New Concept Used in Satellite Subsea Well Systems

Since 1969, Conoco Inc. has installed ten offshore wells and one land test of subsea completion systems. These wells consist of four single zone oil wells plus one water injection well with Thru Flowline (TFL) pumpdown capability and three single zone gas wells plus three dual zone gas wells utilizing the "Plain Jane" wellheads without TFL capability. The control systems for these wells have varied from an electro-hydraulic sequential system to a straight discrete hydraulic system. This paper deals with the design, installation, and operational problems encountered and the remedial procedures taken to solve the problems to date. Introduction Conoco Inc. completed their first subsea well, Grand Isle 47 No.3, on April 2, 1969. Since that time one land test of a simulated subsea completion and nine subsea completions have been placed on production. All of Conoco's subsea wells have been with "Wet Type" Christmas trees; however, the control systems used to control these subsea tree valves have varied. Four different groups of Conoco engineers have designed the control systems to meet their desired control functions. Problems encountered with some of the control systems have changed the basic philosophy of operation, therefore, requiring a change in control system. Primarily this change was made so all production operating control valves are located on the platform or control site. Conoco therefore considers all valves located below the water line to be safety valves. All sequencing of valves to regulate flow is accomplished at the platform and the need for sequencing the subsea tree valves and surface controlled subsurface safety valve (SCSSV) is eliminated. In an emergency situation all valves should close as fast as possible regardless of the order of closure. Discussion Grand Isle 47 No. 3 was completed in April 1969 as an 8500 foot single zone oil well located in 100 feet of water in the Gulf of Mexico approximately 1700 feet from the production platform. This subsea completion utilized a "wet type" tree with Thru-Flowline Pumpdown (TFL) capability. The subsea tree was operated by a ganged type discrete control system. (See Figure No.1.) Four control lines (1/2 inch Schedule 80 black pipe) were connected as follows:production line master "M" and wing "W" valvesservice line "M" and "w" valvesannulus "A" valvecrossover "C" valve The first problem, encountered with this system occurred five months after initial completion. A coupling failure occurred in one of the hydraulic control lines at the flowline-to-subsea-tree-connector. Couplings on all four control lines had to be changed. Four months later three of the control line were plugged with an unknown material and had to be disconnected and purged with fresh oil/water hydraulic fluid. This well had to be prematurely abandoned due to the inability to perform TFL scrapping operations. A bad alignment problem with the service flowline to subsea wellhead connection terminated scrapping operations.

This paper describes the design, manufacture and operation of a simple, tubing-based, triple bore riser used for the initial completion of the Shell-Esso Underwater Manifold Centre (UMC) wells. The design demonstrates the use of standard well tubular goods and couplings in a completion riser system requiring special end terminations only. The novel design of these riser end terminations permitted timely manufacture of the components required to complete the riser system. The installation technique and operation of the riser in service is reviewed and solutions to the several problems encountered are presented. The paper concludes that a relatively simple and low cost alternative to a multibore integral riser system has been proved by its successful operation. INTRODUCTION Initial completion activities of Central Cormorant UMC wells (150 m W.D.) typically involve extensive operations through the permanent completion after the subsea christmas tree has been installed and connected to the UMC manifold (Ref.1). Figure 1 depicts the simplified downhole completion and riser system for a typical production well. Dual strings of 3 ½' O.D. tubing are installed in the permanent completion, even for the single zone production well shown, as the downhole completion provides for future well maintenance via Through- F1owline (TFL) well servicing techniques. The christmas tree installed is a triple bore, solid block design providing vertical access to each of the tubings (denoted primary and secondary string) and to the tubing/casing annulus below the tree. All.completion work could be performed through a single strong riser system; however, this would involve several deployments of the riser on each well if vertical access to more than one bore were required. Simultaneous connection and access to all three bores, via a triple bore riser, provides the most technically efficient and time-effective method for the perforating, production testing and wireline work required. With ready access to all bores, 10 to 15 days work are generally required per well for initial which completion activities through a triple bore riser system. BACKGROUND As shown in Figure 1, the completion riser system consists of a triple bore solid valve block at each end of the triple bore riser. For completion work conducted from 1980-83, the riser itself comprised a number of integral completion riser joints of 50? typical length. Each integral riser joint consisted of two 4' O.D. tubings and one 2 7/8' O.D. tubing encased in 13 3/8' O.D. structural casing. Riser joint connections were similar to those found on drilling risers except for the addition of three internal stabs or receptacles for connection and sealing of each of the tubing bores. During refurbishment of the integral riser joints at the end of 1983, inspection revealed material defects and deficiencies in most of the riser joints. It was considered that repair and replacement could not be accomplished in time for use on the next well, due for completion six months later.

New concepts were used to install three satellite subsea wells at Conoco's Murchison field, located in 510 feet of water in the North Sea. Originally drilled as exploratory wells, they were re-entered and completed. The sequence of events in bringing the wells to production incorporate the following concepts:Completion with dual 3 1/2" O.D. tubing retrievable safety valves inside 9 5/8" O.D. - 47 pound casing.Subsea controllers were not used.Flowline bundles were constructed onshore and towed below the surrace 264 miles to the field.Six high pressure lines were connected at one time using metal to metal gaskets while the flowline bundle was buoyant nine feet off the seafloor. Two satellite subsea wells have produced more than 23,500 BOPD and demonstrated the viability of using exploratory wells for field development. Introduction In 1974 Conoco concluded an extensive engineering study for deepwater production systems. This study revealed that satellite subsea wells failed because of:Complex subsea control systems.Downhole safety valves.Inadequate flowline laying, connection, and burying methods. The results of a 7 year development program are the successful installation and operation of three satellite subsea wells in the North Sea. This accomplishment has truly begun a new era for Submerged Production Systems. Three wells originally drilled in 1975-76 for exploratory purposes were re-entered and completed as satellite subsea completions with Through the Flow Line (TFL) Pump Down Tool capability. Flowline bundles too, complex and expensive to be installed by conventional methods, were constructed on shore, launched into the sea and towed below the surface 264 miles (Figure 1) to the Murchison Field, where they were lowered to the seafloor and then connected to the wellheads and platform. Two wells, located in 510 feet of water, produced more than 23,500 BOPD. A third well is a water injection well located 6500 feet from the platrorm. Production from each well flows through two horizontal tubing extensions to a platform located christmas tree. Four lines control the safety functions of each subsea well from the surface. Six lines are bundled inside a pipe which serves as a buoyancy chamber, thus permitting the lines to be "flown" into position (Figure 2). Selection of this outer pipe was such that balancing chains overcame the natural buoyancy of the system allowing the flowline bundle to land a controlled distance from the seafloor. Economic Justification The economic justification of the satellite subsea wells was early production and accelerated production rate buildup. The Murchison exploratory wells, which in the early planning stages had been considered expendable, were brought onto production at the same time as two wells which were drilled from the platform; thus making four production wells and one water injection well available, when the platform facilities were ready to receive oil. Development Schedule A failure analysis conducted by Conoco of other satellite subsea wells showed many incidents of failure were caused by anchors dragging on the seafloor.

K5F3, the world's first fully all-electric well of the subsea industry, has been opened to production on 4 August 2016. This paper will present the benefits of electric subsea control compared with current state-of-the-art hydraulics methods, describe R&D projects that led to this first industrial application, and outline the main project phases and milestones. Difficulties encountered will be presented, and lessons learned will be disclosed. Finally, this paper will present future plans for subsea electric control going forward. The current state of the art for subsea well control is based on hydraulic technology. Hydraulic fluid is supplied from a host facility to the subsea wells through dedicated tubes within an umbilical and is distributed to the wells, in which the typical components are the manifold, Christmas tree valves, and downhole safety valve. The all-electric subsea well consists of an electric subsea Christmas tree, electric downhole safety valve, and associated subsea control modules. Valve control is established via an electric cable. The main driver for this innovation is cost reduction. Umbilicals are complex, difficult to install, and highly expensive. Replacing hydraulic fluid tubes by an electric cable within the umbilical can provide a 15% cost savings over a 30-km step-out. Implementing electric technology for Christmas tree valves and downhole safety valve control can also generate a further 10% cost reduction. All-electric subsea control is also an enabler for subsea processing innovations for more cost-effective subsea developments in a low oil price context. A global 30% to 40% reduction, outside of market effects, is the goal. This technology improves control of environmental impact by removing the risk of hydraulic fluid release, and personnel safety is improved with the removal of high pressure equipment and containment on topside facilities. Finally, electric technology demonstrates higher reliability compared to hydraulic systems and offers less complex subsea distribution and simpler hardware components. Electric Christmas trees have been successfully operating on two wells of the K5 field offshore Netherlands since 2008, and the electric downhole safety valve has been developed. Although K5F3 is a subsea well in a shallow-water environment, all components have been qualified for 3,000 m of water. In 2015, the global control system has been fully qualified and successfully tested through factory acceptance testing (FAT), extended factory acceptance testing (e-FAT), and site integration testing (SIT). The well was spudded early 2016, completed in June, and successfully put on stream in August. Electric control of wells is already taken into account for conceptual development studies and will become the base case for all of one operator's deep offshore projects when K5F3 demonstrates the efficiency of the technology.

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

K5F3, the world's first fully all-electric well of the subsea industry, has been opened to production on 4 August 2016. This paper will present the benefits of electric subsea control compared with current state-of-the-art hydraulics methods, describe R&D projects that led to this first industrial application, and outline the main project phases and milestones. Difficulties encountered will be presented, and lessons learned will be disclosed. Finally, this paper will present future plans for subsea electric control going forward. The current state of the art for subsea well control is based on hydraulic technology. Hydraulic fluid is supplied from a host facility to the subsea wells through dedicated tubes within an umbilical and is distributed to the wells, in which the typical components are the manifold, Christmas tree valves, and downhole safety valve. The all-electric subsea well consists of an electric subsea Christmas tree, electric downhole safety valve, and associated subsea control modules. Valve control is established via an electric cable. The main driver for this innovation is cost reduction. Umbilicals are complex, difficult to install, and highly expensive. Replacing hydraulic fluid tubes by an electric cable within the umbilical can provide a 15% cost savings over a 30-km step-out. Implementing electric technology for Christmas tree valves and downhole safety valve control can also generate a further 10% cost reduction. All-electric subsea control is also an enabler for subsea processing innovations for more cost-effective subsea developments in a low oil price context. A global 30% to 40% reduction, outside of market effects, is the goal. This technology improves control of environmental impact by removing the risk of hydraulic fluid release, and personnel safety is improved with the removal of high pressure equipment and containment on topside facilities. Finally, electric technology demonstrates higher reliability compared to hydraulic systems and offers less complex subsea distribution and simpler hardware components. Electric Christmas trees have been successfully operating on two wells of the K5 field offshore Netherlands since 2008, and the electric downhole safety valve has been developed. Although K5F3 is a subsea well in a shallow-water environment, all components have been qualified for 3,000 m of water. In 2015, the global control system has been fully qualified and successfully tested through factory acceptance testing (FAT), extended factory acceptance testing (e-FAT), and site integration testing (SIT). The well was spudded early 2016, completed in June, and successfully put on stream in August. Electric control of wells is already taken into account for conceptual development studies and will become the base case for all of one operator's deep offshore projects when K5F3 demonstrates the efficiency of the technology.

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.

This paper will present the work to date accomplished by a petroleum equipment company and its licencer in conjunction with a major oil company in developing a subsea satellite layaway christmas tree to be used in l800m water depths. The paper describes the techno logical agreement tree description; the solution adopted in key areas of the design; how interfaces points were defined for installation and operation; and future work plans on prototype fabrication and tests. Upon completion of this project this will be the first subsea satellite tree built to be used up to this water depths. INTRODUCTION In the beginning of the 80?s t with the deep water oil fields discovered in Brazil one question came out: "How to produce the oil in so deep water depth?" Research studies was initiated to investigate and evaluate conceptions to answer that question, and in 1986 a technological agreement with the oil company was officilized to develop a deep water christmas tree to make possible production up to l800m water depth. The preliminary specification was defined in the contract and after some recommended revisions considering the operational and installation procedures for this water depth, the tree design has been defined and this paper presents the design of the equipment, result of the united work that join the operational and technological experiences. TREE AND WELLHEAD SYSTEM OVERVIEW The DLL-GLL-1800m subsea christmas tree, is totally diverless and is installed without guide lines in a maximum water depth of 1800 meters. It has been designed to land on 16-3/4" × 10,000 PSI tubing spool. Material mechanical properties are controlled to allow service in high concentrations of hydrogen sulfide (H2s). The design provides a layaway flowline system to land flowlines attached to the tree or attached to the tubing spool. Wellhead description The wellhead on to which the tree will be installed is an 16-3/4" × 10,000 PSI SG- 5 external profile guidelineless system. The tree design can be easily adapted to land on to other wellhead profile. Tree description The subsea christmas tree has one 4-1/16" production bore and one 2-1/16" annulus bore. Vertical wireline access is provided for both bores. The tree is rated to 5000 PSI maximum working pressure. All hydralically operated tree gate valves have a hydraulic override to be operated by a R.O.V. The valves maybe mechanically locked open in case of problems with hydraulic lines. They are fail close excepting the optional external crossover valve. The production tubing strings is suspended by a tubing hanger set in a tubing spool. Tree and tubing hanger will be run on a 9.5/8" completion riser. Operation for the SCSSV is provided by two separate lines during tubing hanger installation and after tree installation by one line from the surface with by-pass for both lines on tubing strings.

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.

Production from small oil reserves found offshore which would be uneconomic on the basis of a conventional approach have been developed by utilising a Floating Production Storage Unit permanently moored to the seabed by a Single Anchor Leg System. The storage unit not only supports the production facilities but also acts as the offshore terminal, thus offsetting the cost of a pipeline and shore terminal. In addition to the use on small reservoirs, a similar installation may also be utilised for the early production of large offshore oil accumulations and in both cases, retains the advantage that a major part of the investment can be redeployed elsewhere when the field has been exhausted or permanent facilities have been installed. This paper describes a system installed offshore Tunisia by Shell Tunirex but unlike other floating production systems, it has the capability of tying in several sub-sea completed wells. In addition, it has the flexibility to cater for additional wells or functions, such as gas lift or water injection, should they be required to optimise oil recovery later in the field's life.

One of the problems oil operators face in offshore fields in the production phase is the formation of hydrates in the production flow line, as well as in the gas lift injection line, on subsea wells. This problem is a consequence of the very common conditions in flow lines of submarine wells on production for some time, with high pressures, low temperatures and certain water in produced fluids. Once the hydrate is formed on either line, well production is compromised. Although several products and procedures have been applied to avoid this type of scenario, the problem persists, and operators must remove the hydrate plugs from gas lift and flow lines. As those hydrate plugs are formed under high pressure (1400 to 2800 psi) and low temperature (2 to 4 ºC), exposing them to lower pressures even at the same temperatures will dissociate them. Hence, an operator offshore Brazil has for many years removed such plugs by injecting nitrogen in the lines and releasing the pressure at certain point, thereby reaching the lower pressures required to dissociate the plugs. This procedure, although effective, is inefficient, as a floating rig is required to access the subsea Christmas tree and control over the pressure applied on the plugs is limited. As a result, most of the time the removal of thoseplugs takes weeks, making it a high-cost solution. To find a more efficient solution, the operator and a service company joined in a technological cooperation agreement to test on two wells a field-tested concentric coiled tubing technology with a jet pump, to improve the control over the low pressure applied on hydrates formed in flow and gas lift lines. This paper presents the case histories on those pioneering operations, the challenges found in offshore scenarios and the successful results of the application.

The latest pumpdown (TFL) completion methods and capabilities are now being used with consistent reliability worldwide including the North Sea, Gulf of Mexico, Borneo, and on land United States. These capabilities allow placing the H-member at well bottom, full alternate multiple zone dual completions, surface selective downhole shifter/locator system, and downhole gas lift and safety systems; all of which are adaptable to subsea manifolds and atmospheric chambers, riser systems, floating platforms and standard platform completions. INTRODUCTION The search for oil has pushed the oil industry into deeper and less accessible waters. The costs for production platforms and pipelines have increased accordingly. For a well to be profitable under these conditions it must be able to produce large amounts of oil and be easily maintained. The result has been an increased demand for pumpdown (TFL) completions with large bores specially designed for deep water. These completions, in addition to the basic pumpdown (TFL) requirements, must also incorporate other certain features as discussed below.The capability to perform maintenance and service work on subsea wells with flow lines up to 20 miles long. This distance results from cluster and satellite wells being placed further from fixed or floating platforms.The capability to locate downhole equipment selectively. This is more a demand on the deep or long flow line wells where the pressure response is minimal.The capability to perform limited maintenance work on wells with BHT up to 450½F and BHP's over 20,000 PSI that are in excess of 20,000 feet deep.Maintaining pressure integrity and response and keeping fluid losses to minimum While performing service operations. This is very important in wells having low bottom hole pressures and subsea wells having extremely long flow lines.The compatibility of downhole equipment within the whole system.The incorporation of a circulation path (H-member) of some sort, whether downhole or in the wellhead.Surface controlled subsurface safety systems. This is a necessary safety precaution with the ever present threat of damage to wellheads and flowlines. As will be discussed in this paper, recent innovations in pump down (TFL) equipment now provide these features and offer solutions to the problems of well maintenance. DESCRIPTION OF EQUIPMENT In the past three to four years much development work and testing has taken place to help answer the problems faced by deep water completions. The developments include wellhead plugs, pumpdown retrievable ball valves and tubing retrievable ball valves for pumpdown use, pumpdown kickover tools with side pocket mandrels and side-pocket H-members, 'Select-20' shifter and locator systems, upper H-members with emergency circulating shear discs, sliding sleeve H members for gas lift in tubing less completions, and equipment for servicing deep, high pressure land wells.

This paper describes the concept and design of six subsea wells installed in the Gulf of Mexico in 1978. Wellheads, Christmas trees, control systems, and drilling operations are described in detail. Choice of equipment and methods was based on experience, simplicity, and reliability. Diver assistance was planned and incorporated. Costs compared favorably with those of other methods of production. Introduction Since 1975, when the first underwater wells were completed in 100 ft (30 m) water in Lake Erie using conventional land equipment, subsea well completions have increased in number and complexity. Today, more than 300 sublake and 100 subsea completions have been installed worldwide. Major technological developments include Seal's intermediate system (SIS), Lockheed's 1-atm (1.02-kPa) wellhead cellar, Exxon Corp's submerged production system (SPS), Transworld Drilling's production system (SPS), Transworld Drilling's satellite well and central manifold concept, and Deep Oil Technology's template concept with tension leg platform-all created for deepwater production. platform-all created for deepwater production. Because of associated technological advances, new methods, procedures, and equipment now allow us to make shallow-water, single-well completions with "off-the-shelf" equipment at costs competitive with platform development. These shallow-water wells platform development. These shallow-water wells have become attractive alternatives for producing shallow reserves (especially gas) that cannot be reached from existing platforms. Fig. 1 illustrates the system concept.This paper describes the concept and design of six subsea wells that Conoco Inc. (as operator with Atlantic Richfield, Getty Oil, and Cities Service companies -the CAGC group) installed in the Gulf of Mexico in 1978. The wells were drilled to develop shallow [4,000 ft (1200 m) total depth] gas reserves in 100 ft (30 m) water. This paper describes the wellheads, Christmas trees, control systems, and drilling operations (both jackup and semisubmersible rigs.) Summary This specific subsea system design was chosen with the intention of paying out the investments with proven equipment; we did not intend to test new proven equipment; we did not intend to test new technology. The only new developments were improvements based on practical, field-oriented experience. Essentially, this paper updates the state of the art of wet Christmas-tree technology by presenting a simple, reliable system that can be used presenting a simple, reliable system that can be used quickly and easily. Fig. 2 illustrates the subsea system components.The wells were isolated individually at six different locations in the Grand Isle area, offshore Louisiana. In each case, the directional angles and distances were too great to allow drilling from existing platforms. Reserves would not justify installing even the platforms. Reserves would not justify installing even the least expensive type of fixed structure. However, the subsea method was a feasible alternative economically (Fig. 3). From an operational standpoint, our belief in the dependability of the equipment was justified by recent experiences. JPT P. 1083

Aiming the rationalization of subsea operations to turn the production of oil and gas more economical and reliable, standardization of subsea equipment interfaces is a tool that can play a very important role. Continuing the program initiated some years ago, Petrobras is now harvesting the results from the first efforts. Diverless guide lineless subsea christmas trees from four different suppliers have already been manufactured in accordance to the standardized specification. Tests performed this year in Macae (Campos Basin onshore base), in Brazil, confirmed the interchangeability among subsea Christmas trees, tubing hangers, adapter bases and flowline hubs of different manufacturers. This interchangeability, associated with the use of proven techniques, results in operational flexibility, savings in rig time and reduction in production losses during workovers. By now, 33 complete sets of subsea Christmas trees have already been delivered and successfully tested. Other 28 sets are still being manufactured by the four local suppliers. For the next five years, more than a hundred of these trees will be required for the exploitation of the new discoveries. This paper describes the standardized equipment, the role of the operator in an integrated way of working with the manufacturers on the standardization activities, the importance of a frank information flow through the involved companies and how a simple manufacturing philosophy, with the use of construction jigs, has proved to work satisfactorily. INTRODUCTION Most segments in the oil industry consider that interface standardization is an important tool that can be used to achieve rationalization of methods and equipment, bringing considerable advantages, mainly economical. Particularly in the subsea equipment area, these advantages can also be obtained. In fact, Petrobras has already gained benefits resulting from standardization made in the past. The main significant interfaces already standardized by Petrobras are:the H4 profile for subsea wellheads;the internal profiles for wireline set plugs in the tubing hanger and subsea christmas tree reentry mandrel for both production and annulus bores;the tops of tubing hanger running tools and subsea tree/tree cap running tools terminating as a standard completion riser pin;the top of guide posts;the ROV interfaces used on subsea chrisfmas free. The following facts have been considered when Petrobras decided to implement a standardization program:the operational offshore experience acquired during the last decade;the large number of subsea wells to be drilled and completed to develop Marlim, Albacora and Barracuda fields whose development is being carried out using large number of guide lineless subsea christmas trees;the potential economical advantages in dealing with common rigs, tools, risers, wellheads, subsea trees and spare parts for more than 200 wells The main concern about the standardization program devised by Petrobras was to achieve the interchangeability with equipment manufactured in different occasions and even by different suppliers. So, it was necessary to define not only functional and performance requirements, but also some crucial geometry and dimensions, mostly of interfaces.

The original Ursa TLP development plan called for 16 production wells, 11 firm and 5 contingent. Initial design was for 11 TLP wells and 3 subsea wells. The plan also included batch setting 21 well positions and pre-drilling 6 of the TLP wells in 3,950' of water in MC block 810. In late 1997 a significant shallow flow occurred at the batch set site during the final batch operations. Events proceeded such that all wells were lost and the site became unusable for the foundation support. Development plans were modified to move the installation site to an area with still significant but smaller shallow flow risk in MC block 809, in 3,800' of water. The batch set was reduced to only 12 TLP production wells. Drilling was to proceed with 1 to 2 pre-drills. Subsea wells were deleted from the plan. This paper discusses the Ursa well systems including early drilling, final batch set and pre-drills, the TLP rig, riser systems and completion systems. It presents how these areas approached shallow flow and the other challenges to produce the Ursa reservoirs. Introduction The Ursa field was discovered in 1990 in 4,023' of water in Mississippi Canyon (MC) block 854. The expected gross reserves are estimated to be 431 MMBOE in five reservoirs (Below Pink, Above Magenta, Lime Green, Yellow and Aqua/TerraCotta) in MC blocks 809, 810, 853 and 854. Depths of the objective sands range from 12,000' TVD to 19,000 TVD. Approximately 80% of the reserves are in the Yellow and Aqua/Terra Cotta reservoirs. Ursa is an oil field with significant gas volumes. Following the appraisal drilling program, it was decided that Ursa development would utilize a 24 well slot TLP located in MC block 810. The initial design called for 11 TLP wells and 3 subsea wells. The original development plan included 21 batch set wells and 6 pre-drills on the TLP. The initial site location in MC block 810 was lost due to shallow flow problems during batch drilling. At a new site in MC block 809, the number of planned batch set wells was reduced to from 21 to 12, the number of predrilled wells was reduced from 6 to 1 or 2, and subsea wells were deleted. A total of 11 batch wells were successfully drilled with casing set below the base of the shallow flow sands. The reserves associated with the other 3 originally planned wells will be developed with TLP well sidetracks or future subsea wells. The rig on the TLP will complete the predrilled wells and proceed to drill and complete the rest of the wells. The original rig rating was for 25,000' measured depth (MD) and 12,000' step-out. The MC block 809 site requires a rig rating for over 28,000' MD and 17,800' step-out at 19,000' TVD. The rig capability was evaluated and slightly modified to meet the new requirements. The production riser system includes equipment from the connector which attaches to the subsea wellhead up to the surface tree and choke. Ursa uses a dual pipe riser system which accommodates 10,000 psi and 15,000 psi pressure ratings. The 10,000 psi system is 13-5/8" by 10-3/4". The 15,000 psi system is 14" by 10-7/8". The decision to complete the wells with 5-1/2" tubing drove the size of the dual riser system. The large size, high pressure and water depth pushed the riser loads to very high values. The completions on Ursa are designed to deliver high rate and achieve high ultimate recoveries. Multiple techniques will be considered, including: internal gravel pack, frac pac or high rate water pack and possible horizontal completions. The system must accommodate 15,000 psi and 10,000 psi pressure ratings and 5-1/2 and 4-1/2" full bore tubing sizes. The completion type will be determined on each well as drilling is completed and well logs are evaluated.