Through-flowline Research Articles

Pompano Through-Flowline System

Summary The Pompano field development was done in two phases. The first phase consisted of installing a deep water platform, topsides and export pipelines in 1994. The second phase consisted of installing a 10-well subsea oil production template in 1995 and tying it back to the host platform. The subsea template system, which incorporates through-flowline (TFL) well servicing capability, is discussed in this paper. The subsea system, with emphasis on the TFL aspects is described and costs are provided. A single-phase, steady-state, isothermal circulation model is described. This model was used during predesign to aid simulation of the wide range of TFL system operating conditions that are expected during field life. Actual field experience that has been gained since start up of the subsea system in 1996 demonstrates the value of doing this type of hydraulic modeling. Further TFL-related development work is needed to extend TFL capabilities beyond those applied at Pompano, and these development needs are discussed. Conclusions are provided at the end of the paper.

Evolution of Subsea Production Systems: A Worldwide Overview

The evolution in the use of subsea technology has seen advancement from one well in the Gulf of Mexico in 1961 to more than 750 wells in a wide variety of locations by the end of 1993. Along with the growth in numbers, the industry has seen rapid advances in technology, increased distances from the host facility, and water depth records. This paper gives an overview of the evolutionary changes in subsea applications, with emphasis on the most active regions and on some of the milestone installations that shaped the technology advance.

Pressure Falloff Response Time Considerations in Subsea Wells Equipped for Through-Flowline Maintenance

Summary Applying subsea wells many miles from a production receiving location is feasible. In some instances, equipping wells for through-flowline (TFL) maintenance is economically attractive, particularly if well vertical reentry to perform simple downhole particularly if well vertical reentry to perform simple downhole tasks using wireline methods is costly. As the subsea well distance increases, the effect of pressure falloff response time for some types of TFL tool-string operations becomes more important. This paper describes an analytical method that can be used to predict the pressure changes with time at the remote TFL tool predict the pressure changes with time at the remote TFL tool string for a typical subsea well system. Also, analytical methods for selecting the active tool-string components, including accelerators and jars, are described. Introduction Subsea well applications have been used for more than 20 years to complement conventional offshore platform field developments and the more recent floating production system field developments. Subsea well applications will continue to be of increasing interest as hydrocarbon discoveries are made in deeper water and, in some instances, in unusually inclement environments. Through mid-1982, a total of 183 subsea wells had been installed worldwide, 1 and 34 of these subsea wells were equipped for TFL servicing. TFL methods can be used to minimize the need for using a drilling/workover rig to re-enter a subsea wellbore to perform relatively simple downhole work tasks. Since these rig perform relatively simple downhole work tasks. Since these rig costs can be as high as $100,000/day, the economics of equipping subsea wells for the TFL servicing from a remote producing location can be favorable. Depending on the specific subsea well configurations and number of wells, adding TFL servicing capability can increase well system costs by 10 to 25%. Although basic design methods for TFL-equipped systems have been established, TFL technology continues to be developed. Thus, each new subsea well that is equipped for TFL servicing should lead to further advances as applications experience is gained. To date, TFL methods have been applied on subsea wells that are located up to 3 miles [4.8 km] from a support location. As these methods are applied in larger line sizes and over longer distances, the effect of pressure falloff response time on TFL tool-string manipulations becomes pressure falloff response time on TFL tool-string manipulations becomes more important. Although many different types of tool-string manipulations are performed during pumpdown operations, jarring operations involve specific manipulations that activate tool-string components. These manipulations are strongly affected by the pressure falloff response time, and this paper addresses these effects. Typical TFL- equipped systems, tool strings, and a method for predicting pressure falloff response time across remote TFL tool strings are pressure falloff response time across remote TFL tool strings are discussed in the following sections. TFL-Equipped Subsea Well A typical subsea well system that includes TFL servicing is shown in Fig. 1. The system includes the subsea well completion, flowlines, and surface support equipment. Well completion equipment is designed to meet two basic objectives. First, completion tubulars and flowlines are selected to allow producing the well at desired rates while meeting pressure requirements. Second, TFL-related downhole equipment is selected and positioned so that TFL tool strings can be circulated to specific work points in the system. TFL equipment designs are currently available for selecting up to 20 downhole work positions. Surface support equipment is connected to the subsea well and configured to meet three objectives. First, subsea well production equipment is integrated with the pumpdown equipment. Second, pumpdown manifolding and pumping equipment is provided for pumpdown manifolding and pumping equipment is provided for circulating TFL tool strings to and from subsea-well work points while maintaining well control. Third, a TFL lubricator assembly is incorporated to allow easy and safe insertion and recovery of TFL tool strings from the pressure piping system. The high-pressure pump and manifolding system can be either portable or permanent, and pumpdown fluids may include dead oil or inhibited permanent, and pumpdown fluids may include dead oil or inhibited seawater. Also, various clear, weighted completion fluids can be used. A TFL-equipped subsea well system allows many routine and nonroutine downhole work activities to be performed from the surface support location. JPT P. 1082

Newest Through-Flowline Retrievable Safety Valves for Subsea Completions

Two new retrievable-ball-type safety valves are now available in the through-flowline (TFL) (pumpdown) configuration. These valves offer greater depths in a more simplified configuration to operators planning subsea completions. They were developed at the request of major producers for use in the North Sea and Southeast Asia. Design of these new valves began in 1977 and early 1978 by engineers from our RandD Dept. One valve is a balance-line valve with a fail-close leak protection feature. The other valve is a single-line, deep-set valve that allows installation at greater depths than previously achieved. They have tested successfully in test wells and test loops by the manufacturer and in two land test wells by the operators. The safety system packages for these valves currently are installed in two subsea wells, one in the North Sea and the other in the South China Sea. This paper discusses how the capabilities of subsea production are expanded by the development of a truly failsafe, balance-line, retrievable-ball valve and a deep-set, single-line ball valve that can be placed at or near the packer, below paraffin levels, or below the kickoff point.

Evolutionary Developments Advancing the Floating Production, Storage, and Offloading Concept

Summary Tanker-based floating production, storage, and offloading (FPSO) systems have been in operation since Aug. 1977, when a single-well FPSO facility was put into production by Shell Espania in the Mediterranean. The overall operational experience with this system at this field is reviewed, with special attention to the wireline work over facilities, which have proved very satisfactory. A subsequent evolutionary step, a FPSO system accommodating multiple wells, necessitated development of a multi bore fluid swivel. A design program for this swivel was initiated in 1978; a prototype was built and full-scale testing finalized in 1980. A summary of the test results is presented. Simultaneously with the multi bore swivel development, detailed engineering for an eight-well FPSO unit was begun. This system includes gas-lift and water-injection capabilities. Provisions for through-flow line (TFL) well work over can be incorporated. The detailed design is reviewed, as well as the latest development whereby the FPSO concept has been adapted to the North Sea environment. Introduction and Background Stationary offshore terminal facilities using former trading tankers were employed by the oil industry as early as 15 years ago. Initially, a tanker was connected by conventional hawsers to a catenary anchor leg mooring, where it served as a combination buffer storage vessel and mooring platform for shuttle tankers. Poor operational experience, low survival characteristics, and high maintenance costs stimulated the development of the single-buoy storage (SBS) system employing rigid arms for permanently mooring the vessel to the buoy. The first terminal of this type became operational in 1973, and it and half a dozen similar terminals have served efficiently for many years. In Aug. 1977 a further step in the evolutionary process was taken with the startup of a tanker-based, rigid-arm single anchor leg storage (SALS) floating production facility at the Castellon field in the Mediterranean off-shore Spain. This system incorporates conventional separation equipment on the vessel for producing from a single subsea-completed well. A second similar facility also producing from a single well was installed in 1980 at the Nilde field in the Sicilian Channel. Recognizing the need for testing and producing independently from two or more wells and injecting into wells, Shell instigated a program in 1978 to develop a high-pressure, multi flow-path swivel for interfacing the weathervaning vessel with the nonrotating buoy or riser. In Aug. 1981 a facility went into operation at the Cadlao field offshore Philippines using this new high-pressure, multi flow-path swivel producing from two subsea-completed wells. A fourth FPSO facility capable of accommodating eight wells went into production at the Tazerka field onshore Tunisia in late 1982. Table 1 provides a recap of these four FPSO facilities. The Floating Unit While a semisubmersible platform is usually in a fixed mooring pattern, a tanker-based floating production facility is normally designed to weathervane, thus introducing the necessity for mechanical and fluid swivels. Both types of swivel must be engineered carefully and constructed to precise specifications. JPT P. 695

Insert Tree Completion System

Summary This paper outlines the over-all project for development and installation of a low-profile, caisson-installed subsea Christmas tree. After various design studies and laboratory and field tests of key components, a system for installation inside a 30-in. conductor was ordered in July 1978 from Cameron Iron Works Inc. The system is designed to have all critical-pressure-containing components below the mudline and, with the reduced profile (height) above seabed, provides for improved safety of satellite underwater wells from damage by anchors, trawl boards, and even icebergs. In addition to the innovative nature of the tree design, the completion includes improved 3 1/2-in. through flowline (TFL) pumpdown completion equipment with deep set safety valves and a dual detachable packer head for simplified workover capability. The all-hydraulic control system incorporates a new design of sequencing valve for both Christmas tree control and remote flowline connection. A semisubmersible drilling rig was used to initiate the first end flowline connection at the wellhead for subsequent tie-in to the prelaid, surface-towed, all-welded subsea pipeline bundle. The acceptance stack-up tests in the U.S. and the subsequent land tests in Brunei also are described in this paper. paper. Introduction The insert tree is the 11th satellite underwater well to be completed in the northwest Borneo area. The earlier completions all have employed the conventional above-seabed type of underwater Christmas tree, and the last five trees stand about 35 ft above the seabed. This has increased concern about the vulnerability of subsea completions. We conducted various studies to improve the safety and simplification of satellite underwater well design. The insert tree completion system evolved from these studies. Although the total system (including the downhole completion design, control system, and flowline installation) is described, the tree, its design, testing, and installation are the primary subjects of this paper. paper. The Insert Tree Concept This project is the first attempt to lower substantially the profile of subsea Christmas trees above the seabed. The profile of subsea Christmas trees above the seabed. The insert concept (Fig. 1) entails the installation of the wellhead tubing hanger, master valve block, and flow loops inside the marine conductor of an underwater well. The design was achieved following close study of the purpose of the various valves in conventional surface and purpose of the various valves in conventional surface and subsea Christmas trees. On the basis of favorable long-term experience with TFL as a servicing method, vertical access for wireline servicing by use of swab valves and a wye spool are not strictly necessary, and these items safely can be eliminated if desired. Similarly. for a subsea tree. the working wing valves are at the platform, and the subsea valves are used only to shut in the well safely during an emergency or routine testing. This philosophy yields the valve configuration shown in Fig. 2. As indicated. plugs also can be installed in the tubing hanger or above the Christmas tree valves by pumpdown methods, circulating through the normally pumpdown methods, circulating through the normally open production crossover valve. During the completion stage, these plugs can be set and pulled vertically by wireline from the drilling rig before finalization of the completion. P. 2125

Subsea TFL Systems - A Technology Update

This paper presents and analyzes equipment development and testing, completion procedures, and maintenance operations using through-flowline (TFL) methods on five subsea wells in 100 to 200 ft (30.5 to 61 m) of water offshore Brunei. These wells, installed in 1974-76, presently are operated by Brunei Shell Petroleum and include both single-and dual-string (multizone) completions. Introduction In the early 1970's, Shell Internationale Petroleum Mij. (SIPM) undertook a series of studies aimed at the development of systems for producing deepwater oilfields beyond the continental shelf. An important building block in deepwater production systems would be the underwater completed (UWC) well. A principal objective was that the UWC wells would be drilled, completed, produced, and serviced using remote control and servicing techniques. Downhole servicing of the well would be done by pumpdown TFL techniques. Single-Zone Well In 1971 it was envisaged that the UWC wells would have to be large producers for an economical deepwater field development. The terms of reference established for a diverless deepwater subsea completion resulted in these basic requirements and assumptions:the well must be a prolific producer of 5,000 to 10,000 B/D (794.9 to 1589.8 m3/d);no artificial lift by gas lift would be needed;sand production would not be present;completion would be as simple as possible, preferably with a single production string probably 4 1/2 in. (114.3 mm) OD; androutine well servicing by TFL. It was decided to install a pilot UWC (Fairley 16) offshore Brunei (Borneo) in relatively shallow water, permitting easy intervention by divers if necessary. For this purpose a project team was set up in Brunei. Since at that time TFL tools and ancillary equipment had been well-developed only for 2 3/8-in. (60.3-mm) tubing, SIPM approached Otis Engineering Corp. in Oct. 1971 to set up a program for developing and testing TFL capability in the larger tubing size [4-in. (102-mm) nominal size tools].Subsequently Otis designed and constructed the TFL tool string and service tools, a surface-controlled subsurface safety valve suitable for TFL, a Sliding Side-Door (SSD), and a standing valve. The equipment was tested in the Otis test well in Dallas from Aug. to Oct. 1972. A number of modifications were made to the equipment. It became apparent that the "reach rod" approach using conventional sucker rods led to unacceptable friction resistance in the TFL loops. ("Reach rod" refers to an operation whereby a flow control may be installed in a nipple below the TFL circulation point by using rods or bars to span the distance between the flow control running tool and the TFL piston units, which must remain above the circulating point.) To counter this friction, knuckled spacer bars approximately 3 ft (1 m) long were introduced and later tested successfully. JPT P. 1538＾

Abandonment of a Subsea Well

A completed subsea oil well was abandoned in 95 ft of water offshore Louisiana. This paper describes the abandonment procedures, drilling, completion, production operations, and the technical analysis of the recovered Christmas tree. Single-well subsea systems are available for development of shallow-water reserves, but still need improving. Introduction Since 1975, when the first underwater completions were made in +/- 100 ft of 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), the Lockheed One-Atmospheric Wellhead Cellar, Exxon Corp's Submerged 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 in anticipation of deep-water Platform - all created in anticipation of deep-water production. Because of associated technological production. Because of associated technological advances, new methods, procedures, and equipment now allow industry to make shallow-water, single-well completions with "off-the-shelf" equipment at a cost competitive with platform development. These shallowwater wells have become an attractive alternative for producing shallow reserves (especially gas) that cannot producing shallow reserves (especially gas) that cannot be reached from existing platforms (Fig. 1). This paper presents Continental Oil Co.'s experiences in abandoning the subsea well, Grand Isle 47 No. 3, while acting operator for CAGC (Continental, Atlantic Richfield Co., Getty Oil Co., and Cities Service Oil Co.) This well was completed April 1969 in the Grand Isle Block 47 field in 95 ft of water, offshore Louisiana. The completion was primarily an experimental program, but also provided the necessary development to drill in an 8,500-ft oil zone and produced 150 to 250 BOPD. The subsea system was a remotely operated, hydraulically controlled Christmas tree designed for completion and production operations without diver assistance (Fig. 2). production operations without diver assistance (Fig. 2). Through-flowline (TFL) pumpdown tools were used down hole in the dual tubing strings. The TFL and hydraulic control manifolds were located less than 2,000 ft from the well on the Grand Isle Block 47 "A" platform. Two 2 3/8-in. flowlines and four 3/4-in. control lines connected this system to the platform equipment. The well was abandoned in Aug. 1975 because of mechanical problems down hole and with the subsea tree, and because reserves could be recovered by offset updip wells. Summary Diving was the most critical and time-consuming requirement of the abandonment. More than 41 hours of diving time were spent on valve operations and wellhead re-entry. Proper coordination and control of diving by using a television monitoring system mounted on the diver's helmet was the key to operating success. With this subsea system, diver assistance cannot be eliminated completely, but it can be minimized. In fact, diverassisted backup in shallow water can be feasible economically. Initial design and planning of shallowwater, subsea systems should include diver-assisted wellhead re-entry, component repair, and production operations. JPT P. 435