bluuebunny/crossref_metadata_2025_split 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

Abstract
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

Abstract
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

ABSTRACT
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.