bluuebunny/crossref_metadata_2025 huggingface dataset:
Mitigating Flow Assurance Challenges Using Subsea Meters on Independence Hub
Authors: Joshi Nikhil B. , Buck Robert John
Published: October 2008

The Independence Hub development is a fifteen-well subsea tieback to the host capable of producing up to 1 bscf/d of gas production and associated fluids. The subsea architecture is designed to deliver the required amount of hydrate inhibitor (mono-ethylene glycol) to each well. This is done using a combination of subsea wet gas meters (SWGMs) installed in the well jumpers and subsea orifice valves installed with the subsea trees, in addition to topside MEG injection pumps and meters. The SWGMs measure the total gas, condensate and water production from the wells and these measurements are used to optimize the MEG injection requirements. In addition to the SWGMs and subsea orifice valves, subsea acoustic sand detectors are used to monitor sand production. A combination of these devices provides a robust methodology to mitigate any flow assurance challenges for this development.

The subsea architecture is such that a common MEG injection umbilical can deliver the required volume of MEG and chemicals to each well by using the information from the SWGMs and by controlling the subsea orifice valves. In addition to the CAPEX savings from avoiding a MEG injection line for each well, the use of SWGMs also provides accurate production measurements to conduct produced gas and liquid allocations. The wells producing to the host are of varied royalty regimes and ownership. The use of one SWGM per well provides the required measurements for allocation of production with minimal uncertainty.

The experiences from the Independence Hub operation are shared in this paper, especially related to the measurement of production from each well and optimization of chemicals using subsea orifice valves. Also, some of the operational challenges and lessons learned during startup and routine operations are addressed.

Introduction

The Independence Hub development started as a joint project between Independent producers to tap the reserves around the Mississippi Canyon 920 block. During the exploration and development phase, the hydrocarbons discovered were primarily dry biogenic gas with a condensate-gas ratio of less than 1 bbl/mmscf. Several independent E&P companies had discoveries in the vicinty (a summary is provided in Table 1 below). The E&P companies made a decision to jointly develop these fields to not only optimize CAPEX and OPEX, but to also use the best expertise in various areas of development to make the project feasible and successful. The Independence Hub semi-submersible platform receives production from these wells with a capacity to process up to 1 Bscf/d of hydrocarbon gas. It is located 123 miles southeast of Biloxi, Mississippi. The platform is operated by Anadarko and owned by Enterprise (80%) and Helix (20%). The Independence trail, owned 100% by Enterprise, is used to transport the gas and associated fluids from the platform to the shallow-water hub (West Delta 68). The wells and subsea systems are owned by the operating companies.
Analyses and Measurements of Conductor Response for Jack-up Drilled Wells in 110 m Water Depth in Harsh Environments.
Authors: Baerheim Morten , North Andrew , Steinkjer Oddrun
Published: October 2008

The analysis of conductor systems for wells drilled by jack-ups is often limited to analysis of the conductor alone as a free standing unit. This paper discuss the various aspects of the analysis of the whole conductor system and shows that the limitations in strength may be in the conductor itself, but in other parts of the system

Introduction

This paper deals with top tensioned drilling conductors that are drilled from jack-up platforms. The conductor system consists of an outer drilling conductor cemented to the sea bed and kept in tension by a tension system on the jack-up. The conductor is guided horizontally at the Texas deck. The conductor system also includes equipment connected to the conductor such as BOP, wellhead, packer and overshot system. The paper describes a conductor system typical for the jack-up rig used for the deep water drilling. Other jack-ups may have different systems, but the main message of this paper on total system analysis is still valid.

Conclusion

It is important to model all elements of the conductor system for deep water jack-up drilled wells. There are strength limitations in various parts of the system, and changing the strength or stiffness of one part may have negative effects on other parts of the system.

Analyses of the drilling conductor

The analysis of the drilling conductor need to include all components in the system. Typical components included in the analysis are:Seabed fixation (soil-pipe interaction modelled with springs)Conductor pipe with internal pipes (pipe to pipe contact modelled)Texas deck supportTension systemAdjustable landing ringWellheadBOPMandrelPacker / overshotDiverter

In addition, the jack-up movements must be input to the analyses.
Onshore Versus Offshore LNG Import Facilities - Commercial Advantages and Limitations
Authors: Danielsen Hans Kristian , Andreassen Goran
Published: October 2008

As LNG stakeholders assess whether and how to commit billions to re-gasification infrastructures, it is imperative that they address, early and meaningfully, the issues associated with commercial optimisation of their investments. Potential terminal developers face the option of moving offshore or stick with a traditional onshore development.

There have been large developments in offshore receiving terminal design, where many companies are hoping that new technologies can ameliorate the actual or perceived risks of a land-based location - that is, without introducing too many new dangers and challenges. Until Excelerate and Energy Bridge Floating Storage and Re-gasification Unit (FRSU) opened in the Gulf of Mexico, all LNG import terminals were land-based. FRSUs are now under construction to operate in Tuscany, Italy (using a refitted LNG carrier), Southern California (using a new, dedicated vessel), as well as Pecem and Guanabara Bay in Brazil.

This paper presents the learning from a number of site and concept selection studies. Through these early phases of project development there are commonly a limited number of parameters that are deceive for the concept that ultimately is chosen.

Typical concept differentiators such as; cost, lead time, technological maturity, asset risks and safety will be discussed.

Introduction

As LNG stakeholder assess whether and how to commit billions to re-gasification infrastructures, it is imperative that they address, early and meaningfully, the issues associated with commercial optimisation of their investments. Potential terminal developers face with the option of moving offshore or stick with a traditional onshore development.

There have been large developments in offshore receiving terminal design, where many companies are hoping that new technologies can ameliorate the actual or perceived risks of a land-based location - that is, without introducing too many new dangers and challenges. Until Excelerate and Energy Bridge Floating Storage and Re-gasification Unit (FRSU) opened in the Gulf of Mexico, all LNG import terminals were land-based. FRSUs are now under construction to operate in Tuscany, Italy (using a refitted LNG carrier), Southern California (using a new, dedicated vessel), as well as Pecem and Guanabara Bay in Brazil.

In addition to these sites which are in the construction phase, offshore import facilities have been considered as an alternative concept for a number of other sites. Experience from such studies is that a limited number of key parameters are decisive for concept selection in terms of offshore versus onshore.
Paraffin Cleanout in a Single Subsea Flowline Environment: Glycol to Blame?
Authors: Bailey J. Claire , Allenson Stephan John
Published: October 2008

Paraffin deposition was found in the RedHawk #2 subsea flowline and was successfully removed using a xylene slug swept by produced gas from the well. Testing indicated that the problem resulted from the interaction between glycol and produced condensate. Overtreatment with glycol and low produced water volumes contributed to the precipitation of paraffin and eventual plugging of the flowline.

The objective of this procedure was to clear the restriction by pumping a slug of xylene into the flowline and producing the well to carry the solids to surface. Glycol can react negatively with the condensate in some dry gas wells, resulting in paraffin precipitation. When there is sufficient water present to mix with the glycol the problem does not occur, however a lack of water causes the glycol to react with the condensate and form paraffin. Clearing the restriction would eliminate a pressure drop in the flowline, thus allowing the well to produce at optimal rate and prolonging the well's life. All work was performed from the host spar facility using temporary separation equipment and platform methanol pumps.

The RedHawk flowline restriction was successfully removed using two 25 bbl xylene slugs which were swept from the flowline with produced gas from the well. With the restriction removed, 982 psi of frictional loss was regained and the well was returned to optimal production. The deposition appears to be reoccurring, although at a much slower rate than before. However, any further reduction in glycol usage would not guarantee effective hydrate inhibition. Changing hydrate inhibitors is impractical due to platform equipment and annual cleanouts are a more cost effective option.

It is quickly becoming critical to develop means of cleaning single flowline systems with highly efficient and low cost methods. By understanding new problems that arise and putting new solutions into practice operators can extend the life of some wells and avoid significant downtime and workover costs.

Introduction

RedHawk is an Anadarko Petroleum Corporation operated cell spar located in 5300' of water in Garden Banks Block 876, about 177 miles southeast of Cameron, LA in the Gulf of Mexico. Devon Energy Corporation is a 50% working interest partner in the RedHawk field. The platform consists of two dry gas subsea tie-back wells, shown in figure 1, that are treated with recycled MEG via RedHawk's Glycol Reclamation Unit (GRU) for hydrate inhibition. As the GB 877 #2 well's chokes were opened to maintain the target rate of 75 MMCFD, it became apparent that the chokes were no longer controlling the flow from the well but rather some other restriction in the flowline (see figure 2). Modeling and testing showed that there was a restriction in the flowline causing a pressure loss and limiting the production rate of the well. The restriction was initially thought to be the result of fluids from the initial completion cleanup or from a preexisting blockage that occurred during installation of the flowline.
API RP2T and RP2FPS: Moving Forward
Authors: Leverette Steven J. , Wolfram Bob
Published: October 2008

API is developing updates for two key floating/tethered system documents for issuance in 2008. Impactful changes in RP 2T based on learnings from the 2004-2005 hurricane season, over 10 years of experience and technology development and metocean changes have been incorporated. Additional criteria regarding tendon loss/damage and an integrity check for conditions significantly above the 100 year design basis will be discussed.

API RP 2FPS is being developed using ISO 19904 as a basis (19904 was built upon the current version of RP 2FPS and updated) and " wrapped?? with US Gulf of Mexico specific additions.

This paper will present the key changes/additions in these documents and provide a discussion as to the impact.

Introduction

From the first floating production systems in the 1970's and early 1980's, semisubmersibles, FPSOs, TLPs, and more recently spars have featured prominently in the industry's vision of how to produce oil in deeper water depths. The first floating production system, a converted semisubmersible, was developed in the North Sea for the Hamilton Brothers' Argyle field (1974). The first FPSO was installed on the Shell Castellon field offshore Spain in 1977. The first production TLP was installed in the Conoco Hutton field (1981) in the North Sea. Since then, there have been many floating production systems successfully installed in locations all around the world.

The first API recommended practice to address these structures was RP2T, the Recommended Practice for the Planning, Design, and Construction of Tension Leg Platforms, first issued in 1987. Until recently, RP2T was the only issued API document to address floating production systems. Although RP2T was limited to TLP's, it served as a technical basis for other types of structures, along with various classification society documents and European codes. In 2001 the first edition of RP 2FPS was issued.

As the industry has developed more experience with these structures, the body of information available for guidance to designers, builders, and operators has expanded, while the methods and practices have evolved and improved. In response to this evolution, API typically issues updates to incorporate the new information. The impetus for issuing an updated RP2T and a new RP 2FPS at this time includes a number of factors. The technology for both FPS's and TLP's has evolved to include varied concepts and configurations. The engineering tools and practices have greatly improved. And finally, the understanding of the environment, especially in the Gulf of Mexico, has changed significantly following the 2004-2005 hurricane seasons.

One other evolution in the API offshore structure recommended practices has been brought about by the progress made in the standards developed by the International Standards Organization (ISO). When the ISO first started to develop offshore structure standards, there was a move within API to eventually replace the API RP's in favor of the international standards.
First use of Swell Technology in Campos Basin Proves Water Conformance Solution - Case History in Campos Basin-Brazil
Authors: Ueta Eduardo Midufo , Neto Jose Nolau , Nunes Max Amado , Barrios Oscar D. , Tocchetto Andre Luiz Rodrigues , Barretto Neto Edison Baptista
Published: October 2008

The Pampo Field is in southern Campos Basin, Rio de Janeiro, Brazil and contains sandstone and shale reservoirs with good quality oil (14 to 32 API). In Dec. 2004, a major operator in the region drilled a horizontal well, which was completed with an openhole gravel pack. During production, water break through was noted from the upper producing part of the reservoir in the horizontal section, and this phenomenon steadily increased. Due to the higher hydrostatic pressure from the water-producing area, oil production from the lower section of the reservoir was inhibited. A work over was performed to isolate the water-producing zone by isolating the interior of the gravel screens.

This paper will discuss a new technology for the Campos Basin area that was capable of resolving the water production problem. A concentric string was developed to run inside the gravel pack screens and included sliding sleeve circulating devices and two swellable packers that were connected at the end of the string and were spaced out to isolate the water producing shale. The objective of this configuration was to decrease flow from the upper producing portion of the sandstone to isolate the water production area and allow higher production from the lower producing portion of the sandstone (3595 to 3935 m).

Swellable packer technology was successful in providing the required results. In this technology, a rubber configuration that expands to create a permanent seal when exposed to liquid hydrocarbons such as crude oil, diesel, oil-based mud, etc. is placed around the packer, and thus, when it expands, it can provide a long-term water shut-off tool. This case history will show that the swellable packers:Performed with predicted results from the simulated designHelped reduce water productionGained operator approval for other operations.

This paper describes the well scenario in which swellable packer technology was used to perform zonal isolation in an offshore horizontal well in Campos Basin, Rio de Janeiro, Brazil to effectively control water influx and manage oil production.

Introduction

The Pampo concession is situated in the southern part of the Campos Basin, approximately 80 km from the Rio de Janeiro state coast. Water depth is approximately 108 m. Figure 1 is a map of the area and shows the Pampo Field. Several lithologies including carbonates, sandstone and conglomerates prevail in the target formations. The producing formation is from the upper and lower sandstone located above and below the shale section. The oil produced from these formations is of good quality with gravity ranging from 14 to 32 API.
New Design in Surface-Controlled Subsurface Safety Valves Resolves Valve Problems in Subsea Completions in the Gulf of Mexico
Authors: LeBoeuf Gerald Joseph , Adams Shane Michael , Pittman Adam , Dodd Paul
Published: October 2008

Shell has been developing wells in the Gulf of Mexico (GOM) in environments that have required 10,000 psi working pressure surface-controlled subsurface safety valves (SCSSVs). The well environments have been sweet service with up to 11,750 psi bottomhole pressures and depths of up to 18,000 ft and SCSSV setting depths of approximately 7,600 ft. Valve failures have not only compromised well integrity but also resulted in production down time, as a SCSSV fails to a closed position. Additional cost is also incurred in order to recomplete the wells. Although failures in current nitrogen-charged SCSSVs and the valve operating systems are not as common as they once were, the incurred costs from these failures prompted a search for an improved safety valve. Requirements were determined for the sought-after safety valves, and the following discussion provides the list of critical needs.

The primary requirement was that the sought-after safety valve be capable of maintaining integrity in the above conditions and be compatible with 4-1/2-in. tubing and 9-5/8-in. casing. To comply with the well design, the SCSSV would require capabilities that would support the following parameters:Dual line set-up for operation of SCSSV and balance of control-line fluids across operating pistonNon-tubing pressure sensitiveLower operating pressuresOperating system isolated from wellbore pressureDebris protectionSetting at any depthFewer moveable parts and seals than other SCSSVs.

A unique magnetic coupler SCSSV that met the required capabilities is the focus of this paper. The new SCSSV offered several advantages that were important to Shell.

The design of the valve, a comparison with traditional valves in similar well conditions, and the first installation for Shell will be presented. The new valve is successful, and as a result, four additional installations using the magnetic coupler valve have been scheduled.
Diving Bell Escape Systems: Some Observations and Test Results
Authors: Nuytten Phil
Published: October 2008

The operation of deep diving bell systems (SDC's) onboard today's offshore drilling vessels has become a routine exploration tool. Virtually all diving support contracts specify system depth capability to at least 600 feet and, in many cases, to one thousand feet.

With well over one hundred such systems currently operating in the waters of the world, the inevitability of emergency situations that may require diver abandonment of the SDC is an alarming spectre. Entanglement of the SDC, toxic contamination of the SDC atmosphere and entrapment by structural failure are just' a few of the potential hazards that could cause an emergency abandonment situation or a prolonged bottom stay awaiting rescue.

This paper examines some D£ the procedures programmed for use during a bottom emergency, the viability of commonly accepted but little used safeguards and briefly discusses the specific problems of recovering a disabled SDC or having the occupants leave an irretrievable SDC and ascend to the surface.

DIVING BELL ESCAPE SYSTEMS: SOME OBSERVATIONS AND TEST RESULTS

Under normal operations, the submersible diving chamber (SDC) or diving bell is lowered and raised from the work platform by means of a strength wire. Few, if any, of the SDC's operating around the world have any means to effect a controlled surfacing should the strength line become severed or otherwise detached or the SDC become entangled on the bottom. There are. a number of possible situations that could prevent the SDC from being raised to the surface station in the usual manner. A detailed examination of these potential situations may cause some reflection on the adequacy of existing emergency measures and the possible consideration of modifications and/or the formulation of additional measures.

The recent, well publicized tragedy involving the submersible "Sea Link" is a graphic illustration of the type of situation which may be encountered in the petroleum exploration support role. The SDC's usually operate under conditions where speedy outside assistance, in the event of an emergency, is logistically impossible and reliance must be placed on whatever self-contained measures are available or can be programmed.

There are at least five major factors to consider in programming emergency procedures:Nature of the problem (e.g. is the SDC entrapped?Depth of water (e.g. possible to use standby diver?Umbilical condition (e.g. severed or intact?Load line condition (e.g. severed or intact?SDC pressure condition (e.g. pressurized or unpressurized?

If one fixed case is assumed for question "A" - the SDC is entrapped - the critical examination of the possible combinations of other factors will require a detailed analysis of at least sixteen possible situations and the calculation of the most effective emergency procedures to use in each case.
Hydrates Blockage Experience in a Deepwater Subsea Dry Gas Pipeline: Lessons Learned
Authors: Kane Moussa , Singh Aditya Pratap , Hanssen Ronny
Published: October 2008

The Matterhorn field, operated by TOTAL, is located in the Gulf of Mexico, on block 243 of the Mississippi Canyon. It produces oil and gas from seven wells in a water depth of approximately 2800 ft.

This paper reviews a hydrate blockage incident which occurred on the Gas Export Pipeline (GEP) of the Matterhorn platform. A comprehensive flow assurance study (fluids characterization, steady state and transient flow simulations) was conducted in order to understand the causes of the incident and to develop prevention, mitigation and remediation strategies. The study described herein gives a methodology to be used in the design and operation of gas pipelines, principally in the deep water subsea environment, from a hydrate management perspective.

The GEP was operated in the hydrate-stable and two-phase region, but still within industry standards in terms of dryness (dewpoint). The study shows that a temporary deviation from the normal operating conditions lead to a gradual water build-up, resulting in hydrates formation and eventually causing a total obstruction. The transient simulations performed with OLGA® were able to predict the condensate and water accumulation rate and holdups along the GEP.

The incident described and the subsequent flow assurance study highlight the potential risk of hydrates formation in " dry?? gas pipelines in deep water subsea environment. In subsea gas export lines, the current dryness (dewpoint) contractual requirements agreed upon by the operators are believed to provide safe operating conditions with regard to hydrates. The present work demonstrates that hydrates formation risks remain even when operating within the industry requirements. The remediation strategy adopted after the hydrate blockage, and the prevention measures applied since, provide useful guidelines for the management of hydrates in gas pipelines.

Introduction

With oil and gas developments moving to ever deeper subsea environments, hydrates-related issues become a growing concern for the industry. Hydrates blockages, beyond the safety risk they represent, result in time-consuming and costly mitigation and remediation operations. Most hydrates experiences found in the literature, and the corresponding prevention and remediation strategies, concern multiphase pipelines. This paper relates a hydrates blockage incident which occurred in January 2007 on a deepwater dry gas pipeline. A detailed review of the events and subsequent remediation actions is given, along with an analysis, including a PVT study and transient multiphase simulations.

The lessons learned from this experience are presented here and are currently being used as a basis for improving operation guidelines and hydrates prevention strategies for dry gas deepwater pipelines.
Subsea Equipment Installation Challenges for Malaysia's First Deepwater Development
Authors: Murray Gordon , Stensgaard Thomas , Lowther David , Ledingham Adrian , Robertson Ian
Published: October 2008

The Kikeh Development is the first deepwater project in Malaysia located Offshore Eastern Malaysia in the South China Sea with a water depth of 1320 m. Kikeh is produced via a Spar and a subsea water injection and production system back to a Floating Production Storage and Offloading (FPSO) unit (see Figure 1). Kikeh is planned to be developed using 34 wells and initial production commenced in August 2007.

The main subsea installation portion of the Kikeh development was executed through an Engineering, Procurement, Construction, Installation, and Commissioning Support contract with Technip Marine (Malaysia) Sdn Bhd. The installation scope of work included the following:5 manifold support piles*5 subsea manifolds*5 flexible risers and flowlines with a total length of over 31 km of flexible pipe7 riser holdback anchor piles4 electro-hydraulic control (EHC) umbilicals (2 dynamic/static and 2 infield static)*5 rigid spools c/w vertical connection module (VCM) clamp connectors (out of 14 in total)*5 subsea distribution units*6 hydraulic flying leads (out of 27 in total)*6 electrical flying leads (out of 48 in total)*Pre-commissioning of the subsea systems

* Free issued from subsea equipment EPCC contractor

The paper will discuss the process of offshore installation vessel selection including the effects on the decision process of utilizing local equipment versus mobilizing deepwater construction equipment from other deepwater basins around the world.

In addition, with deepwater Sabah being a greenfield deepwater basin, a number of challenges arose in relation to availability of equipment within the region and logistics to support the deepwater construction operations. Highlights from Phase I, Phase II, and Phase III installation programs are also presented.
The Next Major Challenge for Deep Water: Developing Marginal Fields
Authors: Millheim Keith K.
Published: October 2008

Worldwide, there are hundreds of deep water oil fields that have been discovered, and many hundreds yet to be discovered that are not commercial using existing conventional deep water approaches. A new paradigm based on production materiality is an alternate approach for deep water marginal oil field exploration and development. This new paradigm shows that first oil could be consistently achieved in one to two years from discovery to first oil with attractive economics if there are new ways to significantly reduce drilling costs, capital investment, and operational costs. This paper presents a paradigm of how these results might be possible in the foreseeable future with the innovation of what might be called the micro chip for deep water—the self standing riser.

INTRODUCTION

History of the oil industry shows the early discoveries of oil and gas started with the shallow, easiest to find hydrocarbons, onshore. With innovations in seismic and drilling equipment and technology deeper discoveries were made. Later exploration was extended offshore to the shallow shelf areas. The North Sea and Gulf of Mexico (GOM) and offshore Brazil led the development of offshore technology which focused on drilling with jack-ups, drill ships, and semi submersibles with most of the production facilities based on compliant platform structures. However, as smaller fields were discovered and field extensions extended beyond the reach of the drilling/production platforms the subsea well became a viable option. Subsea wells near the platform were tied back via pipeline to the platform. However, in some cases, a floating production unit (FPU) was used to process the subsea well(s) production and tie back to the main production line. Other cases where the tie-back to the main pipeline was not feasible a floating production storage off-take vessel (FPSO) was used not only to process the reservoir fluids but also to store the oil for later pick up by an oil tanker. For most of the world (except for the Gulf of Mexico), especially the North Sea, Brazil and Australasia, the subsea well and FPU/FPSO became the normal development path for the smaller offshore fields. The FPU/FPSO offered more versatility, quicker construction, and in most cases better economics.

The Gulf of Mexico was a unique case where there has always been enough offshore pipeline infra-structure where all the oil and gas production went into the main pipelines. Because of the pipeline network and some other perceived safety and environmental issues the use of FPSOs was non-existent. Only a few FPUs were commissioned in the GOM.

In the middle of the '80s the exploration community, with the help of advanced seismic technology, showed the likelihood of finding large oil fields in deeper water with Brazil leading the way. Deeper water discoveries in the GOM and West Africa followed. Except for the Middle East few places held the potential for the discoveries of big fields like deep water.
SS: Panel- Session on Risk Management in the Offshore Energy Industry, International Risk Management
Authors: Murphy Daniel V.
Published: October 2008

Executing any design or construction project involves risk, and complex projects have a potential for even greater risk. The function of project management is to establish processes which control the performance of work by the project participants. Project managers plan project execution around the expectation that events will occur within a ‘normal’ range, both temporal and financial. The intent of managing risk is to establish a program to prepare for both negative and positive risks which manifest outside of this normal range. While certain risks, such as property damage, are frequently insured, many risks are not. In this paper, the term Project Risk will refer to these abnormal risks and Project Risk Management will refer to the efforts required to exert control over the impact of Project Risks. In 1992, The Project Management Institute (PMI) defined Project Risk and Project Risk Management (Reference 1) as follows:Project Risk is the cumulative effect of the chances of uncertain occurrences adversely affecting project objectives.Project Risk Management is the art and science of identifying, assessing, and responding to project risk throughout the life of a project and in the best interests of its objectives.

In 2001, another definition of Project Risk Management was stated as follows (Reference 2):

Risk management is the act or practice of dealing with risk. It includes planning for risk, assessing (identifying and analyzing) risk issues, developing risk handling options, and monitoring risks to determine how risk has changed.

By 2004, PMI had modified its definition in the Guide to the Project Management Body of Knowledge (Reference 3) as follows:Project Risk is an uncertain event or condition that, if it occurs, has a positive or negative effect on at least one project objective…the cumulative effect of the chances of uncertain occurrences adversely affecting project objectives.Project Risk Management includes the processes concerned with conducting risk management planning, identification, analysis, responses, and monitoring and control on a project; most of these processes are updated throughout the project.

In this same Guide, PMI goes on to establish the purpose of Project Risk Management as follows:Specifically identify factors that are likely to impact the project objectives of Scope, Quality, Time and Cost;Quantify the likely impact of each factor;Give a baseline for Project Non-Controllables; andMitigate impacts by exercising influence of Project Controllables.

This paper does not provide a comprehensive specification for a Risk Management program; rather, it is intended to provide the reader with an overview of the general concepts as well as provide sources of additional information for further study. It is also provides real-world examples of what happens when projects experience a breakdown of Project Management and fail to recognize the time and cost impact of relatively small issues, avoidable with a Project Risk Management Program.
Differences In Shear Strength Between Jumbo Piston Core and Conventional Rotary Core Samples
Authors: Wong Patrick C. , Taylor Brian , Audibert Jean
Published: October 2008

In order to reduce costs associated with offshore site investigations, particularly in deep waters, large-diameter piston corers (also called jumbo piston corers) have been used as a cost-efficient tool to supplement conventional drilling and sampling and to obtain continuous seafloor samples as long as 30m. The STACORÒ is believed to be the jumbo piston corer that has the least soil sample disturbance, due to its unique design. There have been indications that samples obtained using the STACORÒ piston coring system yield undrained shear strengths higher than those obtained using conventional rotary borings. For example, comparison of data from five sites offshore West Africa shows that undrained shear strengths measured with the minivane and unconsolidated-undrained (UU) triaxial test tend to be 19% higher in STACORÒ samples than in rotary boring samples. This paper explores the reasons for those differences and attempts to quantify the differences in undrained shear strength of samples obtained with the two methods. The higher strengths associated with the STACORÒ samples appear to arise from two causes. Firstly, comparison of water content profiles appears to show that the STACORÒ " blows by?? (by-passes) the upper 1.5 to 2m of the sediment column, most likely due to penetration of the STACORÒ base into the very soft seafloor soils encountered in deep waters. This depth shift results in an " apparent increase?? of the STACORÒ undrained shear strength profile of 2-3 kPa. Secondly, comparison of minivane and UU triaxial tests on STACORÒ samples and rotary boring samples shows that, on average, STACORÒ samples are less disturbed and, therefore, yield higher shear strengths. Design implications are discussed, suggestions to measure penetration of the STACORÒ base are offered, and the need for alternative characterization of the first 2 to 3m below the mudline is described.

Introduction

For planned production facilities in deep water where the soils consist of soft silts and clays, the use of large diameter piston coring systems offers advantages over conventional rotary borings. These " jumbo corers?? can be rapidly deployed and recovered, obtain a large volume of continuous sample material, and the sample material tends to be of high quality. They are, however, limited in their depth of penetration. For example, the barrel length on Fugro's STACORÒ system limits recoveries to 24m, as further described below.

The Stationary Piston Corer STACOR®

Development History. Large-diameter piston corers capable of sampling up to 30m of soft sediments have been derived from the well-known Kullenberg corer widely used for oceanography purposes, in theoretically unlimited water depth. However, the degree of soil remolding during the piston sampling process is unacceptable for geotechnical engineering purposes (Borel et al., 2002).
Geotechnical Sampling and Survey of Salt Strata
Authors: Stevens Ross , Frazer Andy , Richards Mark , Stacey Andrew
Published: October 2008

FSCL has just completed an exploratory borehole to determine the suitability of ground conditions for the development of the world's first offshore salt cavern gas storage scheme. The facility, for a UK developer, is a series of sub-surface caverns, to be created in the salt strata below the Irish Sea and when built (subject to planning consent and financing), will substantially improve the security of energy supply for the UK and Irish Markets. The paper will review the detailed planning, project risks and bespoke equipment that was needed to produce excellent, 100 mm diameter core recovery down to 865 meters below the seabed.

Site investigations to circa 1000 meters below the seabed are possible and cost effective solutions can be offered against the need for oilfield drill rigs. Excellent core recovery can be achieved in salt strata and can be combined with a detailed testing programme to give a total picture of the strata investigated. This may open the door to development of future offshore salt cavern facilities.

The return of 100mm core for the full depth of the borehole allowed direct correlation of the site with other land based salt strata core samples. The core samples correlated well with the downhole testing programme data and the result provided detailed characterisation of the geology investigated. The site investigation has provided the necessary information to design the salt storage caverns and moved the project forward from a possibility to a reality. The design of the gas storage caverns has commenced and the cavern construction programme is planned to start in 2010.

The caverns will provide an initial working gas capacity of 1,200 million cubic meters, and the storage facility will substantially improve the security of energy supplies for the UK and Irish markets.

Introduction

In August 2007 FSCL undertook an exploration borehole for Gateway Storage Company Limited (" Gateway??) in the Morecombe Bay area of the Irish Sea. The purpose of the borehole was to establish the feasibility of using the underlying salt beds as an area for gas storage in solution mined caverns. This was only the second offshore site considered worldwide. The British Government has set the highest priority on increasing gas storage capability in the United Kingdom.
Augmentation of a Mooring System Through Dynamic Positioning
Authors: Sargent J.S. , Morgan M.J.
Published: October 2008

A dynamic-positioning (DP) system can be designed to stabilize and damp the motions of a vessel when moored as well as unmoored. The vessel motion dynamic characteristics are generally significantly different when the vessel is moored as opposed to unmoored and may Vary over a wide range with changes in depth, scope, pretension, mooring pattern, and offset. In the paper, a design process is described whereby the DP controller parameters and their fictionalizations are derived for smooth stable response through the operating regime of the moored vessel. Field results from a North Sea operating drill ship are compared with predicted results, and the problems that were encountered are discussed. An augmentation scheme is presented by which the DP system will automatically back up and reinforce the holding capability of the mooring system under varying weather conditions and yet remain quiescent in calm weather.

A mooring system may be deployed to extend the holding capability of a dynamically-positioned offshore drilling rig in shallow and intermediate water depths when heavy seas are predicted and vice versa. When the DP system is augmenting the mooring system, the DP system improves the damping of the moored ship in addition to increasing its holding capability, and minimizes the time required to deploy and adjust the anchor system by keeping station. For the worldwide operating offshore drilling or pipe laying rig, the combined DP and mooring systems offer unmatched flexibility and redundancy by extending the operating water depth of the rig yet providing low power requirements and operating costs in shallow water.

INTRODUCTION

Considerable discussion has been given to both mooring and dynamic positioning (DP) systems for offshore floating vessels.l, 2,3,4 However, generally speaking, in each case the discussions were limited to one system or the other at a time. This paper considers the combination of the two systems on one vessel and the manner in which the DP system can assist the mooring system.

The paper begins with a brief review of the sizing and dynamic characteristics of a mooring system. This review establishes the range of mooring system parameters which must be accounted for in the design of the DP system for effective assistance to the mooring system. Then, a design process for the DP controller is given which allows the DP system to effectively augment the mooring system in a stable fashion in all operating regimes of the mooring system.

Throughout these discussions, actual data recorded on the drill ship SAIPEM Due is used to amplify points of interest and connect theoretical with actual results. The data was collected off the coast of Italy in February 1973 and in the North Sea in Norwegian waters in May 1973. A description of the SAIPEM Due and its dynamic positioning and mooring system is given in Table I.

Before reaching the final conclusions, the paper contains a section describing less obvious benefits in using the DP system with a mooring system.
Mooring System for Atlantic Generating Station
Authors: Harlow E.H. , Harris Frederic R. , Kehnemuyi Muzaffer H.
Published: October 2008

Public Service Electric and Gas Company of New Jersey Central Power and Light and Atlantic City Electric Company in joint ownership will construct the world's first major commercial floating nuclear generating station at a location approximately 3 miles east of Little Egg Inlet on the coast of New Jersey. The floating nuclear plant named Atlantic Generating Station, will consist of two units each capable of producing 1150 MW electric net and will be built by Offshore Power Systems at Jacksonville, Florida. (Figure 1)

Each unit of plant will be constructed on a steel barge hull measuring 378 feet by 400 feet in area and having a displacement of 160,000 tons. The units will be moored within a breakwater enclosure to minimize the environmental effects of the ocean on the plants. Since the two stations will be operated in all but the most severe weather conditions over a period of forty years the mooring system must restrain their motion to tolerable limits against forces hitherto unprecedented in designing vessel moorings. Figure 2 shows the site and layout.

There are several alternative concepts for holding the rectangular platform hulls in position during the storms, tornadoes and earthquakes that a nuclear plant must be designed to withstand during its life span.The most conventional method is by means of cables, ropes or chains - members that exert horizontal forces against the vessels but allow vertical motion with the tide, as in the age-old tradition of ship moorings. Note Jin Figure 3 that all chains are of equal length, thus equalizing tensile forces, and minimizing the rotational moment imparted to a plant by uneven resistance to a horizontal force.Another method is by vertical caissons, pylons or piles whose lower portions are embedded in the sea floor and whose upper portions rise close alongside the plant so as to resist horizontal movement by vertical cantilever action. (Figure 4).A variation of this is a more or less continuous pile-supported platform, surrounding the plant. (Figure 5).A different method is by horizontal struts, pivoted at each end, which transfer forces by axial tensile or compressive stress into dead men on two sides of the plant. (Figure 6).

Any of these methods must be capab1e of withstanding forces new to berthing floating bodies -- not so much because of the size of these vessels, for many modern tankers are larger, but rather because of the severe weather conditions that must be postulated, and the safeguards necessary for the preservation of the health and safety of the public, as required for all nuclear facilities. Even during hurricanes and tornadoes these plants must be maintained in position. Ships at moorings ordinarily leave port under such conditions, and their moorings are not designed for these unlikely extremes. Two levels of security are set -- one for safe operation of the plant, and the other for safe shutdown condition. Operation must continue in storms up to the severity of a 100year hurricane, and during earthquakes of moderate intensity.
Environmental studies for Major Offshore Developments
Authors: Heckard John M. , Woodford Donald L.
Published: October 2008

Major offshore developments initiated or planned in recent years to ease the energy crisis include mono-buoys and docking islands for VLCCs and offshore nuclear power plants. Legislative requirements for environmental studies needed for licensing of such facilities is discussed as well as the scope of work needed for comprehensive environmental evaluations. Emphasis is placed on special considerations such as oil and LNG spill?s and movements, and dredging. Experience gained in ongoing studies will be of importance in planning similar projects.

INTRODUCTION

History teachers of the 21st Centurymay refer to the 1970's as a time when the United States was rocked simultaneously by an environmental crisis and an energy crisis. Future students may never appreciate the problems which the government and energy producing industries had to solve during an extremely short period of time. This paper will attempt to focus on one small aspect of that crisis period; namely, the environmental issue as related to offshore developments of the energy-producing industries.

The clash of our fuel "shortage" coupled with an increased concern for environmental protection has resulted in an interesting development. The energy related companies, particularly the power and petroleum industries, have turned their attention to the offshore in an attempt to mitigate the energy shortage. The petroleum industry, long involved in offshore developments, is entering a new era of SNG terminals, transportation of and dockage facilities for LNG, and deepwater ports for supertankers. Exploration and drilling are moving into virgin and deeper waters. Utilities and their vendors are designing offshore power plants.

Interestingly, this movement to major offshore developments is not necessarily consistent with environmental objectives. Outside of the arctic region, our most ecologically sensitive zones occur in coastal areas. Consequently, -improper construction practices or operational accidents can severely affect a valuable ecosystem. The Santa Barbara oil release incident demonstrated that, if designed and handled improperly offshore developments can aggravate environmental degradation, not arrest it.

The objective of this paper is to address environmental conservation in light of new and major offshore developments. We now have an experience record of two years and, while incomplete, it allows us to draw preliminary conclusions relative to federal requirements, the scope and depth of Environmental Impact Reports, the methodology for assessing environmental impact, and the application of earlier studies to new proposals.