bluuebunny/crossref_metadata_2025_split huggingface dataset:
Vortex-Induced Vibration and Design of Pipelines in Deepwater
Authors: Chaudhury Gautam 
Published: October 2008

Abstract
Field developments in remote areas of deep water offshore require the services of long distance pipeline systems. Design and installation of pipelines in deep waters are expensive. Seabed terrain in deep water is rough and more numbers of unsupported spans of long lengths are expected. Design against vortex induced vibration (VIV) is of concern for the reliability and cost of deepwater pipelines.
The practice of design against VIV has been to limit allowable span lengths such that onset of VIV cannot be initiated. This is a highly conservative approach resulting in expensive span corrections. Probability of occurrences of current velocities at seabed reaching critical is very low, hence, it is proposed that the designs be based on actual fatigue damage. This is also recognized by DnV Guideline 14 (June 1998).
Existing methods of VIV response calculation produce extreme response, which leads to conservative fatigue damages. Based on a non-dimensional analysis and fitting model test results an empirical relation, as a function of Reynold's number, reduced velocity, and reduced damping, is proposed. The formula determines equivalent response, which represents overall fatigue accurately.

Introduction
Offshore pipelines transport reservoir fluid from wellhead to production platform and produced oil and gas from platform to shore terminal. It is one of the most important and expensive items of an offshore field development project. It is even more expensive for developments of fields in deep waters. The sea floor terrain is rough in deep waters, consequently, unsupported spans are large and more in numbers. One of the major elements of cost in offshore pipeline system is the span correction and quite often correction of spans are required to satisfy the design against vortex induced vibration (VIV).
Classification notes (DnV) are available explaining the principles and procedures of VIV, but until recently (June 1998) there was no regulatory guidance on the design of unsupported pipe spans against VIV. Even after the introduction of the DnV Guideline No 14, normal design practice has been to limit the length of a span in such a way that the natural frequency of the pipe is away from the shedding frequency of the vortices such that no resonant vibration can take place. Reduced velocity for no onset of inplane vibration is small. This means small allowable free span and costly remedial measure for longer spans.
The major drawback of the present design practice is that it is unreasonably conservative. It does not consider the magnitude, duration, and the combined damaging effect of the VIV in relation to the available resistance to fatigue damage of the pipe line structure. Current velocities at the seabed are mostly small and negligible. The probability of seabed current velocity reaching critical is extremely low and, therefore, a realistic approach to design a pipe span would be to design it against fatigue, like other submerged structural members are designed against wave induced fatigue.
Gas Hydrate in Seafloor Sediments: Impact on Future Resources and Drilling Safety
Authors: Dillon William P. , Max Michael D. 
Published: October 2008

Abstract
Gas hydrate concentrates methane and sometimes other gases in its crystal lattice and this gas can be released intentionally creating a resource or escape accidentally forming a hazard. The densest accumulations of gas hydrate tend to occur at sites where the base of the gas hydrate stability zone (commonly the upper several hundred m of the sedimentary section) is configured to trap gas, often as a broad arch. The gas may rise from below or form by bacterial activity at shallow depth, but gas commonly is concentrated near the base of the gas hydrate stability zone by recycling. This gas accumulates in presumably leaky traps, then enriches the hydrate above as it migrates upward by diffusion, fluid movement through sedimentary pores, or flow along fracture channelways. Analysis of seismic reflection profiles is beginning to identify such concentrations and the circumstances that create them. The first attempt to explore for gas hydrate off Japan by the Japanese National Oil Corporation produced quite favorable results, showing high gas hydrate contents in permeable sediments. Gas hydrate dissociation can be a safety concern in drilling and production. The volume of water and gas released in dissociation is often greater than the volume of the hydrate, so overpressures can be created. Furthermore, the gas hydrate can provide shallow seals, so the possibility of high-pressure flows or generation of slides is apparent.

Introduction
The gas-bearing, ice-like form of water known as gas hydrate or gas clathrate occurs in abundance in marine sediments and stores immense amounts of methane, with major implications for future energy resources and seafloor stability. Gas hydrate forms wherever appropriate physical conditions exist - moderately low temperature and moderately high pressure - and the materials are present - water and gas near saturation in the water1. These conditions can be found in the deep sea, commonly at water depths greater than about 500 m or somewhat shallower depths (about 300 m) in the Arctic's colder water. Like ice, crystalline methane hydrate is less dense than water, so if hydrate forms in the water it floats upward and breaks down (dissociates) at lower pressures and warmer temperatures. However, if the gas hydrate forms within sediments, it is bound in place. Gas hydrate can exist in a zone (the gas hydrate stability zone - GHSZ), that extends from the seafloor down to a depth where the temperature has risen sufficiently to make hydrate unstable (even though the pressure increase that comes with greater depth will increase gas hydrate stability). The base of the GHSZ ranges from just below the seafloor to several hundred to a thousand meters below it at greater water depths (higher pressures).
Gas hydrate in ocean sediments is mostly (99%) formed of biogenic methane, but significant amounts of thermogenic gas hydrates that include higher carbon-number hydrocarbons exist in active petroleum areas (e.g. Gulf of Mexico, Caspian Sea).
Estimates of Worldwide Gas Hydrate Resources
Authors: Lerche Ian 
Published: October 2008

Abstract
Gas hydrates have been touted as the next generation of energy resources exploitable for commercial gain and anthropogenic use. It would then seem relevant to estimate the potential resources available in order that one has an appreciation of availability. Several such estimates have been made over the years for both onshore and offshore gas hydrates. This paper examines the relative percentages and the ranges of uncertainty for both the onshore and offshore estimates. In addition, the estimated resources are plotted versus the year in which the estimate was made to see if any convergence of results is being achieved with time as more data become available.
The main conclusions are that there seems not to be any systematic pattern of convergence of resource estimates with time, nor does there seem to be any narrowing of the uncertainty of the estimates for either onshore or offshore resource estimates as more data have become available over the last twenty years. It would seem that a concerted effort is needed to improve estimates if there is to be any hope of assessing the commercial worth of hydrate resources and of deciding whether hydrates really do represent a significant exploitable energy resource on a worldwide basis.

Introduction
As a cleaner energy source than hydrocarbons, gas hydrates have often been advertised as an appropriate alternative. The fundamental question is whether there is a sufficient resource of gas hydrates, on a worldwide basis, to act as a dominant energy source for the future. To be sure there are also technical problems of extraction and production of hydrates, once found, be it in the onshore or offshore regions. But the technical and commercial risk problems are secondary in the sense that unless there is a sufficient worldwide resource of gas hydrates, then technical methods will not be developed to exploit a constrained limited resource. There would be no profit in so doing. Likewise, even if technical extraction methods already existed, there would be no worldwide xploitation of gas hydrates if the costs of involvement and recovery were to rise to a point were no profit could be made-much as happens with oil and gas fields today, which are often not produced because of too high a cost relative to potential gains.
So the sine qua non is to first estimate the resources available. Indeed, this aspect has been recognized as the ultimate driver of potential further developments for over twenty years now (Kaplan, 1974). And, as new information has become available over the years, such has been incorporated in estimates of worldwide resources of gas hydrates both onshore and offshore. Since the early 1990's, after the dissolution of the Soviet bloc, much information has become available that heretofore was the exclusive province of the Soviet Union and/ or the intelligence gathering agencies of the world - most notably the CIA in America.
A History of a Gulf of Mexico Deepwater Subsea Production System Development Strategy
Authors: Schneider Dennis R. 
Published: October 2008

Abstract
In the early 1990's Shell held a dominant leasehold in the deepwater Gulf of Mexico. Development of this leasehold faced several challenges including the need for significant technology expansion, staff limitations and limited subsea experience relative to the U.S. based staff. This paper discusses the strategies established at that time in order to overcome these challenges. It traces the execution and evolution of those strategies through the 1990s up to the present day. Finally, it summarizes the current status of Shell's Gulf of Mexico subsea portfolio and discusses plans forward.

Introduction
Shell has one of the industry's largest leasehold positions in the deepwater Gulf of Mexico and has consistently led the way in producing from ever-deeper waters. Through 1999, the company drilled 81 exploration wells in depths greater than 1,500 feet, resulting in 36 discoveries.
However, during the early 1990s, Shell faced a dilemma. Among the company's deepwater discoveries were a promising portfolio of reserves, but few fields large enough to justify the huge expense of installing large surface-based production systems to develop them. Additionally, the sheer number of these discoveries and time constraints on the leases forced the company to look for alternative approaches.
The solution for Shell was to go with subsea production systems.
Much of the original subsea technology had actually been developed by Shell in the 1960s for fields off the coast of California and, later, in the Gulf of Mexico. However, the technology had fallen into disuse in the Gulf of Mexico and been superseded as advancements in fixed structure design allowed this solution in water depths beyond 1,000 feet. In the early 1990s, as discoveries moved deeper into the Gulf of Mexico, the idea of subsea developments once again came to the fore.
Today, Shell operates 14 highly successful subsea fields in the Gulf of Mexico, each one put into operation in a shorter time than the one before and at lower cost. Four more are currently under development. Subsea success, however, didn't come easily.

Background
When the determination was made to install subsea systems in the deepwater of the Gulf of Mexico, it marked a step change from the company's then-current approach. As a result, the subsea team faced enormous challenges:

Staff and Organization.
In 1993, Shell's deepwater staff included only a few U.S.-based engineers with subsea experience. To that time, the company had been focused on leading the way in serving the deepwater of the Gulf of Mexico with large fixed structures and TLPs. Ultimately, the fixed structuresand TLPs created the infrastructure for the development of smaller deepwater accumulations. However, when subsea was selected as the preferred means for exploiting these smaller reservoirs, there was not a large base of subsea expertise from which to draw. Moreover, it was clear that these projects would be sparsely staffed, requiring the project managers to find innovative ways to support their undertakings.
Recent Research on Stiff Clay Jetting
Authors: Machin J.B. , Messina F.D. , Mangal J.K. , Girard J. , Finch M. 
Published: October 2008

Abstract
A research study into water jetting of stiff cohesive soils has recently been performed by Perry Slingsby Systems Inc. The project is part of a cable and pipeline burial tool Research & Development project. The study program has set out to investigate the effect of water jetting on stiff to very stiff clay soils. To date, such soils have generally been beyond the capabilities of the industry's existing cable burial and maintenance ROV fleet. However, Perry Slingsby Systems have found that it is becoming an increasing requirement for operators to be able to extend the range of seafloor conditions in which burial can effectively take place. The intention is that the project will eventually lead to the delivery of a new range of high capability jet burial equipment.
This paper describes the background and methodology of the testing program as carried out to date. It also details the selection of suitable soil test beds which were used to model stiff clay seafloor conditions. The test apparatus and procedures are also described and indications and discussion of the result trends obtained are given.

Introduction
Despite several well publicized claims to the contrary, there is a considerable amount of evidence that the majority of existing ROV cable jetting packages tend to prove ineffective at jetting in cohesive soils at shear strengths greater than about 50 kPa (classified as "firm" conditions). In fact Perry Slingsby's last major cohesive soil jetting research project in 1994 was geared towards establishing the burial capability of a range of equipment, known as the TXL250® ROV class, in soils up to this strength limit. These tests were described by Adamson and Kolle (1995).
The intent of the new Soil Jetting Program is ultimately to develop an engineering model to predict soil trench formation under the action of an array of advancing water jets in stronger, "stiff" clay soils with strengths in the range of 50 to 125 kPa. Such a model is considered vital to designing an effective and power-efficient seafloor jet burial system as it allows the array of nozzles to be optimized and tuned for maximum possible performance over a range of conditions. Because there is only a relatively small amount of published research data appropriate to such soil conditions, further physical testing was considered to be an essential component in the validation of such a model.

The Response to Market Requirements
Without doubt, there is a general industry trend towards specifying post-lay cable burial via ROV water jetting systems at deeper burial depths and in stronger cohesive soils. In fact, there are increasing demands for future ROV type systems which can start to approach the burial performance of plow systems. It is this market pressure which has provided the incentive to develop a burial model that incorporates stiff clay jetting behavior based on reliable, accurate physical testing.
FPSO EIS Results and Record of Decision
Authors: Cranswick D. , Eve H. 
Published: October 2008

Abstract
The United States Department of the Interior (DOI), Minerals Management Service (MMS) prepared an environmental impact statement (EIS)1 to evaluate potential environmental effects of the proposed use of floating production, storage, and offloading (FPSO) systems in the deepwater parts (i.e., in areas &gt;650 feet [200 meters] in depth) of the Outer Continental Shelf (OCS) in the Central and Western Planning Areas of the Gulf of Mexico. The EIS was prepared in accordance with the National Environmental Policy Act (NEPA), as amended, 42 U.S.C.§§ 4321-4370(d)(1994).
The FPSO EIS is a programmatic document to examine the concept of, and fundamental issues associated with, the petroleum industry's proposed use of FPSO's on the OCS of the Gulf of Mexico. The EIS considers a generic FPSO system and operation, as well as a range of technical variations. The "base case" evaluated is a permanently moored, double-hulled, ship-shaped FPSO with up to 1 million barrels of crude oil storage capability.
This NEPA/EIS process will result in one of three basic decisions by the Federal Government:conceptual approval of FPSO's,conceptual approval of FPSO's with certain restrictions or conditions, ora decision for no action (i.e., no conceptual approval by the Government at this time).
In accordance with the requirements of the NEPA, the Government's decision will be detailed in a Record of Decision (ROD) and published in the Federal Register. The ROD has not yet been issued at the time of this writing.

Background
In 1996, OCS operators, as well as FPSO operators and builders, began having serious discussions with the MMS about the possibility of using FPSO systems in the Gulf of Mexico. FPSO's are floating production systems that store crude oil in tanks located in the hull of the system and offload the crude to shuttle tankers or ocean-going barges for transport to shore. FPSO's may be used as production facilities to develop oil fields in the deepwater areas of the Gulf of Mexico OCS that otherwise would challenge or exceed the limits of current deepwater production and transportation infrastructure and technologies.
Recognizing that the use of FPSO's would represent new technology and potential impacts in the Gulf of Mexico, the MMS approached the issue on several fronts. The EIS was initiated to evaluate the potential environmental impacts. The EIS process provided for public disclosure and input. The MMS funded a comparative risk assessment to evaluate the risks associated with FPSO technology as well as those associated with three types of existing Gulf of Mexico deepwater facilities. The U.S. Coast Guard (USCG), U.S. Fish and Wildlife Service (FWS), and the National Marine Fisheries Service (NMFS) were consulted on FPSO-related issues under their respective jurisdictions. The MMS sponsored and participated in several joint Federal/industry workshops to identify the technical, safety, and environmental issues and information needs related to FPSO's, as well as to gain a better understanding of FPSO technology and scope of operations around the world.
FPSO Environmental Impact Statement: Government and Industry Cooperative Effort
Authors: Cranswick D. , Regg J. , George J. , Daughdrill W. 
Published: October 2008

Abstract
This paper reviews the cooperative efforts between the Federal Government and the offshore energy industry to identify and evaluate the technical and environmental issues related to the potential use of floating production, storage, and offloading (FPSO) systems and supporting shuttle tankers on the Gulf of Mexico Outer Continental Shelf (OCS). FPSO's are floating production systems that store crude oil in tanks located in the hull of the system and offload the crude to shuttle tankers or ocean-going barges for transport to shore. FPSO's may be used as production facilities to develop oil fields in the deepwater areas of the Gulf of Mexico OCS.
This paper also discusses the effort to obtain resources and information for performing an environmental impact statement (EIS), as well cooperative efforts with the MMS contractor to develop the EIS. The initiation of the National Environmental Policy Act (NEPA) EIS process was the first step in the Minerals Management Service's (MMS) fulfillment of its regulatory mandates to address the technical and environmental implications of this technology, which is new to the Gulf of Mexico. In addition to cooperative efforts in support of the EIS, the MMS, the U.S. Coast Guard (USCG), and industry have cooperated in support of a Comparative Risk Assessment and in the identification of regulatory requirements that would be applicable to FPSO's. These components will provide the basic framework for the evaluation of site-specific proposals for the use of FPSO's in the Gulf of Mexico.

Introduction and Background
The western and central portions of the northern Gulf of Mexico constitute one of the world's major oil-and gasproducing areas, and have proved a steady and reliable source of crude oil and natural gas for more than 50 years. The pace of exploration and development in the deepwater Gulf of Mexico has accelerated rapidly in the last few years. The passage of the Deep Water Royalty Relief Act, specifically designed to encourage the development and production of deepwater tracts, resulted in the MMS receiving record bids in both the 1996 and 1997 lease sales. As reported at the 1998 OTC, "Deepwater GOM has reemerged as one of the principal offshore oil and gas basins in the world, a welcomed change after the slowdown during the late 1980s and early 1990s. With this move into deepwater came new challenges for both MMS and the energy industry."1 In water depths exceeding 1,000 feet, the use of conventional, bottom-founded (fixed) platforms quickly becomes uneconomic. As new discoveries are made in progressively deeper water, technologies continue to evolve to meet technical, environmental, and economic needs of deepwater development.
The MMS formalized a deepwater strategy in 1997 to address the many technological, environmental, and regulatory issues associated with increasing deepwater activities. Many of the components of the deepwater strategy existed in part but had not been evaluated from the broader needs of MMS and industry.