bluuebunny/crossref_metadata_2025 huggingface dataset:
Field Test Results of a Rotary Separator Turbine on the Ram/Powell TLP
Authors: Rawlins C.H. , Ross G.D.
Published: October 2008

This paper will present the design of the Rotary Separator Turbine and skid package used in the first offshore field trial of this technology on the Ram/Powell tension leg platform (TLP) located in the Gulf of Mexico. The RST is a compact gas-liquid separation and power generation device designed to operate on process fluid pressure. This technology offers a potential 50% weight and space savings over conventional vessel separators, and is under development for use on minimum footprint facilities. The purpose of the test was to verify the separation and mechanical characteristics in actual production conditions. An integrated test package installed on the Ram/Powell TLP in June 2000 tested the RST on actual well production.

Rotary Separator Turbine

The Rotary Separator Turbine (RST) enables compact and efficient gas-liquid separation while recovering pressure drop energy. The energy provides liquid pressurization, shaft power, or a combination of the two. Separation efficiency of the gas and liquid meets or exceeds the performance of a conventional vessel separator, with substantial weight and volume reduction. Additional benefits of the RST stemming from the centrifugal separation include foam reduction and improvement in operability due to motion insensitivity.

The RST is a product of high velocity two-phase flow research at the Jet Propulsion Laboratory1. During the 1970's and 1980's several prototype turbines were tested in geothermal power applications. A 30" full-scale unit installed in August 1998 at Cerro Prieto, Mexico operates at a power output of 0.5-1 MW.

The first oil and gas application employed the RST as a centrifugal foam breaker for an offshore application. A reaction design RST tested in an onshore gas facility on natural gas/crude mixture provided complete foam breakdown with a liquid carryover of 30 PPM. Further test work in 1996 used a RST for separation of inert gases and crude oil during offshore loading. A pilot plant unit tested on a North Sea shuttle tanker exhibited good separation and performance unaffected by ship motion. A 1997 Joint Industry Programtested a second RST at a major oil and gas flow facility2.

Operating Principle

Figure 1 shows the basic principles of operation with the liquid and gas flow paths. The four main components identified in the diffuser type RST are the two-phase nozzles, rotor drum, gas path blading, and diffuser scoop3.

Two-Phase Nozzles

The inlet nozzles convert the pressure energy of the two-phase flow mixture into kinetic energy. Due to the density difference, the gas phase accelerates more rapidly than the liquid. Shear forces, exerted by the high velocity gas, break up the liquid into small droplets. In turn, the small liquid droplets have a large surface area to mass ratio. This facilitates efficient momentum transfer between the liquid and the gas during the pressure decline, resulting in an even distribution of fine liquid droplets suspended in a continuous gas phase of the exit jet.
Norne-Heidrun: Closing "The Loop" With Diverless Flanged Connections
Authors: Jansen J.O. , Corbetta G. , D'Aloisio G.
Published: October 2008

Subsea completions in deep waters are becoming more and more frequent around the world. This entails the use of innovative technology, remote interventions but, of course, also a constant attention to cost effectiveness to make any possible development a viable one.

As a result of these continuous efforts towards new solutions, Statoil decided in 1999 to focus their attention on the possibility of using flanges as remote connection system. The idea originated from two basic concepts:Flanges have been widely used in the past within the offshore industry, therefore they have got a large track record and are standardized equipment (e.g. ANSI or API);Procurement cost for flanges is low when compared to other type of connectors.

Sonsub proposed to Statoil the use of their newly developed Brutus system as part of the new development in the Norne-Heidrun area. Brutus is a tie-in system capable to tie-in rigid pipeline up to 16" and with minor modification could reach up to 24"; larger sizes are strictly dependent upon specific scenario requirements.

It was Statoil's intention to connect the Norne FPSO to Heidrun TLP and to the 42" Åsgard Transport system through a 16" piggable pipeline system called "The Loop".

With this respect Sonsub were awarded an EPCI contract for the design, fabrication and installation of two subsea manifolds, tie-in spools and relevant protection covers, two In-Line tee protection covers and the installation of the flexible riser to Norne FPSO. The offshore campaign took place in the last quarter of 2000.

This paper presents the project, briefly describe the Brutus system capabilities and give all information on how the operations for "closing" the Norne-Heidrun U-Loop were completed.

Introduction

The objective of the project is to connect two production facilities operated by Statoil on the North Sea (Norne FPSO and Heidrun TLP) with a 16" piggable pipeline system (called "The Loop") in order to export the produced gas towards the 42" Åsgard Transport System. Norne Heidrun Subsea Structure and Tie-in is the name of the project that in September 1999 Statoil decided to award to Sonsub. Statoil specifically decided to trust the use of flanges and gave Sonsub the go ahead on the basis of a competitive economical proposal, which showed that the avoidance of mechanical connectors is in itself a major saving.

This is an EPCI contract which has seen Sonsub for the first time as main contractor for such kind of work, and it has been carried out in co-operation with Saipem and Sasp Offshore Engineering involved in the installation analysis and engineering respectively.

The scope of work includes the Engineering, Fabrication, Testing and Installation of the following subsea structures:Norne Export Riser Base;U-Loop Manifold;Norne and Heidrun In-Line Tees Protection Covers;Norne Expansion Spool, Heidrun Expansion Spool and Åsgard Crossover Spool;GRP Protection covers for the three spools;Subsea Pig Launcher;Blind Flange Removal Tool.
Mooring Analysis of a Truss Spar
Authors: Kristoffersen Guro , Weaver Tim
Published: October 2008

A time domain analysis procedure is used to calculate maximum design tensions for the mooring system of a truss spar. Fairlead motions are used as input to calculate time histories of dynamic mooring line tensions. Several random simulations are used to derive design values of maximum tension. The variability from simulation to simulation in maximum tension and in the dynamic portion of the response is summarized. Alternative methods for estimating the maximum value are compared and the effect of the number of simulations on the uncertainty in the maximum is demonstrated. The dynamic characteristics of the mooring line tensions are examined by looking at the high frequency and low-frequency portions of the response. A comparison of mooring line tensions for a truss spar and a classic spar is also provided. In addition, maximum tensions from the time domain analysis are compared with results from a frequency domain analysis.

Introduction

There are three production spars presently operating in the Gulf of Mexico. Those spars are deep draft, vertical steel cylinders and are referred to as "classic" spars. An alternative configuration is the truss spar, where the ring-stiffened shell of the midsection is replaced by a tubular steel truss (Figure 1). The improved structural efficiency of the truss reduces the weight of the hull, which reduces the cost and fabrication time. In many cases, the drag load on the open truss section is less than for the classic spar. This reduces the mooring line tensions in high current conditions. There are three truss spars presently under construction.

From a global motions perspective, one disadvantage of the truss spar is that there is no longer the large mass of water (both enclosed mass and added mass) associated with the midsection of the classic spar. The added mass and damping of the truss heave plates produces a heave response that is nearly the same as a classic spar. However, the reduction in lateral mass of the truss spar increases the surge/sway highfrequency response. This is because the lateral wave load on the truss spar is essentially the same as it is on a classic spar. Since the mass is less, the high-frequency response in surge/sway will be greater for a truss spar than for a classic spar.

Due to the increased high-frequency motion, it is important to accurately account for line dynamics in designing the mooring system of a truss spar. When using time domain simulations to evaluate maximum response, it is also important to understand the variability in the response and the uncertainty in the estimate of the maximum response.

The results presented herein are for a typical truss spar hull configuration and mooring system. The mooring tensions are also compared with those of a classic spar whose topside capacity and maximum pitch response matches those of the truss spar.
Dynamic Mooring and Fendering System
Authors: Tam W.A.
Published: October 2008

This paper describes a new approach to the problem of docking and mooring ships. This system utilizes momentum transfer-between relatively high pressure stream of water and the sea to draw the tanker to the docking facility and hold it there during the loading operation. The system can either partially or wholly eliminate the requirement for tugs and mooring line depending upon the design basis.

Experimental results are presented for a full size one foot wide section of the dynamic docking device. Predicated upon experimental work done to date a preliminary operational procedure is presented illustrating the techniques used in docking and undocking a ship.

Introduction

An increasingly higher percentage of exploration and development funds are being expended for offshore work. This trend is expected to continue or perhaps accelerate during the next decade. In those cases where the field under development is distant from shore or located in an area where there are no immediate port facilities adequate to handle large tankers, the ability to load out a tanker offshore becomes increasingly attractive from an economic standpoint.

The economics of tanker operations has resulted in a trend toward the mammoth super tanker. Feasibility studies have been completed for a one million DWT-tanker. In many areas a requirement to handle a tanker of 75 to 100'; draft makes the conventional harbor berthing system economically unattractive. Furthermore, while the tanker size has increased, the turnaround time has not increased correspondingly. Consequently the load out rates are truly impressive 100,000 bbl. per hour is not an unusual figure.

When berthing and mooring tankers offshore, the loading and mooring system are exposed to more severe environmental conditions than those normally experienced in sheltered waters. Wind, waves and currents loads are the three principle factors which affect the berthing and mooring operation. All three may have different directions or may act in the same direction. The conditions vary widely from one geographical location to another and must be thoroughly investigated before attempting to design any type of mooring system.
Motion Compensation On Drilling Vessels
Authors: Butler Bryan , Larralde Edward
Published: October 2008

Ten years ago the problem of attenuation of ship heave motion was receiving only scattered attention from the drilling industry, mostly because the offshore oil industry was mainly operating from jack-up rigs in 200 feet of water or less. However, the last five years have seen a rising interest in deep water drilling from floating vessels and the problems associated with heave motion have prompted a number of ideas to be patented for various types of motion compensators. These ideas can be generally divided into three approaches. One approach places the compensating device between the hook and the block. In another, the device is attached to either the fast line or dead line, alternately paying out or taking up line. The third approach moves the crown block. However, because simplified analytical models of such systems indicated difficulties would be encountered; or because of other reasons, most of these ideas remained unused in the patent files. However, a few small units that hung between the block and the hook were built for wire line work in 1965, and later a larger unit operating on the dead line was built by Rucker for the STAFLO. In February, 1970, a motion compensator designed for general drilling operations was invented by E. Larraldel and a small prototype was built by Vetco Offshore Industries. It was tested in June, 1970, in the Santa Barbara Channel. The initial success of the test led the company to make a detailed investigation of the dynamics of the machine. Additional tests were also conducted which led to the design of a larger machine capable of drilling to 20,000 feet. The results of this effort are the substance of this report.

OPERATING FEATURES

The Vetco Motion Compensator is basically a hydraulic-pneumatic device which follows the heaving ship while transmitting very little of this motion to the hook. Basic models of the machine have either a 200 or 300 ton operating capacity and are offered with either a 15 foot or 20 foot stroke capability. Static load capacity is equal to the rated capacity of the derrick and blocks. The basic parts of the motion compensator are shown in Figure 1. Two cylinders are mounted in a frame connected to the traveling block and move up and down with heave motion. Within the cylinders are pistons connected by rods to a framework supporting the hook. The pistons remain relatively stationary with respect to the earth so that as the cylinders move upward with the ship, fluid is driven out, and as they move downward; fluid returns. This active fluid volume from the cylinders is received by piston type accumulators which have fluid on one side and pressurized gas on the other. Incoming fluid drives the accumulator piston against the gas, thus decreasing the gas volume and creating a pressure rise. Likewise, the outgoing fluid will create a pressure drop. The magnitude of the pressure changes is reduced by connecting the accumulators to additional gas vessels known as accumulator back up bottles.
Lift And Drag Forces On A Submerged Circular Cylinder
Authors: Beattie J.F. , Brown L.P. , Webb B.F.
Published: October 2008

Correlations for drag coefficients of circular cylinders in a symmetrical flow field have been available in the technical literature for a number of years. However, correlations for drag coefficients on a circular cylinder adjacent to a plane wall are not available in the literature. In addition to the drag forces, the aforementioned geometry of a cylinder adjacent to a plane results in a lift force on the cylinder due to the induced flow. The correlations for this resultant lift coefficient are also unavailable in literature.

Investigation of the relationships between the various flow and geometric parameters for the case of a full-size (diameters ranging in size from 6 to 30 in.) circular cylinder submerged in a semi-infinite induced flow stream was undertaken in the U. of Tulsa low speed wind tunnel and the U. of Tulsa-Williams Brothers water tunnel. This was accomplished by placing full-size test cylinders adjacent to a flat plate. Data was recorded for the test cylinders in both the vertical and horizontal position. The depth of the semi-infinite flow field was varied depending on the size of the test cylinder to eliminate the hydraulic jump effects.

An empirical correlation of lift coefficients vs Reynolds number and drag coefficients vs Reynolds number were obtained for smooth and rough pipe.

INTRODUCTION

In the design of'; pipelines which traverse the bed of a flowing stream, hydrodynamic lift and drag forces must be considered. Insufficient strength can result in pipeline rupture due to drag. Insufficient weighting can lead to oscillation and fatigue due to lift forces.

Accordingly, an experimental study was undertaken to measure and correlate lift and drag forces. The study was conducted in a water tunnel using pipes ranging in diameter from 6 to 30 in. Pipes were tested in an "as received'; condition and in an artificially roughened condition intended to simulate a concrete jacket.

LABORATORY EQUIPMENT

Equipment utilized during this investigation included the U. of Tulsa water tunnel. The tunnel circulates water through a test section. In order for flow in deep channels to be simulated and to avoid the difficulties involved in constructing and operating a water tunnel with a very deep test section, a vane is provided in the test section simulating a fluid streamline in very deep flow. The effect of the vane, or solid streamline, is to eliminate free surface effects resultant from the placement of the test object in the shallow test section. The tunnel test section with vane is pictured schematically in Fig. 1.

Circulation in the water tunnel is accomplished by means of a stationary propeller driven by an automobile engine.

Tunnel velocities are measured by a pitot tube coupled to a mercury inclined manometer. Test object pressures are measured on a water manometer board.
Potential Studies Of Aluminum Alloys Under DesalinationConditions And Their Relationship to Pilot/Plant,Experience
Authors: Lindberg R.L.
Published: October 2008

Early in the operation of a 50,000-gal/D pilot plant with aluminum heat transfer " surfaces, it became apparent that the electrochemical relationships among aluminum alloys were, radically different than at "normal";" conditions. " As a result, a series of laboratory investigations were undertaken to determine the effect of variables upon solution potential of aluminum alloys, as well as on their corrosion characteristics. Sample size, temperature time to equilibrium, and alloy were among the major variables. Factors such as alloy temper, velocity and pressure were of secondary importance.

Marked excursions of solution potential vs. temperature were, found for all alloys tested. The effect of velocity is small in comparison to the effect of temperature. Sample, size has been found to be a critical factor when relating, lab experience to field observations.

Pilot plant inspection data, obtained aft, er21 months of operation, are compared to laboratory data when such comparisons are possible. Major pilot plant problems encountered. were galvanic in nature. The primary problem was with contact to steel, but less, severe effects were found between aluminum alloys. The data from the lab indicate that present operating limits are most severe, for "aluminum and that an increase or decrease in temperature could reduce galvanic interactions.

Based on both lab and field data, the use of aluminum in desalting appears to be nearing engineering reality.

TEXT

The operation of a 50,000-gal/D multistage flash desalting plant with aluminum heat transfer surfaces indicated that the electrochemical relationships of the alloys" changed markedly at higher temperatures. At temperatures above 180 °F, the sacrificial cladding of alclad alloys was expended so rapidly that alloys suitable for normal seawater are no onger useful. Similarly, anodes used to protect steel evaporator sections were rapidly used up., Galvanic attack to steel was greatly accelerated. Finally, an aluminum-magnesium alloy normally immune to grain boundary precipitation developed this problem under a combination of heat and cold work.

A proposal for a laboratory study of:-the potential vs. temperature relationships of various alloys was made to the Office of Saline Water (OSW). This proposal was limited to studies in recycle brine and product water from the pilot plant. Effects of velocity and oxygen concentration were also to be considered. The proposal was. accepted and became OSW Contract 14-01-0001-2301. This paper describes work done under'; the contract prior to Nov. 1, 1970. The contract was completed Jan. 31, 1971.

Static potential-temperature studies were made in an autoclave depicted schematically in Fig. 1. The autoclave is made of type 304 stainless steel and contains an 8-1 glass vessel in which the test solutions are contained. PVC pipe connects the half cell to the solution. The unit is gas fired with suitable regulators, gauges and safety valves.
Competitive CVAR-FPSO concepts with Dry trees in ultra-deepwater; Weathervaning CVAR-FPSO for Brazil and Indonesia vs. Non-weathervaning for West Africa
Authors: Okamoto Norihiko , Hirayama Hiroaki , Ishida Kozo , Otomo Kazuhisa , Nishigaki Makoto
Published: October 2008

A new FPSO concept termed CVAR-FPSO is under development by a JNOC headed Joint Industry Project (JIP). The concept, using Compliant Vertical Access Risers (CVARs), dry trees, a workover rig, and including the ability to complete and workover wells, offers enormous economic and operational benefits to deepwater oil field development. The JIP introduced the CVAR-FPSO - "OTC 12990 An FPSO with Surface Wells and Workover System in Deepwater" at the OTC2001. The original CVAR-FPSO design for Indonesia and Brazil allows weathervane with a turret, fluid transfer system, and riser centering system, which are the most expensive facilities of the FPSO. However, the CVAR-FPSO doesn't require these expensive facilities in West Africa, because a spread mooring system works without weathervaning there. Hence, CVAR-FPSO with CVAR, a spread mooring system and a skidding W.O. rig delivers much more practical and economical performances in West Africa. The central attribute of the CVAR-FPSO is the use of CVARs. These compliant but rigid risers connect wells from the seafloor to the dry trees mounted on the FPSO, and the compliancy can compensate for vessel motion. The CVAR, being vertical access to the wells, also allows completion and workover operations to be performed from the FPSO. The field development concept involves the drilling and temporary abandonment of wells by a MODU. The CVAR-FPSO is then moved onto location. CVARs are installed, and wells are completed from the CVAR-FPSO.

CVAR-FPSO would be more economical and practical with the following system; weathervane system in Indonesia and Brazil, and non-weathervane system in West Africa.

1. Introduction

The JIP introduced the original CVAR-FPSO design which allows weathervane with a turret, fluid transfer system, and riser centering system (we call it CVAR-FPSO I afterward). Here, we introduce CVAR-FPSO with CVARs, a spread mooring and rig skidding (we call it CVAR-FPSO II afterward). CVAR-FPSO I works in Indonesia and Brazil, while CVAR-FPSO II works in West Africa. Each Figure. 1 and Figure 2 shows CVAR-FPSO I and II. Background of introduction of the CVAR-FPSOs is the following.

An FPSO has become a widely used oil production platform worldwide, being used in many different seas, for many different reservoir types. This wide range of applications is due to the inherent benefits of the system, including the ability to produce, store, offload, the ease of adaptability to different reservoir and sea conditions, re-usability, applicability as Extended Well Test (EWT) or Early Production System (EPS) and relatively short system implementation lead times.

However, current FPSO implementations have disadvantages, as all use subsea completions, connected to the FPSO via a turret or buoy. Subsea completions are more complex and expensive than surface completions, with wellknown reliability issues.
Nonlinear Dynamic Response Of Offshore Structures
Authors: Selna Lawrence G. , Cho M. David
Published: October 2008

The problem discussed concerns the dynamic response of offshore bottom supported structures to the action of periodic deep water waves when yielding is considered in the structure. Results of mathematical studies show that unbounded response can occur after several near-breaking waves have passed a typical offshore structure. Also, the predicted response of a structure, which is considered to, yield, is significantly affected by the number of degrees of freedom considered in the idealization.

INTRODUCTION

Background

Ocean structure engineers have recently been concerned with the design of offshore tower structures for dynamic behavior. Pursuant to the design procedure, knowledge of the dynamic loads and structural behavior is necessary. The research concerned with the loading on these structures has been pertinent and of high quality. It is surprising that very few tudies have been started with the purpose of finding basic structural behavior, viz. deformation patterns or even failure regimes. The basic simulation has not been made for the case where materials in the structure exceed the elastic limit.

The relationship of force on structures to fluid motion due to free gravity waves - considered to be a design load case-has received a great deal of attention (1,2,3,4). Large amounts of experimental data on wave forces have been gathered for shallow water cases where structural motions are small. Unfortunately no data has been gathered for cases where there is structural dynamic wave interaction type response.

Theoretical studies have frequently(2,3,S) sought to characterize wave forces using statistical methods. The following comments extracted from Ref.(2) are pertinent: " ... The statistical techniques ... neglect the time sequence of the phenomena as they assume the random phase. Thus, one entire class of information is often thrown away in the analysis of waves. From an engineering standpoint, it is the groups of several periodic waves, which are almost always the highest waves in the wave system, that are most effective in causing structural damage..." These comments are unfortunate because the statistical method makes a valuable contribution to wave force evaluation by characterizing the spectrum of the water surface elevation(6). Clearly a reconciliation of views between the deterministic wave train and surface spectrum approaches is needed.

Other studies on wave forces were concerned with effects of structural motions on the forces. The governing equation, originally developed by Morison, et. al.(l), has Deen generalized so that relative fluid velocities and accelerations are related to force on the structure (7,8). In certain cases these modifications will significantly alter the predicted results. Experimental verification of these proposed modifications is needed.

Perhaps the most comprehensive representation of structural behavior during application of wave forces was attempted by Edge and Mayer(9). This linear mathematical model was structured to include effects of soil and waves on the tower.
Composite Choke and Kill Lines
Authors: Johnson Douglas B. , Baldwin Donald D.
Published: October 2008

Replacement of existing steel choke and kill lines on a drilling riser string with composite lines will result in weight savings that will allow third generation mobile offshore drilling units to operate in 6,000 feet of water depth without undergoing major upgrades. The design and analysis, fabrication and qualification testing of high pressure (15,000 psi) composite choke and kill lines is discussed. The objective is to develop a low-cost composite design of reliability equivalent to that of existing metal systems.

Introduction

Replacement of the steel choke and kill lines on a standard drilling riser string with composite tubulars will result in a 15%-20% weight saving. Table 1 is a weight comparison of a typical 4.5" steel choke and kill line with a comparable composite line. This straightforward substitution would allow a third generation mobile offshore drilling unit (MODU) to operate in water depths as great as 6,000 feet without major upgrades. One of the limiting factors in taking a MODU out into deepwater and ultra-deepwater is the deckload capacity of the vessel. Mooring lines, riser joints, hook, and variable loads all contribute to this weight. A variety of other limitations require third generation semisubmersibles to undergo major upgrades before they can operate in water depths as great as 6,000 feet.

For composite lines to be widely accepted, they must be designed to be 100% interchangeable with existing steel lines, with no modifications required to the riser pipe body, flange, brackets or buoyancy modules. When installed on a steel main riser pipe and flange joint, these composite lines create a hybrid drilling riser system. Such hybrid riser joints would then be completely interchangeable with the all-steel riser joints of a deepwater riser system.

The market focus for a hybrid riser system is very specific. The drilling and production units being targeted are those third generation rigs on the edge of deepwater that want to be able to drill in 6,000 feet of water without undergoing major upgrades. The use of hybrid riser joints will lighten deckload, hookload and craning requirements for these MODU"s. Equally important is the reduction in the volume of syntactic foam buoyancy needed to support the riser joints underwater. Foam modules with a smaller outside diameter can be used, allowing the hybrid riser to be run by many of the vessels operating on the fringe of deepwater which still have 49.5- inch rotary tables. Another advantage to the use of smaller diameter buoyancy is the narrower profile of the riser string in the water, which reduces the drag forces of the sea currents.

Composite Choke and Kill Line Requirements

The API specification for choke and kill systems (Ref. 1) states that: "Choke and Kill Lines are an integral part of the surface blowout prevention equipment required for well control. The kill line provides a means of pumping fluid into the well bore when normal circulation through the drill string cannot be employed.
Malampaya Deep Water Gas-to-Power Project: Onshore Gas Plant Value Engineering and Flawless Start Up
Authors: Reymert D.
Published: October 2008

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

The Malampaya Onshore Gas Plant (OGP) at Batangas is a vital part of the overall Shell Philippines Exploration B.V. (SPEX) Malampaya Deep Water Gas-to-Power Development. The plant design and execution schedule was from the outset extremely tight, mainly due to uncertainties during the definition stage on the exact requirements for H2S removal. Consequently, the project awarded the main Engineering Procurement and Construction (EPC) contract ahead of final design optimisation.

To ensure an optimised design and to reduce cost without scarifying the functional requirements, the project executed a Value Engineering exercise prior to start of detail design. The exercise not only resulted in a reduction of overall cost of20%, it also produced a better design.

In addition to discussing the benefits gained through the Value Engineering process, this paper will address the fast track nature of the Project and the application of the conceptof Flawless Start-Up to meet the tight schedule. This involved the necessary up front work in detailed engineering, procurement and construction, as well as commissioning, start up planning and risk analysis to support a short and trouble free start up.

The paper also addresses key aspect of HSE management in construction and start up for this green field project in Batangas, Philippines. The OGP executed some 11.3 manhours without a Lost Time Incident (LTI) utilising mainly local, in most cases unskilled, labour. The project was also certified to ISO 14001 from start of construction and through until start up and full operation.

Introduction

The OGP facilities are designed to take the sour dehydrated gas from the Malampaya gas export pipeline, which lands at Batangas and process up to 500 MMscf/d of natural gas. The treated gas feeds three power stations with a cumulative capacity of 2700 MW of electric power for domestic consumption (Fig. 1).

The OGP is designed to remove up to 1000 ppm H2S from the gas, using an amine process and deliver specification gas(less than 20 ppm H2S) to the customers. The facility also includes fiscal metering for the three customers, a sulphur recovery unit and various utilities. The plant has two process trains with common inlet and outlet facilities.
Introducing the AUUV: An Autonomous Underwater Utility Vehicle
Authors: Sonnier Carl
Published: October 2008

The unprecedented partnership of Boeing, Fugro and Oceaneering has resulted in the development of an AUV incorporating many unique features. This paper introduces this new AUV, its modular payload and its extended weather launch and recovery system.

With AUVs finally approaching commercial viability, they are expected to be the tool of choice for deep water site and corridor (route) surveys providing improved productivity, reduced cost and the ability to survey in areas previouslyinaccessible.

This paper presents an overview, comparing productivity, sensor quality and positioning accuracy of the new AUV with a deep tow system using identical sensors.

Introduction

At the Underwater Intervention Conference of 2001, Boeing, Fugro and Oceaneering announced a joint effort to field a commercially viable AUV within a year. That year is approaching an end and the AUV is now in Sea Trials.

At the start of this program we were confident that AUVs could collect excellent data on par with Fugro's DeepTow II and do so much faster than deep towed systems. The partnership was formed to address poor reliability of commercial AUVs, weather-limited launch & recovery systems that often required deployment of a small boat to effect recovery, and to achieve full autonomous operation with the required navigation accuracy.

The teaming of a survey company with an ROV engineering company along with a military contractor, as unusual as it sounds was a natural given our goals for the AUV. Boeing brought to the effort experience with autonomous vehicles where reliability and true autonomous navigation were normal mission objectives. Oceaneering took on the task of building an all weather solution for AUV launch and recovery. Fugro brings to the partnership its extensive experience with deep water surveys, its positioning systems and its knowledge of remote sensing.

The intent of this paper is to focus on the unique aspects of this new AUV and how these bring us closer to the goal of conducting routine surveys with AUVs.

Background

AUVs are just another platform to carry sensors underwater. For survey, the typical sensor package includes a sidescan sonar (SSS) a sub-bottom profiler (SBP) and a multibeam swath bathymetry system (MB). The sidescan system provides a map of the acoustic reflectivity of the seafloor to either side of the tool. The swath bathymetry system provides the depths of the seafloor to either side of the tool and the subbottom profiler penetrates the seafloor directly beneath the tool to image the sediment layers.

Alternative Sensor Platforms.

In this section, we will compare alternatives to the AUV for deep water surveys and discuss the advantages and disadvantages.

Near Surface Sensors.

Near surface sensor platforms include vessels with hull mounted multibeam systems, shallow towed sidescan and bathymetric systems along with the use of 3-D seismic data. All of these near surface sensors share the advantages of wide swath and fast speed of data acquisition. They also all share limited resolution.
Ceiba Field Subsea Architecture Design and Installation
Authors: Davidson Bruce W.
Published: October 2008

The Ceiba Field, Offshore Equatorial Guinea was a fast track phased development with Deepwater Features and Innovations. In order to meet Triton Equatorial Guinea Inc. (acquired by Amerada Hess Corporation in August 2001), aggressive schedule of 14 months from discovery to first oil for Phase 1, development of a seamless project team was critical. After confirmation from drilling of prolific resevoirs and ideal conditions, contracts were awarded to key contractors whom besides having experience with Project Management on deepwater developments exhibited the right attitude for this challenging project. This paper describes the events of this significant achievement and the technical challenges and innovative solutions associated with installation of the subsea architecture.

Introduction

The Challenges:Fast track phased development-14 months from discovery to first oilVery tight procurement and fabrication schedulesInnovative technology-Subsea based riser structure versus traditional arches - Deepwater freespan rectification-Flexible jumpers versus rigid jumpersMultiple interfacesWater depth from 95m at FPSO to 750m at the wellheadsLong step-out distancesA large number of wells, with 40 risers required in total for full field developmentHigh risk of congestion between criss-crossing risers, pipelines and umbilicalsSeabottom topography reflecting steep slopes, ravines and Freespans

A Systematic Approach is presented Showing:Definition of the scope of work and development ofspecifications to suit the Ceiba FieldEstablishment of, via early brain storming meetings, interface issues, defining the problems and finding the technical solutionsThe importance of detailed planning showing the various interfaces and determining the critical path for the projectEstablishment of communication procedures and trust leading to successful execution of the project objectivesAdaptation of off-the-self deepwater technology to achieve immediate production goals and to facilitate continuationof full field developmentOptimization of the local services (fabrication yards, marine bases, and offshore equipment)Creation of flexibility in the operational schedule by utilizing multipurpose resources

Subsea Architecture Design and Installation

One of the most technically challenging portions of the Ceiba project was the installation of the subsea flowlines, umbilicals and manifolds from each of 4 subsea wells that formed the EPS phase of the project. Triton selected Stolt Offshore. The two companies worked closely to develop the frame work for this fast track project. This included innovative designs and procedures, refine design basis, select qualified material suppliers and prepare the Master Schedule identifying the critical path for the project. The first-oil timing objectives meant that the design basis, scope of work, specifications, interfaces (drilling, subsea hardware supplier and FPSO owner), material procurement and offshore vessel allocations would need to be defined in detail and well managed.
LNG FPSO Based on Spherical Tanks
Authors: Wadahl Anders , Christiansen Per
Published: October 2008

During the last years, the interest in LNG FPSO's has been revived. One of the challenges in designing a LNG FPSO is the liquid sloshing in partial filled tanks. One of the unique features of the spherical tank is that it is certified for operation with part filling to any level. It is therefore well suited as containment system for floating LNG production units.

The spherical tank was developed as a containment system for LNG carriers more than 30 years ago. The tank is essentially a shell supported by a cylindrical skirt through a patented transition joint. The spherical shape results in membrane type operational stresses and bending moments are limited to the transition area where they are carefully controlled. The tanks are today constructed entirely of aluminum by specialized shipyards around the world. The spherical LNG tank is installed in close to 70 LNG carriers, some of which are nearly 30 years old and have recently been certified for another 20 years service. All vessels built are still in service today and no serious incidents directly attributed to the tank construction have ever been reported.

Through a number of studies for major oil companies we have acquired a solid database and a good overview of the technical and economical challenges which must be met and the safety requirements that have to be adressed. This paper will outline the unique features of a floating LNG production facility based on the spherical tank system. It will be shown how the overall safety is enhanced through the use of the spherical tank and how it can be adapted to suit requirements for harsh as well as mild weather conditions, different production capacities and feed compositions.

INTRODUCTION

Although having been the subject of numerous concept studies and proposals for the last years, the idea of LNG production on a floating structure is by no means new. In the mid-to late 1970's a LNG FPSO was offered to Iran for the Kangan field. A full basic engineering design including comprehensive safety assessments was carried out and Det Norske Veritas prepared a Rule Proposal. The unit consisted of 6 spherical LNG tanks and a 2-train APCI process in a steel hull. The hull was weathervaning on a single point mooring and the unit had a LNG production capacity of 2,8 MMTPA and a storage capacity of 165 000 m3.

Complete front-end engineering was carried out for this project including comprehensive risk assessment. The project was terminated for political reasons. The main features of the Kangan LNG FPSO are shown in Figure 1.

Figure 1 - General arrangement and main features of the Kangan LNG FPSO(Available in full paper)

Since then, a number of concept studies have been done for oil companies on the same subject. However, recently these activities have become more and more frequent due to thegeneral interest throughout the LNG industry.
Vector Fidelity in Ocean Bottom Seismic Systems
Authors: Berg E.W. , Rykkelid J.I. , Woje G. , Svendsen Ø.
Published: October 2008

Through accurate large-scale test experiments, direct comparisons of node and cable-based sensor responses have been performed. Though short conceptual cables were used, significant differences in the vector responses of the two types of sensors were shown. The vector fidelity of the nodes is very good, whereas for the cables, it is not. The vector fidelity of the nodes is also confirmed by data acquired offshore. Regarding studies of anisotropy effects and the low frequency content of PS converted data, the cable effects observed on the first break and PS reflected data have also been observed on commercial systems.

Introduction

The potential of using converted (PS) waves to image through a gas chimney was demonstrated for the first time in 1994 by Berg et al. [1]. Since then, the importance of converted waves and the need for proper equipment to record such shear waves, have been proven time and again. Nowadays, several largescale offshore 4C-3D surveys are performed every year. Both the oil and the service companies agree that in many cases, high quality 4C-3D data are necessary to meet the mapping objectives predicted by using the 4C methods.

As converted waves cannot be transmitted through water, the sensors have to be put on the seafloor. This poses several new challenges. Obviously, it is not as simple as for surface surveys, where the survey vessels simply tow long streamers. To record shear wave data correctly, the sensors will have to be well coupled to the seabed. Furthermore, the irregularities of the seafloor may make it impossible to put sensors on a straight line. Some locations may have a fragile seabed (for instance coral reefs) where special care must be taken when placing the sensors. Finally, as converted waves convey a direction of movement, the sensors must record this information correctly. Accurate measurement of this direction of movement is what we call vector fidelity.

A set of test results will show weaknesses and benefits of a couple of common sensor strategies regarding their vector fidelity. Basically, one might divide the sensors into those that are cable-based and those that are node-based. The vector fidelity will be tested, and its significance will be evaluated.

Theory and Definitions

A couple of definitions and ways to test for vector fidelity are given.

Vector fidelity.

Mjaaland et al. [2]: Vector fidelity is defined as that property of multi component seismic receivers wherein a given particle motion impulse applied parallel to one of the components registers only on that component, and wherein the same impulse applied parallel to the other components give the same response, so that the various components can be combined according to the rules of vector algebra.

Node.

A node is the underwater equivalent of a land geophone. In addition, a node usually consists of a hydrophone as well. The node has a skirt to achieve good coupling, and the connecting wires should be so light and flexible that they don't have any significant influence on the response of the sensors.
Design, Manufacture, and Installation of the Typhoon Project Flowlines
Authors: Roseboom Kenneth W. , Kaplan Keith B. , Sawyer Martin A. , Lecomte Hubert , Hogben Stan
Published: October 2008

The Typhoon Field development required 9,000 psi MAWP flowlines from the four subsea wells to the TLP. An overview is presented of the design, manufacturing and installation of these four flexible flowlines. The flowline design required the use of insulation for flow assurance, start-up fluid considerations in the carcass metallurgy, and tensile and armor wire design for the testing and operation conditions. Because the design temperature caused aging concern for the Polyamide-11 (PA-11) pressure sheath, additional manufacturing requirements were placed on this flexible pipe component. Additional testing and inspection was also performed due to the high-pressure application. A flowline and associated umbilical installation overview highlights the use of diverless bend restrictor to I-tube connectors, brine filled flowlines for start-up hydrate inhibition, wellhead Staband-Hinge-Over connections, subsea heat exchanger installation, and installation sequence considerations. Lessons learned from this project scope are presented.

Overview

The Typhoon Field is in Green Canyon Block 236 and 237 in approximately 2,100-ft water depth. Equity is fixed at 50% Chevron and 50% BHP Billiton, with Chevron the designated operator. The discovery well was drilled in April 1998. The Typhoon Project was sanctioned in January 2000 for the development of 4 subsea wells produced to a centrally located TLP. First oil was achieved from the field on July 29, 2001. All four wells were on production at full rate by August 16, 2001, which was 54 days after the installation of the TLP.

Design

Design Basis.

The flowline design was based on a well shut in tubing pressure (SITP) of 9,000 psi. The flowlines for the field connect 4 subsea wells offset from 3,000 ft. to 9,800 ft. to a TLP centrally located in the field. Design maximum flowrates were up to 22,000 BOPD for the most productive well in the field. The wax appearance temperature was 82 °F. Because the wells were centrally located with relatively short offsets and wax plugging was not thought to be a major concern, a single flowline for each well was determined to be adequate. Flowline routing was required to avoid a methane gas vent area and possible chemosynthetic community area(Figs. 1, 2 & 3).

Of concern in the design requirements were the well head temperatures. The temperature forecast for the hottest well in the field, the GC237 No. 2 well, was for an initial wellhead temperature of 184 °F. For flow assurance reasons the overall heat transfer coefficient for the pipe was required to be 1.7 BTU/hr-ftÂ2-°F.

The flowline design was specifically engineered for the Typhoon field conditions. Although the well lives were expected to be less than 7 years, the fatigue and corrosion design was based on a 20 year design life requirement. The design life for the pressure sheath layer in the flexible pipe was allowed to be 10 years based on the maximum expected heat content from the flow stream.