bluuebunny/crossref_metadata_2025 huggingface dataset:
Meren Field, Nigeria: A 4D Seismic Case Study
Authors: Lumley D.E. , Nunns A.G. , Delorme G.E. , Adeogba A.A. , Bee M.F.
Published: October 2008

In 1996 Chevron Nigeria Ltd. acquired a repeat 3D seismic survey over the Meren Field, offshore Nigeria, for time-lapse seismic reservoir monitoring purposes. By comparing the 1996 survey with a Chevron legacy 3D survey dating from 1987, the time-lapse 4D seismic images show evidence of significant reservoir fluid changes during the 9-year interval1. A detailed 4D seismic interpretation of the Meren E-05 reservoir sand in Block 2, based on horizon amplitude extractions from the 1987 and 1996 cross-equalized seismic cubes, is consistent with well production histories at 22 of the 24 wells that penetrate the reservoir. The remaining 2 well inconsistencies are possibly due to limited seismic resolution. 1D seismic modeling from Meren well logs shows that waterswept oil zones can decrease in impedance and seismic amplitude by as much as 40% from original oil-full conditions. Using the modeling results to calibrate the seismic images to the well production data, map estimates of injected water and bypassed oil are created. The 4D seismic interpretation suggests that water from two injectors has very preferential channel-flow characteristics, indicating a strong stratigraphic flow-unit overprint on the reservoir not previously discernible from well data alone. In addition to identifying pathways of injected water flow, the 4D seismic interpretation has identified three areas within the E-05 that may contain major bypassed oil reserves, and has better defined the leaking or sealing nature of reservoir faults.

Meren Field, Nigeria

The Meren Field is located southeast of Lagos, Nigeria about 10 miles offshore in 50 feet of water. Meren is one of the largest and most prolific producing oil fields in the area. There are six major fault blocks, each block containing up to a dozen productive reservoir sands, with more than 40 total producing sands. The total estimated original oil in place is 1.8 billion barrels, of which about 750 million barrels have been produced to date. Recovery factors are typically high in reservoirs with good pressure maintenance through water injection or aquifer support. Meren was discovered in 1965 and first production began in 1968. Over 80 producer and injector wells have been drilled to date. Current production from the field is about 85,000 barrels of oil per day. The productive sands range in depth from 4,800 to 9,500 feet. The reservoirs are part of a set of sand-shale retrograde/prograde near-shore depositional sequences. Many of the reservoirs, but not all, are below bubble point and have gas caps that have enlarged or decreased during production, which can complicate 4D seismic monitoring of oil and water. The oil is fairly live seismically at Meren with a solution GOR on average of 400 scf/stb. This gives a good compressibility contrast with reservoir brine that is advantageous for seismic monitoring of oil-water saturation fronts.

Seismic Data Acquisition

The first Meren 3D seismic survey was shot in 1987 as a Digiseis survey.
A New Technique for Acoustic Data Analysis
Authors: Nelson Joseph L.
Published: October 2008

INTRODUCTION

A new technique for the spectral energy analysis of acoustic data taken during bottom and subbottom profiling surveys will be described. This technique is intended to be an additional tool for the evaluation and analysis of subbottom data.

Single frequency acoustic systems [sonars] are widely used for bottom and subbottom profiling in shallow and deep waters. The system consists of a pulsed transmitter, a transducer or transducers for coupling acoustic energy into and out of the water, a receiver and a display such as a graphic recorder.

A single transducer may be used as both the transmitter and receiver, or separate units can be employed. Transducers may be mounted to a ship's hull, or in towed vehicles [fish].

The echoes from the bottom and subbottom features are displayed on the recorder for immediate evaluation, and can also be recorded on magnetic tape for further processing.

It is the purpose of the new analysis technique to extract additional information from these echo signals to allow more accurate identification of features and properties of the bottom and subbottom.

This method, when used in conjunction with bottom sampling and coring operations, can establish the basic reference datums for a computer-aided automatic analysis system. When fully operational, this system with automatically identify subbottom materials and geologic features.

The data display of conventional profiling recorders will be reviewed and then the basis of the new technique will be presented. The new display resulting from the energy analysis will be examined using acoustic signals from several sources, and the basic computer aided analysis system will be described.

ACOUSTIC PROFILING

Basic System Charts

Classically, the data gathered from subbottom surveys is presented as a profile chart shown in Fig. 1. These records are interpreted and analyzed relying on prior experience in reading the records) and correlation with core borings is used to identify specific materials.

The abscissa [horizontal axis] is the linear distance along the survey track and is a function of the speed of the transducer over the bottom. The ordinate is the time for the echo to return to the receiving transducer and is calibrated in depth [feet or fathoms] of the reflection below the transducer. The depth calibration is based on a sound velocity in water. The depth calibration is corrected for the two-way travel of the sound energy from transducer to bottom to transducer.

The intensity of the echo is a function of both the reflecting material and the acoustic properties of adjacent strata. Therefore) in order to completely identify a particular subbottom layer) it is necessary to evaluate the echo from that layer of interest in conjunction with the echoes from overlying material. These echoes are qualitative indications of the acoustic parameters of the strata. The analysis and interpretation of these parameter must start from scratch, due to the lack of any established standards against which new data can be evaluated.
60 Days to Success (Critical Program Management)
Authors: Scott R.A. , Duell Ken
Published: October 2008

This paper will describe the fast track method utilized by senior management of both EEX and Cal Dive to meet very critical scheduling requirements for the abandonment of the Garden Banks 388 (Cooper) Field in 2100 feet of water. Being the first deepwater abandonment, several ground-breaking procedures were employed, which included innovative economic considerations as well as challenging operational and contractual hurdles. The procedures utilized at Garden Banks 388 can be employed on certain abandonment projects where there is a requirement for production to be run up to the time limit of regulatory periods prior to shut in and removal of the facility. Commencement of the offshore activities utilizing well-proven traditional methods while specific procedures for each phase of the works is implemented independently. By limiting the number of personnel in the decision making and approval process, by instilling flexibility and excellent communications between the contractor, operator and regulatory parties a project can be moved forward with confidence on a true fast track basis. This enables offshore operations to commence prior to all of the typical project elements being in place and allows for rapid infield decisions and change in operational procedures when required

Discussion

In 1998, EEX Corporation (EEX) was facing a challenge that no one in the oil industry had faced before, the decommissioning and abandonment of a producing field (Figure 2) in water depths of 2,100 feet and deeper. EEX management reviewed their options on how to move on this formidable task. Should they hire an engineering company to work up the plans? Should they study it at EEX, come up with detailed plans and bid out the detailed work? EEX knew what had to be done. As the Nike-ism says "Just Do It!"

EEX had already begun the regulatory process in August 1998 and as of March 1999 the Minerals Management Service (MMS) permits had not been finalized or approvals granted for the project. Management at EEX knew that the permits would be granted but it was a matter of time when it would happen. EEX's hope was to remove the Floating Production Facility (FPF) and Free Standing Riser (FSR) before the hurricane season reached its peak in late August or early September.

Selection of the Main Contractor

The task seemed overwhelming but EEX had a secret weapon on their side... Trust. EEX management had decided up front that they were going to handle this project different from how other companies in the deepwater areas would handle it. Their trusting and open discussions with the MMS were working well at advancing the permitting process. Couldn't they use the same tact to get the plans for the fieldwork put together and executed? Management thought it was worth a try. EEX management and staff met to determine the essential needs for the project.
Troll Pilot Control System: Advanced Control System for a Subsea Separator
Authors: Baggs Chris , Kent Ian , Allen John
Published: October 2008

This paper describes the design of a subsea control system for control and monitoring of a subsea water separator, for use by Norsk Hydro in the Troll field, offshore Norway. The separator uses a gravity separator to extract water from produced fluids. The water is then re-injected into a disposal well, via a subsea variable speed pump.

The control system comprises topside computers and fibre optic communication, together with a subsea control module for control of separator valves and monitoring of pressure, temperature and separator water level sensors. The system operates in a closed loop, with water level measurements resulting in control of the water injection pump speed.

Key feature is fibre-optic communication at 1.5 MHz, primarily for immunity from interference from the pump electrical supply, operating in half duplex mode on a single fibre. Full redundancy is provided for all electrical and optical equipment including sensors with 4 redundant communication channels.

The level sensors use a combination of technologies to give accurate and reliable, long-term measurements in the hostile separator environment.

A redundant high-speed general-purpose Fieldbus (DC power and communication) is provided subsea for connection of complex sensors (level sensor) plus others as required in the future.

Topside computers, which are fully integrated with the Troll C facility network, provide analysis of the data from dual level sensors, to detect the Interfaces between water, oil and gas, in the presence of emulsions and foam. This is used to control the pump speed in order to maintain a constant water level in the separator.

The equipment began integration and land trials in the last quarter of 1998, and was installed subsea in September 1999.

INTRODUCTION

The Troll field in block 31/2 and 31/5, 100 km west of Bergen, contains large quantities of oil and gas, together with significant amounts of water. It was decided therefore to install a subsea separator in order to avoid installing additional topside processing equipment and to maximise useful flowline capacity. Figure 1 shows the location of the installation and a diagram of the subsea arrangement, together with some basic field details.

The separator is a self-contained seabed unit, based on ABB Offshore Systems' SUBSIS technology and is located between two conventional production manifolds and the Troll C platform.

PROCESS SYSTEM

A simplified P&ID of the separation process is shown in figure 2. Essentially water, oil and gas flow into a large gravity separator tank, where the water sinks to the bottom and the oil floats on top, with gas filling the void at the top. The oil and gas flows over a weir plate and flows on to the Troll C platform under the driving pressure of the wells. The water is drawn out of the bottom of the tank and is injected into a disposal well by a large 1.6 M Watt subsea pump. Figures 3 and 4 show the pump and overall separator assembly.
Corrosion Control In the Splash Zone
Authors: Richardson Murl R.
Published: October 2008

Offshore platforms, by the very nature of their existence in salt water, are vulnerable to corrosion. A particularly troublesome area of this costly phenomenon is the portion of the platform legs or risers exposed to the direct lapping of the waves at water level: the splash zone.

There are several methods by which metal corrosion can be controlled, including complete isolation of metal from the harmful elements which attack it. Several oil-producing companies have already demonstrated the effectiveness of a relatively indestructible neoprene cover on offshore platform legs to seal off the splash zone from corrosive attack.

The primary purpose of this report will be one of information. I propose to show the reasoning behind my company's selection of neoprene as the best possible isolator for platform legs and risers.

This will be accomplished by a discussion of some of the development work done in this area, including laboratory tests, and on-the-job installation tests. Also included will be a discussion of the economic advantages of using neoprene for corrosion control.

Since a good bond between metal and rubber is of prime importance in isolating the legs, I will discuss the aspects of rubber-to-metal adhesion, with special emphasis on surface preparation of the metal, application of the cement and rubber, and the vulcanization process itself.

It is anticipated that the information contained in this report is only the beginning of the contribution of neoprene coverings to the technology of offshore production in the future.

EARLY DEVELOPMENTS

Corrosion by the sea and nature is an everyday occurrence, and many techniques have been tried in attempting to control this corrosion, but until lately none have been relatively successful.

In 1965, we at Oil States Rubber Company were asked by a major oil company to attempt to solve the problem. Our approach was to completely isolate the metal from the corrosive tendency of the sea by the use of a synthetic rubber. The various synthetic rubbers were studied to find the best material that could be used in the given application.

The main requirements considered were:bondabilityresistance to sea water,resistance to oxygen and ozone,good tear strength, andabrasion resistance.

Two types of synthetic rubber met these requirements: neoprene and ethyleneproylene terpolymer.

(In that same year. 1965, Oil States' first corrosion control material was applied to a riser and still is in service and showing no bad effects from the elements and no cracking upon inspection.)

THE ALTERNATIVES

Ethylene-propylene terpolymer, which has an ASTM designation of EPDM, was ultimately eliminated. Although this material held up good in testing, there were difficulties encountered in the buildup process. It did not have enough building tack, at the time, to allow us to use it in production. This EPDM rubber was relatively new, then, and little was even known about its performance in sea water.
Dry-Tree Semi for Brazil and Gulf of Mexico
Authors: Often Ola , Ludwigson Robert , Carlsen Henning
Published: October 2008

A large number of dry tree concept's have been proposed to the offshore industry over the last few years for application in deepwater fields in the Gulf of Mexico, West Africa and Brazil. Looking into the details of these concepts, they all to a varying degree apply new and unproven technology that will increase project risk when brought to first use.

PGS Offshore Technology has over the last 3 years developed the Dry Tree Semi or DTS, which limits the cost and risk aspects of unproven technology by using a standard semi-submersible hull with top-tensioned risers suspended by large volume buoyancy cans. A Norwegian patent has been awarded, and US and international patents are pending for the riser support system developed for the DTS, which comprises a light weight truss tower placed in the centre of the hull. Conventional sliding or roller bearings provide lateral support to the buoyancy cans inside the riser support tower. The DTS concept avoids the disadvantage of dry tree concepts with riser tensioners, which rapidly loose payload capacity in deep water because of the increasing weights of the riser system. Compared to SPAR alternatives, the DTS has a substantially better steel weight to payload ratio. Also, installation costs are considerably reduced since offshore lifting and mating operations are not required.

At the OTC 2000 (ref. /1/), a DTS platform concept for West Africa was presented. This paper presents a DTS platform concept, primarily for use in the Gulf of Mexico, but also suitable for deepwater applications offshore Brazil.

Introduction

During the last two decades there has been a general trend towards higher oil recovery factors, and platform based or dry completed wells have a distinct advantage over subsea developments in this respect. There are a number of reasons for this, including amongst others, pressure drop in flowlines and limits on completion size, but even more importantly the cost and risk of performing subsea interventions. The latter reduces in practice the frequency of the whole range of recovery-enhancing measures such as logging, testing, reallocation, stimulation, recompletion etc.

The CAPEX costs for current platform designs with dry well completions increase however dramatically in deep water. The cost balance often tips the scale towards an FPSO and subsea development rather than the current dry completion unit alternatives, which are mainly TLP or mini-TLP in medium to deep water and Spar type platform in deep to ultra deep waters.

The most prolific deepwater exploration areas are currently West Africa, Brazil and Gulf of Mexico, ranging from benign to moderately harsh environments. The motivation for the DTS (Dry Tree Semi) development during the last 3 years has been to significantly reduce the cost of dry tree solutions for these main markets, starting with West Africa, which was subject for a paper presented at the OTC 2000 (ref. /1/). Subsequently, work has continued to extend the DTS application to Brazil and Gulf of Mexico (GoM).
Global Analysis of the Terra Nova Riser System
Authors: Allen Sam , Kassner Chris
Published: October 2008

Flexible riser systems are critical for the use of floating production systems in harsh shallow water environments. The use of flexible risers in such environments is driven by large vessel offsets, large vessel motions, and harsh shallow water environmental conditions. Where turret disconnectability is required in ice-infested waters, the riser system must be able to accommodate not only the normal FPSO motions, but also the disconnection and freefall of the spider buoy from the FPSO, and the spider buoy motions in the disconnected position. The Terra Nova riser system is the first large capacity disconnectable riser system in the world and the systems successful design and installation have demonstrated the ability to utilize flexible pipe technology for this type of application.

Introduction

The Terra Nova field development is located in 94 meters of water off the East Coast of Newfoundland, Canada in the Grand Banks Offshore area. The region has a harsh environment with intense storms occurring frequently in winter and the presence of pack ice and icebergs.

Terra Nova is an FPSO development. The Terra Nova FPSO has an overall length of 292.2 meters (277.0 meters between perpendiculars) with a nominal crude oil storage capacity of 960,000 barrels. The first phase of field development utilizes four remote drill centers connected to 34.4 km of static flexible flowlines and umbilicals. Eleven dynamic risers and four dynamic umbilicals provide the link between the static pipelines and the FPSO. Considering future development, the entire riser system accommodates for 14 dynamic risers and 5 dynamic umbilicals.

The selection of a floating production design for Terra Nova, the seasonal presence of ice, and the possibility of an iceberg encroaching on the field introduced basic functional requirements for the field's development. These main requirements were the design/fabrication of an ice strengthened vessel and a facility capable of disconnecting from its risers and mooring chains;thus enabling the vessel to move off location to avoid a potential collision with an iceberg. Pursuant to these functional requirements and the overall design requirements, this paper details the challenges imposed on the global design of the Terra Nova riser system and its associated equipment. Furthermore, a synopsis of the riser installation in year 2000 is provided along with lessons learned from the design and installation of the Terra Novariser system.

Riser Configuration Selection

Three types of riser configurations were considered for the Terra Nova riser system. The first of these configurations was the Pliant Wave® (Fig. 1). The riser's wave configuration is shaped via a distributed buoyancy module section. Following this section the riser is anchored to the seabed via a tether that is connected to a swivel clamp on the riser and a gravity base on the seabed. The riser then descends to the seabed and ultimately is terminated at the flowline connection.
Protection Against Underscour
Authors: Posey Chesley J.
Published: October 2008

This paper summarizes the results of several investigations of underscour, which can endanger offshore structures. Reproduction at model scale of an unusual pattern of scour first observed by divers led to improved understanding of the phenomenon, indicating the use of graded reverse filters for stopping erosion completely. Model tests, special severe erosion studies, and experience with offshore installations show how effective and economical protection can be obtained.

INRODUCTION

The foundations of offshore structures must be secure if catastrophic losses are to be avoided. Where such structures are built, the bed of the sea is likely to be sand or loosely compacted alluvial material. If the bottom level has remained constant, there must have been an equilibrium between the erosion and deposition of material occasionally moved by the velocities normally occurring there. The local velocities next to parts of a structure having circular or less well streamlined cross-section, in contact with or penetrating the bottom, must be more than double the average, and hence will have much greater capacity to move material Underscour is the inevitable result. Research dealing with scour at bridge 'piers and abutments might seem to provide a safe basis for estimating its depth, since in open waters the strong currents do not come from the same direction for long periods of time. Measurements made around a Padre Island offshore drilling platform which had become alarmingly unsteady, however, disclosed a type of erosion which was entirely different from what the bridge-pier analogy would predict (Ref. 1). The volume of material removed was many times greater, and it had disappeared in a comparatively short time. The present paper summarizes briefly the results of a number of investigations which have dealt with various phases of the problem.

TWO TYPES OF EROSION

The first type, which we shall call bridgepier type, is localized around the pile or shaft where it enters the sea bed. Approach velocities a pier-diameter or two above the bottom are higher than those close to the bottom. They cannot, therefore, curve out to go past the pier at as small a radius as the lower velocities can. This gives rise to a "horseshoe" vortex, a strong three-dimensional boundary-layer phenomenon, which erodes a hole next to the pier (Ref. 2). If the bed material is cohesionless the scour hole is on the sides and upstream nose of the pier, providing, of course, that the direction of the bottom current remains the same for a long enough time. The shape is an inverted cone with base diameter several times that of the pier (depending upon pier shape and roughness as well as other factors) and with side slopes equal to the submerged angle of repose of the material. Scour holes of more complicated shape are formed if the bed material is cohesive. This bridge pier type of erosion is easily reproduced at model scale, using gilsonite, coal, or ordinary sand. Where there are a number of pipes or piles not too close together, each one has its own scour hole (Ref .3)
Effective Stress and Axial Pile Capacity: Lessons from Empire
Authors: Bogard Dewaine
Published: October 2008

The results of a number of field experiments with instrumented piles and probes in highly plastic normally consolidated clays have led to the development of accurate and reliable axial pile design methods. Alternate methods have been developed using total and effective stress approaches. In this paper, the methods used for developing the ultimate resistance relationships are demonstrated, using the results of eight in situ model pile experiments at a site near Empire, La. as examples.

The choice of the particular design method to be used is generally determined by site-specific variations in the shear strength profile. For classic normally consolidated clays, the methods give identical results, with either the availability or the reliability of the geotechnical data determining the choice of the design method.

Introduction

Comprehensive studies of the behavior of friction piles under static and cyclic loading have been performed for Conoco and other industry sponsors. Based on the results, methods were developed for the design of friction piles in normally consolidated clays (Bogard and Matlock, 1990a; Bogard, Matlock, and Chan, 2000). The design methods include consideration of the setup time, the load-deformation behavior, and the effects of cyclic loading on the axial shear transfer capacity.

The design methods were based on the results of field tests on a fully instrumented 30-inch-diameter pile and on 29 in situ experiments with instrumented model piles. The results of the experiments led to the decision to base the ultimate axial capacity calculations on the undrained shear strength. The decision was made primarily from the standpoint of technical accuracy. However, the total stress approach results in greater economy in the required site investigations and provides more flexibility in its application.

The close agreement among all the experiments was documented in Bogard, Matlock, and Chan (2000). In this paper, the results of eight experiments at the Empire test site will be explored, and the methods used to formulate the design equations for ultimate capacity will be demonstrated.

Experimental Results from Empire, La.

Fourteen pile segment model tests were conducted at the site of two previous axial pile research programs (Bogard and Matlock, 1990b). Eight of the fourteen experiments were performed between depths of 115 and 165 ft, corresponding to Pile 1, as described by Cox and Kraft (1979), and encompassing the test depth reported by Azzouz and Lutz (1986). The remaining six experiments, performed between depths of 210 and 250 ft, disclosed a high degree of variability, suggesting that this depth interval consisted of mixed and interlayered sand, silt, and clay.

Consolidation and Setup Time.

Pore pressure dissipation data from the eight experiments are shown in normalized form in Fig 1. The data were normalized with respect to t50 (the time for dissipation of half the excess pore pressure) in the rawest possible form, without embedding arbitrary permeability or consolidation coefficients in the relationships.
Cost-Saving Solution for Offshore Piles in the Egyptian Mediterranean
Authors: Gilchrist J.M. , Wali I.M. , Ragab H.G. , El Ashmawi A.S.
Published: October 2008

Rosetta P1 is a fixed, steel offshore gas production platform situated in 63m of water some 80km north east of Alexandria in the Mediterranean Sea. The platform, which weighs around 3200tonnes, has four 54-inch diameter, 1.5-inch wall thickness tubular steel piled foundations, one located at each of the four jacket legs.

The foundation strata contain a very dense sand layer between 57.5 and 63.5m penetration, ideal for terminating the piles in. However, conventional API RP2A methods of pile design would have resulted in at least 3 of the 4 piles being driven to over 90m penetration to achieve the design capacity of 32MN. A solution evolved from two main aspects of design:State of the art soil mechanics provided justification to increase the limiting unit end bearing capacity to 15MN/m2 from the currently recommended API value of 12MN/m2.The introduction of a steel cruciform insert into the pile toe to bridge the gap between the lower coring pile capacity and the higher plugged pile capacity.

The solution enabled the piled foundations to be accepted and certified at 60m penetration and resulted in project budget savings of about USD 1.5 million.

This paper provides a detailed account of the solution and the resulting project benefits.

Introduction

The Rosetta offshore gas field lies in the Mediterranean Sea, offshore east of Alexandria, Egypt. Rashid Petroleum Company (Rashpetco), a joint venture between The Egyptian General Petroleum Corporation (EGPC), British Gas (the operator), Shell and Edison, is developing the field.

The Rosetta Gas Field Development Project comprises an offshore platform, an offshore pipeline, an onshore terminal and two onshore pipelines.

During the course of the offshore platform foundation design, it was determined, by conventional API RP2A methods, that the piles would be required to be driven to depths of over 90m to achieve the design capacity of 32MN (Fig. 1). However, soils data from the geotechnical survey and the results of various field tests performed at site revealed a dense, strong sand layer at approximately 60m, ideal for terminating the foundation piles. If any unnecessary conservatism in conventional design methods could be removed, considerable savings could be achieved. In an effort to optimise the design and save costs a detailed review of conventional design methods was launched.

The identification of certain limiting values defined by API RP2A were determined to be the most significant design constraint. Accounts provided by practitioners and researchers alike suggest that more recent advances in geotechnical testing tools and methods provide better quantitative assessments of soil behaviour and should allow the extension and application of these values in design. A discussion of empirical findings in recent practice and research, which led to the relaxation of conventional limiting values adopted in the Rosetta piled foundation design, are presented in this paper.
Seabed Borehole Mining: Why Not?
Authors: Abramov Grigori Greg
Published: October 2008

This Paper is dedicated to Borehole Mining (BHM), the method of remotely extracting rock material through boreholes by high-pressure water jets. The technology is based on in-situ jet cutting of rock mass, creating slurry, and delivering it to the surface.

Remote operation in this case scores significant advantages over traditional mining methodology, the most important of which are: total personnel safety, high mobility, minimal environmental impact, and low capital/operational cost. Since these advantages, such regions as the World's Offshore and Polar Zones become the most appropriate BHM's application areas.

Introduction

On-land developed, Borehole Mining is well known in the "Continental" engineering community. The recent BHM's list of successfully extracting minerals includes Coal, Uranium, Iron Ore, Titanium, Zirconium, Kimberlite, Bauxite and several more. This list also includes stimulation of water, oil and gas production. The depth of operation just exceeded 1 km. In addition to exploration, mining and stimulation, the array of BHM application also includes environmental and underground construction areas, river banks reinforcement and several more.

Despite widespread acceptance of the theory behind BHM, and its recent and verifiable track record in the field, few offshore specialists or professionals are aware of the explosive financial potential of Borehole Mining. Meanwhile, no known obstacles prevent application of BHM from the water surface. Owing to aggressively pursued standardization, the list of required equipment includes only a vessel or a floating platform, with a pump station and the Borehole Mining Tool. This paper is to introduce the "ground" Borehole Mining technique and experience and present the opportunity of BHM application from water surface.

BHM Equipment and Technology

Few innovations in mining science have been so universally sought as a viable method of remotely controlled, automated subterranean excavation - the extraction of deeply buried natural resources while personnel and controls remain safely above ground. After years of design, laboratory tests, field trials, and actual operations, that dream has been realized, and is known today as Borehole Mining.

Originally developed as a remote underground exploration and mining method, Borehole Mining (or BHM) soon found applications in related areas such as underground construction, environmental projects, abatement solutions, and more. The extension of exploitability presently under review is mineral extraction below the seabed.

The BHM method is based on in-situ water jet cutting of rock mass, creating a slurry and delivering it to the surface. In Fig. 1 the schematic of the method is presented. The borehole mining tool 1 is lowered into the borehole 2 and high pressure water 3 is pumped down. At the bottom part of the tool, one portion of that water comes out through the hydromonitor nozzle 4 in a shape of water jet 5 and cuts the material 6 creating slurry 7. The other portion of high pressure water then comes to the eductor 8, which produces a vacuum.
Sensitivity of SCR Response and Fatigue Life to Variations in Hydrodynamic Loading at Low Keulegan-Carpenter Numbers
Authors: Imas L. , Triantafyllou M.S. , Thompson M. , Hsu T. , Young R.
Published: October 2008

Very little reliable hydrodynamic data exists for bare and straked pipes subject to oscillatory flows which describes drag and added mass behavior as a function of Keulegan-Carpenter (KC) and reduced parameter Beta (B) numbers, namely for KC below 4 and B above 6000. The ability to accurately predict the global motions response and fatigue life of an SCR riser operating at such low KC/high B numbers to a large degree depends on the appropriate selection of hydrodynamic coefficients for such an analysis. This paper presents the experimental procedure used in obtaining the drag and added mass coefficients at low KC numbers, consequent results and their use in a design analysis of an SCR operating at extremely low KC numbers.

Introduction

The question of appropriate drag and added mass coefficients for risers operating at low KC numbers was raised early in the design of a steel catenary gas export riser connected to the Typhoon TLP (Figure 1). The Typhoon SCR is 18" in diameter, and the TLP is located in approximately 2100 feet of water. Drag and added mass coefficients were needed for the straked riser region, which extends several hundered feet below the riser attachment to the TLP, and the bare pipe region, which extends below the strakes to the riser touch down point. The Typhoon 18" SCR is particularly critical in terms of fatigue life at the touch down point due to the low water depth / diameter ratio, which is in fact the lowest of any SCR installed to date (Figure 2).

1Formerly with Advanced Marine Technology Inc.

For the most damaging fatigue seastates, motions of this riser are small, typically less than half a diameter. Figure 3 shows KC values for a typical fatigue seastate plotted along the riser length. From the figure it can be seen that most KC values are below 4.0.

The Typhoon TLP operating conditions relevant to the SCR fatigue life analyses are those of surge and sway in random seas, with underwater current effects considered negligible. Greatest fatigue life sensitivity was found to occur under conditions where significant wave heights varied from 10 feet to 1 foot, and the corresponding wave periods varied from 8 seconds to 2 seconds. In terms of SCR geometry and motions, the above conditions correspond to KC numbers between 4 " 1, and (reduced parameter) Beta numbers of between 20000 - 10000. The KC and Beta numbers are defined as:

KC = Vm*T/D

Beta = D2/(T*nu)

Vm is the SCR maximum oscillation velocity; T is oscillation period; D is riser diameter; and nu is the kinematic viscosity of water. The maximum value of SCR velocity is used, since both the sea-state and the vessel motions (hence the SCR forcing) are specified as random processes.

Hydrodynamic data, compiled in Bearman (1988), Sarpkaya (1986), Triantafyllou (1980), for bare and straked pipes in oscillatory flows does not provide pipe CD values (as a function of KC & Beta numbers) below KC ~ 4 and Beta ~ 6000.
An Algorithm for Determining the Uncertainty of Complex Multiphase Flow Models
Authors: Wilkens R.J. , Flach L.
Published: October 2008

An algorithm was developed for determining the implications of multiphase flow uncertainties. The specific method employed combines the classical uncertainty analysis of Kline and McClintock with multiple random variable probability theory. The initial results indicate that in addition to uncertainty prediction, the algorithm can also be used to statistically reduce the sharp discontinuities common in multiphase flow modeling, thus leading to improved simulation convergeance.

Introduction

Flow assurance and risk assessment are major issues in the offshore petroleum industry today. While there is a push for increasingly more complex flow models it is important not to lose the understanding of the accuracy of such models and their sensitivity to input parameters. Error bars for flow assurance simulations can greatly affect field planning, equipment sizing, and risk assessment.

At present, uncertainty calculations for multiphase flow conditions are not well understood and are rarely reported. Over short distances, uncertainties in prediction of pressure drop in the design stage can be large without causing significant production problems. However as multiphase transport in pipelines extends into tens of miles, a significant error can occur in predicting capacity. The method described can also be extended to the prediction of such values as corrosion rate, arrival temperature, and wax deposition rate.

In developing a method for determining uncertainty, it is desired that re-coding of the model not be necessary, implementation be simple, practical computational constraints be considered (e.g., no Monte Carlo approach). This led to an approach that was discrete and also was able to lessen the effects of sharp discontinuities. Specifically, existing model functions can be evaluated at selected intervals with the results being probability-weighted to arrive at a solution.

Statement of Theory and Definintions

Error bars represent the confidence interval for a given confidence level. When engineering results are specified, error bars are attached to the data to give the reader an idea of the level of uncertainty associated with the results. A list of values for common confidence intervals is given in Table 1. It is important to note that when the confidence level does not accompany the error bars, it is common to assume 2.15 - 1 odds. The values in Table 1 were generated using Eq. 1 in conjuntion with the Gaussian distribution.
Challenges and Experience in ROV-based Deepwater Seabed Mapping
Authors: Rasmussen Gert Juel
Published: October 2008

Detailed seabed mapping by use of multibeam echosounder (MBE), sidescan sonar (SSS) and subbottom profiler (SBP) mounted on ROV's has been common practice for several years in the North Sea region. The details from this type of survey compared to vessel based surveys have added valuable information for planning and detailed engineering for field development. The details revealed by ROV seabed mapping is even more necessary as field development progresses towards deep water (> 1000 metres).

As survey ROV's and survey sensors typically are rated to 1000 metres or less, it requires significant planning and preparation to prepare a spread capable for deep-water operations. Several challenges, known and unexpected, experienced during a mapping campaign off the coast of West Africa in water depths down to 1450 metres are discussed below. The paper describes the pre-studies and analyses carried out prior to mobilisation, problems encountered during mobilisation and survey, and the corresponding problem solving.

The modifications made to the ROV prior to the survey proved to be very profitable as survey speeds in excess of 1.5 knots were obtained in water depths of 1400 metres. The data quality appeared to be good, although some of the survey data partly suffered from background noise.

Background

Even with significant experience in ROV seabed mapping it is a comprehensive task to build a ROV survey spread suitable for deep-water. The task appears simple at first sight. We just want to do in 1500 metres water depth what we have done for years in 300-600 metres water depth.

But after the most obvious thoughts of "what is the depth rating of the ROV" and "how long is the umbilical" more complex questions arose. As the answers turned out to be negative for our standard survey spread for both the above questions, new ideas had to be developed. But first a target objective was established. The work task included more than 800 line km of seabed mapping and therefore survey speed became an important issue. We aimed for a speed of 1.5 knots (0.77 m/s). This was approximately 10 times faster than the only known deep-water ROV MBE survey at that time (but less than the speed we operate with in the North Sea).

In addition to the survey speed, the following main tasks were identified as the key to successful mobilisation and performance:Upgrade of deep rated WorkROV to Survey ROV.Identification and integration of deep rated survey sensors.Fast and reliable data transmission from ROV to surface.

Survey spread

The survey spread should include a vessel with good DP capabilities and high accuracy sub-surface positioning system, e.g. HiPAP (High Precision Acoustic Positioning) from Simrad, and DGPS based heading and attitude sensor (Seapath from Seatex). Low noise environment around the vessel is an advantage for the quality of the acoustic link to the ROV.
Responses of a Tanker-Based FPSO to Hurricanes
Authors: Ward Emmett G. , Irani Mehernosh B. , Johnson Robert P.
Published: October 2008

A series of model tests were completed in the Offshore Technology Research Center wave basin to investigate the responses of a tanker-based FPSO to hurricane environments. Results indicate that transverse responses, particularly roll, are significantly influenced by non-parallel environments and directional seas.

Introduction

While FPSO.s have successfully used in many other areas worldwide, none have been used to date in the Gulf of Mexico. With increasing interest in their use in the Gulf, model tests were conducted at the Offshore Technology Research Center wave basin to examine the behavior of FPSO.s in wave, wind, and current conditions typical of the passage of a severe hurricane. FPSO.s for the Gulf of Mexico will likely be passively moored through a turret system so that the tanker can weathervane or rotate in response to the changing wave, wind, and current directions in a hurricane.

In many areas where FPSOs have been used, the wind, wave and current conditions are relatively parallel or collinear. In such an environment, the FPSO is generally subjected to head seas. The typical design practice for such FPSOs assumes that the design wave, wind, and currents are parallel. The waves are assumed to be unidirectional or long-crested.

However waves, winds, and currents in a hurricane can be quite non-parallel [1], and subject the vessel to quartering or beam seas that can significantly influence the response of a ship-shaped vessel. For example, conditions that result in quartering or beam seas can cause larger roll amplitudes than that would result from head seas. The extreme responses of a moored FPSO can be sensitive to non-parallel waves, winds, and currents. The extreme or design responses of an FPSO is recognized to be sensitive to non-parallel waves, wind, and currents [1,2], but few studies have addressed this issue.

A recent study investigated response based design criteria for FPSOs in the Gulf of Mexico [3]. A frequency domain analytical model was used to predict the responses of an FPSO from hindcast hurricane waves, winds, and currents that were generally non-parallel. The effect of directional waves was approximated in the model. Results showed larger than anticipated roll that was due in part to quartering to beam seas that can result from non-parallel waves, winds, and currents, and in part to directional seas.

Larger than anticipated roll has also been observed on operating FPSOs[4].

The model tests described here were designed and conducted to examine the responses of an FPSO in nonparallel wave, wind, and current conditions and wave directionality (i.e., short-crested waves) typical in the passage of a severe Gulf of Mexico hurricane. Results from these tests can be used to assess the importance of realistic descriptions of hurricane wave, wind, and current conditions on the simplifying assumptions often used in design practice.