measurement unit, a controlling unit and a hydraulic winch is researched in the paper. For attaining the efficiency of the active heave compensation system, simulating model is built and the computer simulation is achieved. The computer simulation proved the effectiveness of the active heave compensation system. For verifying the correctness of the simulating model and acquiring the efficiency of the real active heave compensation system, an active heave compensation experiment system which includes a heave motion generating unit, a load and an active heave compensation system is built. The movement which created by the heave motion generating unit simulates the heave motion of the supporting ship. The load is a substitute of the underwater vehicle. The result of the active heave compensation experiment certifies the correctness of the simulating model and the effectiveness of the active heave compensation system.

Small water-plane area twin hull (SWATH) technology is being used for seagoing vessels in the marine construction industry to provide a stable working deck in strong sea and weather conditions. Deck area can be used to support concurrent offshore operations, from saturation diving and remotely operated vehicle (ROV) deployment to installation of smalldiameter (4-inch) pipelines for oil and gas production. A SWATH vessel also transits at a competitive and economic speed in a heavy sea state. For these reasons, SWATH technology is increasingly targeted for deepwater and remote subsea system intervention. The Global Pioneer multi-service vessel is the only semi-submersible SWATH vessel presently marketed for offshore oil field construction. However, the process of re-supplying the Pioneer for deepwater development has been limited to the transit ability of monohull supply vessels. Re-supply by a monohull vessel is generally limited to favorable weather conditions, thereby limiting the work program of the SWATH vessel during winter months. A three-month reconfiguration of Pioneer was completed in August 2000 to increase the vessel's deck load capacity for supplies and limit the need for re-supply. Certain bow and stern modifications were implemented to reduce drag on the vessel and improve transit speed; and an auxiliary generator was added to the vessel to enhance its continued, independent operation in the deepwater markets of the Gulf of Mexico. Introduction Original design for the Global Pioneer specified a 150-ton deck load capacity, limiting the vessel to installation of smalldiameter pipelines no longer than 1.89 miles. In general, the design of a SWATH vessel is similar to that of a semisubmersible drilling rig. A steel frame comprising the work platform is built on columns with two submerged pontoons. The twin-pontoon structure (lower hull) of the Pioneer contains tanks for ballast, fresh water, diesel fuel, and marine systems. It also supports a system of four thrusters controlled by an ASK 4002 dynamic positioning (DP) system. Under its original construction, the Pioneer succeeded in providing a stable work platform with little roll and pitch but could not overcome its dependency on weather-sensitive supply vessels. Each pontoon of the Pioneer is connected to the upper hull by two watertight columns. The upper hull contains a buoyant inner bottom that extends to the bulkhead deck (2nd deck) and is watertight up to the main deck. The upper deck contains the largest portion of marine and industrial systems. At maximum load capacity, 150 tons, the Pioneer could not achieve its optimum specified speed of 10 to 12 knots. It was determined that a reconfiguration of the lowers hulls, columns, bow, and stern of the Pioneer would improve the vessel's payload, speed, and performance for deepwater construction. Technical Specifications Global Industries, Ltd. constructed the Pioneer SWATH vessel in 1995 based on BSM Joint Venture SWATH technology (Table 1). The Pioneer features a modular design, with a wide deck area and 12-foot deep pontoons for navigation through small and shallow waterways

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212939, “A Proven and Versatile Coiled Tubing Live-Well Intervention Solution From a Monohull Vessel in the Norwegian Continental Shelf,” by Kjetil Austbø and Stein Kristian Andersen, Equinor, and John Stuker, SPE, SLB, et al. The paper has not been peer reviewed. _ The complete paper describes the use of a riser for coiled tubing (CT) operations from a monohull vessel already performing riserless well interventions (RLWI). The project was developed by the operator, an intervention-vessel company, and several service providers. The solution covers 200- to 500-m water depths and converts back to riserless operation after CT operations. Introduction The operator has more than 600 subsea wells globally in multiple countries and more than 550 subsea wells on the Norwegian Continental Shelf (NCS), which accounts for more than 83% of all subsea wells in the area. Successful interventions here using RLWI vessels encouraged the operator to investigate the possibilities of also performing CT operations from a vessel. The best option was found to be a strategy that included a monohull vessel that could perform both RLWI and CT operations. The analysis of operations in rough-weather conditions in the NCS showed that riser-based CT operations from such a vessel could be performed in the summer season only. Thus, the operator required a flexible solution such that the same RLWI vessel could cover both year-round RLWI and summertime riser-based CT interventions efficiently. The solution materialized when a larger vessel was engaged to expand the usable weather season and allow year-round RLWI operations. Description and Application of Equipment and Processes To enable riser-based CT intervention in the NCS, the chosen option required more equipment and interfaces than were required when performing RLWI. To conduct riser-based CT interventions in live wells, a way to handle, deploy, and tension the high-pressure riser was required, as was an interface for both wireline and CT equipment in the vessel. A system to handle live-well returns from the well also was necessary. After many engineering iterations, the RLWI vessel implemented a modular riser-handling package that could be installed and then removed when not needed. On top of the surface flow tree, a custom CT tension frame (CTTF) was developed for the CT and wireline stacks and pressure control equipment (PCE), each inside separate support frames within the CTTF. With the CTTF connected to the riser, each support frame could be skidded to the well center, eliminating the need for crane lifts while changing between wireline and CT. CT Planning Well Control and Barriers. Because of limited space on the RLWI vessel, only one dual-ram blowout preventer (BOP) would fit in the CT support-frame cartridge within the CTTF. In addition to the dual strippers, the rest of the PCE requirement considered the subsea emergency disconnect package (EDP) and lower riser package (LRP) to complete the well-control equipment. The EDP and LRP included a safety head, a production isolation valve, and a retainer valve, all capable of cutting wireline and CT.

Three subsea oil wells in a water depth ranging between 5200 and 5400 ft in the Gulf of Mexico are tied back to a Tension Leg Platform via a flowline network of a single 2.3 miles pipe-in-pipe connected to a 17 miles dual active-heating flowline. During normal operation these wells flow to a common separator at the topsides. Production allocation to each well is done by subtracting the topsides separator measurement by the subsea multiphase flow meter reading dedicated to one of the wells and manually splitted between the other two wells. When the topsides separator started showing some water production, more rigorous well testing is required to know where the water comes from. The information is crucial for the depletion plan of the field. Since well testing would cause some production deferment, its objectives were expanded to include subsea pigging valve integrity testing, subsea multiphase flow meter validation, and rigorous fluid sampling. The program was executed smoothly and met all its objectives. The formation water was identified from the unexpected well; thus suggested re-visiting the reservoir model. Although not predicted by the transient simulation works, slugging was experienced when the weakest well was producing by itself but it was managed through topsides choking. The key success for the smooth operation was a well-thought plan developed by a multi discipline team and the guidelines based on transient simulation works. Introduction King and King West oil fields are 100% BP operated and located in the Gulf of Mexico (GoM). The fields consist of three subsea wells, i.e. King D5 and D6 wells and King West D3 well located in a water depth ranging between 5200 and 5400 ft. They are tied back to the Marlin Tension Leg Platform (TLP) located in 3200 ft water depth. D3 well is connected to D5 well through a 2.3 miles, 6 by 10 inches pipe-in-pipe flowline. D5 and D6 wells are then connected to the TLP via a 17 miles, 8 by 12 inches dual active heating flowlines (Figure 1). The flowlines connecting D5 and D6 wells to the TLP are designated as the West and East flowlines, respectively. A remotely operated subsea pigging valve located close to D6 well is normally open. D5 and D6 wells are producing from the same reservoir while D3 well is producing from another reservoir. For reservoir management purposes, D3 well is equipped with a subsea multiphase flow meter (SS MPFM) located in a jumper between the wellhead and the flowline. Fig. 1- King/King West Field Layout Marlin TLP processes production stream coming from 3 dry tree wells (two oil wells and one gas well) and 5 subsea wells (three oil wells and two gas wells). The well fluids go to three three-phase separator (HP, Test, and IP) set at the same pressure (Figure 2). The oil flows through the LP separator and the gas goes to the compression system before they both going to the export system. The produced water is treated and dumped overboard. D3, D5, and D6 wells are normally flow to the IP separator. However, the topsides piping and manifold systems allow any well to flow to any separator providing it does not upset the plant, mainly the water treatment process

Introduction Atlantic Richfield Co. is now operating eight subsea wells offshore Louisiana. These wells are in the Eugene Island Block 175 field, about 70 miles southwest of Morgan City, La. Average water depth for the field is 85 ft. These wells were among the first to be installed as subsea completions in the Gulf of Mexico. The wells were drilled and completed as three-string completions between 1966 and 1968. All wells are producing from multiple pay zones and are flowing to a common production platform located 1 to 3 miles from the wells. production platform located 1 to 3 miles from the wells. Routine service work on these wells, such as pulling and inspecting storm chokes, cutting paraffin, etc., is done by the flowline pumpdown techniques from the production platform. The wells were originally completed with special platform. The wells were originally completed with special cross-over ports that allow the tubing strings to communicate in the well just above the top packer. This feature allows tools, similar to wireline tools, to be pumped down the flowline and into the tubing strings of pumped down the flowline and into the tubing strings of the wells and to be pumped back out and returned to the production platform. Three subsea wells required production platform. Three subsea wells required remedial work because of normal reservoir depletion and various mechanical problems. This paper presents basic assumptions in the planning phase and summarizes the work performed to move in the workover rig and to establish contact with the well. Planning Phase Planning Phase In the planning phase, rig selection was of major importance. A three-leg jackup rig without a bottom barge was selected as the best rig for this job. One of the prime reasons in selection of this rig was its ability to cantilever the derrick 25 ft beyond the hull of the barge. Equally important was the ability to skid the derrick in a lateral position 16 ft. This feature allowed the barge to be positioned 15 to 20 ft from the well and eliminated the dangerous positioning of the rig with tugboats. Another problem concerned how to establish contact with the well after the Christmas tree was removed. Two alternatives were available:utilize underwater blowout preventers and bring a low-pressure riser from the blowout preventers to the rig, orconnect a highpressure riser to the wellhead and use standard blowout preventers on top of the riser. The latter method was preventers on top of the riser. The latter method was selected, but a high-pressure riser was unavailable and one had to be built. The wells had to be in a safe condition to move the rig on location in the event of an accident. Drilling fluid was to be circulated down the wells to kill the well before moving in the rig. This was done from the production platform by circulating the fluid down the production platform by circulating the fluid down the flowlines and into the wells. Several planning meetings were held with the drilling contractor, the subsea Christmas tree manufacturer, and the diving company. These meetings were not only beneficial to company personnel but essential in teaching the divers the tools and techniques to be used to establish contact and to remove the Christmas tree from the water. Moving Workover Rig on Location Before moving the rig on location, divers were sent to inspect the sea bottom in the immediate vicinity of the well and in the area where the rig would be stationed. At this time, flowlines leading away from the wells were buoyed and the Christmas tree was marked with a buoy. JPT P. 445

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 will deal with positioning strategies for a floating production unit and an offloading shuttle tanker. The positioning of the two vessels in a tandem configuration while weather vaning around theterminal point is a complicated task. Experience gained from ten years of operation, 12shuttle tankers and 19anchored units, will shed light on some of the problems encountered along the way and their solutions. Introduction SIMRADALBATROSSA/S has long experience with positioning and station keeping of vessels with large ?traditional" hull shapes. Already in 1978, a DP system was installed on the "Seaway Sandpiper", a 20,000 dwt. bulkship converted to a dynamically positioned stonedumper. In 1981, M/T Wilnora was the first tanker to be converted for dynamically positioned loading at the Articulated Loading Platform (ALP) on the Statfjord field. The many advantages of this concept soon became apparent to the operator of the shuttle tankers at Statfjord, K/S Statfjord Transport A/S, and soon all the shuttle tankers in operation on the Statfjord and Gullfaks fields were converted to DP operation. The concept has since been developed further, both with respect to positioning strategies and number of reference systems. In the British sector of the North Sea, both ESSO and Shell are using dynamically positioned tankers. The floating production ship may be held in position usingjust a mooring spread or its position maybe maintained by a wholly redundant Dynamic Positioning system. However, the most common method is to combine the use of anchors with some form of thruster control. The Petrojarl I, a turret moored production ship owned and operated by GolarNor Offshore A/S, is already in operation in the North Sea. She is currently producing at a rate of 25,000 b/d from two subsea wells via two flexible risers, on the Amerada Hess operated Angus field in the British sector of the North Sea. A new floating production ship (a Tentech 850 design) is currently under construction for Ocean Production A/S and Smedvig A/S at the Astano shipyard in Spain. This vessel will be equipped with both a wholly redundant Dynamic Positioning systemand a Position Mooring system, for operation in a turret moored configuration. The Position Mooring System This section will give a brief introduction to the most essential functions of the Position Mooring system (PM) for anchored vessels. PM systems have been in use for 10 years on 18 moored units, used for oil/gas drilling and production in rough North Sea conditions. Accommodation rigs moored very close to freed installations and connected with a gangway also benefit from the use of these systems. The main objective of the system is to automatically monitor and control of the vessel?sposition and stability within the actual anchor pattern,

This paper describes the state of the art of deep water subsea completion techniques and equipment, showing the milestones that were reached through the completion of wells placed in water depths beyond 700 m, namely MARLIM 03, 06, 07, 08, and 09 (the latter being the current subsea completion record, in 781 m). It also shows the expertise developed through the design and manufacturing of equipment to operate in water depths up to 1,800 m, as well as the future trends in subsea completion. The First End Vertical Connection, Tubing Packer Hanger, Shear able Riser Joint, Integrated Drilling and Completion Base (BINT), and the future use of centrifugal submersible pumps in subsea wells are some examples of the technical innovations that are currently being introduced. INTRODUCTION Since 1984, PETROBRAS' most significant oil finds are located in deep waters, beyond 300m. The Albacora and Marlim fields were followed by the Salema, Bijupira, Barracuda and the 382 Area fields, among others. Motivated by these discoveries, the company has been employing efforts to obtain the technological capability to produce economically and safely the immense reserves already discovered in water depths of up to 2,000 m. In this search for technological capability stand out the PROC.AP program, the Petrobras Technological Development Program on Deepwater Production Systems. The 6 years program that ended in 1991, allowed a coordinated and integrated action between all the different company's departments, suppliers and R&D Centers at low cost and within the time frame the company demanded. Deepwater production is a vital issue for Petrobras, because although presently only 8% of the average crude production (650,000 bpd) comes from wells that are located deeper than 400 m of water depth, this figure is expected to reach 61% by 2001 (barring any onshore or shallow water discovery). Furthermore, the deepwater fields account for 66% of total proved and potential hydrocarbons reserves in Brazil. This paper shows the state of the art of the Deepwater Completion Technology, achieved through the PROCAP or via products jointly developed by the Petrobras' Production Department and its suppliers, as well as the innovations that are that are being currently introduced and the future trends in the area. STATE OF THE ART COMPLETION OF THE MARLIM FIELD WELLS In March, 1991 the 3-MRL-3-RJS well was completed in 721 m water depth with a subsea Christmas tree specially designed for operations with a dynamically positioned (DP) drilling unit without guidelines. The success of the operation, the first in the world at that time, confirmed the technical feasibility of the lay-away operation with DP units and the following items summarize the main achievements:Subsea completion water depth record 721 m (2,365 ft)World's first purpose built guidelineless (GLL) lay-away subsea tree installedFirst well drilled with a DP rig completed in the world

The world's first Arctic subsea producing gas well was successfully completed and produced to shore by means of a wet Christmas tree in April 1978. This paper describes the unique design of a combination land and offshore drilling rig and air transportable subsea blowout preventer for drilling and completing subsea wells from a floating ice platform. The drilling and completion of Panarctic Drake F-76 is described. The design of a prototype subsea wet tree and diverless flowline connector is also discussed. The well was drilled and completed as a demonstration well in 181 feet of water, 3,050 feet from shore using a rig supported by a floating ice platform. The operation demonstrated techniques which could be used to develop extensive gas reserves in water depths to 1,500 feet located up to 15 miles offshore in the Canadian Arctic Islands. INTRODUCTION In 1973 Panarctic Oils Ltd. developed a system of drilling exploratory gas wells offshore between the Canadian Arctic Islands. Exploration had been taking place onshore since 1961 and it became evident that the six gas fields which were discovered onshore all extended offshore, under ice covered waters. As conventional offshore drilling techniques could not be used in the area, a drilling method was developed wherein the ocean ice was flooded and thickened, developing sufficient strength to support a land type of drilling rig, modified for offshore drilling. The major area of current drilling activity is centered at about 760N latitude and l080W longitude. Fig. 1. The area covers a 450,000 square mile sedimentary basin of which about 70% is covered by ice year round. Reserves totalling approximately 13 trillion cubic feet of sweet natural gas have been found and eventually will be connected to markets via a proposed 2,300 mile Polar Gas Pipeline. Starting in 1974 and until the end of the 1979 drilling season a total of 13 offshore wells have been drilled using offshore drilling systems adapted to land rigs supported from floating ice platforms. These systems have been effective in drilling in water depths up to 1,200 feet at locations up to 20 miles offshore at costs comparable to land drilled wells. In 1976 planning commenced to develop a system for drilling and completing an Arctic offshore gas well. This project involved the design and construction of a new and larger ice supported rig, a larger and more conventional subsea BOP stack, a subsea tree and flowline connector, flowlines and control lines to shore and shore based test facilities. DRILLING AND COMPLETION SYSTEMS A study was conducted in 1976 by Tri Ocean Engineering of Calgary to determine the most suitable means of drilling, completing and testing an offshore well to demonstrate and test technology that eventually could be used to develop the reserves commercially.

An Unmanned Surface Vessel (USV) deploying a Remotely Operated Vehicle (ROV) has the potential to replace a conventional manned vessel for various operations from field installation to operational support (including inspection, maintenance, repair and drilling support) and decommissioning. The USV deploying ROV (also written as USV+ROV) is already emerging in the oil and gas industry with maturing technology developments and increasing capacities and performance of autonomous vehicles and remotely operated systems. Beyond the safety improvement generated by the absence of personnel onboard the USV, this solution intends to significantly reduce the subsea intervention costs while improving the intervention (planning) flexibility. One of the advantages of the technology is that the operator is located offshore on another vessel or onshore while maintaining a real-time control with the USV+ROV. Threfore, communication link between the operator and the USV+ROV system is critical. To mitigate limitations (latency and bandwidth) of the communication link, an obvious solution is to evolve disruptively towards autonomous system. However, incremental autonomy approach with immediate return on investment could be made possible with careful mission's analysis and thorough analysis of communications limitations on operation efficiency. This paper will present only a methodology that attempts to develop a deep understanding of the communication physical effects and their consequences on performance of targeted remote operations. The impact of latency and bandwidth are studied using interactive simulations associated to future offshore trials. At the time of writing, the simulator has been commissioned and a proof of concept trials has been prepared.

NASA Ames' Exploration Ground Data Systems (xGDS) supports rapid scientific decision making by synchronizing information in time and space, including video and still images, scientific instrument data, and science and operations notes in geographic and temporal context. We have deployed xGDS at multiple NASA field analog missions over the past decade. In the last two years, we have participated in SUBSEA, a multi-institution collaborative project*. SUBSEA used the research ship E/V Nautilus along with its two remotely operated vehicles (ROVs), Hercules and Argus, to explore deep ocean volcanic vents as an analog for ocean worlds (e.g. Enceladus). This work allowed us to compare the existing oceanographic operations methods and technologies used for ocean exploration with corresponding tools and approaches developed and used at NASA. In the first year of SUBSEA we observed existing remote science operations from the Inner Space Center (ISC)**. In the second year, we deployed xGDS at ISC to complement existing capabilities with xGDS tools designed to support remote Nautilus science operations from the ISC. During operations, video, ROV position and instrument telemetry were streamed from the ship to the ISC. As the science team watched dive operations, they could annotate the data with observations that were relevant to their work domain. Later, the team members could review the data at their own pace to collaboratively develop a dive plan for the next day, which had to be delivered on a fixed daily schedule. The opportunity to compare operations under different conditions enabled us to make several key observations about conducting remote science and planning operations efficiently: (i) Reviewing data collaboratively and interactively with temporal and spatial context was critical for the remote science team's ability to plan dive operations on the Nautilus. (ii) Science team members were actively engaged with the remote dive operations because they could interact with the collected data and visualize it as they desired. (iii) Being able to replay past events at accelerated speeds, and jump to points in time and spaced based on search results, provided efficient access to critical points of interest in a massive volume of data, so the remote science team could deliver plans on time. * SUBSEA (Systematic Underwater Biogeochemical Science and Exploration Analog) is a multi-institution collaboration supported by NASA, NOAA's Office of Exploration Research (OER), the Ocean Exploration Trust (OET) and the University of Rhode Island's Graduate School of Oceanography (GSO). ** ISC is GSO's telepresence operations facility.

The Perdido Regional Host is a Wet Tree Direct Vertical Access (DVA) Spar Facility in the Gulf of Mexico located approximately 200 miles south of Freeport, Texas. Production from subsea wells flows to Caisson Separators at the seafloor. Pumped oil and free flowing gas travel up risers into the center well of the host facility. Shell, Chevron and BP are joint venture partners with Shell as the Operator. The Perdido Topsides was designed to deliver high producing and drilling functionality while capturing the benefits of a single offshore lift module concept. The benefits of a single module are reduced design interfaces, less steel, pipe & cable, and reduced offshore integration cost and duration. Reduced offshore integration reduces safety risk. Final functionality was 100MBOPD, 200mmcfd gas, 80 MBWPD waterflood, Minimum Area Self Erecting (MASE) Drilling Rig and 150 person Quarters. This paper will communicate the efforts required to successfully meet this goal over the duration of development. System Selection In System Selection, subsurface and water depth requirements drove the solution of a Wet Tree DVA Spar with Artificial lift. In the evaluation of Topsides concepts, Spar Deck benchmarking identified two kinds of facilities (see Figures 1 & 2):Single piece modules - medium throughputs, small rigs and medium staff countsMulti modules were required for larger throughputs, rigs and staff counts This step change opportunity initiated an effort to evaluate the feasibility to extend the single piece concept to the functionality required for Perdido. The technical benchmarking compared dry fabricated weight to functionality, which is independent of market, skewed cost indices. We had found previous functionality metrics such as Barrels of Oil Equivalents (BOE) Throughput as misleading, because it did not take into account the impacts of waterflood, subsea artificial lift power, relative compression requirements or export pipeline pump horsepower. After much trial and error, we chose to use " Total Installed Power?? which included all fired drivers for Power Generation, Compression and Waterflood. This metric captured the impacts previously missing above and showed distinction in the break-over from single lift to multi-module (see Figure 3). Early weight studies placed Perdido's functionality requirements clearly into the multi-module category. Technical benchmarking efforts indicated BP's Horn Mountain design as having the best functionality to weight performance of the Spar Topsides to date. With the assistance of our joint venture partners (BP & Chevron) and Alliance Engineering we evaluated the Horn Mountain design and operating performance. We then created a lightweight Perdido concept with Alliance Engineering that would fall below the maximum lift configuration of Heerema's Thialf Vessel. This was followed by performing extensive reviews challenging the scope and the risking of weight growth exposure.

Offshore petroleum reserves have been discovered in depths approaching 3050 m (10000 ft) in the Gulf of Mexico. Therefore, there is a need for the design of a remotely operated vehicle (ROV) and a launch and recovery system for the vehicle that is capable of working in this water depth. The ROV is an observational vehicle used to observe underwater systems and operations. The design criteria is 3050 m (10000 ft) depth, Gulf of Mexico, free swimming, tethered, able to cut 0.64 cm (0.25 in) steel cable, capable of lifting 22.7 kg (50 lb), and a 1.04 m/s (2 kt) forward speed, 5.2 m/s (1 kt) lateral speed, 5.2 m/s (1 kt) vertical speed. The ROV must be capable of being launched in a sea state 4, recovered in a sea state 5, shipped on one truck without permit, and the launch system must provide a 2.4 m (8 ft) clearance from the ROV to the side of the support ship.

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.