bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Approach to Capex and Opex Reduction: An Integrated System for Remote Tie-Ins and Pipeline Repair
Authors: Corbetta G. , Cruden R.
Published: October 2008

The industry move towards deep water is constantly demanding for the development of new and innovative technologies, as well as reduction in costs, to let most of the new reservoir discoveries to be financially attractive. As a result, the demand for designs, which could led to savings in both CAPEX and OPEX is steadily increasing.

As part of their continuos growth, Sonsub International has developed and tested a new system (Brutus) dedicated to the remote tie-in of rigid lines in large water depth. The main design parameters are that it operates to 3000 meters water depth, handles up to 24" diameter pipe and is capable of connecting pipe by using flanges, clamp or collect connectors - as well as special connectors such as Morgrip.

The system will be used during summer 2000 to perform diverless tie-ins of a 16" pipeline and, prior to this, a complete set of shallow water trials will be carried out. Furthermore, the system has also been proposed as a pipeline repair system, due to its working philosophy and Sonsub's knowledge and experience within this field (DSRS - Diverless Sealine Repair System).

This paper will briefly introduce the Brutus system and present the result of the wet trials. Also, the system's pipeline repair capabilities and methodology will be outlined. Consideration about the integrated approach and its advantages with respect CAPEX and OPEX will be given, together with a general analysis comparing the benefit of this concept versus existing tie-ins and/or repair systems.

Introduction

The possibility of utilizing a common system during the completion of a field (CAPEX) and also during its lifetime (OPEX) is a very interesting option, especially for medium/deep waters developments requiring innovative and diverless technology.

Having a large experience in both remote connection technology and repair of either rigid or flexible lines, Sonsub felt that a common approach to both the above topics would be a major step towards cost saving and standardization of equipment for deep water field developments.

As a result of the above, and following the development of both the DSRS (Ref. 1) and the BRUTUS system (refs. 2 & 3), Sonsub has now developed a new concept. The concept is based on the combination of the above systems and will allow Sonsub to offer a single approach to tie-in and repair operations with proven diverless technology.

The DSRS

Background

The DSRS is a development of the original Pipeline Repair System (PRS), first tested in 1992.

A succession of shallow water trials of the various subsystems has allowed optimization of the individual and overall designs.

The final solution is now a "low force" modular concept, which offers the following benefits:It is independent of surface equipment;Low force;In the event of bad weather, the ROV can be recovered and the site temporarily abandoned;Operates using readily available work class ROVs;Can be deployed rapidly from a ROV support vessel;
Proposal for Ocean Drilling Program Research on Gas Hydrate in the Gulf of Mexico
Authors: Sager William W. , Kennicutt Mahlon C.
Published: October 2008

Gas hydrate traps large quantities of hydrocarbon gasses on the continental margins and have potentially important effects on sedimentary geology, climate, slope instability, the carbon cycle, and offshore oil production. The Ocean Drilling Program (ODP) has expressed interest in coring gas hydrate in a variety of environments, including a mature petroleum basin. This article describes a proposal submitted to ODP for a Gulf of Mexico gas hydrate drilling cruise to address this goal. The Gulf is a unique gas hydrate environment because hydrocarbon gas flow is focused along faults which control the location and concentration of hydrate occurrence. As a result, massive gas hydrate deposits occur all the way to the seafloor, in contrast to widely-disseminated layers buried by a few hundred meters as found in many other settings. The drilling proposal targets hydrocarbon seep sites where gas hydrates occur at the seafloor. It is planned that 5–7 locations will be drilled in 1-2 transects at two sites, one at the upper edge of the gas hydrate stability zone (550–600 m depth) and another deeper, where the hydrate layer is thicker and more stable (1000-2000 m depth). At each drilling location, three holes are planned: one to collect core for stratigraphy and conventional sampling, one to fill gaps in the record of the first hole and allow pressure samples and heat flow measurements, and one to acquire logging-while-drilling data. Four sites on the northern Gulf of Mexico slope have been identified for further investigation. Two of these sites are planned for drilling, the others as alternates. One site, at a mud volcano on the border of Garden Banks leaseblocks 424 and 425, typifies a major, active, high flux seep in the shallow gas hydrate zone. The other shallow zone site is at the boundary of Green Canyon blocks 184 and 185 and includes the well-known "Bush Hill" hydrate mound. A site at the border between Mississippi Canyon blocks 852 and 853 is a major seep site in deeper water depths, whereas another located in Atwater blocks 381, 382, 425 and 426 is a deep site inferred to have lesser flux. Currently the proposal is under review by ODP advisory panels, and if approved, it could be drilled in 2002 or 2003.

Table 1. Gas hydrate research team (Available in full paper)

Introduction

Gas hydrates are ice-like compounds in which hydrocarbon gas molecules become trapped within a lattice of water molecules under high-pressure and low-temperature conditions (Sloan, 1990). The proper combination of pressure, temperature, and gas concentration is often found on the upper continental slope. As a result, gas hydrate is found worldwide on continental margins (Kvenvolden, 1993). In many places, the gas is biogenic methane, derived from microbial degradation of organic matter in the upper sediment column. The gas migrates upward and collects into a widelydisseminated hydrate layer located a few hundred meters below the seafloor.
FPSO Integrity: JIP on FPSO Fatigue Loads
Authors: Bultema Stephen , van den Boom Henk , Krekel Max
Published: October 2008

The hull forms used for FPSOs and trading tankers look very similar. So similar in fact that it may appear that one could use the same design and design methods for both vessels. Both vessels will be subject to extreme and fatigue loading and both will have a similar design life. But each will have different design requirements and therefore different designs.

The trading tanker spends most of its life moving oil from one location to another, in either one of two draft conditions, ballast or laden. They are dry-docked at regular intervals for maintenance, inspection and if necessary repair.

FPSOs are stationary, i.e. they have zero forward speed, the vessel's draft is continuously changing, the maintenance and inspection is done in situ, and they are not usually dry-docked.

These apparently subtle differences, see Table 1, in design requirements are not so subtle with respect to the load differences, both short term and long term for the two designs. This difference is the driver for the FPSO Integrity Joint Industry Project.

The JIP was established to obtain fatigue load information on an FPSO through full-scale measurements. The main goals were as following.Develop of a computational model for fatigue loadingEvaluate current practice.Have the Classification Societies conduct a comparative study, andRecommend a fatigue method for use in design of FPSOs.

The work in this JIP is being further enhanced through a sister JIP "FPSO Fatigue Capacity" being administered by DnV. By combining the results of the two JIPs, the industry is gaining a better knowledge of the fatigue loads and fatigue resistance on FPSOs. Predictive methods are being developed to calculate the fatigue lifetime of FPSOs and this is leading toward more reliable systems.

Introduction

In the upstream oil industry it can be generally said that all ideas are bred, birthed and reared from within. In order to maintain this axiom it often means that nothing gets implemented in the upstream sector unless they have thoroughly analyzed and tested it and meticulously prepared proper standards and specifications. The idea of using an oil trading tanker as a floating production, storage and offtake unit is one solution that breaks the rule. It is a crossbreed, a marriage between upstream and downstream, a child of unsuspecting parents. It arrived in time to feed a hunger in the industry to expand operations into the seven seas. It looked positively prefect; it was a solution waiting on a problem. In the enthusiasm to apply the solution not all areas of design and design methods were assessed. The industry has now reached a stage where they are asking the question whether or not shipping standards are applicable to FPSO designs.

The design rules for trading tankers developed through time by trial and failure. In the past, the rules did not recognize fatigue was not a primary issue in ship structure design. In many FPSO cases this is not suitable.
Background and Status of the FPSO Fatigue Capacity JIP
Authors: Lotsberg Inge
Published: October 2008

A joint industry project on the Fatigue Capacity of FPSOs is being carried out with 19 participants from oil companies, designers, shipyards, classification soceieties and one university. This paper presents the background and the status of the project. The main objective of the project is to reduce the risk for fatigue cracks and fracture in FPSOs.

Part of the work is carried out by a number of participants as work in kind.

The project will provide small scale and full scale S-N data on typical fatigue sensitive details in FPSOs and tankers. It will also provide improved information on the important link between S-N data and finite element analyses for fatigue life assessment. Finally it will provide data to assess more reliable the risk for unstable fracture of FPSOs when fatigue cracks are present in the structure.

Background

In offshore oil production there is a trend towards Floating Production, Storage and Offloading Units (FPSOs), either on the basis of converted, used tankers or as newbuildings with a typical tanker structure. Experience from tankers built in the seventies and eighties have shown that especially the side longitudinals have been susceptible to fatigue1,2. Based on this experience the classification companies have introduced more strict fatigue requirements for tanker design3–7.

Various FPSO units are now entering the North Sea and other harsh environments, such as the North Atlantic. FPSO units can be deployed in marginal fields, at remote locations and in deep water. A clear advantage with these units is storage of oil, possibility for relocation and rather early production. Fatigue cracks may lead to stop of the field production, which can hardly be tolerated. Early fatigue problems must therefore be avoided, as a repair during service life might be very costly when cost of lost production is considered. Therefore it has become more important to assess the fatigue life of an FPSO at a design stage in a more reliable manner than was considered necessary for sailing ships where fatigue cracks might be repaired as part of a normal maintenance program.

Design requirements to fatigue of tankers have to a large extent been developed based on service experience. Floating production units have also been in service for several decades, but the concept of the permanently turret-moored tanker is relatively new. Most of the FPSOs in service have still to prove that they can meet the expectations regarding their fatigue life performance, as the majority of them have been in use for less than ten years.

Nowadays sophisticated analysis methods are available for fatigue life predictions of details of FPSOs. However, the reliability of such analysis is significantly depending on the fatigue capacity of the considered details (S-N data) used as input. Therefore it is considered important to reduce the uncertainty associated with the S-N data that are being used for design of typical ship details in order to improve our confidence in the analysis procedure used to calculate the fatigue capacity of these details8–10.
An Analysis of Discover II Motions and Mooring Line Forces
Authors: Sisk James M.
Published: October 2008

This paper covers the performance of the drill ship, Discoverer II, while it was working in severe sea conditions in the Bass Straits of Australia and off the west coast of New Zealand. Motions and mooring line tensions for various sea states are presented. The maximum sea conditions in which the vessel has worked are also presented. The novel, special features, and benefits of the mooring system are discussed.

Introduction

Ship motions, mooring line tensions and weather conditions have been recorded on the floating drill ship, Discoverer II, since it started drilling in May of 1968. An extensive study has been made of these records to evaluate the performance of Discoverer II under severe operating conditions.

The main objectives of this study were:

1. To obtain information which can be used to predict vessel motions and anchor line tensions under various sea conditions.

2. To determine the maximum sea conditions under which the various drilling operations can be performed.

3. To compare actual motion data with model data.
A Study of Different Flared Joint Configurations
Authors: Bouwkamp J.G. , Vaish A.K. , Terata H.G.
Published: October 2008

The paper deals with the stress distribution of flared tubular joints typically encountered in off-shore platforms and semisubmersible oil drilling structures. Stress results of an analytic computation treating the structure as a thin shell and using a finite element approach have been presented for an axial load condition and compared for the following four configurations: namely, a flared joint without any stiffeners, a flared joint with a ring stiffener at the junction between tube and flared portion, a flared joint with four cross-stiffeners (cruciform), and a flared joint with four cross-stiffeners and a ring stiffener.

The analytical results for the non-ring stiffened joints have been compared with results obtained experimentally. The study indicates the effectiveness of the cruciform gusset plate in reducing the shell stresses in general. Ring stiffeners are instrumental in achieving a more uniform force transfer and in reducing the stresses in the critical joint regions.

INTRODUCTION

With the increasing emphasis on large Size diameter column members for both semisubmersible drilling units and drilling platforms, the design of the connection between the brace members and the column member has received considerable attention. A possible direct jacket-type connection is ruled out economically because of the requirement that the column wall thickness should preferably be equal to 4.5 per cent of the outer-diameter of the columns*. Amore appropriate solution is obtained by creating a load transfer through in-plane gusset plates. Another commonly used design incorporates external wing plates or so-called flared jointst2,3). In the latter cases, the intent is to spread' the branch member loads over a larger portion of the column member and to reduce the often critical local bending stresses in the column wall. This solution represents in effect an increase of the d/D ratio, i.e., ratio between the outer diameters d and 0 of the branch and column members respectively, and undoubtedly improves the state of stress in the column wall. However, unfortunately, both solutions inherently cause the development of stress concentrations in the branch member wall at either the tip of the wing plates or at the junction between the tubular section and the flared portion of the branch member. Because of the increasing use of flared connections, the paper deals with a study of the basic load transfer into the flared section as influenced by both ring and cruciform stiffeners. Because of the fundamental aspect of this study, a simple model consisting of a circular tubular section and a flared portion has been selected. The actual junction between the flare and the column has been omitted since the load transfer in that connection is in general less critical. The load condition selected for this basic model is a pure axial compressive load.

The tubular joint under load approximates in structural behavior to a shell; i.e., the load is taken by the geometrical stiffness in addition to the material stiffness.
Deep Water Gulf of Mexico Sea Floor Features Revealed Through 3D Seismic
Authors: Scott E. , Peel F. , Taylor C. , Bryant W. , Bean D.
Published: October 2008

The Gulf of Mexico sea floor has been mapped with a variety of different methods with varying resolution. Until recently higher resolution 3D seismic surveys have generally been limited to site specific localities. With hydrocarbon exploration advancing and evolving, larger 3D seismic surveys have been acquired and are now available on a regional scale.

Mapping of the sea floor reflector on a regional 3D seismic data set in the Green Knoll/Walker Ridge area has resulted in a higher resolution map than previous data sets. The seismic data has revealed a set of regionally extensive furrows, a previously unknown Gulf of Mexico sea floor feature. Preliminary investigations show that the erosive style of the furrows change in a predictable pattern in conjunction with an increase in current flow velocities. The erosional features of the furrow field indicate the presence of strong ocean bottom currents.

Introduction

A variety of methods during the past few decades have been used to map the sea floor in the northern part of the Gulf of Mexico. Until recently, the highest resolution data sets with the most extensive coverage have been surface-towed, multibeam, side-scan-sonar (NOAA Seabeam) and long-range sonar (GLORIA). Maps from these data sets, such as those produced by Jia Liu and William Bryant1, have approximately a 30 meter resolution on the sea floor (Fig. 1). However, in deep and ultra-deep water depths the resolution is lower due to the greater travel time from source to receiver.

Other data sources that have been used to generate sea floor maps of the Gulf of Mexico include gravity, magnetics, satellite sensors and 2D seismic surveys. While maps generated from gravity, magnetics and satellite data cover the whole of the northern Gulf of Mexico or over a larger area, they are of much lower resolution than either the NOAA or GLORIA data. 2D seismic data provides a higher resolution of the sea floor, but due to their nature of a lattice of separate lines, they lack the spatial resolution to define subtle features on the sea floor.

As seismic acquisition and processing technology evolved, 3D seismic surveys became available. With the close spacing of data points, 3D surveys provide greater spatial resolution to map the sea floor and illuminate subtle features. However, due to cost and technological limitations, the first surveys were restricted to site specific localities with small areal extents. With the increased spatial resolution these initial surveys provided a more detailed map of the sea floor but only represented a postage stamp look in a regional context of the northern Gulf of Mexico. With the recent advances in technology along with exploration for hydrocarbons advancing to deep and ultra-deep water, larger 3D seismic surveys have been acquired and are now available on a regional scale. With the availability of these regional surveys, sea floor features that were previously unrecognizable have now been identified.
Hydrate Formation from CO2 and Sea Water
Authors: Makogon Y.F. , Holditch S.A.
Published: October 2008

Carbon dioxide (CO2), which is one of the most abundant compounds on Earth, is present in rock, the oceans and the atmosphere. CO2 influences many biological and dynamic processes. Carbon dioxide is very soluble in water due to its high dipole moment. Solubility of a gas in water is dependent upon the temperature and pressure. This dependence affects the changing content of gases in the atmosphere, and the variable effect that certain gases have on the climate. Currently, many believe that the effect of CO2 on global warming exceeds 50% of the combined effect of all greenhouse gases. CO2 is present as a gas, or can be dissolved in water, or can be found in a solid state. CO2 can also exist in a solid state as a clathrate hydrate.

Gas hydrates are known as metastable minerals, whose composition and properties are determined by the source components, temperature and pressure. Knowledge of the conditions of formation, stability and decomposition of CO2 hydrate with seawater and the mass ratios of gas and water during phase transition appears quite important. In this paper, we present the results of laboratory work concerning the kinetics and morphology of a CO2 -seawater system at pressures up to 50 MPa and temperatures of 268–295 K. Measurements of CO2 solubility in supercooled seawater before and after hydrate formation are discussed. The conditions of CO2 hydrate formation and stability in seawater that is under-saturated with gas are described. The research results reveal a number of details concerning hydrate formation and dissociation, including the limits of dissolved gas in water for stable conditions of gas hydrate crystals in the water volume. Also, the information can be used to interpret the role of gas hydrates in the global changes on our planet. The results of this work permit to determine the most effective technologies to control the content of CO2 in the atmosphere. We cannot include all of our results in this paper, due to the volumes of research data generated on this subject. However, many of our most important findings have been included and discussed.

General Information About The CO2 And Seawater Used In This Work

The following gas and liquids were used during the experiments.

Gas:

Carbon dioxide (99.9% CO2 + 0.04% CH4+ 0.06% N2)

Liquids:

Salt (sea) water - standard laboratory mixture containing 41.953 g/L sea-salt composition (meets American Materials Standard D-1141-52 Formula A) mixed with distilled water.

Table 1 presents the composition of the sea salt used to mix the synthetic seawater.

The density of the seawater that we mixed in the laboratory was 1.025 g/cm3 at 15 °C. Of course, the density of seawater will depend upon the temperature, pressure and salinity of the liquid. For atmospheric pressure, the density of seawater as a function of temperature and salinity is illustrated in Figure 1 (improved, from Sea Water: Its Composition, Properties and Behavior).
Hoover/Diana: Topsides
Authors: Milburn Frank H. , Williams Ron  H.
Published: October 2008

This paper covers the design and construction of the Diana/Hoover Topsides. A description of the facility covering capacity, major equipment, and environmental parameters is outlined. Design issues such as safety considerations on a floating platform, ABS certification, installation considerations, the impact of motion on process facilities, and methanol recovery are addressed. The Safety Management Philosophy is described. The paper concludes with an overview of the key success factors for the project.

Description of Production

The Diana field is composed of five subsea wells located in East Breaks 945, 946, and 989. The wells were drilled and completed with a Mobile Offshore Drilling Unit (MODU). The Hoover field is located in Alaminos Canyon Blocks 25 and 26, and the dry tree wells are being drilled and completed with an API Platform drilling rig installed on a Deep Draft Caisson Vessel (DDCV). The Hoover rig was refurbished and modified to withstand DDCV motions and perform operations not commonly performed by API platform rigs such as drilling and production riser installation and removal.

The Diana Subsea development is located fifteen miles west of the Hoover host facility in a water depth of approximately 4500 feet. The Subsea development consists of a northern drill center (NDC) and a central drill center (CDC).

The NDC is connected to the Hoover host facility via a single 10" production flowline and the CDC is connected to the Hoover host facility via one 10" and one 6" flowline. The manifolds are connected to each other by a three mile 10" infield flowline. The 10" flowlines serve as the primary production lines, while the 6" performs as a production line as well as a test line when required. Flowline and manifold configuration enables well testing capability of all subsea wells and loop pigging of all three of the flowlines.

Processing Facilities

The Hoover/Diana process facilities are represented in a simplified manner in Figure 1. General data for the topsides is given in Table 1. The design philosophy was to use the tried and true wherever possible and get operator input from the beginning. Mustang Engineering, Inc. was the primary topsides facility designer.

The initial process flow for Diana subsea production is heating, pressure reduction through a choke, and flow into the HP production manifolds at approximately 1100 psig. Local Hoover production flows into the IP or LP separator headers atapproximately 530 or 180 psig respectively.

Produced water dumping from the LP Separator flows through hydrocyclones and a vertical flotation unit prior to overboard discharge through a subsea diffusion pipe attachedexternally to the hull.

Each pressure system has a horizontal separator. Gas from each pressure system flows to the appropriate compression stage suction scrubber. Hydrocarbon liquids and water fromthe HP and IP separators flow through hydrocyclones, where the water dumps to a methanol recovery process. Oil then dumps to the next lower pressure separator stage.
World-Record Horizontal Trees for Diana
Authors: Deeken David , Towns Keller , Johnson Jess , Kenny J.P. , Skeels Brian , Vickrey John
Published: October 2008

From July 1999 through May of 2000, five horizontal subsea Christmas trees were installed in 4,750 feet of water in the Diana field in the Gulf of Mexico. The previous depth record for horizontal trees was about 3,400 feet. A wet parking scheme for tree installation was used to save money by reducing BOP trips and by using a less costly installation vessel. The final horizontal section of up to 1800 feet of the reservoir was drilled through the tree. Innovative techniques that saved time and money were used to contract, engineer, and test the tree, and bring the well on production. These techniques and lessons learned can be applied by others using horizontal trees in deepwater applications.

Introduction

The Diana and Hoover fields are located approximately 150 miles east of Corpus Christi and 160 miles south of Galveston, Texas, in the Gulf of Mexico. The Diana Field consists of East Breaks Blocks 945, 946, 988, 989 and Alaminos Canyon Block 21. Initial exploration of the area began in 1990 and two further delineation wells followed in 1996. The Diana reservoir features a slanted crescent-shaped formation with a thin oil rim along the down dip region. However, Diana's remote location and the extreme waterdepth of 4,750 feet made the field challenging. The discovery of the Hoover field (Alaminos Canyon Blocks 25 and 26), 16 miles away, provided additional incentive to develop the necessary infrastructure and co-develop both fields simultaneously.

Hoover would be produced from a deep draft caisson vessel (DDCV) (Figure 1) and the Diana field would be developed via subsea completions tied back to the DDCV. The Diana field consists initially of 5 oil wells that will be redrilled and completed higher as gas wells later in field life. Each tree is tied via a nominal 5" hard pipe U-jumper to one of two gathering manifolds (two at the northern drill center, three at the central drill center). The manifolds are in turn connected together in a daisy chain fashion by 10" hard pipe pipelines, in a round trip loop, to accommodate pigging. The pipelines extend back 16 miles to the DDCV, terminating in steel catenary risers (SCRs). Project timing permitted the Diana field to be drilled, completed, and ready for production when the DDCV was commissioned.

Systems Engineering And Trade-Off Studies

When work began in 1996 for Diana it was recognized that it would be deeper than the then-current subsea world record of about 3,300 feet. However, two vendors were building vertical tree (VXT) systems for water depths in excess of 5,000 feet. Both systems were installed in mid 1997. In addition, if a horizontal tree (HXT) were chosen, it would bein record water depths for an HXT. Consequently the two vendors building the deep water systems were chosen and paid for early trade-off studies for Diana. The results included their recommendations of HXT versus VXT, comparative specifications, procedures, and costs.
Stress-Controlled Porosity in Overpressured Sands at Bullwinkle (GC65), Deepwater Gulf of Mexico
Authors: Flemings P.B. , Comisky J. , Liu X. , Lupa J.A.
Published: October 2008

Porosities, calculated from wireline density logs, decrease from 33% to 30% over a vertical depth range of 1200 feet in the J3 sand of the Bullwinkle Field (GC65), Deepwater Gulf of Mexico. This 10% decrease in porosity results in a 58% decline in permeability (3.3 to 1.4 darcies). The spatial variation in porosity results in a 75% decrease in acoustic reflectivity over a depth range of only 500 feet. The decrease in porosity with depth is interpreted to result from compaction over geological time scales, which results from higher in-situ stresses at the reservoir low points than at the highpoints. The study provides an approach to predict the spatial variation of porosity and permeability expected in a homogenous, isotropic, and compressible reservoir. These rock properties are important parameters for reservoir simulation. The acoustic results imply that the reservoir will be imaged differently due to in-situ stress conditions alone and independent of changes in lithology or pore fluid.

Introduction

The Bullwinkle oil field is located on the western flank of a circular salt-withdrawal mini-basin on the slope of the Gulf of Mexico, approximately 150 miles to the southwest of New Orleans, Louisiana (Figure 1). The mini-basin is primarily located in Green Canyon blocks 65 and 109, in approximately 1350 ft. water depth (412 m). Holman and Roberston1 and O'Connell et al.2 describe the Bullwinkle field; Kikani and Smith3 describe the Rocky field which lies on the southeastern margin of the mini-basin.

The J sands are of early Nebraskan (3.35 Ma) age and host the majority of the reserves at Bullwinkle.1 The 5 sands (J0-J4) are bowl-shaped interconnected channel and sheet turbidite sands that are interbedded with debris flow deposits and shales, and overlain by a thick section (500 ft.) of bathyal shales. The top of the section is characterized by multiple erosional unconformities, suggesting a period of sediment bypass in the basin.1 Pressure drawdown at each well followed the same depletion curve, indicating that all the sands are in pressure communication.1,3

The J3 sand is located on the western flank of the minibasin (Figure 2). It is very fine-to fine-grained and has a blocky log character (Figure 3). The lithology and the grain size are relatively homogenous across the field. It is interpreted to be a ponded, internally amalgamated, sheet sand.1 There is a small oil and gas pool at its crest, while the majority of it is brine saturated (Figure 2). It has been penetrated by 23 wells.

Porosity Analyis in the J3 Sand

Whole core was taken in the J3 sand at the A-32-BP, which is beneath the J3 oil-water contact (Figure 2). In this well, density porosities (DPHI) correlate with whole core porosities when a fluid density of 1.05 g/cc and a grain density of 2.65 g/cc are assumed (Figure 4).
The MMS-USCG Memorandum of Understanding
Authors: Hill Peter J.
Published: October 2008

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

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

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

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

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.