bluuebunny/crossref_metadata_2025 huggingface dataset:
The Brunei Ship Loading System for LNG:Technology Accommodates Environment
Authors: Crowl Robert , Dowdell Thomas
Published: October 2008

I. INTRODUCTION

It's certainly not news to anyone that a general Shortage of natural gas exists in the population centers of the world. All of the industrial countries, including the United states, the industrial countries of Europe, and especially Japan, are particularly thirsty for great volumes of natural gas. It is also no surprise to all of us that the great untapped quantities of gas are usually not found at the point of need or use. Instead, these valuable stores of energy are found in such places as the deserts of North Africa, the far North Slope of Alaska, the Islands of Southeast Asia, and deep in the heart of Australia.

Through the physics of cryogenics, it becomes feasible to gather the gas, shrink its size some 600 times by successive compression and cooling, to its liquid state at a temperature in the range of -260°F. With specially constructed super tankers, the valuable liquid can be taken to the energy-short areas of the world, returned to its gaseous form and put in the hands of the consumer, you and me. This paper presents a description of the Brunei LNG Ship Loading System, a very special solution to a problem brought about by this commercially new technique, cryogenic liquefaction of natural gas at Brunei on the Island of Borneo, and subsequent shipment of the liquid in LNG ships to Japan.

The Brunei LNG Project is a joint venture of Royal Dutch/Shell and Japan's Mitsubishi Shoij and the Brunei Government. Three Japanese terminals will receive the gas, Negishi in Yokohama, Sodeguara Chiba and Sembolu. Brunei LNG, which is the name of the joint venture, owns and operates the liquefaction plant, receiving its gas from the Brunei Shell Petroleum Company, Ltd. through offshore wells. Construction of the Brunei LNG production facility was the responsibility of the engineer/constructor team of Japan Gasoline (JGC) and Procon, Inc., a Division of Universal Oil Products (UOP). Project specifications and construction cognizance on behalf of Brunei LNG, were the responsibility of Shell Internationale Petroleum Maatschaapij (SIPM), The Hague, Holland. Subcontractor to the joint engineer/ constructor team for the LNG Ship Loading System was the Cosmodyne Division of Cordon International, Torrance, California.

Total plant output is expected to reach 5 million tons per annum in full production. The liquid will be carried to Japan in seven special LNG ships that have been contracted to be built for this project. The first ship, the GADINIA, 75,000 cubic meters capacity, has been completed and has made a number of deliveries already to Japan. Checkout of the logistics operation was made in early December 1972. The GADINIA departed Brunei December 9, 1972 to make its first delivery.
Concerns and Their Impact on Offshore Design and Operations: Were Hurricanes Ivan 2004 and Katrina and Rita 2005 100-Year Events or a Result of Moving Over a Warm Loop Current?
Authors: Schellin Thomas E.
Published: October 2008

The return of strong Gulf of Mexico hurricanes has resulted in a re-examination of the 100 year return periods over the Gulf oil leases. Hurricane Ivan in 2004 went through Atwater Valley, Mississippi Canyon, Viosca Knoll, and Main Pass. Hurricane Katrina in 2005 traveled across Lund, Atwater Valley, Mississippi Canyon, West Delta, South Pass, Main Pass and Breton Sound. Hurricane Rita in 2005 moved across Walker Ridge, Green Canyon, Vermilion, East Cameron, and West Cameron. Do these three devastating hurricanes change the 100 year recurrence values for these oil leases, or were they 200 or 300 year events? Are there more and stronger Gulf oil leases hurricanes over the leases closest to the warm loop current?

ESRI's ArcView Software was used to plot all of the hurricanes since 1900 which had maximum sustained winds greater than 99 knots. The area of the oil leases was defined as an area north of 25N and west of 85W. The software was lso used to find all of the tropical cyclones that have moved through the following oil leases: Atwater Valley, Mississippi Canyon, Walker Ridge, and East Cameron. The results of these plots were used to estimate the 100 year return period for each of these oil leases.

If you review the major hurricanes that have moved through the Gulf Oil leases since 1900, you will find that there have been 37 hurricanes which have caused maximum sustained winds of 100 knots or more. There have been 7 years when here was more than one major hurricane over the leases: 1909, 1915, 1916, 1975, 1985 and 2005. The highest observed maximum sustained wind over the Gulf oil leases as defined above was 165 knots during Hurricane Camille on August 17, 1969 as it tracked through Mississippi Canyon, Main Pass and Chandeleur Sound. The next highest observed maximum sustained wind of 155 knots was during Hurricane Allen on August 9, 1980 south of Alaminos Canyon and Keathley Canyon. Hurricane Katrina in 2005 and Hurricane Carla in 1961 both had maximum sustained winds of 150 knots. Hurricane Rita in 2005, Hurricane Beulah in 1967 and Hurricane Ethel in 1960 all had maximum sustained winds of 140 knots. In any year the Gulf of Mexico oil leases have a 36% chance of experiencing an intense hurricane with maximum sustained winds of 100 knots or more, since there have been 37 out of the last 104 years with hurricanes with winds of 100 knot or greater winds.

There seem to be more and stronger hurricanes over the oilleases closest to the warm loop current. The paper will give the 100 year values for maximum sustained winds based on 104 years [1900-2003] and 54 years [1950-2003] for Atwater Valley, Mississippi Canyon, Walker Ridge, and East Cameron. The author will then show how Hurricane Ivan in 2004, Hurricane Katrina in 2005 and Hurricane Rita in 2005 rate.
Underwater Imagery by Mapping Sonar
Authors: Haye Edward F.
Published: October 2008

This will be a discussion of an instrument capable of sea floor mapping with sound waves in a similar fashion to which side looking radar maps the land with radio waves from an airplane.

The instrument used is a long range side scan sonar. One developed specifically for geologic mapping of the sea bottom. This particular instrument was developed by Institut Francais du Petrole; the French governmental petroleum research company. It is capable of producing imagery as far as 1/2 mile on each side of a fish towed behind a ship.

Figure 1 is a picture of a fish. It is 13 feet long and weighs 2000 pounds. In it are mounted transducers that emit sound and receive the echoes from the ocean floor. One pulse is emitted each second.

The frequency used is 37-1/2 kilocycles, well out of the range of petroleum seismic sources. Because a much higher frequency is used, the instrument is compatible with marine seismic techniques. The fish can be towed at speeds of up to 10 knots, although the slower speeds of seismic operations are more ideal.

Figure 2 shows the way in which sound is emitted and received. Sound is emitted in a vertical beam that is 1-1/2 degrees wide on each side of the fish. The vertical sweep can be adjusted from 10 to 30 degrees. In addition to being able to adjust the sweep angle, the look angle of the sweep can also be pointed downward or more horizontally to compensate for changes in water depths.

This particular instrument is unique among sonars in that its range is 750 meters, or approximately 1/2 mile. For geologic interpretation and mapping, the range of the sonar determines the amount of bottom that is mapped with one pass, i. e. the cost per unit area. The geologic interpretability of sonar records is a direct function of the amount of the bottom that is seen; that is its range.

Ideally, the fish is kept at a constant height above sea bottom that is, 50 meters, or 150 feet. The speed of the ship and the length of the towing cable determine the depth of the fish. By pulling the fish 150 feet above the bottom, a scan of 1500 feet of the bottom is obtained on each side, with a 1500 foot blank area beneath the fish.

The range of the instrument is sufficient to allow excellent interpretation from a traverse. Interpretational abilities are enhanced greatly by other information, such as simultaneous sparker profiles. For this reason, the side scan is almost always used in conjunction with some type of vertical profiling.
Disconnectable FPSO - Technology To Reduce Risk in GoM
Authors: Aanesland Vidar , Kaalstad Jens P. , Bech Arild , Holm Anders
Published: October 2008

The paper describes the Submerged Turret Production System (STP) and a state of the art disconnectable FPSO. The STP technology is well proven in the North Sea, South China Sea and other offshore arenas worldwide for both disconnectable FPSO's and for permanent mooring configuration. Lately it is being used for turret mooring of one of the worlds largest FPSOs located in Mexican waters in Gulf of Mexico on the PEMEX KuMaZa field. The FPSO is scheduled for first oil April 2007 and a short update of this project is presented.

The STP technology is built on the Submerged Turret Loading - STL technology used for Offshore Loading of Crude Oil, which is further developed for Discharge of Natural Gas and is the basis for the world's first Offshore LNG Receiving Terminal, Gulf Gateway - located in US Gulf of Mexico, Block WC 603. The paper presents this turret technology and how this technology can significantly reduce development risks in the Deep Water Fields in GoM and how it subsequently can have a positive impact on insurance premiums for the FPS/FPSO facility due to the ability to safeguard and sail away from Hurricanes.

Introduction

The ability to easily connect and disconnect a single point mooring and riser system in a safe way is attractive for a number of reasons. The most obvious reason in Gulf of Mexico is to be able to remove the vessel in case of a hurricane. The technology described, has been developed over a period of 15 years, starting in the North Sea with the STL loading system for shuttle tankers and the disconnectable STP mooring and riser system for FPSOs. Basically the technology is the same, utilizing a submerged buoy integrating riser buoy and turret in one compact module which all together is disconnected.
Resolving the K-2 Salt Structure in the Gulf of Mexico
Authors: O'Brien John , Rodriguez Arnold , Sixta David , Davies Mark A. , Houghton Phillip
Published: October 2008

While depth imaging emerged in the 1990's as a major tool enabling subsalt exploration, imaging beneath salt bodies still remains a technically challenging task. Industry has had many major successes, but also some cases where imaging quality has been inadequate for the task at hand.

Following on the heels of the first applications of depth imaging, a number of additional technologies have been developed that provide further capabilities to image the Base of Salt and the subsalt section. These expand the toolkit available to the explorationist enabling us to image some additional salt bodies, but not necessarily all, which could not previously be imaged. Where multiple independent methods can be applied, they also provide a means of cross-checking our results and evaluating our confidence in the interpretation.

In this paper we present a case study from the K-2 subsalt field in the Gulf of Mexico where Kirchhoff Prestack Depth Migration failed to resolve the Base of Salt updip of the discovery well, leading to uncertainty in the updip extent of the field. This raises key questions about the strategy to use to appraise the field. To address this problem and to guide the appraisal drilling program we used three recently developed geophysical technologies:(a) Gravity Gradiometry,(b) Wave Equation Depth Migration, and(c) Reverse Time Migration.

We present the results provided by the three techniques to show how, in this case, they can overcome the problems encountered by Kirchhoff migration. We also show how they combine to provide a high confidence interpretation of the Base of Salt and provide direction for the appraisal drilling strategy.

K-2 Field

The K-2 Field is located in Green Canyon Block 562 in the deepwater Gulf of Mexico, some 180 miles south of New Orleans. This is a subsalt field, underlying a massive salt body with salt thickness in excess of 10,000 ft. Wells drilled to date have encountered up to 340 ft. of oil pay in Miocene age sands. Prestack depth migration has played a vital role in exploring K-2, providing excellent definition of the salt body and of the underlying sedimentary section in areas where the salt has a tabular morphology. In these areas we can image the Base of Salt, which occurs at a subsea depth of approximately 20,000 ft, and also the underlying sedimentary section down to a depth greater than 40,000 ft. This represents an outstanding subsalt imaging achievement.

While prestack depth migration has yielded some excellent imaging results, the technique is not without problems. In particular, the eastern flank of the K-2 salt has a steep face (~60°) while the salt top displays a prominent structural peak immediately west of this flank. Prestack depth migration using a Kirchhoff algorithm fails to image the Base of Salt and subsalt section in this area, resulting in an uncertainty in determining the updip extent of the K-2 Field.
A New Display Technique for Surveying Sonar Data
Authors: Wood K.E. , O'Farrell J.T.
Published: October 2008

A new display technique has been developed to improve the display capability of 'side-:look sonars used for surveying purposes. The sonar data are displayed in real time as a standard TV pictures which moves across the screen to simulate motion of the sonar over the bottom. The display uses a magnetic video disc in conjunction with digital processing logic to provide a system which is much more rugged and reliable than previous electroniscan converters.

Because seawater is almost opaque to electromagnetic propagation, high-resolution side-look sonar (SLS) has become one of, the primary methods used for undersea searching and for large-area ocean bottom surveying. Sonic energy can penetrate seawater effectively, but its speed of propagation is relatively slow-about 5000 ft/sec. Therefore, the time required for an echo signal from the sonar transmit pulse (about 65 milliseconds for a target 160 feet from the transmitter) dictates a sonar pulse repetition frequency (PRF) much lower than the human eye flicker frequency.

Since scan conversion to a more rapid refresh display for direct viewing adds complexity to the system, the conventional method for imaging slow-scan sonar data has been the paper recorder. Sonar returns (converted to time-varying voltages) are applied to wire helixes that rotate over voltage-sensitive paper. Although that method has been used extensively, the record it provides is generally unsatisfactory - mainly because the image is negative and its dynamic range is limited. Also, when exposed to the high-humidity conditions encountered aboard ship the paper transport often slips and results in image distortion.

Another method for generating a sonar image without scan conversion is the cathode-ray tube (CRT) recorder, similar to the device used in side-look radar imaging. Here, sonar returns are written across the face of a fiber-optic CRT. The light pattern generated is used to expose a dry silver paper that is drawn across the face of the CRT. The image is fixed by heat to provide a high-quality permanent record about 14 seconds after the information is applied to the recorder.

While the CRT recorder does provide an excellent permanent record, there are many applications where it would be desirable to view the ocean bottom directly as it is traversed (as through a "moving window"). For example, it is often useful to make preliminary scans of an area before making permanent records. Or real-time viewing could be used for bottom navigation. But as previously mentioned, direct viewing' requires some form of scan conversion of the slow' sonar PRF to a more rapid refresh rate to permit viewing without annoying flicker. Electronic-tube scan converters have been used for this purpose, and Westinghouse has built several of these systems in the past. They produce a good quality picture, but they are bulky, expensive, and complex to operate.
Investigation of Interference Between Upstream and Downstream Cylinders in a Current for the HRTs and Jumpers With FPSO Application
Authors: Blevins Robert D. , Wu Mason
Published: October 2008

Experiments and analyses have been made to determine the response of a downstream cylinder that is in the wake of a fixed upstream cylinder. This geometry is of great practical importance for risers in deepwater. It arises with jumpers in deepwater hybrid riser towers and in closely spaced risers. The theories of Huse [1], and Blevins [2] are applied to predict the steady response of the down stream cylinder. These predict that within the confines of the wake of the upstream cylinder, the drag on the downstream cylinder is reduced and there is a lift force that acts to draw the downstream cylinder into the wake of the upstream cylinder. There is apparently no simple, direct experimental confirmation of this predicted behavior.

An experiment was made in the flow channel of the Scripps Institution of Oceanography to test these theories up to about 80 000 Reynolds number. The paper describes the methodology and results of these experiments to validate the parameters of the theoretical models.

Preliminary measurements show that as the flow increases the downstream cylinder travels aft and inward towards the centerline of the wake. At small inline spacing the downstream cylinder moves upstream, implies negative lift, and impacts the fixed upstream cylinder.
Dalia Field - System Design and Flow Assurance for Dalia Operations
Authors: Courbot A. , Hanssen R.
Published: October 2008

Evaluating flow assurance risks for the development of Dalia was a key task during system design to safeguard the production over the 20 years design life. A low energy reservoir, heavy, viscous, acidic crude oil sensitive to hydrate formation and one of the world's largest subsea networks in deep water to operate and preserve, led to flow assurance requirements above oil industry experience. Innovative technologies and strategies were required to meet the challenges.

State of the art software tools have been utilised to the edge of their capacity in order to assess the thermal performance of complex subsea structures and the challenging flow conditions associated with relatively large flowline and riser dimensions. Extensive studies have been carried out to help prepare detailed operating procedures, focusing especially on hydrate management and slug handling. Uncertainty in fluid behaviour, naphthenates in particular, has fostered discussions between the project team, partners and expert groups to define best practice management strategies and reduce risk of operational problems.

The paper presents the flow assurance strategies developed to handle the main risks as well as a description of the production system specifics to meet the challenges.

Key Parameters and Flow Assurance Risks

The subsea production network for Dalia is located at a water depth of 1,200 to 1,450 metres. The Dalia field is part of the Angolan Block 17 (Figure 1) and consists of four main reservoirs formed at the Miocene period (Figure 2). They are situated 800 to 1,000 metres below the mudline and are characterised as unconsolidated and highly heterogeneous. They cover an area of 230 km2 and the subsea production system covers an area of 100 km2. Dalia oil is acidic and heavy with an API gravity of 21-23, a viscosity of 4-7 cP at down-hole conditions and the gas oil ratio (GOR) is in the order of 70 Sm3/Sm3. These characteristics combined with the low reservoir temperature (46 to 55oC) and an initial pressure of 215 to 235 bars present one of the greatest technical challenges for operations. The main characteristics are shown in Figure 3 with a comparison with Girassol, which was the first field developed in Block 17. The figure illustrates important differences between the two fields, leading to different system design requirements and flow assurance challenges.

Figure 1 - Dalia Field Location (available in full paper)

Figure 2 - Dalia Reservoirs (available in full paper)

Figure 3 - Reservoir and Fluid Characteristics compared with Girassol

These key parameters emphasise the main flow assurance risks for Dalia:

- Hydrate formation due to low reservoir temperature, water depth and flowline length

- Unstable flow conditions associated with seabed elevation profiles, low GOR and flowline and riser dimension

- The heavy and acidic oil can create strong emulsions and the risk of naphthenates deposition

- The oil viscosity in combination with surface active agents provides the risk of foaming in the surface facilities
Dalia Development-The FPSO Story and Package Challenges
Authors: Mouillerat G. , Regnault G. , Leroux J.
Published: October 2008

This paper will review the hull design together with topsides process modules and functions. It will also focus on the schedule challenges during construction in Korea, the steel crisis and the yards workloads. The global supply chain and management of the contractors and main subcontractors will also be addressed.

Designed and built by Dalia Mar Profundo (DMP), a consortium of Technip / Saipem / Stolt in the TSS joint venture together with Samsung Heavy Industries (SHI) and Daewoo Shipbuilding & Marine Engineering (DSME) in Korea, the FPSO is 300 metres long and 60 metres wide capable of 2 millions barrels oil storage at an average production capacity of 240,000 barrels per day. It has a "total liquid" handling capacity of 405,000 barrels per day and a gas compressing capacity of 8 million sm3 per day. A special seawater treatment for sulphate removal module is incorporated. SHI undertook the task of building the 55,000 tonnes double skinned hull and "about half" of the topside modules. DSME completed the remaining modules and undertook the installation and integration of all the topsides modules before sail away. TSS had the responsibility for onshore pre and final commissioning.

The FPSO is moored with a 12 point chain spread linked to 17 metre high, 106 tonnes suction anchors and attached to the vessel by 120 mm diameter, sheated cables 1,800 metres long, with 100 metre chain segments at either end. Weight control was very effective maintaining the weight within the original targets.

Dalia Field Overview

For more details refer to Dalia paper OTC 18538.

Refer to Figure 1 for the general field layout with the FPSO and its mooring lines, above the subsea production facilities.

Figure 1 - Dalia Development Layout (available in full paper)

General Introduction to the FPSO

The 300 metre by 60 metre new build FPSO, weighs over 85,000 tonnes dry and with a surface area of more than four football pitches, was designed and built by the DMP consortium. With storage for up to eight days at the average plateau production of 240,000 barrels per day, the twin train process system has two stages for oil separation. Each train is designed for 55% of the total capacity, to give better reliability of the separation system. After dehydration and desalting, also undertaken in two phases, the oil is cooled down to 50°C before storage.

Produced water is treated and re-injected into the reservoir for pressure maintenance. Seawater is treated to complement the total injection capacity of 405,000 barrels of water per day. Produced gas is used as fuel and the balance is re-injected in the reservoir until export to the future Angola LNG plant. Three 24 MW Gas turbines generate the power on the FPSO. These gas turbines are dual fuel and run on high quality diesel at start-up and during periods when gas is not available. Anchored in the Dalia field in September 2006 by the 12 mooring lines spread, the FPSO is built to remain in place for the design life of 20 years.
The Development of an FPSO for the Deepwater Gulf of Mexico
Authors: Wodehouse J. , George B. , Luo Y.
Published: October 2008

This paper presents the issues specific to the engineering and operation of FPSOs in the US Gulf of Mexico, and discusses the design of one FPSO currently under development and how it addresses those issues.

The areas of the FPSO design which are discussed in this paper include:Regulatory and environmental requirementsVessel selection and refurbishment for design life extensionRiser and station keeping/mooring design for hurricane and loop current conditions in deepwaterTopsides design including associated gas disposalOil import and export facilitiesShuttle tanker requirements

The design basis of this FPSO has been developed with the intent of enabling the unit to be easily redeployable in different locations, either as an Early Production System (EPS) for large fields, or a Full Field Development on marginal or medium size fields (30- 80,000 bopd). Different technologies are compared and their design and operational limitations identified, for riser design (flexible risers, hybrid riser towers, top tensioned risers, single well riser towers, permanent and disconnectable) and station keeping design, (permanent or disconnectable, dynamic positioning or anchor leg moorings, polyester or wire rope mooring systems). Those aspects of the design which require technology new to the Gulf of Mexico, will be highlighted and comparable applications of the technology elsewhere in the world, if applicable, identified.

There has been an increased interest recently in the application of FPSOs for the development of deepwater fields in the Gulf of Mexico. Damage to offshore facilities and the pipeline infrastructure during recent hurricane seasons, has made the benefits of the FPSO concept more apparent, with its large onboard oil storage capacity and capability to offload via shuttle tankers or pipelines, and its ability to disconnect from risers/moorings and avoid the hurricane conditions design case. Understanding the issues relative to the use of FPSOs in the Gulf of Mexico and developing a design, which utilizes the proven technology of FPSOs elsewhere in the world, is key to applying this concept successfully in this region.

Introduction

So far there have been no FPSOs installed in the US portion of the Gulf of Mexico (GoM) even though the concept has been increasingly selected for field developments elsewhere in the world. What are the key issues when reviewing the suitability of an FPSO for this region, and what has changed recently to affect the selection process? The damage caused to the offshore units and pipelines system by hurricanes Ivan, Katrina, and Rita, plus the continuing exploration success in the ultra deepwater beyond the continental shelf, are two of the main drivers towards the current interest in FPSOs in the Gulf of Mexico.

The ability of the FPSO to be designed to disconnect and sail away prior to the arrival of a hurricane, and the fact it is not dependent on the pipeline network to transport oil, makes it an inherently more robust and safe design concept.
The Effectiveness Of Offshore Motion Compensators
Authors: Pomonik George , Butler Bryan
Published: October 2008

Heave motion compensators are rapidly becoming standard equipment aboard offshore drilling vessels. The effectiveness of these devices are dependent on a large number of variables; not all of which are a function of the compensator 'design. This paper reviews the basic principles for sizing compensators, and uses a computer analytical model to graphically show the changes in dynamic load that result from varying the significant parameters in the compensator system. The variables studied include: piston size, operating pressure" accumulator size, pipe Size, static load, compensator internal damping, depth of operation, vessel heave period, external damping and external added mass.

The'theoretical graphs presented can be used as a design guide for selecting and improving actual systems. The material includes dynamic loads during drilling, as well as for hoisting and lowering a blow-out preventer.

INTRODUCTION

Motion compensators provide numerous advantages during offshore drilling operations. However, the effectiveness of a compensator system is dependent on more than just the theoretical spring rate of' the compensator. The following material reviews the principles and advantages of motion compensators, discusses the parameters of importance, outlines preliminary methods for sizing a compensator, and finally, presents and discusses analytical material which shows the effects of varying the parameters in the compensator systems.

COMPENSATOR DESCRIPTION

Purpose

The purpose of heave motion compensation is to hold a load suspended from an offshore vessel while simultaneously reducing the oscillating force on that load due to vessel motion. At this time the major application of heave motion compensators is for offshore exploratory drilling operations. The advantages provided by a heave compensator system in this application are as follows:Reduction in bit load variationReduction in pipe load variationControl of bit load and drilling feed RateAccurate positioning during setting of casing hanger sealsControl during setting of packersSafety during pulling stuck pipeControl during setting off jarsThe ability to avoid stripping of tool joints through blow-out preventer ramAccuracy during logging and wire line servicesReduction of blow-out preventer stack oscillation during installation (thereby avoiding guide post wear and impact)Safety and control during testing.

Principle of Operation

Primary components of a motion compensator consist of a piston (or pistons) in a cylinder connected to a gas accumulator. As shown in the conceptual schematic in Figure l the pressure in the cylinder supports the load on the pistons and the accumulator provides an air spring for the load on the piston. The compensator pressure is adjusted in order to balance load on the piston.

Types

A number of different types of heave motion compensators are presently in existences including traveling block and crown block units.
J-Lay and Steep S-Lay: Complementary Tools for Ultradeep Water
Authors: Perinet Dominique , Frazer Ian
Published: October 2008

The pipelines are major components of the oil and gas production. With Ultra deep water development, the increasing of assisted recovery and zero-flare policy, pipelines specifications are much more elaborate: fatigue resistance due to cyclical operational loads and frequent shutdowns, thermal insulation for flow assurance purpose. They are often short and associated with many singularities, termination or inline structures. The design of pipelines must take into account walking and buckling, lay out in congested areas, sometimes with geohazards issues. The paper will expose the design of the different pipelines and associated components and describe how the contractors have met these challenges, improved the laying efficiency with using the J- lay method or the steep Slay, which is adapted from conventional laying method continuously improved since the seventies with a deep water application resulting from the revisited strain criteria on the laying ramp.

The S-lay methods are much more appropriate from the pipeline fabrication point of view, and appear as a better option for the laying of relative long lines such as gas trunk line or long tie back. The J lay method appears as a natural configuration from the catenary point of view and is much more appropriate to the installation of in line structures. The paper will illustrate with practical applications that these two methods are not opposed but are complementary tools and have each their own domain of excellence in the production and recovery of the hydrocarbon resources.

Introduction

The driving phenomena for deep water pipelines have drastically evolved over the last ten years with the development of deep water fields. The key driver for the design of the field layout and the flowlines is undoubtedly the flow assurance of multiphase fluids. This has led to a significant increase of insulated flowlines, which has had a great impact on the overall behavior of pipelines on the sea bed. The use of wet insulation materials such as polypropylene and polyurethane has resulted in a general reduction in the submerged weight of production flowlines, this in combination with the very soft soil conditions found in deep water locations has led to the significant increase in pipeline movements induced by pressure and temperature of the internal fluids. These movements known as pipe walking and lateral buckling have been the subject of much discussion within the offshore pipeline industry in recent years /1/, /2/, /3/, /4/. The details of these phenomena are not discussed in this paper, however the influence they have on the installation methods used for deep water pipelines will be addressed. The field layout selected for a particular offshore development has a significant influence on the pipelines and in particularly the installation techniques. In deep water fields, which are dominated by subsea wells, the field layout tends to be very different from those selected for more conventional water depths.
Float-Over High Air Gap: New Solution
Authors: Cholley J.M. , Cahay M.
Published: October 2008

Technip has previously developed, and has widely used, the jacking assisted float-over deck installation concept, called "UNIDECK®", for decks requiring a relatively low air gap. This has demonstrated the advantages of the float-over method which minimizes the overall cost of transport, installation and hook-up by having a deck that can be installed on a jacket as a fully completed and tested single unit without using a conventional crane barge. That concept has been successfully used for relatively benign areas of the world where a low air gap is acceptable but installation is problematic due to the impact of long period swells on the dynamic behavior of the installation vessel.

To allow the float-over method to be extended to harsher environmental areas of the world, a methodology is required to allow deck transportation at low level, but then enable the deck to be installed with a high air gap.

This paper describes a new float-over solution, which is applicable to platforms requiring air gaps of 20m (66 ft) or more, and deck weights up to 20,000 t (22,000 short tons) and extendable to higher weights. It is called "float-over high air gap" - FOHAG.

Introduction

With the discovery of oil & gas fields located in remote harsh environment areas of the world, a cost effective alternative is required to relying on crane vessels for installation, the availability of such vessels becoming limited as demand for their services increases around the world. The FOHAG concept greatly extends the geographical range for deck installation using the float-over method as an alternative to using a crane vessel.

If only using ballasting for float-over deck installation, the stability criteria during transportation restricts the height of the deck above the transportation vessel and hence limits the maximum finally achieved air gap. To achieve a higher final air gap, the use of jacks allows the deck to be raised up once at site and under suitable weather window conditions.

Technip has developed a jacking assisted float-over installation system, called "UNIDECK®", which has been successfully used for decks up to 18,000 t (Ref 1).. This technology uses hydraulic jacking to provide a safe and quick transfer of the deck weight onto the pre-installed jacket. However, the height to which jacks can lift the deck is constrained by the sensitivity of the jacks to lateral forces (at high elevation) and their limited stroke.

The newly developed FOHAG solution consists of replacing the limited stroke jacks by a rack and pinion system that has no stroke limitations within all conceivable air gap requirements.

The main characteristics of the system are that, during transportation, the deck is at a minimum elevation from the vessel in order to maximize the floating stability and reduce horizontal acceleration applied on the deck. Once arrived at the installation site, the deck is elevated to a sufficient height using a rack and pinion system for the vessel to enter above the preinstalled substructure (see Fig 1).
Critical Plastic Bucking Parameter for Tubing in Bending Under Axial Tension
Authors: Wilhoit J.C. , Merwin J.E.
Published: October 2008

INTRODUCTION

Buckling of tubing with moderate diameter to thickness ratios subjected to pure bending, does not take place in the elastic range but occurs by local rippling on the compressive side of the tubing after yielding has taken place. A recent paper by Wilhoit, Merwin, and Jirsa (1) presents a theoretical method of predicting the curvature and wave length at buckling in the plastic range for pure bending and compares theoretical results with previously measured experimental results for full sized pipe. This paper builds upon a solution by Gerard (2) for plastic yielding of thin-walled cylinders in compression using the Ramberg-Osgood (3) representation of the stress -strain curve in pure tension. Wilhoit and Merwin (4) extended a procedure developed by Ades (5) to predict the moment- curvature relationship in both the elastic and plastic ranges for tubes subjected to bending plus axial tension.

The present paper extends the theoretical results of reference (1) to the case of bending with axial tension by using the technique developed in reference (4). Since reference (1) bases buckling on a critical strain on the compressive side of the tubing, it was only necessary to use the method of reference (4) for each case investigated to find the curvature corresponding to the critical strain.

Thin walled welded steel tubing 2½ inches in diameter with diameter to thickness ratios from 35 to 83 were tested in a loading frame built to allow a bending load to be superimposed on an axial tensile load. Theoretical and experimental results are compared.

TEST SPECIMENS

All test specimens were obtained from round welded mechanical tubing MT-1010/202½ inches in diameter with nominal thickness 0.065 and 0.049 inches. Test specimens approximately 20 5/8 inches long were cut to fit into the loading frame. From the 0.048 inch tubing (the actual thickness of the 0.049 inch nominal thickness tubing was 0.048 inches while the actual thickness of the 0.065 nominal thickness tubing was 0.069 inches), specimens with average thickness of 0.036 inches and 0.029 inches were machined.

In order to make these thicknesses of 0.036 inches and 0.029 inches more nearly uniform eight inch lengths of the .048 inch tubing were inserted into special mandrels and then machined to size. These turned down lengths were then welded to.048 inch tubing end pieces to form the test specimen. Thicknesses were still found to vary considerably for these turned down specimens and average thicknesses after testing were ultimately used. It should be noted that tubing of 0.069 inch thickness was used for three tests while tubing originally of thickness 0.048 inch was used for the other nine tests.
Implementation of IOR Technologies
Authors: Kjorholt H. , Utseth R.H. , Strom S.
Published: October 2008

Statoil's ambition is to recover 55% of the STOOIP from subsea fields. To obtain this, extensive R&D efforts are required on all technology areas involved. Statoil's policy has been to establish strategic research partnerships with major suppliers and service companies, ideally with a 50/50 cost split between the parties. The partner selection process has normally been based on combined tender and architect competition, with a broad range of selection criteria.

Implementation of the new technology is secured as far as possible by early commitments from the potential users among our assets. The users are also kept involved in all phases of the project, on an engineering level as well as on the management level. This both helps ensure the project is heading in the right direction and makes people responsible for implementation familiar with the new technology.

Statoil subsea R&D efforts have already led to significant results. Several technologies are now being taken into operation according to plan. The most important being:A new ship for low cost subsea intervention (USD 150 000 per day) is in orderEquipment for subsea low cost TTRD sidetracks (USD 10 mill per drainage point) is ready for operation autumn 2007A complete subsea process plant is under installation in the Tordis field and will be in operation before the end of the year

Introduction

Comparing the present ultimate oil recovery of subsea fields with fields based on dry wellheads we see a significant difference in favor of dry wellheads. For Statoil operated offshore oil fields the average recovery levels are close to 45% and 60%, respectively. Even though these numbers are high in comparison with a world wide average, the ambition is to increase the recovery by another 10% points (Ref. 1). In Statoil's effort to reach this ambition the R&D portfolio addresses all the relevant technology areas. The different focus areas are:Ability to identify more accurate where the oil is located and its volumeImprove modelling of the production process and thereby the production strategyReduce cost of well construction and well interventionReduce cost and increase flexibility of subsea InstallationQualify pumps, compressors and other process equipment for sea bed installationImprove sensor technology, data transmission and data handling in order to make improved decisions

There are no obvious inherent factors like reservoir properties or drilling challenges responsible for the gap in recovery between subsea and platform developments; it is solely a consequence of the economic reality operating subsea versus from a fixed installation. Our experience is that, all other parameters the same, recovery is a function of reservoir infrastructure (i.e. total number or density of drainage/injection points during the life of the field), access to well intervention and ability to minimize the wellhead pressure. Today the cost of a subsea well, all infrastructure included, is in the range 4-6 times the cost of a platform well.
On the Jackup Platform In the North Sea
Authors: Corder Paul R.
Published: October 2008

The adaptability of the jackup drilling platform to the severe environment of the North Sea requires knowledge of its capabilities both Afloat and while standing on location. Through extensive computer analysis, this paper surveys the drilling mode strength envelope of a Marathon LeTourneau type jackup platform. The results form a family of curves which express acceptable combinations of water depth, wave height, wave period, and wind speed for given air gap, storm direction, and current.

1. Introduction

The jackup platform can be designed to operate in the North Sea. While this statement is partially supported by the presence of several jackup platforms in that demanding environment, the limits of these platforms' capabilities need precise definition. Such definition involves multiple disciplines, including naval architecture, materials, and structures among others. This paper concentrates on the structural aspect of jackup platform design and analysis. More specifically, it attends to computer structural modeling techniques and a procedure to provide meaningful data about the standing-on-1ocation strength envelope of a mobile self-elevating offshore drilling platform.

The Marathon LeTourneau type jackup platform is roughly triangular in plan with three legs which may be either triangular or square in cross-section. These legs are open space frames consisting of tubular bracing members and chords of circular or built-up cross-section. Built into each chord are continuous racks which engage electrically driven pinions located in a substructure above the top deck level. These independent electric motors elevate and lower the platform at a rate of 90 feet an hour.

The computerized analysis for determining leg stress levels under various combinations of storm loads requires a mathematical model to simulate the real platform, a definition of the loads on this computer model, and finally a suitable structural analysis computer program. There are many ways to develop an analysis sequence. This paper outlines one approach. For simplicity, only the elevated condition during a simulated storm from 60° off the bow is considered.

2. Statement of Structural Modeling Approach

Analysis of the storm response of a mobile self-elevating offshore drilling platform (nonmat supported) leads one to the conclusion that the portion of the leg within and near the hull is the strength critical portion. Consequently, the philosophy underlying the mathematical modeling of the jackup platform outlined below seeks to simulate accurately the hull-leg interaction. This is accomplished by using a three dimensional beam element model of the platform of sufficient complexity to appraise the actual storm response of the platform. It is noted that any calculated results, whether by slide rule, desk calculator, or large digital computer, are only as good as the assumptions forming the basis of the calculation. Hence, computerized calculations must provide answers which reflect experience and are not just the results of an abstract computation.
Combined Tow Method for Deepwater Pipeline and Riser Installation
Authors: Hellestø Alf Roger , Karunakaran Daniel , Gryttena Trond , Gudmestad Ove Tobias
Published: October 2008

During the last years the number of deepwater oil field developments has increased significantly, resulting in a strong demand for pipe lay vessels. The continuously increasing dayrates of lay vessels is making the combined tow method for deepwater pipelines and riser more competitive. Also a requirement for more sophisticated materials and strict qualification requirements to welded joints, due to sour service and fatigue performance, make the tow method a more preferred solution since the pipeline is fabricated and welded onshore. More than 50 bundles have been installed in the North Sea towed out from the Wick fabrications site located in the northeast of Scotland.

This paper describes a method of towing deep water pipelines and risers, fulfilling both strength and fatigue requirements. The concept incorporates presently available equipment and technology. The proposed method is demonstrated through two case studies presenting the installation of a gas export pipeline at a water depth of 800m and a riser/pipeline string at a water depth of 300m.

Introduction

Pipelines may be installed by the towing techniques where long sections of the line are made up onshore and towed with tug boats to the field. The design procedures for towed or pulled lines are very dependent on the type of tow method chosen. It is also important to control the submerged weight of a towed line to minimize towing forces and at the same time have sufficient weight for stability on the seabed in cross currents.

The combined tow concept reported in this paper incorporate the following tow methods for deep water pipelines and risers:

Figure 1 Controlled depth tow method (available in full paper)The off-bottom tow method (with buoyancy tanks and chains) from the fabrication site to approximately 5km offshore.The CDTM (Controlled Depth Tow Method, Figure 1) from 5km offshore to a temporary location where the buoyancy tanks are removed.The catenary tow method for the deep water tow to the installation site (without buoyancy tanks and chains).

For the off-bottom- and controlled depth tow method, buoyancy steel tanks are mounted at selected intervals. Chains are also mounted at frequent intervals along the pipeline to overcome the excess buoyancy and keep the system stable. During the catenary tow method the buoyancy modules and chains are removed and the submerged weight of the system increases.

Tow Methods

In order to use the tow methods, the pipeline is normally constructed at an onshore site with access to the sea. Once the pipeline sections are welded together to a determined length and hydro tested, the pipe is de-watered and launched into the water by a tow vessel attached to the lead end as seen in Figure 2. Onsite winches are attached to the trail end to ensure back tension and control the launch speed.