bluuebunny/crossref_metadata_2025 huggingface dataset:
Design and Installation of a Cost Effective Completion System for Horizontal Chalk Wells Where Multiple Zones Require Acid Stimulation
Authors: Thomson D.W. , Nazroo M.F.
Published: October 2008

An innovative completion design that allows multiple acid fracs to be performed in horizontal subsea chalk-formation wells with a single trip into the wellbore has recently been codeveloped by a major North Sea operator and an oilfield engineering/manufacturing/service company. The project was initiated to develop a system that would allow multiple acid stimulations to be efficiently performed in the shortest possible time in the North Sea Joanne Field. The system ultimately developed allows acid stimulation of up to 10 different zones in a single trip with no through-tubing intervention. The first well in which this new technique was used had 7 zones, and 3 additional wells with 10 zones each were later completed. The development of this system and case histories of the first four subsea wells requiring stimulation will be presented in the paper.

The key element of the system is a multi-stage acid frac tool (MSAF) that is similar to a sliding sleeve circulating device and is run in the closed position. Up to 9 MSAF tools can be run in the completion with isolation of each zone being achieved by hydraulic-set retrievable packers that are positioned on each side of an MSAF tool. Each sleeve contains a threaded ball seat with the smallest ball seat in the lowest sleeve and the largest ball seat in the highest sleeve. With this system, stimulation of 10 separate zones is accomplished in 12-18 hours by a unique procedure that lubricates varying sized low-specific gravity balls into the tubing and then pumps them to a mating seat in the appropriate MSAF, thus sealing off the stimulated zone and allowing stimulation of the next zone which is made accessible by opening the sleeve.

This technique provided a substantial reduction in the operational time normally required to stimulate multiple zones and allowed the stimulations to be precisely targeted within The case history data will provide comparisons in operational times between traditional stimulations and this new method as well as the significant enhancements to cost that resulted from its use. Additionally, this completion method allowed the stimulations to be designed and matched to the requirements of each reservoir zone, which provided the most cost efficient treatments possible.

Introduction

The Judy/Joanne Fields are located in the central North Sea on block 3017a (commonly known as the J Block of the UK North Sea), 280 kilometers South East of Aberdeen. The water depth is approximately 80 meters. The complete field development consists of a 24-slot platform for Judy and a 12-slot subsea template for Joanne. Production from the Joanne subsea manifold is transported through two 12-inch pipelines, 5-kilometers in length, to the Judy platform.
Deepwater Installation of an Electrical Submersible Pump in Campos Basin, Brazil
Authors: Mendonp J.E.
Published: October 2008

In October11994 Petrobras, leading a team of six companies has installed for the first time in the world an ESP in a subsea well. The subsea ESP system in the well RJS-221, located in 86 meters water depth, in the Carapeba oilfield has now completed more than two years in operation without failures. The success with this installation has encouraged Petrobras to proceed with this project in order to extend the application of this technology to 1150 meters water depth in the second Phase. This paper presents briefly the first subsea ESP installation, calling attention to the main aspects that make the difference from a conventional to a subsea ESP installation and focuses on the developments for the deepwater installation in the well RJS-477, in 11 07 meters water depth, in the East-Albacora oilfield by mid 1997.

Introduction

The oil production in the Brazilian coast is mainly focused on the giant reservoirs discovered in deepwater, making use of floating production systems, that receive the production directly from the satellite wells or from subsea manifolds. In Campos Basin 13 fixed towers were installed, all of them in shallow waters, up to 300 meters. From these, eight are in the so-called North-east Pole of Campos Basin.

Stimulated by an increased oil demand, this production is being complemented by new discoveries in deeper and deeper waters. This production was for a long time based on natural flow, water injection in the reservoir and in the artificial lift method of gas lift.

Production Development has signified the capacity to deal with the increase in the number of floating production units, with longer flowlines, as well as with the problems brought by well depletion and reservoir specific limitations.

Water and gas lift injection used to be the first options to adopt in the majority of the cases. But the efficiency of these solutions is not high and they are not always feasible. Reservoir pressure may be insufficient to produce over long distances and gas lift loses a lot of efficiency in long horizontal flowlines, typical of subsea wells, as well as with the BSW increase.

A new method was then required for oil production over long distances, specially from deepwater wells, allowing the platform to be placed in shallow waters, and for a reduction in the number of platforms, thus simplifying the production layout and reducing the investments.

Within the PROCAP 2000 Program for deepwater technology development, a project was created by the end of 1992 in order to develop such a method.
20 Years of Drilling and Completion Experience in Campos Basin: A Results Review
Authors: Bastos Bráulio Luís C.X.
Published: October 2008

Campos Basin has been producing since 1977, initially from a water depth of 120 m (394 ft), on the Enchova field, to today's record of 1027 m (3,370 ft), in Marlim South field. It will be presented how the profile of Campos Basin environment, considering oil accumulations and water depth, pushed the technology toward deeper and deeper waters. Drilling and completion main concepts, techniques and equipment used in Campos Basin all over these years, together with their performance, will be discussed, as well as their impact on different projects and the basin results.

Milestones in the basin exploration and exploitation, along with surpassed difficulties will be presented, showing their importance for the province development. The paper will also show how the amount of experience gathered throughout these years pointed towards new trends in technology, which already starts to be tested and used in prototype and pilot projects all over the basin. This knowledge starts to prove useful not only in Campos Basin but also on many different offshore sites around the world.

Introduction

Located offshore Rio de Janeiro state, on the southeast region of Brazil, Campos Basin is, by far, the main petroleum province in Brazil. Its area covers 110 sq. km, ranging from 50 (164 ft) to 3,400 m (1 1,155 ft) water depth.

Presently, twenty years after first commercial oil production in 1977, Campos Basin installations comprise 14 futed platforms and 14 floating production systems, distributed among 33 oil fields. This installations account for an average production of 600,000 BOPD (representing near 70 % of the domesticproduction) and 9.5 million daily cubic meters of gas. This production is handled and exported to shore via over 2,900 km of oil and gas flowlines.

By December, 1996, Brazilian total reserves of oil and equivalent gas added up to 11 billion barrels. Of this total, 82 % is located offshore, 63 % in water depths greater than 400 m. Presently, these deep water fields already answer for near one quarter of domestic oil production. In the future, this share will increase until, by year 2005, reaching a level of 70 % of Brazilian production.

Campos Basin Development Milestones

History of Carnpos Basin can be divided in three different periods, each one with its own set of unique characteristics.

1) 1974 to 1982: "20.000 Leagues Under the Sea".

By the year 1974, the northern region of Rio de Janeiro state, around the city of Campos, was a typical country site. Sugar cane agriculture, cattle raising and fishing were the main economical activities.
Campos Basin: A Real Scale Lab for Deepwater Technology Development
Authors: Assayag M.I. , Castro G. , Minami K. , Assayag S.
Published: October 2008

During the past 20 years, driven by the national economical and political pressures caused by the several petroleum crisis of the 70s and 80s, Petrobras has had to innovate in order to increase the Brazilian oil output. The major problem was that the large Brazilian oil reservoirs were all located offshore in water considered too deep, at that time. The water depth was 120m, the distance to shore was more than 100 km, and the estimated production rate was around 7 times higher than in the Brazil Northeast platforms. The adopted solution was based on the international technology available, that is, using fixed platforms. That was certainly a tremendous change in what has been done before, and, certainly, it was the first step to a new era of production facilities. The use of conventional technology would demand both a long lead time to the first barrel and the resources were not compatible with the urge of cutting down the oil import, and to the delicate country foreign cash flow balance. Petrobras had to dare trying new concepts using national technology in its own production facilities as a huge R&D lab. Examples of new production systems, equipment, process, procedures and approaches tried in Campos Basin is given throughout this paper. Past successes and failures that led to the currently used technology, as well as the more recently planned prototype testing programs are presented.

Introduction

The 1973 world oil crisis brought a tremendous economical impact on most countries, especially on those with strong dependence on imported oil. This led to the increase in investment on oil and gas exploration and production worldwide, including the search of new technology for producing fields located in hostile environment.

The first oil discovery in the Camps Basin, in Brazil. occurred in 1974, just in the middle of the economical chaos created by the crisis, worsened by the country's unfavorable external payment balance. Bringing the newly discovered prolific oil province on to production, as fast and at the lowest cost as possible, became a key issue for Petrobras. The increased throughput would help reducing the burden of Brazil to manage its increasing external debts. The oil import was responsible, at that time, for a significant portion of the Brazilian payment unbalance.

The country had to reduce its oil consumption and, at the same time, increase its oil production. The reduction would come with the introduction of alcohol fueled automobile, and the use of other alternative energy sources, while the increase would mainly come through the Camps Basin offshore development.

The problem was to produce in conditions never experienced before. The Garoupa and Enchova Fields, the first ones in the Basin, located in 120 m depth, were already considered in deep waters, at the time.
Automatic Welding and Ultrasonic Inspection for J-Lay of the MARS Tension Leg Platform Export Pipelines
Authors: Kopp F. , Perkins G.G. , Laing B.S. , Prentice G. , Springmann S.P. , McDermott J. , Stevens D.M.
Published: October 2008

The paper describes the use of automatic welding and ultrasonic weld inspection for the deepwater J-Lay of the 18-inch oil and 14-inch gas export pipelines from the MARS Tension Leg Platform (TLP) in the Gulf of Mexico. While automatic welding has seen frequent use on offshore pipelines, its use on deepwater J-Lay was a first, and a significant development effort was undertaken to ensure success during offshore pipelay. To maximize the probability of detecting significant weld defects in these deepwater pipelines, especially those defects with significant through-wall height, Shell specified use of automated Ultrasonic Inspection (UT). This type of inspection can be used to quickly and accurately locate and sue the through-wall dimensions of a defect. These features, in combination with the high toughness of the automatic welds, made it possible to use the Alternative (i.e. Fitness for Purpose) Acceptance Criteria of the Appendix to API 1104, instead of the workmanship criteria of Section 6 of API 1104. As such, a good balance was achieved between, on the one hand minimizing the overall repair rate by not having to repair indications that were not harmful to the weld, an4 on the other hand, maximizing the probability of finding and suing significant weld defects. This first time use of automated UT and application of fitness for purpose weld acceptance criteria on an offshore pipeline project in the Gulf of Mexico goes a long way towards validating the approach as a suitable and cost effective inspection method.

Introduction

The MARS Tension Leg Platform (TLP), a 72%28% joint venture between Shell Offshore, Inc. and BP Exploration, is located in Garden Banks Block 864 in 2940 ft water depth. The two export pipelines, a 14-inch gas pipeline, and an 18- inch oil pipeline were to be installed by J-Lay, using the same J-Lay equipment and lay vessel (the dynamically positioned Derrick Barge DB 50) as used previously to install the 12- inch export pipelines to Shell's Auger TLP'. Dunng J-Lay 165-ft-long pre-fabricated quadruple joints are brought onboard in large storage bins. The quadruple joint is upended in the J-Lay tower and welded in a single station. While on the Auger Project acceptable cycle times were achieved using manual welding (SMAW), the larger pipe diameter and wall thickness on the MARS project warranted an investigation of using automatic gas metal arc welding (GMAW) to obtain much faster joint cycle times than could be achieved using SMAW. The pipelay contractor J Ray Mc Dermott and Shell had negotiated a risk sharing agreement, where both would pay for the incremental cost of automatic welding and UT, but also would share savings resulting from a faster lay rate.
Application of Composite Materials in Deep Water Offshore Platforms
Authors: Botros Fikry , Williams Jerry , Coyle Edward
Published: October 2008

This paper presents the results of a joint project between Conoco Inc., DuPont Advanced Materials System and Kvaerner to investigate the technical feasibility and cost benefits that may be derived from the use of composite materials for structural applications in deep water platforms. The focus of the study was a hypothetical Tension Leg Wellhead Platform (TLWP) installed in I, 400 m water depth in a typical North Sea environment. Although a TLP r e p m t s the most weight sensitive platform configuration, almost all floating production facilities will some benefit from saving weight and lower maintenance costs associated with composite materials.

The project started with the premise that all the platform structure would be considered for composites applications including the hull, deck, topside facilities, risers and tethers. Further screening m w e d down the emphasis for the preliminary design effort to the hull and deck, although all potential applications were considered in the economic assessment. The design concepts developed were driven by the cost of raw materials and the availability of low-cost large-structure fabrication processes. Global design was performed for a base case steel platform as we1 I as for several alternative configurations each comprising a different degree of application of composites in the topsides, hull and risers. The applications ranged from substituting steel payload with composite alternatives all the way to composite columns and deck pontoons and main structural members. A cost estimate for the different platform configurations was conducted and compared to base case steel TLWP.

The paper also highlights important obstacles that need to be overcome before there is wide acceptance of composite materials as a substitute for steel in the offshore industry. Demonstration of the performance of composites is particularly critical for primary structural applications such as those considered in this study.

Introduction

In June 1995 was established between DuPont, Conoco and Kvaerner with the ultimate goal of commercialization of am composite applications within the oil and gas industry. The present study was conducted to investigate the offshore use of composites from a holistic view point in order to provide guidance to themembers as to which particular applications should be pursued Composites have proven to be cost effective and are already being used in a variety of offshore applications such as gratings, being used in a variety of offshore applications such as gratings, skids, tanks, -etc. The objective of this study was to determine if quantum breakthroughs could be made by the use of composites in the primary structure.
Supersonic, High Pressure, Low Radiation Flare System Design
Authors: Smith Scot K. , Selle Gary K.
Published: October 2008

Two years ago, Callidus Technologies Inc. recognized the need in the industry for a new and different method of flaring high pressure gases from onshore and offshore production facilities. After a review of the existing flare tip technologies currently available in the marketplace, a program was developed and implemented to design and prove, in full scale testing, a flare tip that would provide for lower radiation levels, lower flare tip weight, and improved smokeless performance. The flare tip is the first in the world to utilize converging-diverging super-sonic nozzle technology in the flaring of production gases. By using these nozzles to increase the waste gas exit velocities to greater than Mach 1, this flare tip inspirates significantly larger quantities of air into the combustion zone. This results in a much cleaner burning flame, lower emissions in the form of radiation, and a much higher momentum in the flame envelope due to the increased mass of material giving a stiffer and more up-right flame. All of these factors combine to produce shorter boom lengths, reduced flare emissions, and smaller relief header size due to higher flare backpressures. In addition to the combustion process improvements in the flare tip, an evaluation of the construction techniques and metallurgy's was undertaken and relevant improvements were made in these areas also.

To prove the theoretical application of this supersonic nozzle technology, a test facility was designed and constructed to test the flare tip. Initially, a scale model was tested at relatively low flows, up to flows of 10 million standard cubic feet a day. This testing proved very successful. The test facility was then modified to flow larger rates, up to 200 million standard cubic feet a day of natural gas. Testing of the full size flare tips has proven achievement of the theoretical design goals for the project. This new design concept is now being introduced to the production industries worldwide.

Introduction

Flare systems are used in offshore and onshore production and drilling facilities to dispose of the associated gases and liquids from testing and production. In some parts of the world, these hydrocarbon streams can be vented directly to the atmosphere with acceptable environmental impact and with approval of local agencies/government. Combustion of these gases using a flare is used where the impact to the environment is determined to be significant, or safety issues associated with venting unburned hydrocarbons mandate.

Flare systems can be separated into two basic types: Open flares with visible flames and Enclosed flares with non visible flames. Open flares are typically designated as high pressure type or "pipe" flare type.
Process Equipment for Offshore Viscous Crude Handling: Captain Field
Authors: Sutton John E.
Published: October 2008

The Captain Field in the UK Sector of the North Sea is an accumulation of relatively high density, high viscosity, low temperature, low GOR crude oil, all factors which in themselves present challenges in the design of oil and gas processing equipment. The selection of an FPSO-based production facility, with its inherent motion characteristics, compounded these challenges. The Captain Field facility design has successfully incorporated several novel features to address the oil, water and gas processing requirements.

Introduction

The Captain Field is located in UKCS Block 13/22a, 130 km northeast of Aberdeen, in 104 metres of water. The oil accumulation is heavy and viscous by North Sea standards, being 19.3°API and 88 cP at a relatively low reservoir temperature and pressure of 30°C and 93 bara, and with a gas/oil ratio of 23 sm3/m3 (130 scf/stb).@ The fluid properties and offshore environment require innovative horizontal drilling, well completions, and artificial lift technology for economically successful field development. Extended reach, horizontal wells are proposed for all oil producers and water injectors, to be drilled from two drilling centres. Downhole electric submersible pumps will deliver a capacity of 20,000 per well. The initial development comprises a Wellhead Protector Platform (WPP) tied back 1.5 km to a Floating Production Storage and Offloading vessel (FPSO), from which export quality crude will be shuttle tanker. Later stages of development will likely utilise subsea or additional wellhead platform tie-backs to the FPSO.

Process design for the Captain field has had to address several significant concerns not normally encountered in offshore processing applications. The principal problems which have been addressed in the facility design are in the primary three phase separation. Although the separator vessels are some of the largest in the North Sea, implementation ofconventional separator design parameters would have required even larger vessels, exceeding practical limits.

Separator internals have been designed to minimise effects of external motion acceleration forces on the vessels. Submerged liquid inlets to "water wash", the incoming crude are employed to enhance efficiency of separation of the liquid phases. Because of the extremely high foaming tendency of the Captain crude, a novel "foam handling package" has been developed. This process allows treatment of the foam outside of the primary separator, rather than trying to accommodate the foam within an oversized separator vessel. Also, overhead spray headers have been installed in the primary separators in an experimental attempt to mechanically break foamaccumulations. And finally, the process separation train has been designed to accommodate the "mousse effect" (gas carry-under in the outlet oil stream) noted in Captain and other North Sea heavy crudes.

These factors and others have been successfully combined into an integrated process facility designed specifically for the Captain field.
Mars TLP Drilling and Production Riser Systems
Authors: Denison E.B. , Howell C.T. , Ju G.T. , Gonzalez R. , Myers G.A. , Ashcornbe G.T.
Published: October 2008

The Mars riser systems are a major departure from those previously used on TLPs. All risers are operated with top tensions only 20% above their wet weight; the high-pressure, light-weight drilling riser has a secondary pressure barrier while drilling the majority of the well; a platform-style rig is used and all risers incorporate vortex suppression devices. These advances reduce TLP payload, reduce the risks associated with simultaneous drilling and production and minimize fatigue damage and riser interference in an area exposed to frequent Loop Current events. The design and analysis of the systems required the development and improvement of analysis tools, the performance of a multitude of hydrodynamic tests and the development of a scheme for careful tension-sharing among the three tubulars.

Introduction

The simplest introduction to the Mars riser systems is to compare them with the riser systems on the Auger TLP (I), which was installed in roughly the same water depth in 1993- 91. Auger was designed to use proven deepwater drilling methods and platform-like completion techniques. It uses a fixed rig, a drilling riser, a subsea BOP stack and a guidelineless reentry system very similar to those used on today's deepwater floating drilling vessels. Auger uses a surface BOP for well completions and work overs. It requires a lateral mooring system to position the rig (and thus the entire TLP) for reentries, drilling, and completions. It does not use a traditional seafloor well template and, due to the spread-well seafloor pattern, has minimal potential for riser interference.

The Mars TLP utilizes a smaller, platform-style, skid able rig. The high-pressure drilling riser, in conjunction with a surface BOP, still gives a platform-style look for most drilling and completion operations. The skidable rig and gudelines eliminate the need for a lateral mooring system and allow a smaller wellbay. The system also reduces the tensioner stroke requirements by placing the surface trees nearly directly above the subsea wellheads. I t uses an Auger-style dual-casing well system and a conventional hydropneumatic tensioner system which capitalizes on the smaller stroke requirement.

Development of a fuller understanding of riser-to-riser interference in storms and in Loop Current events (LCEs) has allowed the lower operating tensions and closer well spacings for Mars. Reducing VIV and manipulating riser fluids 'and coatings to control thermal effects (tension sharing variations) also help alleviate problems associatedwith low tensions.

Preliminary Design Work, Concept Evaluation

Dual-Casing Production Risers

The Mars Production Riser System is patterned alter Auger (I). Details above and below the seabed are shown in Figure 1. Safety and operability are the predominant design goals.
Gulf of Mexico Subsidence Monitoring Project with a New Formation Compaction Monitoring Tool
Authors: de Kock A.J. , Johnson T.J. , Hagiwara T. , Zea H.A. , Santa F.
Published: October 2008

Formation compaction in unconsolidated geo pressured turbidite reservoirs in the Gulf of Mexico (GOM) is an issue of great uncertainty and concern. When compaction occurs, it changes the porosity and permeability properties of the reservoir rock and can affect recovery efficiency and well productivity. It can deform well tubulars, creating operational problems and shortening well life. If compaction is significant, especially when multiple stacked reservoirs are involved (as in the case in this field example), then compaction can create a subsidence bowl at the ocean floor. In GOM offshore operations, this could cause platforms to subside deeper into the water and therefore create potentially severe safety problems. Therefore, failure to properly address issues of compaction and subsequent subsidence during the design and development phases of these capital intensive, deepwater projects could lead to severe financial setbacks.

Because of the broad impact of compaction and seafloor subsidence, it is crucial to have a compaction monitoring program in place. As a result, we developed a new Formation Compaction Monitoring Tool (FCMT) and new methods of measurement and interpretation. The FCMT is a wireline device that uses multiple gamma-ray detectors to determine locations of and precise distance between radioactive markers planted in the formation or casing. Compaction of the formation can be measured by changes in the distance between the markers. For precise estimation of the vertical distance between a pair of markers, the new method uses an array of three or four detectors.

By examining the tool response to a marker, we developed a new method to determine the exact vertical and lateral location of the marker using a Lorentzian response model. Consequently, not only the vertical compaction but also lateral displacement of markers can be monitored with the new method..

The accuracy of the tool was established in the test facility where gamma-ray sources were placed at precisely known intervals. The tools were logged centralized at three logging speeds (5, 10, and 15 ft/min.), and data were collected at 0.1 in. intervals. The vertical distances between a pair of radioactive markers spaced 30 ft apart were measured accurately to within 0.1 in.

The first base-line logs were collected successfully in the four wells in a GOM deepwater development. High consistency among measurements from different logging passes proved that the FCMT can provide precise distance measurements with newly developed methods.

Introduction

Formation compaction is a major concern in unconsolidated sand reservoirs. Compaction can reduce formation porosity and permeability, affecting long-term hydrocarbon production from the reservoir. Compaction can deform well tubulars, creating operational problems and shortening well life. If compaction is significant, it can cause subsidence of ocean floor, leading to severe safety problems for offshore platforms.
The Engineering of Pigging Equipment for Subsea Systems in Campos Basin
Authors: Lino A.C.F. , Mastrangelo C. , Pereira F.B. , Gomes M.G.F.M.
Published: October 2008

PETROBRAS EXPLOITS oil from fields located in deep water in Campos Basin, a subsea project which faces some problems. One of them is wax build-up subsea production flowlines. So, since 1990, methods to prevent and remove wax deposits have been studied.

The occurrence of wax build-up in flowlines installed in cold sea bottoms is a permanent challenge, so pigging among other methods, is used to control wax deposition on pipeline internal surfaces. Pigging in subsea systems is a difficult task, because reliability in equipment, facilities, and procedures.

This paper is a continuation of other papers that Petrobras has presented in international conferences and describes pigging requirements for subsea equipment, flowlines, platforms and FPSOs designed for the Campos Basin. Some devices that Petrobras has developed to run pigs in subsea systems, such as dual diameter scraper pig, subsea pig signaler, piggable Y, and piggable loops, are also presented.

Introduction

The occurrence of different types of deposits on pipelines, which affects operational routine in offshore installations, led Petrobras to deal with this problem.

In order to evaluate the available methods for preventing and removing these deposits and to develop others, the Program on Deepwater Exploitation Systems has been studying and testing many techniques. Special attention has been given to wax prevention and removal methods, for this is one of the main operational problems to be faced up to.

Since the beginning of first phase of Albacora field exploitation in 1989, it has been noticed that some production flow lines presents organic deposits build-up. This phenomenon happens when paraffin comes out of solution, as the oil reaches the WAF' (Wax Appearance Point), due to low sea bottom temperatures.

Although Petrobras is aware of asphaltene, scale and hydrate occurrence, this paper will focus on present diificulties, solutions and procedures adopted by Petrobras to minimize wax deposit impact on deep water exploitation projects applying pigging. The use of pigging techniques implies an additional investment that must be foreseen in the initial phase of the project.

The following aspects will be highlighted:Piggable equipment for subsea systems.The use of pigging in Albacora, Marlim and Barracuda fields.

The Engineering of Pigging Equipment for Subsea Systems in Campos Basin

Petrobras exploits oil from fields located in deep water in Campos Basin, a subsea project which faces some problems. One of them is wax build-up in subsea production flowlines. So, since 1990, methods to prevent and remove wax deposits have been studied.

The occurrence of wax build-up in flowlines installed in cold sea bottoms is a permanent challenge, so pigging among other methods, is used to control wax deposition on pipeline internal surface.
What Future for Conventional Pipelay Barges?
Authors: Borelli Antoine J. , Perinet Dominique
Published: October 2008

In order to study the evolution of Conventional Pipelay Barges, the paper presents the past and present capabilities of some selected laybarges and how their equipment has been modified to suit the market needs. A second section reviews the pipelay market needs to date and its major characteristics. A segmentation between Conventional lay, Flexible line and Rigid Reel lay is apparent. All three segments grow significantly from 19% to 1997 and remain at a sustained level of activity for the years thereafter. There is a tendency to shift to smaller diameters and deeper waters. The last section discusses the pipe lay barge evolution; it concludes that the fields where the greatest gains can be achieved for the industry seem to be: for station keeping, dynamic positioning; for laying techniques, S-lay: and for production rates, real-time nondestructive control techniques.

Introduction

Since the Sixties, conventional pipelay barges have dominated the market of pipelaying. This has remained the case, even though considerable innovation and effort has been put into alternative laying techniques such as bottom-tow or near-the-bottom-pull or tow, surface-tow, rigid steel and flexible, reel barge or J-lay.

Throughout this period, ETPM has operated conventional pipelay barges, such as DLB 1601, DLB Polaris or LB 200, first on their own behalf, and later for the McDermott-ETPM Joint Venture. The Company is therefore well placed to look back at the various challenges the industry has met up to now to review those it will be facing in the near future, and to outline the improvements and innovations that will be required to adapt to new market requirements.

Past & Present Barge Capabilities

Present Lay barge capabilities have been largely determined by the successive challenges the industry has had to face.

Large diameter trunklines

The challenge to transfer large quantities of crude or gas over very long distances, with minimum intermediate boosting platforms, started in the North Sea in the mid Seventies. It sill continues today and extends to other areas as well.

Typical characteristics of some selected projects are shown in Table 1.

This has resulted in the construction of a different generation of lay-barges able to work in harsh environments, of two types monohull, such as DLB 1601, or semisubmersible, such as the LB 200 (ex Viking Piper) or SEMAC I. These were further upgraded later in time to suit the needs of the market, mainly with regard to tensioning devices, stinger capacities, monitoring and control systems, handling equipment and welding equipment.

Further, the water depths in which the pipelines were to be laid increased dramatically with the crossing of the Norwegian Trench (deeper than 350m) which resulted in additional increases in tension and stinger/ramp capacity (see Fig. 1- LB 200 laying Zeepipe IIB for Statoil).
Evolution Of Concrete Monohulls After The Nkossa Barge
Authors: Valenchon C. , Rossig J.H. , Anrhs S.
Published: October 2008

The NKOSSA Oil Production Barge, now in production offshore Congo in the South Atlantic, is the first Concrete Monohull Production Vessel, and by far the largest concrete barge ever built.

From the unique experience of designing and building this large concrete monohull, extrapolations towards other concepts using larger vessels have been developed.

The first step of the evolution is to add to the production functions the functions of crude oil storage, and offloading while either keeping a spread mooring for mild environments or choosing a turret mooring for harsher environments (FPSO).

The latest and most innovative evolution is a concept for the development of deep water fields in mild environmental areas such as the Gulf of Guinea. This concept is an FPSO which performs, in addition to its usual functions, all drilling and work-over operations, while allowing dry well heads to be placed above the deck of the unit, called a "Multifunction Barge" (MFB).

Introduction

Concrete fixed offshore platforms are found all over the world including Norway, UK, USA, Australia, the Netherlands and Germany. Some of these platforms were installed over 25 years ago. They have demonstrated their excellent long term behaviour in the offshore environment, with very limited maintenance.

After installation in the North Sea in 1995 of the Heidrun Concrete TLP (Ref. l), and the Troll Olje Concrete Semi-Submersible (Ref. 2), the NKossa Barge is the third concrete floater to be installed offshore during this decade.

This "barge type" structure has been built within an EPC contract following an international call for tender for a steel hull, in which the bidders were allowed to propose a concrete alternative.

The paper presents first the main features of the NKossa oil production barge, and a brief history of other concrete floaters, then the evolution of the NKossa concept to concrete FPSO's and the Multifunction Barge is discussed.

The NKossa concrete barge

The NKossa Field, in production since June 7, 1996, is located 60 km off the Congo coast in water depths ranging from 150 m on the East side to 300 m on the West side. The field has been developed using two steel drilling/wellhead platforms, a production facility, and two Floating Storage/Offloading vessels for oil and LPG. It was decided to use a Floating Production Unit for the hydrocarbon processing facility and for reasons stated below, to construct it out of concrete rather than steel.

This unit, which is the largest concrete monohull ever built, has an operating displacement of 110,000 tomes and is designed to carry a deck load of 33,000 tomes.

The barge houses 80 people, serves as control centre for the other field installations and provides oil treatment, LPG production, gas reinjection, and water injection functions, as well as all utilities (see fig. 1 and table 1).
Offshore Facilities Audit Results
Authors: Pomfret Bill
Published: October 2008

Accidents and downgrading incidents are occurring every minute of every hour of every day somewhere in the Offshore Oil Industry. Contrary to popular belief the safety and risk control standards in the industry are unacceptable, and the industry is paying the price with major increases in insurance coverage. The financial costs to the industry in every nation of the world are underestimated because management are unaware of the extent of such losses, due to under reporting, cover ups and there being no desire or requirement to cost out such incidents. This paper will present illustrated case histories from over 250 offshore audits carried out from Canada's east coast and the arctic, the North Sea, Africa, Middle East, Malaysia, China, Korea etc. using the 5 Star Health & Safety Management System (T.M.) (Offshore Module). The average audit result from 19961997 concludes that, those audited scored less than 71% and only achieved a two star grading, a sad indictment of the industry. However, those achieving 4 and 5 stars saved millions of dollars in premium reductions.

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Chairman, Offshore Technology Conference, Organising Committee members and fellow delegates, it is indeed an honour to be selected to address this prestigious event. It is my sincere hope that the aspects I will cover will prove both relevant and interesting, but above all, that it will make a contribution to reducing the terrible number of deaths, injuries and unplanned production losses as have been experienced by the industry in the continuous search for black gold. Throughout this presentation and in the 5 Star system the word "Safety" refers to accident, fire and loss prevention, the maintenance of occupational health and welfare and the effective control of pollution from the rig or platform. Over the past few years 1 and my team have conducted some 250 audits in many parts of the world, from the North Sea to Canada's arctic and from the Middle East to Malaysia and from South Africa to China. The system we have used to conduct these audits is the 5 Star Health & Safety Management System (TM) offshore or marine modules, of which the proprietary rights are held by Safety Projects International Inc. The audit system was developed through the 1970's and 1980's based on the combined experience of S.P.1. staff and several clients who made significant contributions, B.P. Petroleum Development staff in Aberdeen helped considerably in the development and evaluation of the prototype module. The audit criteria covers some 108 elements of which 78 are universally applicable to all industries and 30 elements which pertain to the specific area of the rig or platform. The 5 Star system identifies the strengths and weaknesses of any safety program: It allows for the quantification of managements efforts. Possibly the most important facet of the whole program is the giving of recognition to management and labour by means of a star grading for reaching certain high standards of achievement. Like grading hotels, management understand star grading systems well.
A Processing Approach to the Reduction of the lnfill Marine 3-D Acquisition
Authors: Spitz Simon , Huard Irène
Published: October 2008

The cost and turnaround of the seismic acquisition offshore have been drastically reduced in the last decade. One may argue that the industry has reached a stage where no more gains can be made in terms of cost or turnaround. However, time sharing and infill acquisition still represent a heavy burden on the exploration budgets. In this respect, we present this paper a technique that aims at populating gaps in the coverage. When these gaps are small the technique replaces the widely used flex binning. When these gaps are large, the technique aims at reducing the infill acquisition. In this paper we test the technique on a swath from a survey that required a heavy infill. The comparison between the output of the propsed technique applied to the primary acquisition only and the total acquisition (primary and infill) data set shoes that this reconstruction scheme fills correctly the gaps in the coverage. The technique can therefore be considered as a processing approach to the reduction of the infill in marine 3-D acquisition.

Introduction

For commodity reasons, most of the algorithms commonly used in 3-D seismic data processing assume that the traces are regularly distributed on a grid. Obviously, the character of the marine acquisition itself, the state of the sea, the effects of currents and tides, cause some departures from the ideal currents and tides cause some departures from the ideal regular geometry. It is a fact of life that the marine seismic acquisition is intrinsically irregular in the sense that the recorded traces are never located where one wishes them to be. While small irregularities have little impact, irregularities that lead to gaps in the coverage can adversely affect the quality of the final result. Small gaps in the coverage cannot in general be avoided. The simplest and the widely accepted solution to filling such gaps is flex-binning. Flex binning is nothing else than copying a trace from a filled bin into an empty bin. The range of the flex obviously depends on the dips present in the data set. However, from a practical point of view. an offset dependent range is fixed for a whole survey by testing. In this respect, one can ask if a more sophisticated interpolation scheme could not populate the empty bins even beyond what is nowadays considered as a reasonable range for flex binning. The answer to this question can have a dramatic impact on the marine 3-D acquisition in terms of cost and turnaround. Indeed, when the gaps in the coverage due to currents and subsequent streamers feathering exceed some contractual specitications closely related to the flexing expected range. the vessel has to return and re shoot some portions of the survey. An infill of the order of 10% is common and sometimes it can amount to as much as 50% of the main (primary) acquisition. Obviously, this infill not only increases the cost of the survey but impacts also on the planning of the off shore exploration.
MEGATHYST - A Compact Dynamically Positioned Semisub for Deep Waters
Authors: Ubisch B.V. , Roodenburg J.
Published: October 2008

MSV Amethyst is a compact, fully Dynamically Positioned semisub, designed for workover on subsea wells in the North Sea, supplied in 1987. In 1996 a new rig, based on the Amethyst, was designed with drilling capacities for deep water applications (1200 – 1500 m). The capacities of this new design should match with those of a large drilling vessel. In order to be able to design such a drilling vessel, close cooperation with the drilling equipment suppliers and the drilling operator was necessary to get a cost effective compact light weight semi submersible. This paper describes the process of upgrading the design of the workover unit into a deep water drilling vessel. This involves:– The increase of the payload from 1700 to 4000 tomes.– Design of the powerplant / DP system according IMO DP Class 3.– Reduction of the amount of steel used to build the vessel.– Design of the box girder derrick to reduce the amount of steel and thus weight of the derrick.– Vertical storage of risers in the aft columns of the vessel to lower the centre of gravity.– Integration of the drilling equipment in order to reduce the building time of the vessel in the yard, the weight due to the reduction of the amount of steel needed and as a result costs.– Dual derrick design for simultaneous operations like preparing casing or riser while drilling.

Introduction

In the beginning of 1980's five dynamically positioned diving support vessels were built by our yard for different owners (Fig 1). During the design and construction of these vessels the design team was asked to investigate the possibility of carrying-out workover through a moonpool in the aft deck. A demand for workover on the various subsea wellheads, being installed in the North Sea, was expected (Fig 2). After studying motion-study characteristics the amount of expected downtime was not acceptable to the field operator. The starting-point of carrying-out workover from a monohull was quickly abandoned and, also based on the experience of diving support vessels, a semi-submersible structure was adapted. The market approach was using a dynamic positioned vessel (DP) for workover in the summer and in the winter, as a diving support vessel. The diving work would consist of hyper baric welding, installing templates and spool pieces etc. The vessel, supplied in 1987, started working in the Northsea in 1988 and was named M.S.V. Amethyst (Fig 3). Due to the market situation in 1987 / 1988 the workover equipment was not installed. The vessel was used as a diving support-installation vessel in the North Sea until the beginning of 1995. In 1995 the owners / operators of the vessel were contracted to carry-out workover in Brazil. After completing the workover equipment the vessel left for Brazil in the middle of 1996 (Fig 4).

MEGATHYST design concept

In 1996 the design team of the Amethyst was asked to develop a new design based on the Amethyst. However the operators demanded better performances for drilling in deeper water.