bluuebunny/crossref_metadata_2025 huggingface dataset:
SCSSV System Design Considerations for Hardy Oil's Deepwater Projects
Authors: Melnturff T.L. , Huber D.S. , Bagley D.P.
Published: October 2008

One of the most challenging design efforts associated with deepwater subsea completions is the surface-controlled subsurface safety valve (SCSSV) system. The potential for hydrates to form in the wellbore of deepwater wells forces the SCSSV to be set at increasingly greater depths as the depth of water increases, For conventional wellbore-pressure-sensitive SCSSVS, increasedsetting depths normally yield higher operating pressures, Additionally, dynamic effects inherent in the control system tend to drive operating pressure higher still. These higher operating pressures adversely affect practically the entire system, and must be recognized and accommodated early in the design process to avoid critical limitations in the subsystems which support the SCSSVS (i.e., control system, umbilical, and tree and wellhead system). Likewise, reliability and operability of the SCSSV system must be addressed early in the design phase. The design parameters affecting the SCSSV system for Mustique and Shasta are typical of those encountered in deepwater subsea completions. This paper reviews how these challenges were addressed by the design team for the Mustique and Shasta projects.

Introduction

The Shasta and Mustique subsea satellite wells are located in the central Gulfof Mexico, The two Shasta wells are located in 860 and 1,000 ft of water respectively in Green Canyon Block 136, These gas wells have shut-in tubing pressures of approximately 3,700 psi, are completed with 5,000-psi horizontal trees, and are tied-back 9.5 and 11 miles respectively to Texaco's GC-6 platform (Figure 1). The single Mustique gas well is located in 832 R of water in Garden Banks Block 240, has a shut-in tubing pressure of approximately 7,400 psi, and is completed with a conventional 3-1 /16-in. X I-13/16-in. 10,000-psi subsea tree. The Mustique well is tied-back to Chevron's production platform in GB-236 (Figure 2). Both systems utilize an electro/hydraulic control system with a retrievable control pod mounted on each subsea tree. The coordination of the design, manufacture, testing, and installation of the two systems was performed by a team of contractors' representatives seconded to a team working for Hardy Oil and Gas USA Inc., the operator of the projects.

Early in the project it was recognized that an operable and reliable SCSSV system was critical for project success. For that reason, considerable research and analysis went into the selection of the SCSSV system configuration and components, and as a result of that research, a system utilizing tandem non-equalizing, flapper-type SCSSVS with selective capability and in-line hydraulic control line filters was selected.

The extent to which the SCSSV control system pressure would have to be elevated above shut-in pressure was not tiny appreciated initially. Due to project time constraints, the control umbilicals had to be ordered before final hydraulic analyses could be performed.
Pompano Subsea Development: An Example of How Successful Relationships Result in Effective Project Execution Client/Contractor
Authors: Preston S.M. , Caldwell T.-D. , Beckmann M.M. , Coffman R.F. , Hanks D. , Hebeti C.L. , McDermott J. Ray
Published: October 2008

The Pompano subsea project is a ten well development Iocated in 1865 ft. of water in the Gulf of Mexico. Flow is commingled subsea on a template/manifold and flowed 4.5 miles through dual piggable 8" flowlines to an existing BPX platform, bated in 1290 ft. water. Control is electro/hydraulic, with chemical injection facilities also provided. Primary intervention for paraffin scrapping and reservoir pressure monitoring is TFL (Through FLowline).

This project represents a major milestone in the development of the deepwater oil reserves of the Gulf of Mexico, by being the for remote folded tie-back of an oil producing reservoir. To successfully a project of this nature, it has been necessary to integrate the many engineering disciplines and types of contractors and to exploit the capabilities of the Operator and Contractors in a behavior and business environment which supports team work and innovation.

Introduction

BP Exploration and its partner Kerr-McGee are proceeding with the subsea portion of the Pompano development (Figure 1). This development is located in the Mississippi Canyon (MC) area of the Gulf of Mexico, approximately 135 miles southeast of New Orleans.

Financial approval for the subsea development was given in June 1994, with installation of the template and flowlines in August/September 1995. Drilling started in October 1995 and will continue into 1997. First oil will b achieved in 1st Quarter 1996.

A project of this complexity, representing the first manifolded tie-back of oil production in the Gulf of Mexico, required innovative thinking on bath the technology to applied and on the organizational and behavioral approach to be adopted by the Operator and Contractors. This paper provides an overview of the development, details the project execution philosophy and the procurement strategy that was used to integrate the capabilities of the Project team, and relates the experiences of the key Contractors.

Development Overview

The Pompano subsea development consists of subsea completed production wells, a production template/manifold and associated control system, a flowline/utility line system, and modifications to the existing Pompano platform. There are plans for future water injection if required. Well servicing is by TFL.

The production template supports the subsea Xmas treesand manifold. Ftow is choked on the Xmas trees into either of the manifold production headers. Valving on the trees also allows flow to the well test lines. Diverters on the manifold direct TFL tools to an individual welt for wax scrapping and other TFL activities. A pigging module on the template connects the two oil production flowlines and the two TFL flowlines. The design allows for removal of the pigging module and the future connection of an additional production template in a daisy chain fashion. Figure 2 is the P&ID of the subsea production manifold.
Pompano Subsea Development: Production Control System and Umbilicals
Authors: Pricharct R.M. , DeJohn K.P. , Farrell P. , Baggs C. , Harris D.
Published: October 2008

BP Exploration's Pompano subsea development is a deepwater subsea production project in the Gulf of Mexico. There were various operational and technological challenges which had to k addressed to configure a subsea control system to operate effectively, to be installed and maintained effectively in deepwater, and to do so with the minimization of cost and risk. Through testing and anal benchmarks were developed, which were used to monitor the system performance and provide a powerful analytical tool for this remote system. Another significant feature of the program which greatly reduced risk on costs and time scale, was the contracting style adopted. The control system vendor (GEC-Marconi), as well as other key contractors, involved at the early project definition phase. This provided assistance to BPX in optimizing their field development plan and enabled the key contractors to closely identify with BPXS needs, as well as developing an integrated working relationship. This enabled overall system optimization to occur, while minimizing risks at interfaces. The high-cost derailed implementation phase of the project was extremely fast track.

Introduction

The Pompano subsea development includes up to two subsea template/manifold systems tied back to the Pompano production platform. A ten-slot oil production manifold &T-1) was installed some 4.5 miles southeast of the production ptatform; ten wells are planned at this location. Up to four water injection wells may be installed on a separate template southwest of PT- 1 later. Figure 1 shows the layout of the field development.

The production platform was installed during Phase 1 of the field development in the southeast comer of Viosca Knoll Block 989 (VK 989) in 1,290 foot water depth. The subsea template/manifold was installed in Mississippi Canyon Block 28 (MC 28) in 1,865 foot water depth

The oil production trees, production manifolds, and well systems were designed to be maintained with TFL tools. system has two TFL service lines from the host platform to the production manifolds; one TFL line also serves as a well test line. The production manifold has remotely controlled diverters for directing the TFL tools to the desired well. A multi-fine chemical injection system will treat the subsea production wells and manifolds with paraffin inhibitor, methanol, and corrosion inhibitor.

A multiplex electro and hydraulic system will control and monitor the subsea and related surface equipment. The surface units of the production control system will be heated on the host platform. The operator will control the system from the master control station (MCS) in the control cabin. Separate electric and hydraulic/chemical umbilicals connect the surface equipment to PT-1.
Fracture Control for the Oman India Pipeline
Authors: Bruno T.V.
Published: October 2008

This paper describes the evaluation of the resistance to fracture initiation and propagation for the high-strength, heavy-wall pipe required for the Oman India Pipeline (OIP). It discusses the unique aspects of this pipeline and their influence on fracture control, reviews conventional fracture control design methods, their limitations with regard to the pipe in question, the extent to whichthey can be utilized for this project, and other approaches being explored, Test pipe of the size and grade required for the OIP show fracture toughness well in excess of the minimum requirements.

Introduction

The Oman India Pipeline (OIP) will transport natural gas approximately 1100 km from Oman to India under the Arabian Sea, at water depthsto3525 meters. Because of the unprecedented water depth the design requires line pipe of a size and grade never before manufactured, much less utilized for an offshore pipeline, The pipe will be API Specification 5L Grade X70, with an inside diameter of610 mm and a wall thickness ranging from 36 to 44 mm. The maximum hoop stress will be 330,4 MPa (under shut-in conditions) and the design temperatures are 0° C minimum, 50°C maximum

The pipeline will be constructed with U-O-E pipe made from low-carbon, low-sulfur, micro alloyed steel plate manufactured with thermo-mechanical process control (TMPC) including accelerated cooling. The specified mechanical properties are shown in Table 1. Because so much of the pipeline will be in deep water, the hoop stress of approximately 70 percent of the length of the pipeline will be less than 50 percent of the specified minimum yield strength (SMYS). Therefore, for most of the pipeline the potential for fracture will be much lower than for most pipelines, Figure I shows the maximum hoop stress vs. location along the pipeline

Principles of Fracture Control Design

Fracture control design of pipelines requires that under the most adverse conditions:the pipe has sufficient fracture toughness to tolerate small flaws without fracturing;if the pipe ruptures from any cause, the fracture is ductile;the steel has the capacity to absorb sufficient energy to arrest a ductile fracture, or crack arrestor are added.

Considerable research on the behavior of pipelines sponsored by the Pipeline Research Committee of the American Gas Association(1) British Gas(1) the European Pipeline Research Group ?J)and others has resulted in analytical and test methods to evaluate these three requirements based on the properties of the pipe and the design of the pipeline. Evaluation of these methods by full-scale burst tests as well as their widespread successful application has shown them to be adequate within certain limits of operating conditions and pipeline designs. However, as will be discussed, some aspects of the OIP, especially the wall thickness and design pressure are outside these limits. Nevertheless, as will be shown, the methods can be conservatively applied to evaluate resistance to fracture initiation and to give a reasonable estimate of resistance to fracture propagation.
Simple HydrodynamicModels for the Prediction of Pig Motions in Pipelines
Authors: Azevedo L.F.A. , Bracm A.M.B. , Nieckele A.O. , Naccxhe M.F. , Gomes M.G.F.M.
Published: October 2008

This paper reports results of an ongoing research project on fundamental aspects of the mechanics of pig motions in pipelines. This is a joint research program between PUC-Rio (Pontificia Universidade Catolica do Rio de Janeiro) ad PETROBRAS in Brazil, and in the first phase reported here it has been directed towards the development of simple, analytical hydrodynamic models thereby pass through the pig. In this study, only incompressible, steady state flow has been considered Foam pigs, flat discs, and piston-type cups have been analyzed. Computational fluid dynamic and finite element techniques have been employed in order to provide a solid fundamental basis for the simplified models. This paper has been previously presented in the 7th International Pipeline Pigging Conference& exhibition, held in Houston Texas, February 1995.

Introduction

Pigging of pipelines has been perform fix nearly a century. The use of pigs fm cleaning dewatering batching, and more recently, inspection d pipelines, has become a standard industry procedure. This expanding demand has driven the manufacturers to produce a great variety of pig models. Yet, a difficultly often by the engineer where designing a pigging operation is the lack of reliable tools for the prediction of the many variables related to the motion of the pig through the pipeline. Most of the available knowledge is based on field experience, Hence, selecting the best pig, estimating its speed and the amount of back and forward bypass, often involves some guesswork and, consequently, a high degree of uncertainty. Although one can not overlook the kind uncertainties often associated with complex engineering field operations, such as the passage of a pig through a pipe, there is certainly a need for more scientific based knowledge in pipeline pigging.

Results of research on the motion of pigs in pipelines are Scarcely found in the literature. One may refer to related work by Ellis et al/. in the sixties on the pipeline flow of capsules. Although some of their results can be extended to the flow& pigs. it does not consider important variables such as contact forces or bypass through holes. References 3 and 4 treat the dynamics of pigs in gas lines. MOE recently, an experimental research programs, which address some of the fundamental problems related to pipeline pigging, has been conducted by CALTEC in the U.K. Among other topics, this study focus on the relationship of flow variables with cleaning efficiency and cup wear.

The present contribution reports results of on going research on the dynamics of pig motion in pipelines. This is a University/industry joint effort, carried on by PUC-Rio (Pontificia Universidade Catolica do Rio de Janeiro) and the PETROBRAS R&D Center in Brazil. The goal of this initiative is to develop simple hydrodynamic models to be employed in predictions of bypass, differential pressure velocities associated with pipeline pigging operations.
Formation of Hydrates in Shut-down Pipelines in Offshore Conditions.
Authors: Makogon Y.F.
Published: October 2008

Operation of oil and gas pipelines in deep-sea is sharply complicated by the formation of gas hydrates. The experience indicates that large gas hydrate plugs in gas and oil pipelines form most actively during the period of unforeseen long shutins. In static conditions three types of hydrate crystals form: surface-contact films and massive hydrates which form by sorption of gas and water molecules on the surfaces of growing crystals; bulk diffusional whisker-like which form both in the volume of gas, and in the bulk of liquid water through sorption of molecules on the growing crystal surface and by tunnel sorption of molecules at the base of the crystal; gel-like soft crystals which form in the bulk of liquid water at a deficiency of dissolved gas in water. Under the P-T conditions of hydrate formation there may be a simultaneous formation of crystals and decomposition of other crystals.

Equilibrium content of gas dissolved in water which is in contact with a solid hydrate surface is lower than in water which is in contact with free gas.

Introduction

Gas hydrate is a metastable mineral. Its formation, stable existence and decomposition depend on pressure, temperature, and the compositions of water and gas.

Gas hydrates are inclusion compounds, solid solutions, in which water is the solvent. Molecules of water tied together by hydrogen bonds form a space tilling lattice. Mobile molecules of gases, or volatile liquids are absorbed, or incorporated in the cavities of the water lattice.

Gas hydrates are widespread in nature. They easily form in technological systems of production, transportation and processing of gases, Natural gas hydrates are a tremendous source of energy. Resources of hydrocarbons accumulated on earth in a hydrate state are estimated as 1.5.1016 m'. Several countries have already started to implement intensively their programs for development of gas hydrate deposits.

An intensive growth of oil and gas production is accompanied by putting the fields in sub-Arctic regions and deep offshore into operation. At that the thermodynamic characteristic of the technological systems of hydrocarbon production and transportation almost always corresponds to the conditions of hydrate formation. There is a knowledge about numerous cases of large hydrate plugs formation in wells and gas pipelines. Analysis of the facts about the formation of large hydrate plugs in wells and oil or gas pipelines reveals that the most dangerous periods of time are the unplanned long shut-ins.

Expenses for the prevention of hydrate formation are 10- 15'%.of the production cost. According to Savidge (I), on an average gas or gas-condensate field annual expenses for hydrate prevention are 5 to 15 million US $. Expenses for removal of a complete hydrate plug in a well or a gas or oil pipeline offshore are usually several millions of US dollars.
DeepStar Evaluation of Subsea Trees and Manifold Concepts
Authors: Kirkland Kerry G. , Richardson E.M. , Hey Chris
Published: October 2008

This paper reviews the results of a study performed for the DeepStar Project, CTR A802-2, 'Concept Study and Investigation of Key Areas of Interest for Subsea Systems in Deepwater' (Ref. 1). The report documents the results of a study of subsea manifold systems as applied to the deepwater Gulf of Mexico. Of particular interest is the development of a range of system level philosophies based on recent and ongoing experience from the operators and vendors.

Introduction

Three subsea system scenarios are addressed for deepwater subsea developments in the Gulf of Mexico. Each system represents a variation in development philosophy, based on Cluster, Modular, and Integrated Template Systems. The study was used as a tool to identify the available technology and hardware in the key areas of flowline connections, guidelineless operations, and non-rig intervention, for each concept considered, and for water depths from 3,000-6,000 R. Vendor surveys and operator field history were used as input for the concepts developed.

Study Approach

The study was initiated with a subsea workshop to review operator and vendor experience in deepwater applications. The workshop provided input and direction for the rest of the study by defining the concepts to be considered and key areas of concern. A vendor survey was also issued to solicit information on the state of development of the primary subsea hardware components.

Example configurations were developed for each of the base case concepts, including seafloor layouts, sample component selection, budgetary level costs and schedules, The three concepts were evaluated on a comparative basis and rationale was noted regarding potential scenarios that would favor each method of development.

DeepStar Subsea Workshop.

A DeepStar Subsea Workshop was held in April 1995, to review the general features and configurations of systems planned or in place. The workshop included both operating company and vendor personnel, and served as an open forum for discussion of design alternatives, and rationale that should be considered when selecting the features of a deepwater subsea manifold concept.

Three key areas of interest were defined as being critical to the development of deepwater systems:Guidelineless Operations,ROV and Non-Rig Intervention Operations, andFlowline Connection Methods

These topics were discussed at the workshop and further evaluated in the study. The resulting rationale and philosophy were applied to three subsea concepts that were each developed to a conceptual design level to illustrate the range of equipment available for each concept.

The DeepStar Subsea Workshop was well received by the oil company participants and vendors. A number of comments were noted that this sort of forum should be promoted on an annual basis as a vehicle for exchange of philosophies and experiences.
The Mustique / Shasta Project: A Small Operator's Deepwater Management Challenge
Authors: Huber David S. , Smith Clint D.
Published: October 2008

The project management approach taken by a small independent oil company's first venture into subsea is described from initial business plan scoping economics to putting the wells on-stream, Hardy wanted to remain strictly a producer without a large internal engineering staff, However, they were adverse to delegating the project management or design responsibility to an outside company. The solution was a project management team approach with senior representatives of the major vendors being directly involved in the upfront design process. The vendor selection process included all the major contracting methods including turnkey, partnering, teaming and cost-plus.

The Mustique / Shasta project in the Gulf of Mexico included three wells in 800- I 100 ft water depth tied back 9- 12 miles to two platforms in 650 0 water depth.

Introduction

The technical challenges faced in developing a deepwater subsea field are the same for a large multinational or a small independent operator. However. the managerial challenges are significantly different given the small company's lack of in house engineering and project management expertise. Strong focus on risk management is the key to success for the small oil company given that the capital costs of even a small deepwater subsea project is a very high percentage of the market value of the oil company. The approach and lessons learned on the Mustique/Shasta project can lead not only to minimizing upfront capital cost but also help ensure long-term quality and reliability of the production facilities.

Mustique and Shasta were not to be one-off projects. The business plan was to have an assembly line of continuous small gas tie-back projects after Mustique / Shasta but more importantly expand into projects that would add far more significant value to the company in the future. Specifically, this was defined as deepwater oil developments, 25 - 50 MMBO, in up to 2500 ft water depth. Positioning the company [o grow, while not hiring a large engineering staff, was a formidable task for a company that had only operated land and very shallow water depth offshore fields. To our knowledge Hardy is significantly smaller than any operator that has taken on the deepwater development challenge. It was vital that the company's first subsea project be a strong success and the company's key management knew that most projects fail not because of poor technology but because of poor management. Tremendous emphasis was placed on the quality of the project management process including personnel, contracts, interfaces and equipment design.

The issues addressed and methodology used as part of the project management philosophy focused on optimizing the development through strong vendor input and extensive use of commercial engineering.
The Geotechnical Centrifuge in Offshore Engineering
Authors: Murff J.D.
Published: October 2008

One of the greatest needs in offshore geotechnical engineering is for large scale test measurements on which to calibrate design procedures. The geotechnical centrifuge offers at least a partial remedy. Because it allows one to properly simulate stresses, it is a legitimate, relatively inexpensive option to full scale field testing. As such it is a valuable technique and can be an excellent complement to laboratory tests, l-g model tests and numerical analyses. However, it has not been widely used by industry even though the capability has existed for almost thirty years. This paper argues that this technology should gain acceptance beyond the research community,

The paper presents an overview of centrifuge principles, philosophies of use, and limitations of the technique. For illustration, several actual applications of centrifuge testing for complex offshore problems are described. Results are shown to provide important insights into prototype behavior and to agree well with full scale measurements where these are available.

Introduction

Probably the greatest need in offshore geotechnical engineering is for relevant large scale field measurements. For example, a great deal of effort has been expended in collecting all the axial load tests of piles that might be relevant to offshore applications (Pelletier, et all. This effort has clearly shown that there are relatively few tests that are sufficiently well documented that they can be used in any quantitative analysis and fewer still that are even within an rder of magnitude of the load carrying capacity of modem deep water foundations. This is particularly noteworthy since the design procedures (AP[2) are basically empirical and it is prohibitively expensive to carry out site specific offshore field load tests as is frequently done on land. A few tests, mostly onshore, have been carried out by industry that were especially designed to be applicable to offshore conditions. These few tests play a very important role in calibrating our design procedures but there are clearly major drawbacks in such test programs:the largest piles that have been tested have capacities that are an order of magnitude or more smaller than full scale offshore piles,most tests have beenconducted on pile segments embedded at relevant depths through eased holes,a single program can cost several million dollars to perform,the programs consist of very few tests and hence the test conditions are very limited, andit is virtually impossible to find a site with ideal conditions so that some loss of control is inevitable.

At the same time it can be argued that in spite of a fifty year history with offshore piles, reliable observations of their performance are relatively scarce.
Neptune Project: Spar History and Design Considerations
Authors: Glanville R.S. , Halkyard J.E. , Davies R.L. , Steen A. , Frimm F.
Published: October 2008

Neptune marks the first use of this type of structure to support production operations. The paper will discuss existing spar type structures and the development of the Spar design for the Neptune project. Design considerations for hull sizing and mooring system are discussed. Motion analyses and confirming model tests are presented. The well system design is introduced, which allows for the use of surface type trees providing economical well bore intervention capability. The topsides facility layouts are described. The Spar's capability of future drilling operations, using a semisubmersible drillingrig moored alongside the Spar, is discussed.

History of Spars

Spars have been used for decades as marker buoys and for gathering oceanographic data. The first significant Spar for our purposes is Flip, a structure owned by the U.S. Navy andoperated by the Scripps Institution of Oceanography in California. Flip was put into service in 1965 and is used primarily for ocean acoustic measurements.

Flip is 350 feet long. Its hull is 20 feet in diameter over the bottom half and tapers down to a 12 foot diameter where it passes through the water plane. A shipshape bow is fitted tothe upper end and houses the accommodations, power plant and other equipment, and the controls.

The vessel is towed out to the desired location and upended using its ballast control system. Upending takes approximately 30 minutes, the first 29 being consumed in going from horizontal to 10 degrees of tilt. Once the vessel is upright the instrument booms are extended and the testprogram started. Operating draft is about 270 feet.

Although Flip on occasion has been tethered to the sea floor, it is more commonly allowed to drift in the ocean currents. When the program is complete the ballasting operationis reversed and Flip is towed back to port.

In the early sixties Nippon Telegraph installed a Spar off the coast of Japan to carry a microwave relay station. This Spar is445 feet long with a stepped hull ranging in diameter from 10 feet to 20 feet. The topside structure is a cylinder, 50 feet in diameter by 33 feet high, with equipment, accommodations and a heliport on top. A four point catenary mooring of 3 inch chain connected to 175 ton clump weights keeps the Spar in place. Operating draft is 330 feet.

In the mid seventies Shell installed an oil storage and oftloading Spar at Brent Field, in the North Sea, which is the largest diameter Spar built to date. The hull is 95 feet in diameter, necks down to 55 feet at the water plane, and the operating draft is 357 feet. This Spar was designed to store300,000 barrels of produced crude and to transfer it to bow loading tankers. The mooring system consists of 6 lines, each made up of a 1000 ton concrete gravity anchor, 2600 ft. of 3.5" wire rope, and 935 ft. of 4" chain.
The Hibernia Platform: A New Topsides Structural Concept
Authors: Hewlett D. , Hatcher S.J. , Alner K.
Published: October 2008

The Hibernia Platform uses a new deck structural concept based on the integration of very large modules, i.e. "Super Modules", to form a single primary deck support structure. The paper describes the structural concept, and how it was designed and constructed.

The new concept was advanced from the initial idea to a fully developed design, the Super Modules constructed, transported around the world to the assembly site in Canada, and finally assembled into one structure.

The design effectively makes use of the structural steel frame of the individual nodules to act as the overall deck support structure, thereby eliminating the need for a separate module support frame. Because the modules are the full height of the deck, module lifting operations were nor required, and hook-up work was kept to a minimum.

Extra light strength steel was used extensively for the Primary structure which resulted in significant cost and weight savings.

The feasibility of integrating very large modules using multi-wheeled trailers was demonstrated. Tight dimensional control was essential to a successful integration.

The Super Module deck concept is applicable to other Platforms where minimizing cost and topsides weight is important for the installation and operating phases.

Concept Development

The Hibernia Topsides structure was initially conceived to be similar to several other GBS platforms such as Statfjord "B" and "C". These platforms have an open truss type module support frame(M SF) about 19 meters deep supporting one layer of individual modules. The modules were designed as separate structures for lifting and for the operating phase. In 1986 the first detailed study of the Hibernia Topsides was performed b y Stone and Webster Canada Limited 1. One of the restraints put on the design at that time was that the Topsides should not extend out beyond the perimeter of the GBS so that any icebergs that hit the GBS would be highly unlikely to damage the Topsides. This resulted in a very tall Topsides with multiple levels of individual modules. The final arrangement arrived at required 25 modules weighing up to 2200 tonnes, which the limit of most semi-submersible crane vessels (SSCV's) at that time, for the height and reach required.

Mobil. the Hibernia operator at that time, decided to further study the Topsides configuration to reduce the cost and weight and in 1987 Aker Engineering a .s. of Oslo, Norway were asked to see what alternative approaches were possible. In the first phase of their study, they retained the original concept of a MSF but proposed to use fewer, larger modules which achieved significant cost savings. However, in the second stage of their study they proposed a completely new concept that departed from the MSF concept. Aker proposed that there would be only five "Super Modules" which would be the full height and width of the deck. By joining the individual nodules side by side, an overall primary deck structure 30 meters deep was achieved.
The Glas Dowr FPSO Project
Authors: Lane John A.
Published: October 2008

SYNOPSIS

The Glas Dowr FPSO paper describes a modern "Fast Track" Bluewater Project that began in December 1995 and will be completed with "First Oi/" targeted in May 1997. The Glas Dowr was "Converted and Outfitted" for installation in the Amerada Hess (AHL) Durward & Dauntless Field, UK Central Sector of the North Sea. The Glas Dowr, which is Cornish for Bluewater, commenced life in a Japanese shipyard, before sailing 14,000 nautical miles to Harland & Wolff (H&W) in Belfast for the Project Conversion Phase. The Glas Dowr project continued with the sea tow from Belfast to the Tees Offshore Base for the Outfitting Phase of the project, this covered the installation and integration of the Pre- Assembled Units (PAU's) with the Ship Marine and Utility Systems. From Tees Offshore Base, the FPSO will be towed to the North Sea Durward & Dauntless Field, UK Blocks 21/16 and 21/11 for installation and hook up to the pre installed anchors, Subsea wellheads and manifolds. The paper describes the project strategy adopted, the Operations influenceon the project plus a description of the Self Verification process to obtain the necessary Certification for North Sea FPSO duties.

The names Durward and Dauntless are derived from the classic novels of Sir Walter Scott. Dauntless was the epithet applied to Harold, son of a Danish Viking, whowas granted land between the Wear and the Tyne. The Quentin Durward novel chronicles the activities of a young Scott who enlists in the Corps of Scottish Archers in 15th century France.

1. Introduction to the Field

The Durward and Dauntless Fields are located in the Central North Sea in water depths of 90 metres, approximately 140 Km east of Aberdeen. The Durwardand Dauntless reservoirs were discovered in 1993 and 1994 respectively, the distance between the two fields being 7.5 Km. Amerada is the Operator of both the fields. The Glas Dowr is located between the two fields in the pipeline corridor, at approximately 4.3 Km from the Durward Field, north of the Fulmar pipeline. The Glas Dowr is anchored to the sea bed using a combination of chains, wires and anchors set in a triangular configuration with nine anchors in groups of three spaced 120 degrees apart.

The subsea wells are tied back to the FPSO through a series of subsea manifolds, pipelines, riser bases and riser systems connecting into the turret. A combined subsea production and water injection manifold is located at the Dauntless Field and a separate water injection and production manifold is located at the Durward Field.

The Subsea Control System is an Electro-Hydraulic System combining Field Bus communications and electronic technology with an established high pressure hydraulic system designed to provide control and monitoring of Subsea wellheads and manifolds. Theinitial control requirement is for 7 wells, 5 producing wells and 2 water injection wells. The system is designed for the future control of 45 wells.
Effluent Discharge Limits and How Have They Been Met
Authors: Twijnstra Seppo
Published: October 2008

Introduction. This paper covers a brief description of the Troll field off and on-shore process facilities and the design facilities required to meet the effluent discharge limitations.

Gas from the reservoir, at a design rate of 100 × 106 Sm3/d, enters the four gas-liquid separation trains at theplatform. In the separators a three phase separation takes place between the gas, the condensed water and the liquid hydrocarbons. The aqueous phase is cleaned in the Oily Water Treatment facilities before it is discharged to sea. The hydrocarbon condensate is re-injected into the main gas stream for further stabilisation on-shore. The total fluid is transported through two 36" carbon steel pipelines to the onshore processing facilities. To avoid hydrate formation and excessive corrosion in the transport lines, caused by the equilibrium water and CO2 from the gas, Mono Ethylene Glycol (MEG), which is regenerated at the on-shore plant, is injected into the two gas transport pipelines to shore.

Gas and liquids from the two wet gas pipelines arrive at the on-shore plant in two slug catchers at a pressure of approximately 95 bar and a temperature of 3°c. Gas from theslug catchers is discharged to three identical gas conditioning trains, where it is treated to sales gas specification by a cooling process and compressed by means of five export compressor trains for further transport into the Zeepipe and Statpipe export systems. Glycol, with a concentration of 75 wt % is injected in the gas processing trains to prevent hydrate formation.

The liquids (hydrocarbon condensate and glycol) from the slug catchers mixed with the glycol and hydrocarbon condensate from the gas trains are separated in a glycolcondensate separator. Hydrocarbon condensate from this separator is further processed to sales specification in acondensate stabilisation unit. From the stabiliser the condensate is pumped into the condensate export pipeline to the Norske Hydro oil terminal at Sture. Flash gas which isgenerated at the different stages of the condensate treatment facilities is recovered and recycled into the gas processing trains. The glycol is regenerated to 90 wt % in three identicalglycol regeneration units before it is recycled to the platform for re-injection into the wet gas pipelines. The water from the re-boilers in the glycol regeneration units is sent to the oilywater treatment facilities for further treatment before being discharged to sea (fig. 1).

Effluent discharge limits

Emission objectives. The design for the Troll on-shore plant and off-shore platform had to fulfill the discharge limitations as imposed by the Project for hydrocarbon emission to air andhydrocarbon and glycol emissions to sea. These limitations meant that the hydrocarbon emissions to air, under normal operation, had to be restricted to an absolute minimum for both the platform and the on-shore facilities. Only those off gases which technically could not be re-routed to the process and /or were not suitable for reprocessing were allowed to be flared or vented.
Some Challenges and Innovations for Deepwater Developments
Authors: Salama Mamdouh M.
Published: October 2008

As the oil industry continues its effort to exploit oil and gas reservoirs in deeper waters, new technologies are required to enable the industry to proceed with effective exploration and development programs under the pressure of low oil prices. Threfore serious efforts are being devoted toward the evaluation and the application of innovative approaches to reduce exploration, development, and operating cost. These innovations involve advances in floating production concepts, expanded use of subsea completions, application of composite materials and optimization of life cycle cost. This paper reviews the different concepts that are currently being considered for deepwater development and summarizes the current effort to develop cost effective composites for many critical deepwater applications. In addition, the paper discusses existing technical barriers that need to be recognized and addressed to satisfy the economic and performance requirements for the application of composite materials.

Introduction

The interest in exploration and development of reserves in deepwater has greatly increased because of the positive views, as demonstrated by Shell's Auger field, that large reserves and high productivity wells can be found. This interest can be illustrated by the success of the recent Central Gulf of Mexico Oil and Gas Lease Sale No. 157, April 24, 1996, during which more than 380 leases in water depth between 2500 and 10.000 feet were awarded. This can also be illustrated by comparing the deepwater leasing activities in the Gulf of Mexico for the last three years. While in 1994 less than % million acres were leased in water depth above 1000 A, the area leased in 1 995 and 1 996 were about 2.4 and 4.8 million acres, respectively. In addition, there is a great interest in accelerating the development of the known deepwater discoveries. In the Gulf' of Mexico alone, there are more than 15 known discoveries in water depth between 3000 and 7500 feet. Deepwater activities in other parts of the world such as the North Sea, Brazil, West Africa. Australia, China, and Vietnam are also expanding.

The ability to economically explore and develop these deepwater leases depends on the oil industry's capability to develop solutions based on the innovative application of technology. These innovations cover broad areas that include exploration, drilling, development, reservoir management, and operations. The development and application of new concepts for structural, equipment and materials have greatly been advanced during the last decade. This paper reviews the different concepts that are currently being considered of a deepwater development and summarizes the current effort to expand the use of cost effective composites for many critical deepwater applications.
The Pompano Subsea Inspection
Authors: Ganguly P. , Goldberg L. , Wood B.
Published: October 2008

During launch preparations for the Pompano deepwater jacket, a horizontal X-brace of the jacket experienced excessive wind induced vortex vibrations. This paper describes the post installation analysis work that was done, provides details of the development and execution of the subsea inspection program that 'was designed to examine the X-brace joints for evidence of fatigue cracks, and furnishes the results of the field experience. In conclusion the paper highlights the deepwater Atmospheric Diving Suit inspection techniques that are currently available in the Gulf of Mexico.

Introduction

The Pompano jacket (Fig. 1) is a four legged bottom founded steel structure which was installed in June, 1994 at the south east comer of Viosca Knoll 989 lease block. The development is owned jointly by British Petroleum Inc. (BPX), and Kerr McGee Corp., and operated by the former.

During the fabrication of the jacket it was noticed that certain wind conditions excited the horizontal cross brace on elevation B between elevations -345 ft and -520 ft (below the mean water level). This was attributed to wind vortex induced vibration (VIV), and a supplementary member was connected to the center of the panel to control out of plane vibrations and prevent fatigue damage. The brace geometry and relevant member size and material data are shown in Fig. 2. The panel was restrained throughout the construction and transportation phases. but it was necessary to remove the tie down approximately twelve hours prior to launch. This caused severe VIV under the prevailing wind conditions with a natural period of about one second, and an estimated response amplitude of twelve inches.

Initial estimates suggested that significant portions of the fatigue life of the joints had been consumed and that cracks may be present in the as installed condition. Results of the initial findings are shown in Table 1. Although visual examinations of the affected X-brace connections using a ROV performed immediately after installing the jacket confirmed the absence of gross discontinuities, it was realized that this type of inspection would not have been able to detect smaller fatigue cracks extending part way through the member wall thickness if such cracks existed. A detailed non destructive examination of the joints was therefore planned.

In view of potential consequences of cracked joints at such an early stage in the life of the platform, it was also proposed to conduct a study to assess the significance of the cracks prior to the detailed examination of the joints. The results of this study would provide appropriate information to effectively react to what might be discovered.
Design of Subsea Multiple Pig Launcher for ETAP
Authors: Smith B. , Blower S. , Ferguson G.
Published: October 2008

This paper describes the design of a multiple pig launcher for installation on the MACHAR subsea production manifold, located 150 miles east of Aberdeen, in 300 feet water depth. The manifold forms an integral part of BP's Eastern Trough Area Project (ETAF') and is linked to the Central Processing Facility (CPF) platform by a 22 mile long subsea multi-phase pipeline. The length of this pipeline and the resulting temperature drop from the 120°C well temperature means that wax deposition is a potential problem. To maintain optimum efficiency frequent pigging operations will be required to remove the wax deposits. The ability to maintain this efficiency over the life of the field is fundamental to the economic viability of the whole field. This requirement has led to the development of an innovative design solution for the subsea pig launcher to enable single line subsea pigging operations to be carried out as an integral part of the pipeline maintenance programme. The design is based on optimising CAF'EWOPEX costs, utilising conventional surface vesselsfor deployment and the provision of a reliable, fail safe, ROV operated pig launch mechanism. Although pig launchers have previously been deployed for subsea use, the specific requirement for continuous operation as part of the pipeline maintenance programme will possibly be the first application of this type of equipment in the World.

The most significant aspect of this development is the provision of a reliable, cost effective, long term pigging facility for subsea operations based on simple operation and minimum intervention times.

Introduction : Background

Consent to start the 1.6 billion GBP development of the Eastern Trough Area Project was granted in December 1995. It involves the development of seven distinct fields each of which would have been marginal, stand alone, developments but have been combined into an integrated project by alliance partnerships. Fundamental to the Success of the project is the application of alliance working Concepts embracing the principles of the industry's CRINE (Cost Reduction initiative for the New Era) initiative. BP, with a 58% interest in the development, will operate the ETAP facilities on behalf of the partners : BP, Shell, Esso, Agip. Murphy, TOTAL and Mitsubishi Oil.

The fields involved in the development are Marnock. Mungo, Monan and Machar, Heron, Egret and Skua along with two future fields, Mirren and Scoter will be operated by BP. They have combined estimated reserves of some 400 million barrels of oil, 35 million barrels of natural gas liquids and 1.1 trillion cubic feet of sales gas.