bluuebunny/crossref_metadata_2025 huggingface dataset:
LNG Trials of a New 16' Flexible Hose Based LNG Transfer System
Authors: Rombaut Guillaume , Peigne Alain , Loisel Philippe , Le Cloirec Alain , Machouat Fatima , Maocec David
Published: October 2008

The development of offshore LNG projects, whether for sheltered or harsh environments, represents a vehicle for progress consistent with the LNG market growth and it opens new perspectives and new challenges for the whole LNG Industry. In order to ensure that these new LNG chains will operate correctly and at an optimum rate, the development of an efficient and safe LNG transfer system is a key link, which is still challenging the actors involved in this field.

Since there are several offshore LNG transfer solutions in development, cryogenic flexible hose based LNG transfer systems appear to be able to meet the LNG Industry requirements.

However, in order to demonstrate that a new technology will operate reliably within specific limits, LNG operators generally deem necessary to have either the evidence of such performances through a structured qualification process or to be convinced by significant scale trials in real conditions or close to the ones the system will be used in.

This paper deals with full-scale LNG trials performed in the context of an exiting LNG receiving terminal of a new 16" flexible hose based LNG transfer system designed for onshore and offshore conditions. These trials were the ultimate stage of an industrial qualification of this transfer system and they have been carried out on a unique dynamic test bench able to reproduce open sea conditions in terms of heave amplitude and acceleration.

Introduction

The development of offshore LNG projects is partly based on the ability of LNG industry actors to bring innovative solutions capable of meeting the new technical requirements related to the marine environment. Whether for LNG export or receiving facilities, it appears that the " transfer system?? link is a key element, whose ability to fulfil its role in open sea conditions must contribute to guarantee the availability and flexibility of these new offshore LNG chains.

Gaz de France has undertaken, in partnership with Technip France, KSB and Eurodim, the last stage of industrial qualification of a new LNG transfer system called Amplitude-LNG Loading System (ALLS). This system, based on flexible hose technology and suitable for offshore and onshore conditions, was developed through industrial partnerships involving major oil and gas companies and international certification organizations.

After completion of the technical certification of ALLS main equipment, the requirement to carry out full-scale dynamic testing, with circulation of LNG, was deemed necessary by the LNG operators to demonstrate the performances, operability and safety of this innovative LNG transfer system.

A structured qualification process, managed by Det Norske Veritas (DNV), was then engaged and a full-scale testing programme elaborated with the aim to operate the transfer system in operational conditions with a facility able to reproduce open sea conditions.
Fatigue in Deepwater Steel Catenary Risers: A Probalistic Approach for Assessment of Risk
Authors: Sen Tapan K.
Published: October 2008

Deep water developments are being pursued vigorously in various parts of the world (West Coast of Africa, Gulf of Mexico etc.). The riser system is a critical part of the field architecture. Riser failure results in reduction or cessation of revenue. It may also lead to spillage or pollution and could endanger lives. Hence, riser design must carry a high degree of reliability.

Steel Catenary Risers (SCRs) are considered to be technically feasible and commercially efficient solutions especially when high temperatures and pressures are involved. However, in terms of fatigue, SCRs are very sensitive to environmental loading.

The procedure for fatigue analysis is essentially deterministic.

This paper concentrates on the probability of fatigue failure associated with the design of current practice of fatigue analysis of SCRs. The procedure is illustrated with sample calculations with first order vessel motion and a flow chart for assessing the probability of fatigue failure is also given. The example is chosen so as to highlight the issues involved. The probability of failure is used to determine the ‘safety index’. The probability calculations have been reformulated so that they are applicable for the design of SCRs. The probability of fatigue failure, associated with the recommended factor of safety in API RP 2RD, for the example chosen, is also reported. The overall aim is to increase the confidence in the design of such systems in deep water environment.

1.0 Introduction

A typical SCR attached to a Floating Production Storage & Offloading (FPSO) vessel and part of a deep water field development is shown in Fig. 1. The riser is continuously subject to oscillatory environmental loads. The principal source of structural loading is the ocean waves that impact the riser coupled with the complicated movements of the vessel which itself comprise high frequency response to the waves and low frequency (slow drift) excursion. This paper is concerned with wave induced fatigue only. Stresses resulting from environmental loading and corresponding structural dynamic response at a joint (node) are typically random in nature, as shown in Fig. 2. Metal fatigue in the weld at the joint, due to these oscillatory stresses, is one of the likely causes of failure.

Most vulnerable to fatigue are the welded joints near the touch down point (see Fig. 1) because of high cyclic bending stresses and stress concentration due to both joint geometry and weld defects.

Fatigue life prediction in SCRs is a complicated process involving many factors and has been discussed at length by Campbell (1999). Current practice, mainly deterministic in nature is summarised first.
Seabed Umbilical Stability Analysis
Authors: Hossain Mohammad Kabir , Tjok Ko-Min , Nobahar Arash
Published: October 2008

Subsea umbilicals are widely used as an essential component in offshore oil and gas recovery and production facilities to transport chemicals, hydraulic fluids and electrical power and signals. The umbilical layout on the seafloor usually has a straight section near the riser touch-down-point (TDP) connected to a floating unit, followed by curved sections further beyond on the seabed. The heave motions of the floating unit at the sea surface due to environmental loading can induce cyclic tension loads on the umbilical at the seafloor and move the TDP location, resulting into axial, lateral and vertical motions along the umbilical. In addition to altering available umbilical embedded length this can also alter the field layout and may constitute violation of the design assumptions. This paper describes the results of a parametric analysis of an umbilical static stability with curved and straight sections, in a deepwater Gulf of Mexico seafloor environment, using finite element method (FEM). The finite element model of the umbilical and the surrounding soil was constructed using thin-walled, pipe elements and non-linear springs, respectively. Both, soil resistance to axial and to lateral motions along the umbilical were modeled. Degradation of soil shear strength due to cyclic loading was considered. Umbilical responses to increasing bottom tension loading at the TDP for a selected set of embedment, axial stiffness, radii and lengths of curved sections were examined and the axial and lateral displacements along the length of the umbilical are presented. Based on the results of the parametric analysis, a simple procedure for estimation of umbilical ultimate bottom tension load is presented.

Introduction

A parametric study on the stability of a subsea umbilical was performed and the response characteristics of the umbilical to increasing bottom tension loads were investigated. The effects of the following parameters were studied: umbilical layout and embedment, and umbilical axial stiffness. In this paper, the results of the parametric study and the procedures used in the analyses are presented.

A schematic illustration of a subsea umbilical layout and its embedment is presented in Figure 1. The primary umbilical layout components are: the straight section from the TDP to the start of the curved section (L), the radius of the curved section (R), and the angle of the curved section (f). Umbilical embedment depth into the seabed (H) is shown as a ratio (k) of its diameter (D). The bottom tension load (F) is applied at the TDP.
The Impact of the Use of the Full QTF on LNG Moored in Shallow Water
Authors: Brun Cedric , Naciri Mamoun , Rezende Flavia Caldi , Mombaerts Johan
Published: October 2008

The prediction of slow drift motions for the design of a mooring system is usually made using the Newman approximation [1], based on the assumption of a very low resonance frequency of the system and small contribution of the second order wave fields. This hypothesis is commonly satisfied for most parts of the mooring systems in deep water. However, this is not the case for LNG terminals moored in shallow water.

Unlike the Newman approximation, the FullQTF formulation to compute the low frequency wave loads is more accurate but requires much longer time of computation, which presents limitations in practice when a large quantity of simulations is needed.

Further to the work presented in [2] on the quadratic transfer function (QTF) of low-frequency loading, a new approximation has been developed in [3]. The F1 approximation gives comparable results to the FullQTF and presents the interesting aspect that the loads time series can be reconstructed by means of simple summations, presenting the same efficiency in computation time as Newman approximation.

In this paper, main parameters of mooring systems are analyzed to evaluate the impact of the choice of each method, Newman, F1 or FullQTF. Indeed, this choice is a compromise between calculation time and accuracy of results. The conclusions raised are underlined in the study of an LNG terminal.
Mature Offshore Fields Rejuvenation Via Long Reach Wells and Massive Hydraulic Fracturing: the Kitina Case History
Authors: Tealdi Loris , Rampoldi Maurizio , Casero Alberto , Malonga Henri , Okassa Fabrice , Baioni Antonio , Obondoko Gaston , Itoua-Konga Félix , Isella Davide , Baldini Davide , Riccobon Leone , Pounga Francois
Published: October 2008

Many West Africa Offshore Fields are maturing and operators are completing secondary targets in their wells to maintain the economic operation of their valuable assets. However, the capital expenditure associated to this kind of interventions of critical importance. It follows that the selection of the right and most remunerative well activities is crucial.

In the Kitina Field, offshore from Pointe Noire, Congo, deeper sands have been produced to economic depletion and reservoir studies allowed the determination of alternative production intervals for production maintenance. Large quantities of reserves can be found in low permeability, consolidated, formations as well as in very deep and remote culminations.

From March 2007 to June 2007, the Kitina field production increased of 80% reaching a production level lost since early 2004. This was achieved by infilling the Kitina South culmination with the long reach and ultra deep well KTM-SM5 and via a massive multistage hydraulic fracturing campaign carried out on the three wells draining the low permeability 3A reservoir. These represented the first applications in Congo of such technology. Eight hydraulic propped fractures were placed in three re-completed, cased-hole wells in the with very encouraging production improvements. A stabilized production increase ranging from 2 to 3 times was achieved.

The paper describes the unique reservoir modeling, operation geology, and drilling, completion and production challenges encountered in the 2007 Kitina successful rejuvenation campaign. In particular, it focuses on the successful multi-stage hydraulic fracture campaign carried out on four wells of the Kitina 3A reservoir from the preliminary design and production forecast pre-job to the reservoir model history match and forecast phase post-job.

Introduction

The Kitina Marine, Congolese offshore field, has been discovered through the exploration well KTNM-1 in 1991. Two appraisal wells were drilled later on which confirmed the discovery. The field's production starts up took place in December 14th 1997 via 13 wells (8 oil producers and 5 potentially water injectors).

The Kitina field is composed by the following 5 levels:3A - limestone, sandstone with silty clay2A - Limestone: Oolitic Grainstone/Packstone, bioclastic with good intergranular porosity and intercalation of sandstone with carbonate cement.2A South Culmination: Oolitic Grainstone/Packstone, bioclastic with good intergranular porosity and intercalation of sandstone with carbonate cement.1A - Sandstone with carbonate cement and limestone.1B - Sandstone with carbonate cement and limestone
Kikeh Development: Delivering World Class Completion Performance
Authors: Webb Tamara , Selamat Kasim , Omar Norjusni F. , Desormeaux Rusty Andrew , Moran Patrick M.
Published: October 2008

The Kikeh Development is the first major deepwater project in Malaysia, located offshore Sabah in 1,320m water depth. This 34 well oil development includes Dry Tree Unit (Spar) and subsea producers as well as gas and water injectors.

The Kikeh Field architecture, as well as its subsurface characteristics, required many different completion types to meet the project goals. Early wellbore construction design and rig selection focused on performance while still achieving subsurface strategic requirements. Throughout the design and implementation, many challenges were met in upscaling suppliers to meet deepwater completion needs and managing multiple external interfaces. Great emphasis was placed on working as many activities as possible offline. In addition, lessons learned were captured and implemented immediately, thereby shortening the learning curve impact.

This paper will discuss how these early decisions benefited long-term performance and will describe the grassroots effort for deepwater completion implementation in a new region of the world. Lastly, focus will be on the completion performance, including time, non-productive time and skin describing methodology and techniques used to deliver the Kikeh Development with world-class time and skin results.

INTRODUCTION

The Kikeh Field architecture consists primarily of a Dry Tree Unit (Spar), three subsea manifold sites, FPSO and a pipeline system. The wells include 16 subsea wells and 18 dry trees which were drilled and completed by two different rig types. The field's wells and facilities are designed for peak production and injection rates of 120,000 BOPD and 260,000 BWPD respectively. Figure 1 is an illustration of the field layout and its components.

Completion operations play a major role in the overall Kikeh deepwater development with 25 percent of the total field development CAPEX and 58 percent of the well CAPEX attributed to the well completions. In addition, aggressive production and injectivity skin targets were set as the development thresholds to successfully achieve peak targets. At various levels, the completion design and execution interfaced with each of the facility components and was driven extensively by the subsurface characteristics to optimize production, injection and reserve recovery. The following subject matter discusses the steps taken from design through field execution that were the basis for achieving remarkable results at Kikeh.
Offshore Concrete Structures By Hydraulic Aspects
Authors: Torum Alf , Larsen Per K. , Hafskjold P.S.
Published: October 2008

If large enough, a gravity structure in reinforced concrete will have no problems in overall safety.

Reduction of the dimensions, however, may change this picture. This became evident to Ingenior F. SELMER A/S when modifications of the company's large offshore platform 'design - of 1970 - to more moderate units began. An extensive test program was therefore initiated at the River and Harbour Laboratory (VHL) at the Norwegian Institute of Technology, Trondheim.

The research work was mainly concentrated on wave forces, but other hydraulic aspects relate to bottom mounted concrete structures - such as the effect of shock waves, wave damping devices and scour -are also discussed.

1. INTRODUCTION

Based upon long experience and great confidence in reinforced concrete, a very large platform project for the North Sea was forwarded to the Norwegian authorities in August 1970 by Ingenior F. SELMER A/S. Reference is made to [1] for the background of the design and a ore detailed description than is given here:

Figure 1 shows the basic principles - these include a monolithic raft foundation of circular cells - diameter 20 m - with a system of cutting edges protruding 4 to 5 meters below the bottom slab. From the caisson top - 15 meters below sea level - columns carry the platform and serve as wave dampers as well. The platform would have sides of 300 meters length, giving an area of more than 10 acres.

The intention was to collect many activities on one large, safe base to replace structures scattered over a wider area, thus being more hazardous to navigation as well as more vulnerable individually to the impact.

On a gravity structure sufficiently large in relation to the wave length, the wave loads will the of relatively little significance; but as dimensions decrease, wave loads grow more and more important.

Sea bottoms to which gravity structures are applicable are often also vulnerable to scour. At large structures local scour can usually be counter acted in time, at smaller ones the situation may be more serious.

Problems and risks usually increase as the dimensions of gravity structures decrease. For ordinary steel piling structures the opposite is the case.

Consequently the competition between steel and concrete structures may not lead to the optimum field design if the general lay-out has been- based too rigorously on one type or the other.

The advantage of combining two or more ordinary platforms on a single, large concrete raft should especially be Kept in mind since it opens the possibility of a very inexpensive extention of platform area.

2. WAVE FORCES ON LARGE VOLUME STRUCTURES

The calculation. of wave forces. on large volume structures, e.g. structures where drag effects are of no importance has followed two approaches. The first approach is to use a quasistatic approach introducing force coefficients This approach requires measurement of forces on a model or a prototype-structure to determine these coefficients [1], [2].
Kikeh Development: Design of the World's 1st Gravity Actuated Pipe (GAP) Fluid Transfer System
Authors: Brown Paul , Rooduijn Erik , Lemoel Marc Guy , Stone Geoff , McFadyen Michael Keith
Published: October 2008

The Kikeh Field is located offshore Malaysia in the South China Sea in a water depth of 1320 m. This field development is based on a Floating Production Storage and Offloading unit (FPSO) and a Dry Tree Unit (Spar). Fluids between Spar and FPSO are transported in Fluid Transfer Lines (FTL) based on the first ever application of the patented Gravity Actuated Pipe (GAP) system.

This paper presents an overview of the FTL GAP project for the Kikeh development, which was awarded to Delcom / SBM under an EPCIC contract in April 2005. This paper provides a description of the key project execution achievements and technical solutions. The Kikeh FTL GAP project commenced fabrication activities in 1st quarter of 2006, with offshore installation completed (Figure 1) and first oil achieved in August 2007.

The GAP technology enables development of a deep water field with an FPSO plus Spar without the fluid transfer system touching the seabed. Dry trees have the major advantage of easy surface access such that intervention costs and risks during operation are better controlled. Combining a Spar with fluid transfer to an FPSO system gives a robust field architecture with ‘building block’ flexibility for phased field development.

The GAP principle is based on a large diameter carrier pipe supporting a number of flow lines and umbilicals, with the carrier pipe serving as a structural support. Tether chains are suspended from the floaters to support each end of the carrier pipe. Clump weights or buoyancy are mounted at the ends of the carrier pipe to generate vertical load. The action of the clump weights or buoyancy on the angled chains keeps the carrier pipe under tension. This tension minimizes the hog /sag deflections of the carrier pipe bundle and keeps the GAP system within acceptable hog /sag limits.

The GAP system is an attractive alternative solution to seabed flow lines. The main advantages of the GAP are:improved flow assurance due to higher sea-water temperature leading to reduced risk of blockage by formation of wax and/or hydrates;lower discharge pressures since overall flow line lengths are shorter;avoidance of seabed constraints, for example ground instability, irregular sea-bed profile, subsea hardware congestion.
Self-Erecting Gravity Type Steel Platform for 350 to 500-Ft Water Depths in North Sea By Production
Authors: Minorsky Vladimir U. , Sharman Hugh U.
Published: October 2008

The concept of a two stage jack up drill rig for deep water as developed by George G. Sharp, Inc., was described at the 1973 aTC meeting: in the present paper the concept is modified to suit a steel production platform and utilizes cylindrical legs instead of trussed legs. Storage of more than 500, 000 barrels can be provided in the legs and in a mat. While the design described was developed for 380 ft. of water, it-could be made to apply for depths of water exceeding 500 ft. competitively with other deep water platform concepts.

INTRODUCTION

In the search for oil in the North Sea properly designed semi-submersibles have proven to be satisfactory tools, despite experiencing difficulties with the placement of anchors and with downtime in general. To date, there is not an equally satisfactory general solution to the installation of production platforms in deep water.

The demand for such platforms in the next ten years. is expected to be very strong, with perhaps as many as f gutsy or one hundred platforms needed to bring out oil estimated at forty billion barrels.

Extrapolations of platform installation methods successful in the Persian Gulf and in the Gulf of Mexico to deeper water applications in the North Sea are not valid, because of the weather conditions. Platforms in the North Sea are subjected to much larger overturning moments because of greater water depths and far more severe wave forces. Further, the season for work on the site is quite short, and site work using conventional means of construction during the off season is either impossible or subject to prohibitive downtime.

An insight into the magnitude of the North Sea challenge may be gained by reading about the difficult problems faced and solved by B. P. in connection with the large templates building for their Forties Field. Specially designed equipment to cope with the installation work includes an enormous hammer that will deliver 630,000 ft.lbs. of energy per blow and cranes capable of 1200 ton lifts, Ref. (1): needless to say, the rental of such equipment becomes very costly.

In discussing North Sea platforms, mention must be made of the bold and innovative concrete tank and production platform designed by C. G. Doris and Phillips Petroleum for Echoism 1. Almost all the engineering problems were solved while it was fjord based, so that construction time on site was reduced to a minimum.

There is of course no proper basis of comparison between the solution at Ekofisk I and that at the Forties, since the bottom conditions and depths of water are quite different. Moreover, it would not be economical to extend the Ekofisk solution to greater water depths without radical modifications. Recent articles, Refs. (2), (3) and (4), have described gravity platforms mounted on one or several shafts projecting from a hollow concrete foundation.
Fracture Mechanics-Based Fatigue Predictions for HPHT Equipment
Authors: Cordes Roger , San Pedro Ramon I.
Published: October 2008

A methodology covering fatigue life predictions for high pressure high temperature (HPHT) equipment is presented. HPHT equipment is generally thick-walled and by a common definition involves pressure ratings of 15,000 psi and above and temperature ratings of 350ºF and above. A fracture mechanics-based approach is described including the crack growth methodology and the determination of the design life. The approach is similar to that used in the ASME Boiler and Pressure Vessel Code and discussion is presented including a comparison to engineering criticality assessments (ECAs) covered in API recommended practices and in British Standards. The application of safety factors through input variables and through the analysis methodology is discussed. The limitations of S-N fatigue analysis for the evaluation of thick-walled high pressure equipment are also discussed.

Example problems are presented to display the application of the method to subsea equipment. The stresses are examined on a series of cylinders with several wall thickness to diameter ratios. This includes a cylindrical vessel with dimensions similar to a wellhead housing. The finite element method is used to determine the appropriate stress profiles through the thickness for the extreme loading and the cyclic loading.

Several sensitivity studies are performed to display the influence of the inputs. The relative importance of material toughness (i.e. CTOD or KIC) and residual stress are discussed. While their values are generally important, they can vary widely without influencing the fatigue life prediction. The influence of other material properties, such as the crack growth constants, and residual stresses are also discussed.

Introduction

The design verification of equipment for high pressure high temperature (HPHT) applications, typically defined as those requiring pressure ratings of 15,000 psi and above and temperature ratings of 350ºF and above, will require thinking beyond the " tried and true?? analysis methodologies used in the oil industry for the past couple of decades. Recent changes in and continued development of relevant codes and standards will surely impact the oil field equipment industry in the near future.

The material selection for HPHT components is critical to ensure adequate life. Deep reservoirs can bring about high partial pressures of H2S and corrosive by-products. High temperatures can alter material properties, behavior, and failure mechanisms. While these problems are significant, they are further complicated in that many HPHT components have additional functional requirements. In many cases, factors other than internal pressure (such as excessive deformation, sealability, functionality, fatigue) may limit the design pressure or require wall thicknesses beyond that needed for internal pressure alone.
Modern Deepwater Site Investigation: Getting It Right the First Time
Authors: Campbell Kerry J. , Humphrey Gary D. , Little Robert L.
Published: October 2008

Deepwater site investigation for petroleum production facilities requires much more than the simple one-boring approach that has been common at many continental shelf sites. Instead, because foundation-zone soil and geologic conditions found at many deepwater sites can be complex, a multi-phased approach that integrates and analyzes various geoscience and geotechnical data is required to optimize deepwater siting, geohazard risk assessment, and foundation design. This paper summarizes best practices for planning and executing a modern deepwater site investigation. The paper is based on our experience in carrying out various aspects of more than 100 deepwater site investigations over some 20 years. Although others have documented case histories illustrating specific deepwater site investigations, described various data acquisition tools, and discussed geohazards risk assessment in some detail, to our knowledge no generic, public summary exists that:explains the numerous considerations and significance of each in planning and executing a deepwater site investigation;describes the range and significance of geoscience and geotechnical components that can be required;gives the generic phases and sequence of execution required to optimize the process; andprovides guidance on the cost and schedule time required to carry out a deepwater site investigation.

The paper outlines a methodology for efficient, effective deepwater site investigation that is a useful explanation and guide for anyone responsible for this activity. The methodology will help operators optimize the planning and execution of deepwater site investigations, including geohazard risk assessments, and deliver results to project design teams in a timely manner. Unlike major operators, most independent operators and facilities designers/ constructors do not have site investigation and geohazard specialists on staff who are experts in the methodology presented. This paper is written principally for these organizations and provides them with a practical methodology for planning and executing effective deepwater site investigations.

Introduction

Purpose and Scope. The purpose of this paper is to describe what we believe to be the best-practice approach to a modern deepwater site investigation required for various petroleum exploration and development activities. Specifically, the paper outlines a methodology for efficient, effective deepwater site investigation and is intended as a useful explanation and guide for anyone responsible for this activity. The paper briefly describes what needs to be done and the various tools used, why it is important to do the various tasks involved, and when and in what sequence they should be done. The paper generally does not describe how to do the individual tasks as many other previously published papers have discussed details of deepwater site investigations (see References and Other Selected Literature at end).
Permeability of Laboratory-Formed Hydrate-Bearing Sand
Authors: Kneafsey Timothy J. , Seol Yongkoo , Gupta Arvind , Tomutsa Liviu
Published: October 2008

Methane hydrate was formed in moist sand under a confining stress in a long, x-ray transparent pressure vessel. Three initial water saturations were used to form three different methane hydrate saturations. X-ray computed tomography (CT) was used to observe location-specific density changes caused by hydrate formation and flowing water. Gas permeability was measured in each test for the dry sand, moist sand, frozen sand, and hydrate-bearing sand, and results of these measurements are presented. Water was flowed through the hydrate-bearing sand, and the changes in water saturation were observed using CT scanning. Inverse modeling will be performed using these data to extend the relative permeability measurements.

1.0 Introduction

Gas hydrate-bearing deposits present in the permafrost and in suboceanic environments have been identified as potential sources of natural gas. The production of natural gas from hydrates will pose many challenges, among which is the economic viability of producing gas from a particular resource. This interest in gas hydrates has induced many laboratory studies focused on various aspects of gas hydrates in the natural environment.

Pristine samples of natural gas hydrates have been difficult to retrieve and make measurements on because the hydrates are not stable at atmospheric conditions and require cold temperatures or high gas pressures to stabilize them. Pressure coring has been successfully performed, retrieving the most representative samples so far, however, these are not readily available for all studies, or in some cases not amenable to the needed study.

Several techniques are used to make gas hydrates for laboratory study. In the ice-to-hydrate method (Stern et al., 1996), ice is contacted with methane at the appropriate pressure, and then melted resulting hydrate forming. The hydrate can then be pulverized and mixed with a mineral substrate and compacted. In the excess gas method (Handa and Stupin, 1992), water is distributed throughout a mineral substrate (ie. sand or silica gel) and the mixture is brought to hydrate-stable conditions causing hydrate to form. In the dissolved gas method (Tohidi et al., 2001), water containing sufficient dissolved guest molecules is brought to hydrate-stable conditions and hydrate forms.

Permeability (the resistance to fluid flow under a pressure gradient) and relative permeability (the effect of the presence of other phases such as gas hydrate that interfere with the flow of the fluid of interest) are among the most important parameters governing gas production from a hydrate-bearing reservoir. From the gas production perspective, a large gas hydrate reserve with low permeability can be less desirable than a smaller reserve with higher permeability. Understanding the effects of the presence of gas hydrate in the porespace on permeability and water and gas relative permeability is necessary to more accurately predict natural gas production and economic viability from hydrate-bearing reservoirs.
Improving Reliability and Reducing Intervention Costs of Ultradeep Subsea Technology at the Design Stage
Authors: Fanailoo Pedram , Andreassen Goran
Published: October 2008

The current trend in offshore exploration and production (E&P) is geared towards developments in greater depths and harsher environments. The challenge of realizing fields at depths of greater than 5,000 feet normally requires unproven technology operating in harsh environments.

Deferred production is a function of reliability and intervention times. Harsh operating conditions in deep waters will have a negative impact on reliability. Long mobilization times for intervention vessels and availability of spare parts are also drivers of the performance of subsea facilities. High day rates for intervention vessels operating in deep waters represent an additional risk to project economics.

Target levels of reliability and production availability can be ensured during early design phases through a systematic and rigid reliability management program. As part of the early design optimization effort, a comparison of alternative intervention philosophies and their impact on project economics should also be evaluated. Alternative subsea intervention philosophies may be on an:On demand basis - which is subject to the availability of resources and costs at the time.Contract basis - where intervention resources are available based on agreed contract agreements.

This paper describes the potential risks involved with the reliability of novel subsea solutions required for deep water production, the impact of capital intensive intervention costs and a risk-based approach that can be applied to optimize subsea reliability, design and intervention planning. Det Norske Veritas (DNV) has successfully applied detailed simulation modeling techniques within a risk based approach to optimize subsea developments. DNV has supported operators with the following:Estimates for the reliability of novel ultra deep subsea equipment.Prediction of produced and deferred production volumes.Criticality analysis.Concept evaluation.Evaluation of alternative intervention philosophies.Gains in Net Present Value (NPV) based on optimization of design, reliability and intervention planning.

Deepwater hydrocarbon production is expected to grow from 10% to 25% of total offshore production by 2015 as hydrocarbon deposits in shallow waters and in more accessible regions become depleted. More is being invested in subsea technology to face the increasing demand for systems and equipment to recover hydrocarbons in deep and ultra-deep waters (greater than 5,000 ft / 1,500 meters). This shift in industry focus will result in some key challenges in the decade ahead.

The overall through-life Net Present Value (NPV) of a subsea project is dependent on three factors:Capital Expenditure (CAPEX).Operational Expenditure (OPEX).Revenue Losses.
Lessons Learned on the Open Hole Completions for the Two HPHT Retrograde Gas Condensate Fields Using Expandable Liner Hangers, External Sleeve Inflatable Packer Collars and Swell Packers for Zonal Isolation
Authors: Kim Yong-Seok , Kwang Kwon Ou , Murugappan Basker Stargard , Williford James W. , Jackson Alan Tancel , Nizam Irwan , Lim Derek Chiong Huat
Published: October 2008

Valuable lessons have been learned from the development of eight retrograde gas-production wells located in offshore Vietnam operated by the Korean National Oil Company. The intent of this paper is to share these lessons by presenting the concepts considered for well design, the selection process for the completion equipment and techniques, the preplanning for the installations, and the experiences encountered during the actual installations.

The completion challenges included isolation of water production below the casing shoe and controlling condensate banking, sand production, and co-mingling multiple production zones in the long openhole sections.

A different type of completion that involved an expandable liner hanger (ELH) with an external-sleeve inflatable packer collar (ESIPC) was chosen and installation and cementing were accomplished in a single trip. The ESIPC was deployed just below the water-producing zone, and cement was pumped up the annulus from the ESIPC to where the expandable liner hanger (ELH) was set above it. This would prevent water from entering the wellbore while enabling optimum production. To prove the concept, a stack-up test was done at surface before actual deployment on location to ensure that the cement wiper plugs would pass through the expandable-liner-hanger ball seat and that the concept would perform as intended.

Swellable packers were selected from the various proven openhole isolation devices available to the industry to provide the zonal isolation required in the multi-zone intervals.

This was the first openhole completion in Southeast Asia in a high-temperature, commingled gas environment in which isolation would be contained solely by swellable packers.

Introduction

The Rong Doi (RD) and Rong Doi Tay (RDT) gas fields are offshore in approximately 85m of water. They are approximately 300 km southeast of Vung Tau, Vietnam (Fig 1). This high-temperature reservoir (300ºF) is within the Mid-Miocene Dua formation from 3050 to 3900 m true vertical depth sub sea (TVDSS).

The formation is an anticline with a four-way dip closure, split by three NNW-SSE sealing faults, and overlain by the Thong formation. Data from three offset wells; i.e., RD 1X drilled in 1994, RDT 1RX drilled in 1996, and RD 2X drilled in 1997, were available.
Guide line Systems for Deep Sea Deployment
Authors: Liu Francis C.
Published: October 2008

INTRODUCTION

Definition

A guideline system consists of mechanical cables that restrict the lateral drifting of a payload suspended from a flexible lift line. The guideline system is composed of four basic components: surface support, guideline, anchor, and guide frame (Figure 1). The guideline is either a steel or a synthetic rope which stretches in a near vertical orientation between the surface support and the anchor. The guide frame is a rigid truss which maintains a fixed distance between the payload and the guideline. As the payload is raised or lowered by a lift line, the guide frame slides freely along the guideline. The lateral motion of payload is, thus, controlled by the guideline system. The number of guidelines in a system can vary from one to several depending on the degree of restriction of motion desired.

Objectives

The purpose of this investigation was to obtain a better understanding of the behavior of guideline systems by conducting controlled sea tests. It was intended to identify the difficulties and problems involved in hardware design, motion analysis, and at-sea operation. Once sufficient field data were obtained, then procedures for the design, deployment, and operation of guideline systems could be established for future projects.

The main emphasis of this study was on reducing the probability of guideline entanglement. Field tests were designed to show that with proper precautions, guideline systems could be operated without line entanglement. As a secondary interest, the mechanism of mating two structural modules on the seafloor by using a guideline system was studied. It was intended to demonstrate that the capacity of a gravity anchor could be increased by adding modular weights to the anchor after its implant, and that the alignment of the modules could be controlled by a properly designed guideline and bottom guide posts.

Background

Future underwater construction and salvage operations may require extensive load-handling capabilities for emplacement, suspension, recovery, and assembly of large, heavy structures at predetermined seafloor locations at depths to 20,000 feet. The required capabilities include not only high tension lifting but also seafloor positioning and mating. In general, new load-handling systems must minimize the dynamic loading in the lift line and the large amplitude oscillatory motion of the payload near the seafloor. Additional hardware is needed to provide the required capabilities for accurate seafloor positioning, precise alignment, and repeated returns to the same seafloor site. Guideline systems are a potential solution for these problems.

The concept of a flexible guideline system is simple and inexpensive; yet, it is an effective means of restricting the lateral motions of a payload throughout its vertical travel in the water column. The components of the system are readily available as off-the- shelf items. How ever, the most serious draw back to the system is believed to be its apparent low rehab1hty wh1ch 1S caused manly by line entanglement.
Greater Plutonio - Progressive Subsurface Management in a High Cost, Subsea Environment
Authors: Peak John
Published: October 2008

Greater Plutonio is BP's largest subsea development with an initial plan to drill and complete 43 high tech, high cost, high rate subsea development wells. A relatively low level of classical field appraisal was possible because of high industry costs coupled with the fast pace of the project. Innovative subsurface management has therefore been required to reduce substantial uncertainty during the development phase.

Full use has been made of excellent HiRes seismic data. An optimised well order has been crucial to reduce depth uncertainties and facilitate a focused, early data acquisition programme - while incrementally tackling more and more complex drilling and completion challenges. Extensive learnings have been possible from reservoir interference data resulting from rig-based production and injection tests.

The application of some specific technologies has been key to the success of the project: widespread use of a Subsea Acoustic Monitoring System to interrogate downhole pressure data from multiple offset wells prior to subsea system installation; 100% reliance on Subsea MultiPhase Flowmeters during initial ramp-up and subsequent operations; Extensive use of remote sensing technologies relayed real time to office desktops and fully integrated with well models to facilitate immediate well and reservoir management.

This has enabled significant reservoir learning and therefore reservoir management not only in the early ramp-up phase but actually before field start-up, which was achieved on 1st October 2007. In turn this has allowed the on-going development drilling order to be honed to maximise early production and injection.

The successful subsurface and wells management of Greater Plutonio has been demonstrated by the delivery of sufficient production potential to allow field rates of 200mbd in January 2008 (after just over 3 months of operations) and over 300mmscf/d of injection potential at the time of first gas injection less than 2 months after first oil. In addition, by early 2008 water injection had reached 120mbwd into 4 wells, with potential for a further 40mbwd already completed and tested.

Establishment of full voidage replacement in 2008 to allow sustainable plateau production is ahead of plan. The enhanced reservoir understanding from the pre-first oil and ramp-up data has reduced subsurface uncertainties while the Greater Plutonio development has progressed and will play a crucial part in increasing ultimate field recovery.
Geotechnical Design of Footings for Temporarily Founded Seabed Drilling Systems
Authors: Kelleher Patrick Joseph , Samsuri Nazri , Carter John
Published: October 2008

This paper describes some geotechnical aspects relevant to the design of a footings system used to support a seafloor-founded drilling rig. Once landed on the sea bed and isolated from vessel motions, adequate foundation support is required throughout the course of seabed operations - the duration of which may vary from hours to days, depending on the investigative work being undertaken.

The design requirements for footings supporting these systems are complex. Ideally, the design must:Provide sufficient bearing capacity on very soft seabed slopes of up to 20 degrees.Be resistant to damage in the event that the rig is landed on a stiff seabed.Minimise the surcharge applied to the seabed within the vicinity of the drill centre.Be resistant to seabed scour in prevailing currents.Provide adequate (temporary) support in the event of a shallow gas release.Minimize the breakout forces required during recovery from the sea bed.

All of the above issues were addressed in the design of a temporary footings system for a remotely operated, seafloor-founded, geotechnical drilling rig. This paper describes the observed performance of the prototype footings system that was deployed at a number of soft seabed locations offshore Korea, Western Australia and New Zealand. Recent enhancements to the design are also discussed.

Introduction

Seabed-founded geotechnical investigation rigs are increasingly being used in marine geotechnical site investigations. As investigations rapidly move to deeper waters and softer sea beds, the importance of adequately founding these devices has become critical. Inadequate design of the footings system supporting these devices will inevitably lead to:Poor borehole depth control (relative to the mudline);Potential rig instability (particularly on seabed slopes, and under the dynamic loading associated with seabed drilling operations); andThe mobilisation of excessive breakout forces during recovery from the sea bed.

Most geotechnical sampling and testing equipment requires some interaction with the seabed during the course of a seabed investigation. Properly compensated heave compensation systems typically rely on a stiff link between the moving vessel and the seabed to provide a datum point for the motion control systems. (This is generally achieved by founding a heavy seabed template on the seabed prior to drilling). Single stroke reaction frames and remotely operated seabed drill rigs need to land and remain stable on the upper seabed layers during seabed operations.

Technically superior landing and leveling systems have recently been developed to provide better stability and control of seabed-founded drill rigs, even on very soft seabeds that are typically encountered at deepwater sites. This paper describes the design and field testing of such a system, that has provided support and stability to a seabed founded drilling rig at a range of deepwater seabed sites.