bluuebunny/crossref_metadata_2025 huggingface dataset:
A History of a Gulf of Mexico Deepwater Subsea Production System Development Strategy
Authors: Schneider Dennis R.
Published: October 2008

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 However, the technology had fallen into disuse in the Gulf of Mexico and been superseded as advancements in fixed structure design allowed this solution in water depths beyond 1,000 feet.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

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

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 >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

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.
Status of the Cantarell Field Development Program: An Overview
Authors: Limón-Hernández T. , Ponce G. Garza , Aguiñaga C. Lechuga
Published: October 2008

The Cantarell Complex is the largest field in México and the sixth largest in the world, with original proven reserves of over 17 billion barrels of oil. It started producing in 1981 and, through 1995, produced approximately one million barrels per day.

In 1996, a redevelopment project was started to increase reserves, more than double oil production, utilize all the gas by adding sufficient compression and process capacity, and modernize the existing facilities to improve operational safety and efficiency. Overall, the design, construction, and installation of these facilities are nearly 80 percent complete.

This technical paper provides an overview of the project, a summary of the current status, and a discussion of major project achievements to date.

Introduction

The Cantarell field, located about 80 kilometers (km) offshore of the Yucatan Peninsula in the Bay of Campeche, Mexico (see Figure 1: Location of Cantarell Oil Field), is the largest oil field in Mexico.

The Cantarell field was discovered in 1976 and has a surface area of 162 square kilometers (km2). It is composed of four major fields: Akal, Nohoch, Chac, and Kutz, in addition to the reserves in the newly discovered deeper Sihil field.

These fields comprise an anticline oriented northeast to southwest. The Akal block is the largest of the complex with 91 percent of 35 billion barrels of original oil volume, followed by Nohoch, Kutz, and Chac. The average depth for the Akal field is estimated at 2,300 meters (m) below sea level.

The Cantarell crude is classified as heavy, with a density varying between 19 ° and 22 ° API and containing sulfur compounds. The producing zones consist of different geological formations that are highly fractured with abundant vugs due to dissolution, providing superlative productive capacity.

The exploitation of Cantarell began in June 1979, and reached a production peak of 1.156 million barrels of oil per day (bpd) in April 1981. By 1986, the reservoir pressure of 270 kg/cm2). had decreased by 60 percent to 172 kg/cm2. Pemex installed a lift gas system which stabilized production at approximately one million bpd until 1995.

In 1996 an increase in production began as a result of the Cantarell Project. Production reached 1.4 million bpd in 1997. By early 1999, the production in most of the wells was facilitated by lift gas, yet the bottom hole pressure had further decreased to 112 kg/cm2.

In the beginning of Cantarell field, wells were capable of producing an average of 31,000 bpd. Currently, the average production per well has been reduced to a little more than 7,000 bpd. The relationship between reservoir pressure and oil production is shown in Figure 2: Cantarell Field Production and Bottom Hole Pressure. The pressure-production history of the field indicates that each kg/cm2 of pressure reduction in the reservoir corresponds to a production loss of more than 120 bpd per well.
Remotely Operated Vehicle Work Capabilities in Support of Deepwater Operations
Authors: Jolly R.D. , Moles P.A.
Published: October 2008

Advancing in front of the Oil and Gas industry to deepwater, ROV service companies are steadily improving the tools necessary to support subsea developments. The key tool that permits intervention at depth is the ROV. Combined with custom designed tools, the ROV system is a critical component for subsea operations. And just as the depths have increased, so has the need for intervention by a system that is forced to be more capable, reliable, flexible, and weather tolerant.

Introduction

The dramatic and rapid expansion in deepwater developments has been driven by the attractiveness of deepwater reservoirs despite the technical and commercial challenges that they pose. In order to drill, develop and produce these deepwater reservoirs a number of key ROV and ROV related capabilities have had to undergo, and continue to undergo, considerable improvements. In addition, an entire new set of capabilities has to be developed. This paper will take a closer look at the technical improvements that are necessary to carry out productive work in deep and ultra deepwater.

The basic tool for carrying out this work is the remotely operated vehicle, or ROV, a capability that has been supporting the Oil and Gas (O&G) sector since the late 70's. Over the last 20 years the ROV has progressed from a quirky combination of incompatible and generally unreliable components to a workhorse essential to supporting the industry's deepwater work requirements.

Existing ROV and tool capabilities for deepwater operations, new developments in deepwater ROVs and tooling, improvements in launch and recovery systems and the present and future of AUV/UUV capabilities will be reviewed.

Existing ROV Capabilities for Deepwater Operations.

Initially, Workclass ROVs introduced in the late 70's into the O&G industry worked predominantly in shallow water. In 1983 when Shell initiated its deepwater drilling off the U.S. East Coast, Shell committed to carrying out the drilling support tasks using a ROV. Up to that time a manned submersible, Pisces, had supported the Discoverer Seven Seas' deepwater operations. O&G ROVs had never operated in depths approaching the 2000+msw Shell was planning to drill in. In fact, most O&G ROV operations were in less than 500 msw. Shell's program represented a paradigm shift in the support of deepwater operations.

International Submarine Engineering (ISE) developed the Hydra 2500 in conjunction with Oceaneering and the Hydra 2500 system ushered in the era of deepwater O&G ROVs. The Hydra 2500's first working dive was in 2100msw and over the next 9 years carried out over 2000 dives with an average dive depth of almost 1850 meters, with a deepest dive of 2310msw. The Hydra 2500 proved conclusively that an ROV could operate reliably and effectively in deepwater and produce dramatic cost savings to the overall drilling program. The Hydra 2500 established the baseline for all future deepwater ROV operations in the offshore industry.
Design Of An Automatic Marine Corer
Authors: Bailey Edmond I. , Davis Grayum L. , Henderson H.O.
Published: October 2008

Upon request of several geophysical organizations, a program was initiated at Texas A&M U. under the Sea Grant Program to design a self-contained automatic seafloor setting corer which willextract up to 50 ft of continuous undisturbed. core,operate in depths up to 1,000 ft of water,core in hard as well as soft material andbe as compact as possible to facilitate shipboard handling.

This program was partially funded by Oceanonics, Inc., Houston, Tex. The SEACORE 50 will extract a 3-in. diameter core 49.5 ft long in 11 sections. The unit is octagonal in cross section measuring 6 ft side to side and is 12 ft in height. When the Unit reaches the seafloor, four legs fold down and level the unit on slopes of up to 15 °. The unit weighs 10,000 Ib dry, 8,000 Ib in water, and is lowered to the seafloor by a single power-tension cable. An automatic control system is continued in the unit with shipside manual control available at any time. A drill pipe fitted with a ring-type core bit is rotated under a considerable thrust load while water is pumped down the center of the drill pipe to wash the cuttings back up the annulus. This water is routed through the double-walled bottom joint around the core barrel so that the sample is not washed. A square rod extending from the top of the coring unit retains the rotation of the core barrel. This square rod also supports a piston in thecore barrel, thus affecting "fixed piston" coring. A hydraulic powerhead produces 1,000 ft-lb of torque and 6, 000 Ib of thrust or pull.

INTRODUCTION

The tools and techniques used today in ocean mining and exploration for obtaining undisturbed samples of the seafloor leave something to be desired. They require either logistic support from divers on the bottom or must be operated from a large surface ship with multipoint anchoring.

Upon the request of several marine engineering concerns, a program was initiated at Texas A&M U. under the Sea Grant Program and partially funded by Oceanonics, Inc., Houston, to design a self-contained automatic seafloor setting coring device which will be capable of obtaining a 3-in. diameter core at least 50 ft long in depths of up to 1,000 ft of water. The recovered sample should be at least 90 percent of the amount drilled. The device should be activated with a power package on the ocean floor and supplied by a single umbilical cable from the surface vessel. It should be capable of rapid penetration and withdrawal to circumvent anchor spreads. It should be as compact as possible to facilitate ease of shipboard handling. The device should employ both rotary and push-type operations with interchangeable coring bits to handle all types of sediments and must employ the fixed-piston.
Problems And Solutions In Large Scale Evaporation
Authors: Ennis Charles E.
Published: October 2008

Of all the desalting capacity in commission today, 97.7% employs one of the distillation or evaporative processes. This is rather remarkable when we consider the theoretical basis of distillation as opposed to competitive processes. Distillation, first of all, is burdened with a relatively high potential energy loss in the heat of vaporization hen compared to the heat at fusion, which sets the energy threshold for input to the freezing processes. Membrane processes, on the other hand, don';t even require a change of state and so enjoy a rather significant advantage.

In spite of the preeminence of the distillation processes, however, they still produce water fairly expensively and they still are not attractive enough to support construction of a really large desalting plant. Today, I';d like to review with you some of the problems associated with the distillation processes and some of the solutions that have been proposed to these problems.

First, let';s define the evaporative processes. The most widely used process today is the multi-stage flash, sometimes referred to as the "MSF" or "SEMS" system. This process has its basis in the fact that water boils at lower temperatures as the pressure on the water. is reduced. In an MSF system, the salt water passes through a number of chambers in which pressure is maintained at progressively lower temperatures. in each of these chambers, a portion of the brine boils or "flashes". This flashed vapor is condensed on tubes which carry the incoming feed brine counter currently through the chambers.

Vertical tube distillation, sometimes referred to as "LTV" or "VTE", also depends for efficiency on the boiling point-pressure relationship. In a vertical tube plant, the salt water falls through a number of vertical tubes which are surrounded by steam. As the steam condenses on the outer surface of the tubes, the brine is heated in the tubes and a portion of the brine flashes to vapor. The condensed steam becomes the product for that effect and the flashed vapor becomes the heating steam for the next succeeding effect. The unflashed brine from the first effect becomes the feed brine to the second effect and so on. A plant will consist of a number of effects in series so that most of the input energy, supplied as steam to the first effect, can be utilized.

The multi-effect, multi-stage distillation process uses. a series of two or more multistage flash plants as separate effects to combine benefits of both processes. The principal advantage of this arrangement is that scaling is minimized by exposing the lowest concentration of brine to the highest temperatures and then subjecting the increasingly concentrated brine to successively lower temperatures.

Vapor compression distillation operates on the principle that, when a vapor is compressed, its temperature and pressure increase as the volume decreases. Compression heats water vapor, which then condenses on tubes containing the incoming brine.
Wave Pressures On The Underside Of A Horizontal Platform
Authors: Denson Keith H. , Priest Melville S.
Published: October 2008

The destructive effects of shallow water wave action on the underside of horizontal floors, decks, and platforms is evident from the inspection of hurricane damage. In order to provide some knowledge of the pressure distribution under such conditions, a laboratory study was made. Results are generalized through the use of dimensionless parameters and are presented in graphical form. These graphs show maximum and minimum relative pressure intensity and distribution of relative pressure intensity along the underside of the platform, in the general direction of wave motion, for various conditions of relative wave height, relative clearance, relative width, and relative length.

INTRODUCTION

Inspection of structural damage due to hurricanes along the Gulf Coast has revealed that horizontal floors, decks, and platforms are susceptible to severe damage by shallow water wave action on the underside. In order to gain some knowledge as to pressure intensities associated with such conditions, a laboratory study was undertaken. Although hurricane conditions could not be simulated, the action of shallow water waves on a small scale structure provides useful information as to the nature of the problem.

The study was designed to reveal the separate effects of wave height, clearance above still water surface elevation, width of structure, length of structure, and still water depth on pressure intensity along the underside of. the structure, in the general direction of wave motion. This was done by varying each quantity, except depth, from the value associated with a set of common or reference conditions. The results are generalized insofar as possible through the use of dimensionless parameters, length ratios with stillwater depth as the common quantity.

There is reason to believe that the motion of a large, storm wave through relatively shallow water may be more nearly that of a solitary wave than that of a wave in an oscillatory wave train. Proceeding on this premise, the waves generated for this study were sufficiently far apart that they were considered to be independent of one another. This means that, for the purposes of this study, such quantities as wave period and wave length are not considered to be significant.

DIMENSIONAL CONSIDERATIONS

A rather common structural problem along coasts exposed to hurricanes is that having to do with pressure intensity on the rectangular, horizontal underside of floors, decks, and platforms as a result of shallow water wave action. If the study is limited to cases in which a centerline of the rectangular underside is parallel to the general direction of wave motion, the physical quantities which appear to enter the problem are those necessary to describe the pressure intensity, the location at which pressure intensity is determined, the characteristics of the water, the characteristics of the waves, the spatial relation of structure to water, and the geometry of the structure.
Brutus Project Overview: "Challenges and Results"
Authors: Rainey R.M.
Published: October 2008

Brutus is Shell's fifth tension leg platform (TLP) installed in the Gulf of Mexico. It is located in 2985 feet of water in Green Canyon Block 158 and is 100% owned by Shell. The estimated ultimate recovery is about 250 million barrels of oil equivalent and the total cost is expected to be less than $750 MM including pipelines and wells but excluding lease costs. Brutus is expected to be Shell's next major producer in the Gulf of Mexico with design rates of 100,000 barrels of oil per day and 150 million cubic feet of gas per day.

This paper will provide a general overview of the Brutus project. This will include a comparison of similarities and differences between Brutus and other Shell TLPs. The Brutus project has integrated learnings, designs and components from many previous projects while also adding capability and technology for deepwater hub processing, hydrocarbon dewpoint control of the export gas, and a combination use drilling/production riser system.

The Brutus project has significantly improved overall performance. When benchmarked against comparable projects in Shell, the cost is 17% lower and the schedule from construction funding to first oil is 7 months shorter than previous best in class. This has been accomplished while maintaining Shell's focus on quality and HSE. The early uptime performance of the facility after start-up has also been outstanding with facility uptime averaging 98% over the first five months.

Introduction

The Brutus platform is located approximately 155 miles south-southwest of New Orleans, Louisiana in the Green Canyon 158 block as shown on the map in Figure 1. The platform is an 8-slot Tension Leg Platform (TLP) in 2985 feet of water. A photograph of the completed platform just after installation is shown in Figure 2. Major components of the platform are shown in Figure 3 with a brief description of size, weight, and fabricator. The hull and deck configuration is similar to the Mars and Ram/Powell TLPs. However, the hull has been upgraded to provide additional displacement capacity with total displacement of 54,700 short tons and significant additions have been made for hub capabilities and gas processing equipment.

The platform is designed to handle tieback of up to five subsea fields. The facilities are designed for a throughput capacity of 100,000 BOPD and 150 MMCFD through two separate processing trains. Oil is transported 25.5 miles through a 20" pipeline to the South Timbalier 301 B Platform where it ties into the Amberjack gathering system. Gas is transported 24 miles through a 20" pipeline to the Ship Shoal 332 A Platform where it ties into the Manta Ray gathering system.

A high level project schedule is provided in Figure 4.

System Selection

An extensive system selection process was applied at Brutus with numerous type and sizes of systems considered. This included Spars, Ship based systems, subsea, and TLPs.
Thermal Behavior of Complex Geometric Configurations in Dry Tree Risers
Authors: Golczynski T.S. , Brown T.S.
Published: October 2008

Predicting the thermal behavior of conventional dry tree riser configurations is relatively simple, using standard heat transfer models. However, as developments move into deeper waters, the conventional dry tree riser configurations may no longer provide adequate thermal performance. The steady state arrival temperatures are often below the Wax Appearance Temperature and the cooldown times to hydrate formation can be dramatically reduced. Costly and complex riser configurations such as insulation, offset tubing, and/or fluid circulation may be required to provide adequate thermal behavior. More complex riser designs must take into account natural convection and radiation effects, changes in material properties along the length of the riser, and in general consider more than just a one-dimensional equation to accurately model thermal behavior.

Traditional heat transfer correlations have a large uncertainty associated with these effects or do not account for them at all. This analysis addresses various riser configurations, predicts the resulting heat transfer properties based on more rigorous calculation methods, and calculates the thermal behavior of each system.

Introduction

Dry trees are traditionally not expected to pose significant flow assurance challenges. In the event of wax or hydrate formation, coiled tubing or some other remediation technique could be used, due to relatively easy access to the tubing string. However, for deepwater developments, the flow assurance challenges are quite significant. Steady state issues with wax deposition and transient issues with hydrate formation are prevalent. Along with the structural integrity issues that deeper waters present, flow assurance concerns often require a more complex riser design to provide suitable thermal operation.

The analysis presented here focuses on three main aspects of riser design. First, the effect of using offset tubing in the riser is evaluated. Offset tubing may be required to keep casing diameters small, while accommodating large auxiliary lines. By moving the tubing closer to the casing wall, the conduction pathway for heat transfer is reduced, degrading the overall heat transfer coefficient (U-value) and cooldown times for the system as a whole. The impact of offset tubing is most pronounced for solid annulus materials, since the presence of liquids and gases creates convection currents that more evenly distribute the temperature throughout the riser cross-section.

Second, most heat transfer correlations accurately predict the thermal behavior for conduction, but may not include or model correctly the effects of convection and radiation, which will greatly alter the thermal behavior of the system. Moreover, the impact of convection and radiation for gas systems is sensitive to the pressure of the gas. In deepwater developments, the hydrostatic pressure of the gas will result in different pressures at the base of the riser as compared to the top of the riser. This inherently makes the thermal analysis much more difficult.
Hybrid Tubes for Choke and Kill Lines
Authors: Guesnon J. , Schaeffner P.
Published: October 2008

The main purpose of this paper is to present the technology of hybrid tubes developed to reduce the mass of auxiliary lines of drilling risers used in ultra deep water, by replacing conventional choke and kill lines with lighter tubes. They are composed of a steel core hoop wound with a strip made of carbon fibers impregnated with a polyamide thermoplastic resin.

The paper describes the structure of hybrid tubes, the design methodology and the manufacturing process. It presents all the tests carried out to qualify the technology and the conditions of the field test in preparation aboard a drillship offshore Angola. The principle of their integration in riser joints is described. Finally, the architecture of drilling risers including hybrid tubes is commented and their technical benefits are discussed.

In conclusion, studies performed at IFP prove that hybrid tubes reduce the weight of auxiliary lines by 50% and that this technology is well suited for ultra deep drilling risers.

Introduction

In recent years there has been a great increase in the number of wells drilled in the very deep offshore, in water depths initially slightly greater than 2000 m and now in depths approaching 3000 m. Several drilling rigs of a new generation were recently put in service to allow such operations [ref. 1]. Their huge dimensions facilitate the production and the maintenance of the necessary drilling fluids, as well as the storage and the use of a large number of tubulars. Among these, the drilling riser is definitely one of the key components for these complex operations; therefore its design and make up procedures must be studied with a great attention [ref. 2].

Drilling riser problematics

The main function of the drilling riser is to extend the borehole throughout the water column in order to guide the drillstring and to return drilling mud and cuttings to the surface. It is composed of tubular elements of 21" outside diameter, joined together by mechanical connectors. It links the drill floor of the floating vessel to the subsea wellhead where the BOP allows the well to be closed in the case of blow out. To ensure the control of the well in such a situation, the riser is equipped with two high pressure auxiliary safety tubes, called kill & choke lines. A third auxiliary tube, called booster line, is used for injecting an additional flow of mud at the bottom of the riser to facilitate the return of the cuttings. Finally, one or several hydraulic lines complete the architecture of the riser. All these tubes are integrated into the 75 ft long riser "joints". Each joint of riser is also equipped with buoyancy modules made of syntactic foam to reduce the wet weight of the system.

When studying a drilling riser, the designer has to size the tubes, connectors and buoyancy modules so that the stress levels in the system remain acceptable in all operational conditions [ref. 3]. One of the most important parameters to control is the tension in the riser, particularly at the top end.
Malampaya Deep Water Gas To Power Project-Drilling and Completing the Limit
Authors: Steiginga A. , Holmes C. , Hudson A. , Morris T. , Tosun O.
Published: October 2008

The Malampaya field development comprises subsea wells in 820 meters water-depth producing via a subsea manifold and two 16 inch diameter inconel clad flowlines to a shallow water platform 30 km distant. Condensate is removed on the platform and the dry gas is then transported via a 504 km long 24 inch export pipeline to an onshore gas plant at Tabangao (Batangas, Luzon Island) for extraction of H2S. The condensate is stored in the platform CGS Caisson prior to export via a short 3 km long 24 inch diameter pipeline and CALM buoy (Fig 11).

The Malampaya Deep Water Gas to Power Project in the Philippines has delivered first gas as advertised on October 1st 2001. The gas production is from five high rate deep water subsea gas wells. This paper summarises the delivery of the wells, in particular, the specific challenges that had to be surmounted to deliver high quality wells whilst remaining within the tight Malampaya project schedule.

These challenges related to the deployment of leading edge well technology systems in an environmentally pristine and remote area. This within a country with extremely limited petroleum infrastructure and very long supply lines. The definition and management of good performance within this context and the management of the many interfaces with other disciplines working concurrently required unique ways of working to be established.

Within the technical arena, many novel solutions were adopted with respect to rig modifications, drilling with losses, management of hydrates, horizontal Xmas trees, monobore well completions, coiled tubing perforating from a semi-sub well test clean-up and extensive/detailed planning. Organisationally, a working atmosphere was developed based on open, detailed and relentless inter-team challenge. This led to drilling and completing, genuinely to the "limit" of what was achievable for Malampaya.

INTRODUCTION

Malampaya, developed and operated by Shell Philippines Exploration BV (SPEX), is the first and only gas development in the Philippines. The five subsea wells are the first link in a production chain that supplies 30% of the mainland power requirements. In each well, high deliverability and high availability are critical from day one and throughout the full 25 year field life. There are no other fields that can supplement any shortfall in well performance.

Planning was initiated in Houston in late 1998 and moved to Singapore and Manila in mid-1999. Offshore execution started in early-2000 and was completed by September 2001. Innovative business processes and technical solutions were employed in "striving for excellence" in an environment characterised by a very short planning time and a multitude of project interfaces.

The Malampaya gas wells were handed over to the production team, on time and within budget. They have been proven capable of production rates exceeding 120MMscf/day. Included in this paper are the key highlights from planning, drilling, completing and commissioning the Malampaya gas wells.
Comparison of Models to Predict the Annulus Conditions of Flexible Pipe
Authors: Last Sijm , Groves Steve , Rigaud Jean , Taravel- Condat Carol , Wedel-Heinen Jakob , Clements Richard , Buchner Stefan
Published: October 2008

Corrosion and corrosion fatigue of the steel reinforcement wires will take place if the annulus of a flexible pipe is flooded with seawater. It will also occur under non-flooded conditions if water permeates from the bore and condenses in the annulus. The combination of water or seawater with permeated CO2 and H2S gases results in a corrosive environment that may cause stress corrosion cracking, hydrogen induced cracking, pitting, general corrosion or, in dynamic risers, corrosion fatigue. The type of corrosion, its severity, and the reduction in fatigue life will depend on the actual composition of the annulus environment. Until now, uncertainties about the annulus conditions have caused difficulties in assessing the remaining service life of flexible pipes with flooded annuli or even the service life under normal operating conditions. In this context, a review has been carried out on permeation, corrosion and corrosion fatigue in flexible pipe. This paper will focus on the first step of a service lifeassessment procedure: the modelling of the annulus condition.

Introduction

The flexible pipes in the offshore industry transport water and/or oil and/or gas. Due to permeation, some of the components in the bore fluid will permeate through the pressure sheath of the flexible pipe and into the annular space between the pressure sheath and the outer sheath. Vent ports in the end fitting of each pipe will vent the permeated gas if the gauge pressure on the vent valves is reached. After some time the conditions in the annulus will reach equilibrium. The time until equilibrium conditions depends amongst others on the temperature profile across the pipe, the pressure differential across the pressure sheath and the gauge pressure on the vent valves.

In operation, water from the bore will permeate through the polymer pressure sheath. Depending on the conditions in the annulus, it may be present as condensed water or as water vapour. After dissolution of permeated CO2 and H2S, the condensed water will form a corrosive solution for the steel wires in the annulus. Sometimes the annulus is flooded with seawater, for example if the outer sheath is damaged or if an end-fitting plug is missing or badly installed. It is obvious, thatseawater in combination with the permeating gases will also cause corrosion of steel armour wires. The severity of corrosion depends amongst others on the composition of the aqueous solution and hence on the composition of the annular gas mixture. Predicting the annulus conditions in the design phase of a project is therefore important.

A Round Robin annulus prediction exercise has been performed as part of a joint industry project with the three manufacturers of unbonded flexible pipe and a number of users. This paper describes some results of the case studies. It should be emphasized that the results are equally applicable to static and dynamic flexible pipes.
Radial Canyon System, Volta Fan Fold Belt, Ghana
Authors: Nibbelink K.A. , Huggard J.D.
Published: October 2008

A radial canyon system is observed with 2-D and 3-D seismic data in 1500 to 2500 meters of water on the Volta River Fan in Ghana, West Africa. Interpretation of seafloor topography in a deep-water hydrocarbon system is critical for migration and seep detection, potential shallow drilling hazards, seismic imaging problems and drill site or production facility location. This paper defines the seafloor canyon geometry, proposes a model of genesis and discusses the affect on deeper seismic imaging.

Eight straight canyons form a radial pattern on a 2 to 3 degree incline in the middle slope of the Volta Fan. They are 20 to 30 km long, 150 to 200 m deep and 2 to 4 km wide, and have flat floors with high seismic amplitude. The straight canyons are distinctly separated from shelf edge, V-shaped, meandering canyons on the 4 to 5 degree upper slope. Between the radial canyons, a weak seismic reflection interval is interpreted as gas hydrate ridges. Below these hydrate ridges a thick interval of high amplitude is interpreted as free gas in the shallow sediment. Both gas hydrate and free gas zones are interpreted to occur only on the crest of the regional Keta Arch. The interface between the gas hydrate and free gas zone is interpreted as a decollemont surface, which allows slumping and progressive headward erosion of the canyon system.

Gas seeps on seismic data and oil slicks on radar images demonstrate a working hydrocarbon system and potential thermogenic source for the gas hydrates as seen in the Niger and Congo Fans. The variation in amplitude associated with the free gas zone may cause masking of amplitudes in deep structures. From the early recognition of a working hydrocarbon system and correctly imaging deep seismic data to shallow drilling hazards identification and positioning production facilities, understanding the seafloor is critical to the success of any deep-water program.

Introduction

Seafloor mapping has become standard practice in deepwater exploration to understand bathymetry, slope stability for drilling and production facilities and reservoir depositional models. The Volta River Fan in Ghana, West Africa exhibits a radial canyon system in the Middle Slope between 1500 to 2500 meters of water, (Figure 1). These canyons present significant challenge for potential deep-water oil and gas development. The gas hydrate slump model provides for a method of generating these canyons and implies oil and gas in the deeper sediments. Structure, isochron, amplitude and variance maps from 2-D and 3-D define the geometry of the canyon system and the distribution of seabed lithology.

Methodology

Canyon topography on the seafloor was observed on early 2-D seismic, however a seismic program acquired in July 2000 defined the radial pattern for the canyons over the Keta Arch, (Figure 1). The seafloor, hydrate and free gas zones were mapped on pre-stack time migration sections and depth sections. Gridding, contouring and 3-D visualization of the 2- D seismic were used to develop the gas hydrate slump model for the mid-slope canyons.