bluuebunny/crossref_metadata_2025 huggingface dataset:
Site Characterization through the Integration of Geophysical and Geotechnical Data
Authors: Ehlers Clarence J. , Lobley Graeme , Spikula Daniel Robert , Brand John Richard
Published: October 2008

This paper illustrates how the integration of geophysical and geotechnical data can be used to characterize and provide an explanation for variations in soil properties across a deepwater development site.

At a deepwater offshore development site, a high-resolution geophysical survey identified the presence of current scour features at the seafloor, in-filled and buried scour features, and thinning parallel-continuous stratigraphy across the site. A subsequent geotechnical investigation was performed at three anchor cluster locations with Piezocone Penetration Tests (PCPTs) and Jumbo Piston Cores (JPCs) targeting areas both inside and outside of the scour features to assess soils variability. The investigation revealed the presence of sand in one surficial scour feature, no significant change in shear strength within a buried scour feature, the presence of deep, localized " weak?? soil zones at varying depths with sudden 25 to 30 percent decreases in cone tip resistance of up to 30 percent, and a variation in OCR across the site.

Integration of the geophysical and geotechnical data revealed that the local presence of sand across the area could not be determined by strictly geophysical data alone and required confirmation with geotechnical data. The " weak?? soil zones detected in the PCPTCPT data could be correlated to a discernable set of seismic reflectors, permitting the mapping of the depth to top of the " weak?? soil zones over the entire site. This in turn allowed the PCPTCPT data to be used to characterize these weak layers, and thus variations in shear strength, across the site. Finally, the thinning stratigraphy due to erosion observed in the geophysical data supported the trend in the OCR and associated shear strength variation across the site.

Introduction

A turret- moored FPSO with a three point mooring system is being installed in about 1100 meters of water at a deepwater oil development site. A shallow, high-resolution, AUV geophysical survey and geotechnical investigation were performed at the development site to investigate seafloor and shallow geologic features and to define soil conditions within the foundation zone of the anchors for the mooring system. The geophysical survey revealed the presence of seafloor and buried in-filled scour features that result from seafloor currents. These results were used in the scoping of the geotechnical investigation, which targeted these scour features to determine if variations in soil conditions might exist. The geotechnical investigation in turn revealed conditions that were not identified in the high-resolution geophysical survey. The results of the geotechnical investigation were then integrated with the geophysical data to identify and explain trends or correlations between the data sets.

Geological Setting

The study area is located along the north flank of a significant submarine canyon as shown by the grayscale seafloor rendering Figure 1.
Model Testing Techniques In Offshore Pipiining
Authors: Clauss Gunther , Kruppa Claus
Published: October 2008

If offshore pipelaying operations are to be simulated at model scale complete geometric similarity can not be maintained. Model pipe cross section dimensions and material have rather to be chosen in a way quite different from full scale conditions, in order to fulfill the relevant scaling laws. Using large deflection beam theory the latter are derived from first principles, allowing for gravity and elastic forces in addition to inertia forces. Recommendations for selecting model pipe material, geometry and possible liquid content are made.

For a mercury fifed Perspex pipe with insert rod model test results are presented. Static deflection and bending stresses are measured over the pipe. length and compared with theory, as a function of horizontal tension forces acting on the pipe head. Dynamic stress fluctuations are assessed for cyclic motions of the pipe head, separately for pure surge and heave

Introduction

Offshore pipe laying operations become more hazardous as depth of water increases and adverse sea conditions prevail. This is the case in present-day North Sea pipelining, where discontinuity in operations is rather a matter of seasons than of days. Under these circumstances it is of utmost importance to he able to predict probability of pipeline failure with a high degree of accuracy, or rather to define wind, sea and current conditions under which a particular pipe laying process has to be interrupted. :'-Jeedless to say that this is largely a function of the sea keeping characteristics of the pipe laying barge or vehicle.

Stress calculations and full scale measurements have so far been the instruments which helped to develop an understanding of the more important factors governing stress levels during pipe laying operations [e.g. 1,2]. Although discrepancies between theory and full scale experiment have been shown to be acceptably small under steady-state conditions, the results so far published are less conclusive with regard to dynamic response [e. g. 3,4 1. Under these circumstances it is hoped that model tests, requiring neglegible funding if compared with field measurements, may help to resolve some of the problems that have so far remained unanswered.

With a small text apparatus set up at the Institute für Schiffstechnik of the Technique University Berlin the authors have carried out some basic experiments, with the intention of showing the validity of steady-state performance calculations and indicating the importance of dynamic response assessment.

In modeling offshore pipelining the number of scaling laws is larger than can be fulfilled by adhering to complete geometric similarity. Therefore model pipe dimensions have to be selected on the basis of a compromise, the extent of which can only be assessed by deriving the appropriate scaling laws, from first principles. This will be done at some length in the following paragraphs, adding some model test results in the subsequent ones.
The Future Drilling Scenario
Authors: Strom Steinar
Published: October 2008

This paper will include:The technical basisThe work processesPlans and visions for the future

The paper gives an overview over field tried equipment, pilot tested equipment and the synergy effect when combing the different technical solutions in future drilling scenarios.

Drilltronics is an integrated control system for real time monitoring and control of the drilling process. Based on mathematical computer models for dynamic real-time analysis of the well behavior, critical limits for operational parameters like drilling fluid pump rate, trip velocity and optimal process parameters are calculated. The result of the calculations is applied directly to control drilling equipment in real time. The Drilltronics system has been field tested on the Statfjord C platform. Combining the Drilltronics system with wired pipe, decision support programs, and continuous measurements of drilling fluid parameters give synergy effects that in future may allow remote operated drilling systems.

To handle drilling through sections with large pressure variations between individual layers or between the overburden and the reservoir future drilling practice will change. Rotary steerable liner drilling systems will be available primo 2008. StatoilHydro and one of StatoilHydro's suppliers are developing a 9 5/8?? and a 7?? system. A full drilling tool package can be included in the system. By combining steerable liner drilling with the expandable pipe technology and managed pressure drilling methods, lot of to-days drilling challenges can be solved.

Background

StatoilHydro has identified Automated Drilling Systems (ADS) as one of our major technological efforts in a relatively near future. The technology as such is to a large extent at hand. It is a matter of taking the technology into operation. Our experience is that many of the drilling problems are related to human error or rather; slow response wrt corrective actions. ADS has the capability, if designed correctly, to eliminate this type of misbehaviour. It is mandatory to design the Automated Drilling Systems such that the general progress in operation is not slowed down.
Deep and Very Deep Oil-Storage Tanks
Authors: Pliskin Lucien
Published: October 2008

INTRODUCTION

Man is just beginning to anticipate the dizzying wealth hidden in the seafloor as research and production of offshore oil are increasingly developing in deeper waters. Today 150 to 200 m (500 to 600 ft) deep fields are no longer considered as exceptional. Oil companies are now contemplating production in blocks situated in various seas with depths down to 500 to 600 m (1,500 to 2,000 ft). We can expect confidently that within the next 10 years the interest of the oil industry will shift from the present relatively shallow waters to sea depths going down to, let us say, 2,000 m (6, 000 ft), giving birth to important new developments in oil research and production.

Temporary underwater storage of crude oil on the field will be one of the numerous problems to be solved, perhaps even more need fully than for shallow seas.

The Sea Tank Co. performed an active role in the development of gravity underwater storage tanks and platforms to be laid on the continental shelf. 1,2. Now we are extending our field of internet by preparing designs of deep and very deep storage tanks to be used in a range of depth from 200 m (600 it) to 1,000 m (3,000 ft).

GENERAL PRINCIPLES

A first approach of the problem makes it clear that the following principles have to be respected in order to design deep tanks.The structure is to be a gravity structure. Its stability on the seabed will be secured by its dead weight without any piling or anchorage. This condition can be easily fulfilled since the influence of wave forces is very small when the depth is larger than 200 m (600 ft). The main force to be withstood is the uplift force due to the difference of density between the stored oil and the sea water.The tank must not have to withstand external hydrostatic pressure. That means that the stored oil is to be in acupressure with the external sea water. Communication is to be provided between oil and sea. The tank will work following the water-oil displacement principle.There should be no rigid connections between the tank and the sea surface, for exploitation as well as for immersion, because of the great depth taken into account. This point is important since it leads to immersion procedures of the tanks that have to be quite different from those usually adopted for shallower seas. 1,2. In this latter case, the presence of emerging columns or towers acting as floats makes it easy to control the immersion processLast, but not least, the design of such a tank must allow safe, simple, and quick offshore operations. This is particularly important for the immersion operations that must be performed in open sea.
Kikeh Development: Sand Control Selection, Design, and Implementation of ESS
Authors: Omar Norjusni F. , Webb Tamara , Desormeaux Rusty Andrew , Moran Patrick M. , Selamat Kasim , Beare Steve P. , Jones Colin , McWilliam Kevin Charles
Published: October 2008

Discovered in 2002, the Kikeh field is located 120 km northwest of the island of Labuan, offshore Sabah, East Malaysia. The water depth at Kikeh, Malaysia's first deep water development is 1,320m. The field development consists of a dry tree unit (Spar) and two subsea production hubs, all tied back to an FPSO. Two of the three productive intervals in the development were determined to require sand control, representing about two-thirds of the field's production.

This paper documents the selection and design process for a multi-zone sand control completion with zonal isolation to meet the requirements of both the open hole oil producers and the cased and perforated injector wells on Kikeh.

The primary objectives of the system being:Maximize productivity/injectivityProvide efficient sand retentionMinimize cost and timeDesign for well life to minimize workovers and interventionsHave a large bore to maximize the capability for future selective completions

After extensive testing and evaluation was performed on the seven appraisal wells across the field, including well tests with sand control, expandable sand screens (ESS) were selected as the primary sand control method. The evaluation, coupled with extensive local ESS installation experience in both Southeast Asia and Malaysia, gave the confidence that the installation objectives would be met.

This paper describes the evaluation of sand control methods and why ESS was determined to be the best choice for the Kikeh field development. It also describes the details of each ESS type (water injector, producer, and intelligent completion) and the testing required to qualify each system.

Swelling Elastomer Packers were used to provide zonal isolation in both the injector and producer wells. The qualification and selection process for these packers is also discussed.

Significant application learnings will be discussed and, lastly, well productivity and skin results will be reported.

Introduction

Murphy discovered the Kikeh field offshore Sabah in 2002. A seven well appraisal program was conducted, which included well tests (two) with sand control. It was identified at this stage that one of the many challenges that the Kikeh field posed, was to find a sand face completion that could control the relatively unconsolidated, and poorly sorted sands present in Kikeh's geology. The system would have to be truly flexible in its multi-zone capabilities, to safely and efficiently exploit the highly laminated sands in Kikeh, while isolating the shales, throughout the expected 20-year life span of the field. As part of the design case, the system would have to provide a suitable interface for a future selective completion allowing for reservoir management as required.
Oooguruk Project Field Development Concept and Execution
Authors: Hall Jerome D. , Perry Conrad Joseph
Published: October 2008

The Oooguruk project is located in the Alaskan Beaufort Sea and consists of a 6 acre gravel drill site approximately 5 miles offshore in 4.5 feet of water. The drill site is connected to an onshore facility by a complex flowline system consisting of a 5.7 mile subsea buried flowline bundle which transitions onshore to a 2.3 mile traditional North Slope above ground flowline support system. Approximately 38 horizontal extended reach wells will be drilled into two horizons to develop the field. Drilling commenced in December 2007 and the field is scheduled to come online in 2008.

This paper generally describes the Oooguruk field development concept, project execution strategy and the challenges faced during planning and construction. Details regarding island design, environmental design criteria, pipeline design and construction, and drilling rig capabilities are included in other technical papers.

Introduction

In the winter of 2003 (January - April), Pioneer Natural Resources (as operator) and Armstrong Oil & Gas drilled three wells (Ivik No. 1, Oooguruk No. 1, Natchiq No. 1) in Harrison Bay, northwest of the Kuparuk River Unit Field. Pioneer determined that the resource was economic to develop after analyzing the results from these wells and subsequently acquiring well and geological data over the area. Pioneer would develop two separate reservoirs called Kuparuk C and Nuiqsut from a single drilling center.

The development plan consisted of three major components: an offshore drill site (ODS); an onshore interconnect and production support facility (OTP); and a system of flowlines, power cables and communications cables connecting the onshore and offshore facilities. Three phase production would be delivered through an interconnect to existing infrastructure at the Kuparuk River Unit (KRU) drill site DS-3H operated by ConocoPhillips. The location of these facilities is illustrated in Figure 1.

Five wells, three producers and two injectors, would be needed to recover the Kuparuk reserves in the original plan. A total of 33 wells, 18 producers and 15 injectors, would be drilled to recover the Nuiqsut reserves. The estimated recoverable reserves for the project were between 50 and 90 MMBOE. The depletion plan for both reservoirs would require long horizontal wells. Recovery would be enhanced by incorporating water-alternating-gas (WAG) injection capability and by installing electric submersible pumps (ESPs) in each of the production wells. Since the drill site would need to be self sufficient due to isolation during certain times of the year, a Class 1/Class 2 disposal well would also be drilled.
Monitoring of Floating Offshore Installations' Wave Frequency Motions
Authors: Liagre Pierre , Gupta Himanshu , Banon Hugh
Published: October 2008

Severe hurricane activity of 2004 and 2005 has reminded the industry of the importance of integrity management of floating structures. One of the main methods used in assessing the fitness of a floating system after a hurricane event, is to evaluate the actual behavior of the hull, mooring and riser systems versus design assumptions using high and low frequency motions of the platform. As a result, vessels are typically outfitted with inertial six degree-of-freedom inertial navigation systems (INS) and differential global positioning systems (DGPS). Common practice is to use INS for wave frequency measurements whereas DGPS is used for low frequency drift motions.

Combining INS and DGPS signals into a single signal covering the entire frequency range requires the choice of appropriate cut-off frequencies for both instruments and the use of advanced filtering techniques. Both tasks are usually source of much debate.

The objective of this study is to demonstrate that modern DGPS have the same ability as INS to measure floating systems wave frequency motions and provide a redundant set of measurements that users can use to verify the accuracy of the INS data.

Using marine data collected on BP Holstein truss spar during hurricane Katrina and BP Atlantis semi-submersible during a 2006 winter storm, the wave frequency motions extracted from the DGPS signals after correcting for pitch and roll motions show very good agreement with the INS signals in the time domain.

Since both vessels are outfitted with DGPS of varying accuracy, the accuracy of these different systems is discussed. The results are also presented as a function of the sea states to demonstrate the ability of DGPS in the smaller sea states. The results of the study show that the DGPS can be used in the wave frequency motion ranges, which is typically been measured with INS. The results presented in this paper help in better understanding and interpretation of the field data and lead to better practices in the integrity management of offshore platforms.

Introduction

BP's fleet of deepwater floating offshore installations (FOIs) in the Gulf of Mexico include a tension leg platform (Marlin), three truss spars (Horn Mountain, Mad Dog and Holstein) and three semi-submersibles (Na Kika, Thunder Horse and Atlantis) moored in water depths ranging from 3,250 to 7,070 feet.

In the last five years, BP has led a significant effort to preserve and analyze the data collected by comprehensive marine monitoring systems installed on each of these FOIs. Even though the six degree of freedom motions of these three types of floating systems have been studied extensively during model tests and numerical simulations, a lot of interest is placed on capturing their true motions for several reasons:Comparison to predictions of fully coupled numerical models.Calculation of actual fatigue accumulation in the risers (H.H. Cook, 2006)Post hurricane investigation.
Use of Analytical Models and Monte-Carlo Simulation for Quantification of Uncertainties Associated With Gas Production From Hydrate-Capped Gas Reservoirs
Authors: Gerami Shahab , Pooladi-Darvish Mehran
Published: October 2008

A large number of studies are underway to evaluate the possible role of gas hydrates as a potential energy resource. While one class of such studies involves characterization and quantification of hydrates in geological setting suitable for exploitation, another class of studies involves development and use of mathematical models to estimate hydrate recovery under different operating conditions. Quantification of the hydrate resource using geological and geophysical techniques, while continuously improving is subject to very large uncertainties. A meaningful development plan should incorporate the associated uncertainty, requiring large number of simulation runs. This is impractical using currently available models, as (i) most of the available numerical models are not commercially available and (ii) setting up and running of these complex models is quite time-consuming. Furthermore, the accuracy associated with these models is not necessary, because the input parameters could vary over a wide range. Recently, the authors have developed an analytical model for prediction of gas production from hydrate capped gas reservoir. In this paper we present of this model and then use it along with Monte Carlo simulation to capture the effect of uncertainty in hydrate and reservoir parameters on the performance of the hydrate capped reservoir. The usefulness of these analytical models for fast engineering calculations, particularly those that are conducted at the beginning of the life of reservoirs (and are based on very limited information that do not warrant numerical simulation) is shown using a hypothetical case studies.

Introduction

The demand for energy has stimulated the development of the unconventional gas resources (such as gas hydrates) which are occur in enormous quantities around the world. Gas hydrates tend to form in two geologic settings:on land in permafrost regions, andin the ocean sediments of continental margins.

During the last decade a number of projects have been conducted for detection and characterization of the hydrate-bearing formations, drilling, logging, coring, production testing and mathematical modeling of hydrate reservoirs, with the eventual objective of assessing commercial producibility of gas from hydrate resources.

One type of hydrate reservoirs that are thought to be most amenable to production are those that overly free-gas bearing sands (i.e. hydrate-capped gas reservoir). Makogon9 reports that in the Messoyakha reservoir, where part of the reservoir lies below the base of the hydrate stability zone (and contains free gas), production of the lower conventional free gas led to the decomposition of the overlying hydrates by depressurization. Another example is the Eileen accumulation in Alaska25, where production testing using the depressurization method is underway.
Borehole Pressure Coring and Laboratory Pressure Core Analysis for Gas Hydrate Investigations
Authors: Humphrey Gary D.
Published: October 2008

Marine gas hydrate investigations, whether they be conducted as resource evaluations for national governments, as geohazard assessments for major oil companies, or as climate-related scientific endeavors funded through international funding agencies, have begun to develop common strategies. Gas hydrate can occur up to several hundred meters below the sediment-water interface, depending on the water depth and thermal gradients; consequently, for a full assessment of gas hydrate occurrence, nature, distribution, and concentration, samples must be obtained through drilling and coring. Samples retrieved and analyzed at full in-situ pressures using pressure coring techniques are the only way to ground truth the findings from other techniques, including physical and chemical analysis of non-pressure cores or the interpretation of seismic and borehole log data.

Thermal imaging of non-pressure cores provides an immediate and valuable method for observing the endothermic behavior of dissociating gas hydrate but does little in itself to characterize the gas hydrate morphology or concentration. Porewater analysis techniques rely on the freshening of porewaters when gas hydrate dissociates, generally measured via chlorinity; these analyses provide excellent spot measurements of the concentration of gas hydrate if the background chlorinity profile is well established, but tells the investigator little about the nature of the gas hydrate. Furthermore, in lakes or nearshore environments where the porewaters may have very low or highly variable chlorinities, this technique will be far less reliable or accurate. Only methane mass balance calculations from depressurization of cores recovered at full pressure provides the benchmark or " gold standard?? for gas hydrate concentration assessment.

Measurements of the density and volume of pressure cores through X-ray imaging and gamma densitometry have removed errors in estimation of pore volume, making this methane mass balance technique accurate and robust. Non-destructive testing and analysis of gas-hydrate-bearing cores at in-situ pressures and temperatures also provides detailed information on the in-situ nature and morphology of gas hydrate in sediments. The detailed profiles of density and VP, together with spot measurements of Vs, electrical resistivity, and hardness, provide background data essential for modeling the behavior of the formation on a larger scale. X-ray images show the hydrate morphology in relation to the sediment, which will control the kinetics of methane release. Gas-hydrate-bearing pressure cores subjected to X-ray tomographic reconstruction provide compelling evidence that gas hydrate morphology in many natural sedimentary environments is particularly complex and impossible to replicate in the laboratory.
ISO Floating and Fixed Standards ISO 19902, ISO 19903 and ISO 19904
Authors: Galbraith David Ninian , Wolfram Bob , Leivestad Steinar
Published: October 2008

The ISO 19900 series of international standards comprises different levels of standards, ISO 19900 giving General Requirements for offshore structures, ISO 19901 giving Specific Requirements for various aspects of offshore structures that have relevance to different types of offshore structure (in several parts), and then a series of standards giving requirements for the different generic types of offshore structure.

Of this last category, three have now been published; ISO 19902 for Fixed Steel Offshore Structures, ISO 19903 for Fixed Concrete Offshore Structures, and ISO 19904-1 for Floating Offshore Structures. The development of these three International Standards is described in this paper, which gives details of the scope, provenance, key features, contents, and organization of each of the three standards.

ISO 19902 is a development of API RP2A LRFD, but in the preparation of the International Standard a number of research and Development Joint Industry Projects (JIPs) were commissioned, and the enhanced knowledge from these projects, together with knowledge and experience from the offshore operating areas around the world, have been incorporated.

ISO 19903 is a new and somewhat different standard, as it deals with the entire task of engineering a concrete offshore platform facility, with mechanical systems, etc., rather than just the detailed design of its concrete members. To a large extent the standard relies on the existence of national or regional standards for design of concrete structures that can be safely used in an offshore concrete structure, as such structures can range from quite simple to really sophisticated structures.

ISO 19904-1 is a new standard entirely. It is based partly on API RP 2FPS, which was developed in the same timeframe, but includes concepts taken and harmonized from North Sea practice represented by then HSE and NPD guidelines and from class rules. Some text was written specifically for this standard, particularly the clause on structural integrity monitoring and various sub clauses elsewhere that represent lessons learned in from industry experience during the period in which the standard was written.
Greater Plutonio:BP's First Operated Project in Angola
Authors: Brown Sally A.
Published: October 2008

Greater Plutonio is BP's first operated project in Angola and enables BP to establish a prominent footprint in country. It also provides the base to build future developments as well as creating a local energy company which will deliver sustainable long term benefit to Angola. Greater Plutonio is located in Block 18 which covers 4,880 km2 approximately 150 km from the Angolan coast. The plan calls for the development of 5 fields - Plutonio, Cobolto, Paladio, Cromio and Galio. The development concept is for a large scale FPSO capable of processing 240,000 mbd, with a storage capacity of 2 million barrels. The FPSO being linked to 43 subsea wells at water depths between 1200 - 1500m via a complex riser tower system and an extensive subsea architecture of flowlines, umbilicals, manifolds, jumpers and trees. This paper summarises the challenges, successes, learning's and their application for future developments. It is supplemented by companion papers covering specific areas of the development from sand face to facilities (OTC - 19673, 19674, 19675, 19676 and 19669).
Subsea, Umbilicals, Risers and Flowlines (SURF): Performance Management of Large Contracts in an Overheated Market; Risk Management and Learnings
Authors: Oldfield Gerald
Published: October 2008

Greater Plutonio is BP's biggest subsea project worldwide and consists of 5 separate fields in 1500m of water, over an areal extent of 4,880km2, 150khm offshore Angola in Block 18. One of the many challenges of the development concept was to deliver the complex Subsea production system, Umbilicals, Risers and Flowlines (SURF) which will connect the 43 subsea wells to the spread moored 2 million barrel storage, new build FPSO with production capacity totaling 240,000 barrels per day, in an integrated manner over a fast track schedule to allow a safe, efficient and phased start up, with rapid production ramp up. The challenge was heightened by a commitment to deliver the highest level of local Angolan content ever achieved to date.

This paper will address the challenges in project managing SURF projects of this size and highlight some of the unique aspects and challenges of this development, particularly given its Angolan content and market conditions by applying risk management principles and applying learning from previous deepwater projects in WAF, GoM and West of Shetland It is supplemented by companion papers covering specific areas of the development from sand face to facilities (OTC - 19673, 19674, 19675, 19676 and 19669).

The key points and challenges to note about the SURF system are:43 wells with flexibility and expandability in the subsea architecture for up to 88 wellsSingle compliant riser tower with condition monitoring system, fabricated and assembled in AngolaHighly dynamic seabed flowlines subject to high lateral buckling forces and end expansions107km dynamic and static production control, chemical injection and data acquisition umbilicals150km production insulated flowlines, water injection plastic lined, gas injection and service flowlinesSimultaneous subsea construction, commissioning, start up, production and offtake operationsProvision for a future subsea gas export offtake

The project was led by a core BP Project Leadership Team supported with directly hired contract staff co-located to major contractors' offices to work in integrated teams, through FEED, system engineering, detailed design, procurement, manufacture, fabrication, installation, commissioning, start up and production. Throughout the project functional departments provided expert technical support and integrity assurance with formal reviews and specialist advice.

BP partnered with their key contractors to identify key project drivers, issues and challenges, and then mapped out a plan to systematically improve safety performance, especially in Angolan fabrication yards and for offshore simultaneous marine construction and commissioning operations.

This partnering approach increased ownership and ensured that improvements were embedded in the contractor's systems and procedures, as well as enabling the contractors to take advantage of the significant safety resources/experience available within BP.
Emerging Geophysical Technologies: Downhole Microseismic Reservoir Monitoring (MRM): A New Instrumentation Technology for Monitoring the Digital Oilfield
Authors: Wilson Stephen , Le Floch Gilles , Jones Rob
Published: October 2008

As a seismic technology, the microseismic technique is unique in that it provides direct 4D information about the stress changes in the reservoir that are caused by injection and production operations. These changes in stress are common to all producing reservoirs. As a consequence reservoirs emit packets of seismic energy and information about all the small slip events triggered by oilfield operations.

It is possible to detect tiny slip magnitudes corresponding to only a few microns of movement. Such movements may correspond to slip on a fracture, movement within the cement, slip on bedding, the opening of a frac or even precursory slip in the completion. Mapping these changes in both space and time provides a unique insight into stress change in the reservoir, the overburden and the well stock. Although this activity is triggered by oilfield activity, the emitted energy derives from strain energy stored within the rock mass.

Offshore wireline deployments have shown the value of the microseismic technique and more recent onshore pilots have emphasized the value of permanent sensor installation for reservoir management (Jones et al., 2004).

Until very recently microseismic monitoring has been constrained by the requirement to deploy seismic sensors within inactive monitor wells. The recent availability of seismic technology that can be deployed in live wells represents a step-change in our ability to seismically monitor hydrocarbon reservoirs. Such monitoring can now take place even during active injection or production and in offshore environments where monitor wells are rarely available.

The key stakeholders in terms of deploying and utilizing the value of this technology include asset managers, engineers involved in production, drilling and reservoir management, together with the seismologists who process the data and deliver value to the reservoir engineer.

Microseismic reservoir monitoring represents a new deep-reading technology to understand reservoir processes and thereby better optimize reservoir management and better target field development investment with the goal of producing more oil at a reduced cost. The installation of appropriately designed systems also offers the prospect of combining microseismic monitoring with conventional downhole reflection seismic technology in the form of VSP on demand (Wilson et al., 2004).
Improved EPC Integration Management for FPSOs
Authors: Kim Jung-Goon
Published: October 2008

The paper presents a ship-builder focus on integration management in EPC contracts that combines the requirements of client (owner), subcontractor and vendor, minimizes cost and schedule delays and utilizes international standards in product delivery. The interface issues have been traditionally identified as the challenges and risks in the construction process. SHI presents the refinement of construction management method based on Nexus-1 FPSO as it applies lessons learned in subsequent projects.

The methods employed in integration management and its' elements are presented. They include alignment with international project management practices (PMI), presence of dedicated integration (interface) manager for full project lifecycle, use of a common interface procedure and interface register and protocols, integration workshops and ongoing integration assessment, utilization of formal processes that enhance communication and understanding in multi-national projects, focus on communication with vendors and subcontractors, continuous monitoring and control for optimization, focus on efficiency of hull / topsides interface to name just a few.

Effective management integration methods ensure reduced risk, savings in time and cost, and provide efficient design that minimizes interface problems between all involved parties.

Contents

1.0 Introduction 2.0 The Generic FPSO Concept & Specification 2.1 Dimension and Characteristics 2.2 Process Description 2.3 Major Design Parameter (Topside) 2.4 Module Description 2.5 Safety and Environmental Considerations 2.6 Future Design 3.0 Classification, Rules and Regulations 3.1 Flag States 3.2 Classification 4.0 Scope of Works 5.0 EPC Projects Integration Management 6.0 Project Phases and EPC Execution Principles 7.0 Interface Management 8.0 Project Execution 8.1 Overall Schedule 8.2 Detail Engineering Phase Challenges 8.3 Major Issues for Regulatory and Safety Requirements 9.0 Conclusion
High Integrity Pressure Protection Systems (HIPPS) Development for the Gulf of Mexico: Update on Deepstar, API 17O and Industry Developments
Authors: Lindsey-Curran Christopher J.
Published: October 2008

As oil and gas exploration has moved into increasingly deep water in the Gulf of Mexico, the potential to find increasingly higher pressure and higher temperature reservoirs has increased. High Integrity Pressure Protection Systems (HIPPS) are seen as essential for development of these prospects. The paper will cover the key differences between applying HIPPS in the Gulf of Mexico compared to North Sea applications, as well as the associated regulatory process involving the Minerals Management Service, the regulatory authority in the Gulf of Mexico. It will also provide an update on API 17O and industry developments.

1.0 Introduction

The installation of High Integrity Pressure Protection Systems (HIPPS) has been limited to the North Sea for subsea applications. As exploration and drilling have moved into deeper water in the Gulf of Mexico, discoveries have increased in pressure and also temperature resulting in an increased need to address the application of HIPPS technology in this region. Although there are a number of subsea systems operating successfully in the North Sea, it has not been possible to transfer this experience directly to the Gulf of Mexico without a significant amount of ground work. This paper discusses the key differences, the impact on subsea architecture and the work with the regulatory authority associated with HIPPS technology.
Developments in Underwater Technology and the Role of the Learned Society
Authors: Gallett Ian Niacholas Leigh
Published: October 2008

This paper reviews the whole round of technology used underwater and looks to the future direction each of the technologies is going. It also seeks to bring out areas where these technologies can cross-fertilize and where diversification of the skill sets developed can be used elsewhere. Examples are the use of experience gained in the oil & gas sector being used in the offshore renewables area and the retro-fitting of technologies developed for autonomous underwater vehicles into ROVs. The paper concludes with a review of how a learned society, such as the SUT, can contribute to the development of subsea technology and its global and sectoral diversification.

Introduction - Underwater Technology

There are many uses of technology subsea. The main purpose of this presentation is to highlight these and to indicate developments in these which are important to the future efficient and cost effective extraction of resources to be found underwater. These are mainly described in the oil & gas sector, but it is also emphasised where the technologies and skill sets developed in this sector can be utilised elsewhere and where developments are taking place in nascent sectors which have a strong relationship with oil & gas. The role of a learned society, such as the Society for Underwater Technology (SUT) is important in disseminating knowledge vertically within a sector, but is also vital in the transfer of knowledge across the perceived boundaries between sectors.

For convenience, this presentation is broken up into six operational areas of interest and two ones that can be described as enabling technologies. The latter two find applications across many if not all of the operational ones. The six operational areas are:Subsea Engineering & OperationsMarine Renewable EnergiesOcean ResourcesOffshore Site Investigation & GeotechnicsEnvironmental ForcesUnderwater Science

The two enabling technologies are:Diving and Manned Submersibles (ie man underwater)Underwater Robotics (ie machine underwater)

Each will be dealt with in turn.
Installing Disconnectable Turrets and Offloading Buoys
Authors: Green Brian Kevin , McClure Keith
Published: October 2008

Cost and time pressures on installation and field operation, and health and safety concerns are encouraging new methods of subsea connection that reduce the cost and complexity of pile and buoy installation, yet also provide on-going operational benefits. This paper reports on how installing disconnectable turrets and offloading buoys is made quicker and easier, using subsea mooring connectors based on ball and taper technology, within the primary mooring lines.

The use of FPSOs with STP (disconnectable submersible turret production) or BTL (bulk turret loading) buoys has created a demanding environment for chain and shackle installations resulting in increased time, equipment and vessel costs. Subsea mooring connectors enable installation of piles without the need to use large vessels and no requirement for diving operations, resulting in a safer operation. Mooring pile installation and mooring line installation can be carried out in different campaigns and from different vessels.

Subsea connectors reduce the number and size of tugs required to facilitate hook-up of STP and BTL buoys; tugs with minimal bollard pull are used to manoeuvre the buoy to facilitate hook-up of the last mooring lines. No diver intervention is required to carry out the subsea connections. Safety concerns that arise from making up connections on the back deck of installation vessels are avoided. Moreover, disconnectable turrets and offloading buoys can be installed later in the project cycle; and with simpler mooring line arrangements, thus avoiding damage to other structures in the field and the environment such as coral reefs, during tow out.

In a recent development, subsea connectors featuring an on-board CCTV have been used to remotely find and connect a mid water arch buoy, providing easy retrieval without the need to search for a floating rope, ROVs and diver intervention. The connector systems allow an operator to abandon turrets in the event of tropical storms or temporary abandonment, retrieving them later once the vessel is back on location.

The paper will also touch on the implications of subsea mooring connectors on subsea field architecture with particular reference to the more efficient installation of Mid Water Arch Buoys.

Introduction

Installing disconnectable turrets and offloading buoys has traditionally relied on chain and shackles methods of mooring. However this approach can be costly in terms of the numbers and types of vessels needed for pile installation and buoy tow-out and connection. In addition the surface connection of the chains under-tension, can pose a significant health and safety hazard.
Analytical Determination of Ship Motions and Mooring Forces
Authors: Bomze Herman
Published: October 2008

This paper describes a computer program which calculates the three translator motions heave, surge and sway - and the three rotary motions - roll, pitch and yaw - of a ship, represented by a rectangular block, moored in regular waves of given height and period approaching from an arbitrary direction. Accelerations, velocities and displacements and the forces in up to 30 non-linear mooring lines or breasting dolphins are printed out at successive small time intervals during passage of the waves, using first order linear wave theory and the Froude-Krylov hypothesis. The ship is represented as a rectangular block of equivalent displacement and is partitioned into a number of elements by equally-spaced planes parallel to its length, width and height dimensions. The Froude-Krylov hypothesis and the Airy Theory are used to calculate inertia, pressure and drag forces. The six degrees of freedom of the floating rigid body are represented by a system of six equations of motion which take into account all the forces acting on the body at a given instant, including hydrodynamic forces, forces in the moorings and external forces due to tornado, wind or current. A solution for the simultaneous accelerations in the six degrees of freedom is obtained by Newmark's "beta" method, from which velocities, displacements and mooring forces follow directly. The latest set of mooring forces is used to recalculate the accelerations until convergence is obtained to a predetermined tolerance, usually after only a few cycles.

INTRODUCTION

From the time man first went to sea in ships, naval architects have been concerned with the motions of a ship in a seaway. Their concern stemmed from considerations of safety of the vessel and its cargo, speed, passenger comfort and economy of propulsive power. Only relatively recently has the civil engineer become interested in the problem of ship motions. His concern was aroused by the need to locate ship berths in ever increasing water depth which brought with it increased exposure to ocean. waves. Although the design of mooring facilities tends to be governed by berthing impacts, exposed locations require that the designer also examine the forces on the ship and on the mooring structures induced by waves which may arrive while the ship is still moored at its berth rather than underway in the relative safety of the open sea.

The interaction between the flow of water around a floating body and the motions of that body is so complex that in the past greater reliance had to be placed on model tests rather than on mathematical analysis. While confirming model tests will continue to be required, the mathematics for the solution of the ship motion and mooring forces problem has made sufficient progress to provide a reasonable basis for the design or mooring facilities.

Wilson (1959) showed that a fairly accurate solution for ship motions in a monochromatic head or beam sea could be obtained by making assumptions which simplify the problem considerably.