bluuebunny/crossref_metadata_2025_split huggingface dataset:
The MMS-USCG Memorandum of Understanding
Authors: Hill Peter J. 
Published: October 2008

Abstract
This paper documents the joint MMS, USCG, and Industry effort to update the Memorandum of Understanding (MOU) signed December 16, 1998 between Minerals Management Service and the United States Coast Guard1. This MOU defines the respective agencies' responsibilities and jurisdiction under the Outer Continental Shelf Lands Act. The previous version, signed in 1990 was identified as deficient in light of advancements in offshore technology.
The USCG and MMS have shared responsibility for activities on the OCS since 1953. A series of memoranda and agreements have defined the agencies' roles. Advances into deep water, coupled with the introduction of new types of facilities, particularly floating facilities, had rendered the previous MOU obsolete. The Environmental Impact Statement (EIS) on FPSOs provides additional insight related to these type units.
This paper will explore some of the in-work issues of the process whereby joint industry and government teams seek to define and provide feedback and input into regulatory issues. It will also identify the challenges to implementation of the MOU, which continue to be faced by the agencies. It is hoped that this paper will form the basis for further refinement and aid the overall implementation of the MOU.
The prospect of operating an FPSO in the Gulf of Mexico presents a myriad of challenges. Principal among these is a clear understanding of the regulatory requirements that will be applied. The MOU uses a "systems" approach to agency jurisdiction. As rewritten, it was intended to satisfactorily address all floating OCS facilities, including FPSOs. This paper will examine the MOU and explain its applicability to FPSOs, and will identify areas where further refinement is recommended.

Introduction
It is beneficial to have an understanding of the purpose and history behind the MMS-USCG MOU. Agencies that are charged with shared responsibility under legislation or law usually execute a Memorandum of Understanding or MOU. The MOU or alternatives such as a Memorandum of Agreement, or Letter of Agreement may also be appropriate when regulatory jurisdictions or processes overlap. The MOU between MMS and the USCG has been in existence in some form since the first laws were passed addressing the mineral resources in the lands beneath the outer continental shelf.
The Outer Continental Shelf Lands Act2 (the Act) was enacted in 1953 and amended in 1978. This Act assigned to the Secretary of the Interior responsibilities associated with the exploration for and exploitation of the minerals contained in the lands under the OCS. The Act charged the "agency under which the Coast Guard is operating" with responsibilities related to safety of personnel, navigation, firefighting, lifesaving and other marine operations. (The Coast Guard, currently under the Department of Transportation had operated under the Department of the Treasury, and in time of war, under the Department of the Navy. This historical and statutory tendency for the Coast Guard to change departments necessitated this rather obtuse language in the law.)
Field Trial and Subsequent Large-Scale Deployment of a Novel Multiphase Hydraulic Submersible Pump in the Captain Field
Authors: Harden W.G. , Downie A.A. 
Published: October 2008

Abstract
A unique hydraulic turbine driven submersible pump, (HSP), was successfully trialled in a multiphase oil production well on Texaco's North Sea Captain development. The express purpose of the trial was to prove the pump's field performance on high GOR flows as a precursor to its wider deployment in the second phase of development of the Captain field, Area"B".
The paper briefly describes the pump concept and the application specifics. Also presented are the operational results from both the field trial and early experience from Area B, indicating the performance of the pumpset and well system. The paper describes the ways in which the HSP installation and well completion has been designed to accommodate a very wide range of operating conditions, and how full use is made of downhole monitoring to optimise management of the start-up and operation of the wells under these variable conditions. The new design of HSP has proved to be capable of extended operation on both single and multiphase heavy oil, and has generally operated successfully under difficult transient downhole pumping conditions.

Introduction
The continuing drive to maximise recovery rates and quantities from oil assets is increasing the requirement for the development of reliable artificial lift systems which are flexible enough to operate in free gas cap areas, at greater drawdowns and on well streams where the bottom hole pressures are closer to the bubble point. Such applications are becoming increasingly common as we attempt to tie in previously considered problematic assets to existing infrastructure for low cost incremental production, and where there is a desire to operate with lower bottom hole pressures tosqueeze more barrels from mature wells.
One of the main technical challenges associated with this trend is the development of pumping systems that are capable of operating on varying well streams containing significant quantities of free gas, either as a homogenous mixture or as slugging flow. Conventional downhole centrifugal pump designs are limited in the amount of free gas void fraction, (GVF), that they can handle to around 40% unless fitted with in-line separation equipment. This performance also falls off dramatically at off-design conditions, thus limiting the effective operating range. A further drawback in the use of mechanical rotary separators at pump inlet is that they are an additional complexity that can compromise the system reliability through imposition of higher shaft loadings. However, with significant reserves capable of being produced at gas void fractions above this level, there remains a clear need for the development of enhanced pump designs capable of continuous, reliable pumping at elevated gas levels.
Texaco and Weir have therefore collaborated in the development of an enhanced version of Weir's HSP, which promised the ability to pump fluids containing from 0 to in excess of 60% free gas at pump suction.
Assessment of One Company's Regulations for Offshore Lifting Operations
Authors: Thiagarajan Krish P. , Yann Neil 
Published: October 2008

Abstract
During subsea lifting/lowering operations, offshore operators typically utilize published regulations or recommended practice (e.g. Ref 1 & 2) for calculating key parameters such as maximum and minimum crane wire tension during deployment through the splash zone and through the water column. First hand observations by the authors has revealed shortcomings of accepted practice in key areas such as:Over-prediction of wire tension and snap loads, leading to lesser weight being liftedUnder-prediction of underwater heave motion of module while being lowered
These issues are discussed in light of the fact that added mass of the module changes with submergence. Model tests and numerical simulations using DNV's software SESAM are used to evaluate the added mass of cylindrical and rectangular modules and to gain an understanding of heave motions experienced by the modules in moderate wave conditions. Sample calculations are used to show areas where existing regulations are inadequate.

Introduction
Offshore drilling and production operations often require heavy objects to be lifted out of, or lowered into the water. Examples include lifting/lowering of subsea pipeline manifold for well fluid marshalling and control, or lowering of suction anchors or anchor piles for offshore structure foundation. A limited capacity crane vessel (also called derrick barge) is utilized to conduct these operations, normally in favorable weather conditions. A schematic of a derrick barge used to conduct this operation is shown in Figure 1. Ref. 3 describesthe background study and the installation process of a subsea production manifold in 620 m water depth at the Albacora field in Campos Basin, offshore Brazil. The manifold dimensions were 19 m × 14.5 m × 7.5 m, and weighed close to 500 tonnes. One of the major considerations of the study was to determine the safest and least time consuming way to lower the manifold in 620 m water, using a conventional crane vessel. Considering that the end result of the operation has limited tolerance in terms of positioning the manifold, and the fact that the environment can create sudden unpredictable challenges on the load dangling off the crane wire, it is obvious that such offshore operations are quite risky and challenging. Thus a very careful in-depth study incorporating numerical and experimental simulations would be a prerequisite to the actual operation (Ref. 4). This would also shed light on weather downtime for derrick barges and ensure safety during operations.
For a crane vessel the ability to work is primarily a function of the relative motions between the package being lifted and the foundation on which it is to be set down. The best way to set the load down is to deposit it gently once, and leave it there. However, this invariably does not happen. A suspended package, when lifted by a floating crane vessel, will experience motions due to its own suspension (such as natural frequency effects), along with induced motions due to the floating vessel as it responds to waves.
Installation of Vertical Loaded Anchors Using a Subsea Tensioning Device in Ultra- Deepwaters in the Gulf of Mexico
Authors: Degenkamp G. , Ruinen R. 
Published: October 2008

Abstract
This paper presents a method for the installation of anchors for deep water moorings, based on the use of a subsea tensioning device to generate the high installation loads required. Subsea tensioning devices have been used in waterdepths of up to approximately 200 m for the installation of conventional drag embedment anchors and pre-tensioning of piles, but have not yet been used for a deep water application. The proposed method of installation will be presented, and is based on data gained from full scale tests with vertically loaded anchors (VLAs) in approximately 1000 m of water offshore Brazil and also on simulations performed on the computer.
The results of the computer simulations and the field tests show that using a subsea tensioning device in deep water can significantly reduce the required time to install the mooring system as the installation and pre-tensioning of the anchors can be performed with two anchors simultaneously, instead of installing them one by one. The use of the subsea tensioning device also requires less powerful vessels for the installation as only vertical pulling capacity is required and not bollard pull. The simulations and field tests show that by using a subsea tensioning device a vertical pulling capacity of approximately 40% to 50% of the required anchor installation tension is required, meaning that the winches of current anchor handling vessels are quite sufficient for deepwater installation of anchors.

Introduction
The use of catenary moorings systems in deep and ultra deep water requires long and heavy mooring lines. As a consequence the floater has to support a large weight and the mooring footprint becomes large and may interfere with neighbouring infrastructure. Installation of these mooring systems becomes very expensive due to the vessels that are required. For deep and ultra deep water mooring systems the more appropriate moorings system is the taut leg mooring, using shorter and lighter mooring lines. The mooring loads arrive at an angle between 30 and 45 degrees with the bottom, requiring the anchor points to resist not only horizontal, but also considerable vertical loads.
As conventional drag embedment anchors are not capable of withstanding large vertical loads, a new type of anchor had to be developed with the capability of withstanding the large vertical loads associated with a taut leg mooring system. Research in finding a solution for a Vertical Loaded Anchor (VLA) capable of resisting large uplift loads started with laboratory testing of models in sand, laponite, bentonite and mud. This resulted in the fine tuning of an anchor shape that is stable in the soil during penetration, able to resist large normal (vertical) loads and easy to handle. These model tests were followed by large-scale tests in the Gulf of Mexico and offshore Brazil. Petrobras initiated a test program on several deep-water sites in Campos Basin where the handling, installation and pullout capacities of VLA anchors have been verified.
Management of Water Breakthrough Using Intelligent Well Technology
Authors: Armstrong Aleks  C.C. , Jackson Matthew D. 
Published: October 2008

Abstract
We focus upon the use of Intelligent Well Technology (IWT) to monitor and optimize production from wells containing a single tubing string completed in multiple pay zones. Wells producing under a water injection programme are inevitably susceptible to water breakthrough. Once breakthrough occurs, the operator of the well is faced with a choice between continuing recovery at a reduced rate, or sacrificing recoverable oil. If the well is producing from multiple pay zones then the situation is more complicated, as breakthrough may occur at different times in different layers. IWT allows the operator to regulate production from each zone using Interval Control Valves (ICV's).
We begin by investigating the application of IWT to a simple conceptual model: a single well producing from two isolated pay zones of contrasting permeability. This enables the factors influencing water breakthrough in a multi-layered reservoir to be investigated in isolation, providing fundamental insight into the impact of reservoir characteristics, fluid properties and well architecture. We find that the optimum method of producing from multiple pay zones is to employ IWT to choke back the high permeability zones, which results n the synchronised breakthrough of water along the wellbore. This serves to accelerate and/or increase production, and to optimise the displacement efficiency. We also find that IWT yields optimum benefit in fields with an adverse mobility ratio, and either limited field life or limited well productivity.
We then apply this knowledge to a full field model of the Maureen Field, UKCS. The Maureen Field was deposited in the deep marine environment, and is made up of submarine channels, fans, and poorer quality interchannel sands, separated by shales of varying lateral extent. We find that IWT does not accelerate or increase production from either of the target wells, because oil is simply displaced into the catchment area of other nearby producers. This suggests that IWT is best employed to choke production from wells which are isolated, or far from, other producers. Caution is therefore required when identifying candidate wells for IWT, as production may be reduced rather than enhanced.

Introduction
Intelligent Well Technology (IWT) has the potential to improve reservoir and well management. An intelligent well system is a combination of: 1Downhole sensors to sample environmental parameters;Downhole actuators to change the operating conditions of the well; andInterpretation and processing algorithms to optimise reservoir/well performance.
IWT provides the operator with ‘real time’ data from the wellbore, and enables the wellbore architecture to be reconfigured remotely by the operator in response to this data without shutting in the well and introducing a workover rig. Candidates for IWT are remotely located wells where interventions are difficult, and wells with complex wellbore architectures where frequent interventions are required to optimise production.
Hydrocarbons Under The Sea - A New Survey Technique
Authors: Schink David R. , Guinasso Norman L. , Sigalove Joel J. , Cima Norman E. 
Published: October 2008

Abstract
Hydrocarbons seeping from the sea floor can reveal the location of commercially significant offshore-oil and gas deposits. Such seeps produce a localized increase in the concentration of hydrocarbons dissolved in the adjacent sea water, but these concentrations will be transported and dispersed by marine currents and mixing. Calculation of the resulting concentration patterns shows that an optimum search requires sampling very near the sea floor. Equipment to perform such searches has been constructed and tested.
A submersible, pump is attached to special faired tubing containing hose and electrical and support cables. An automated winch deploys or recovers the hose and pump at survey speeds. Sampling can extend to depths of 185 meters at speeds up to 6 knots. Sea water from the pumping system is passed through a rotating disk stripper, where over 95% of the dissolved light hydrocarbons are removed by a counter-current flow of purified air. Total hydrocarbon concentration is measured continuously. Ethane, propane, and isobutane are collected, and six-minute integrated samples are determined continually. Sensitivity is sufficient to measure natural levels in the open sea. The system contains integral "blank" and "calibrate" functions and is designed to function automatically without constant operator attention.

Seeps Point the Way
Oil and gas seeps have helped to guide oil exploration ever since Drake drilled a seep area to the first producing oil well. Link (1952) prepared an extensive review of their types and locations and emphasized that they have provided the first clues to most of the major oil producing regions of the world. He showed that such features are widespread, numerous, and almost always found when there are major deposits. The Texas-Louisiana area is considered anomalously free of large seeps yet Link was able to locate more than 85 oil and gas seeps within 100 miles of the coast in those two states alone. Gas seeps of dramatic strength are well known.
Design And Actual Behavior Of Pentagone 81 Semi-Submersible Drilling Platform
Authors: Rey-Grange A.C. 
Published: October 2008

Abstract
The design of PENTAGONE 81 semi-submersible platform is based upon extensive model tests and uses advanced knowledge for computation.
Behaviour of the actual first unit was analysed and confirms satisfactorily the predictions.
Using statistical information treatment methods, it is possible to predict the behaviour of the unit or of similar units in any area.

Introduction
So called semi-submersible floaters are highly sophisticated compared with plain barges or even ships. They are also more expensive, because they are a lot more complex and have not as good a structure steel weight efficiency. But the offshore drilling industry is ready to pay for it since these floaters average a better overall economical cost per well in difficult seas, when they are not the only effective means for extreme conditions. Perhaps somewhat irrationaly for the very first units, their principle was settled when it was realized that an elaborated hull configuration was able to provide a better stability than a larger and heavier plain floater, over the minimum hull displacement governed by the cargo capacity.
Various Uses For The Articulated Column ELFOCEAN, A New Concept
Authors: de Chassy C. Bellon , Frankhouser H.S. , Picard J. Bellon 
Published: October 2008

ABSTRACT
The articulated column, ELFOCEAN, has proven the feasibility and advantages of this new type marine structure. Installation of the column was performed without derrick barges or heavy equipment in the minimum time.
During the two year test period the column has behaved as predicted by calculations and model tests. This behavior confirms the application of the column for the drilling, production, storage, flaring, mooring and loading functions associated with offshore oil production.
Each use of the column was studied separately. Hence important technological problems, specific to each use, were solved. Studies which simplify the analysis and design for each specific case have been completed. Extensive model basin and field tests were carried out to check field behavior of the column with a tanker moored to it. The behavior and structural response of the column have been correlated with results of computer calculations.
Designs have been developed for water depths as great as 1200 feet for the various uses of the column.

INTRODUCTION
Since the mid-1950';s oil production has been moving into deeper and deeper waters. Costs of conventional, fixed bottom-supported structures have increased rapidly. Incomes from offshore fields have been correspondingly reduced.
There are several possible solutions to this problem. For instance, a conventional fixed structure could be used with the top of the structure submerged below the level of significant wave action. This would reduce both the overall size of the structure and the cost. But, operation and maintenance are apt to be costly with the top of the structure submerged, and the danger of pollution is greatly increased.
The articulated platform with an above water section provides a very realistic alternate solution, for water depths up to 1200 feet. To prove the acceptability of this new concept, a prototype was built. This prototype provided a full scale test model which was subjected to difficult test conditions.
For the past 2½ years the prototype articulated platform has performed very well in 328 feet of water in the Bay of Biscay. During this period the platform has been exposed to very severe sea conditions.

ELFOCEAN - Prototype of the Articulated Platform

A. Description
The experimental prototype articulated platform, ELFOCEAN, has been in continuous service since 1968. There-have been numerous articles in engineering and trade publications about the platform. Hence, only a brief description of the essential characteristics of the platform will be given.
The major component of the platform is a vertical cylinder 110 meters long and 7 meters in diameter. Atop this vertical cylinder is the cylindrical head which is 10 meters in diameter. A universal joint connects the cylinder to a rectangular gravity type base. The base is 21 by 24 meters and serves to hold the cylinder in position on the bottom. Buoyancy and lateral support for the cylinder are provided by six buoyancy chambers attached near the upper section of the cylinder.