bluuebunny/crossref_metadata_2025 huggingface dataset:
Global Performance Comparison between Composite and Steel Tendons in Ultra Deepwater TLPs
Authors: Wu S. , Karayaka M. , D'Souza R.
Published: October 2008

Tendons that vertical moor TLPs are a major cost driver in deepwater TLPs. Carbon fiber composites have many of the desirable material properties for use as TLP tendon as an alternative to steel. This paper investigates the performance and cost impact on the overall TLP design. The focus is on the comparison of global performance of two generic Gulf-of-Mexico TLPs with steel and composite tendons in 7,000 ft water depth. Fully dynamically coupled TLP-tendon system dynamics of both TLPs has been analyzed in time domain with hydrodynamic input complete to 2nd order. The use of composite tendons leads to improvements on global performance related to airgap, maximum horizontal offset and maximum tendon tension. These improvements have been achieved despite the fact that the heave natural period of the TLP with composite tendons has been increased to 4.72 second from 4.2 second for the TLP with steel tendons. It is demonstrated that use of composite tendons in lieu of steel results in significant reduction in pretension, hull size and hull steel.

INTRODUCTION

The tension leg platform (TLP) is a proven floating offshore structure for deepwater drilling and production. However, the high cost of steel tendons is a major cost driver, perhaps even limiting its commercial application in water depths beyond 6,000ft. Alternative tendon materials must be investigated for TLPs to remain cost competitive in these water depths. The most promising appears to be carbon fiber composites, which have material properties highly desirable for use as TLP tendons. Although there is lack of experience in the use of these materials as critical components in offshore applications, interest has been growing in their potential use, such as TLP tendons.

This paper compares the global performance of Gulf of Mexico TLPs in 7,000 ft water depth configured with steel and composite tendons, respectively. Global analysis is done in time domain by considering the full dynamic coupling of the vessel-tendon system. The hydrodynamic computations are complete to 2nd order to account for the slow drift motions in the horizontal plane as well as the springing motions in the vertical plane. The analysis results have been discussed together with the potential benefits of composite tendons regarding reduction in TLP size, maximum tension on foundation, tendon dynamics and fatigue and platform response.

COMPOSITE TENDON

Material

Carbon fibers possess highly desirable material properties for use as TLP tendons. These include high stiffness/weight ratio, high strength/weight ratio, high resistance to fatigue and corrosion, and high material damping. With proper jacketing, adequate abrasion resistance can be achieved. Table 1 shows the properties of typical carbon fiber composites.
The Status for of the Submersible as a Useful Tool Offshore Resource Recovery
Authors: Horton Thomas F.
Published: October 2008

Five years ago on the first of March 1964, the Shell Oil Co. leased the services of the Cousteau Diving Saucer for a one-day operation to evaluate the submersible in terms of its usefulness as an observation inspection tool for a subsea production well-head. This operation was conducted off of Gaviota in the Santa Barbara Channel. To my knowledge this was one of the first uses of a manned submersible as a useful tool for offshore resource recovery.

The offshore resources industry has changed and progressed dramatically in the past five years. This is particularly true of the offshore petroleum industry. In this five year period, thousands of acres of underseas leases have been taken and at greater and greater depths. New technology in both exploration drilling and production have been developed. Millions of dollars have been invested in new equipment and tools for offshore resource production.

If we consider the 1960's as the beginning decade for submersibles then the first five years, 1960 to 1965, will have to be considered as the planning and design phase of the first generation boats.

During this period the design and fabrication of a variety of submersibles was accomplished. This would include, the Perry Family of Submarines starting with the Cubmarine. In a11 the Perry submarine builders have manufactured five submersibles.

General Mills/Litton designed the Alvin, which has been effectively operated by Woods hole up to late 1968 when a Handling System failed, dropping Alvin into approximately 4,300 ft. where she now lies, but fortunately without injury or loss of life.

General Dynamics electric boat division have produced more large submersibles, at this time, than any other company. This would include the three Star Boats, Aluminaut, and two Alvin type submersibles for the Navy.

Westinghouse have now completed well over 500 dives with the Deepstar 4000 submersible. Deepstar is an excellent example of the first generation submersible and the problems of adapting what was basically an observation chamber into a work boat. Deepstar is equipped with a very frail manipulator and a three segmented claw which will lift 25 to 40 Ibs. Since the first contract for the submersible was in the area of Scientific Data Taking, a technique for carrying instruments weighing more than the submersible's payload, had to be found. The instrument packages also had to be mounted in such a way as to allow visual observation by the observer and pilot. The weight and placement of the instruments was also considered so as not to affect trim. Engineers from the U. S. Naval Undersea Warfare Center in San Diego solved the problem by designing an attachment rack for the instruments, which mounted on the front of the Deepstar in view of the occupants, buoyancy was accomplished by adding special syntactic foam which offset the instruments weight.

International Hydrodynamics have completed two manned submersibles" the PISCES I for 2000 ft. depths and the PISCES II 3500 ft. depth submersible. PISCES III a second 500 ft.
Modern and Ancient Hurricane Deposits
Authors: Walton William R.
Published: October 2008

Four large destructive hurricanes have crossed the coast lines of Texas and Louisiana since 1960: Hurricane Carla in 1961, Hurricane Betsy in 1965, Hurricane Beulah in 1967, and Hurricane Camille in 1969. The severe damage done to property in the affected areas of these storms is measured in millions of dollars and in much personal suffering. The "geological damage" done by these storms is equally dramatic but is in many ways more difficult to measure. The opportunity to observe by overflights the shoreline effects of Hurricane Betsy, Hurricane Beulah and Hurricane Camille has indicated that large quantities of beach sand or sand and shell are moved from their site of temporary deposition and widely distributed both inland and seaward on the continental shelves as well as along shore. Some of the shoreline sediment moved during these massive storms is quickly returned to the normal transport system along the beach and in most cases the beaches are "healed" within a few months' time. Some of the shoreline material is moved beyond the reach of "normal processes" and becomes permanently incorporated with other kinds of sediments. The observation of hurricane deposits along the coast lines in the Gulf of Mexico makes an interesting analogy with older deposits of Oligocene age in the Gulf Coast Tertiary. The inference is that at least some part of the subsurface sediments in the Gulf-Coast Tertiary represents storm deposits and some Tertiary deposits have been so interpreted.

Hurricane Betsy

Hurricane Betsy entered the Gulf of Mexico on September 8, 1965, and on September 9th crossed the coast of south Louisiana in the vicinity of Grand Isle. Betsy was a fast-moving storm that had maximum wind velocities of 160 miles per hour as it crossed the coast. Maximum storm tides from Betsy were observed at Pointe a la Hache, Louisiana, and were measured at 16 feet above MSL. The area to the east of Grand Isle, Louisiana, took the brunt of the high tides and hurricane winds and storm waves and the most severe damage was done in the modern Mississippi delta east of Grand Isle. One hundred fifty miles per hour winds were measured 40 miles from the eye of the storm and 100 miles per hour winds were measured 100 miles from the eye of the storm. A series of photographs in the vicinity of Grand Isle, Louisiana, before and after this storm indicate the erosional effects on the beaches. Additional before and after photographs of Breton Island and Chande1eur Islands, Louisiana, and Ship and Horn Islands, Mississippi, indicate the movement of considerable quantities of sand.

Hurricane Beulah

Hurricane Beulah entered the Gulf of Mexico across the Yucatan Peninsula on the 16th of September, 1967. After cutting across the Gulf of Mexico, it crossed the coast line of south Texas near Port Isabel. Maximum wind velocities were measured at 136 miles per hour and 100 miles per hour winds were measured 90 miles from the eye.
Design for Reliability in Floating Drilling Operations
Authors: Harris M.
Published: October 2008

Floating drilling systems used in water depths greater than 1,000 feet in the Santa Barbara Channel, California, have been designed for maximum reliability, well control, and safety. Redundancy in systems, exacting maintenance and equipment testing, detailed written procedures and skilled personnel are all an integral part of maintaining these standards.

Introduction

Conditions are encountered in drilling from floating vessels that are different from those known in normal land drilling operations or in drilling from fixed offshore structures. It is the purpose of this, paper (1) to analyze the unique aspects of operating from this continuously moving drilling rig, (2) to discuss the equipment and methods available to provide safe, reliable operations, and (3) to review Humble's experience in drilling fifteen wells on the Federal leases in the Santa Barbara Channel, California.

The Unique Features of Floating Drilling

Three areas of major differences experienced in operating from a floating vessel can be readily identified. They are:

1. Motion and Motion Compensation

2. Remote Location of Well Control Equipment

3. Weather and Oceanographic Influence on Operations

The design of a floating drilling system includes an analysis of these differences to determine the possible consequences and to establish methods to provide full reliability. This analysis then becomes the foundation for the development of a basis for equipment selection and practices for floating drilling operations. Additional practices common to all land drilling operations but critical to well control and blowout prevention are then included to provide safety.
Offshore Application of a Real Time Computerized Microwave Positioning System
Authors: Jones J.J. , Johnston R.J. , Payne G.W.
Published: October 2008

Brown &Root, Inc., with assistance from Computer Usage Company, has developed, implemented and successfully tested a computer- based Microwave Survey System, which provides greatly improved accuracy and flexibility in positioning and navigating for offshore operations. Ease of operation and presentation of data in highly useful formats have been integrated with absolute positional accuracies on the order of ±2 meters over a 50 Kilometer range.

Introduction

The ability to determine the exact location of under-water pipelines has become of considerable importance in offshore exploration, surveying, construction and pipelaying. The congestion of the ocean floor, the cost of pipe and installation, the additional cost of acquiring a wider right-of-way, the pressure to quickly locate and repair leaking pipe, all dictate the need for improved mapping of existing fields and for improved precision in locating new pipe as it is laid.

To meet this challenge, Brown &Root, Inc., with assistance from Computer Usage Company, has developed, and subsequently field tested, the Microwave Survey System (MSS) described in this paper. This system is designed to enable precise and absolute navigation along a predetermined course. For pipelaying operations, it can guide barge positioning and record the actual location of pipe laid. It can additionally serve as a precision locating device for platform construction. In conjunction with acoustic devices, the system can be used for locating and tracking pipe, and for general area survey and exploration of the ocean floor.

For all these applications, the plots and printouts generated by the system provide real-time position indications, as well as hard copy records suitable for job certification; this data can also be recorded on paper tape for subsequent processing. The system has been shown to determine position to an accuracy of about ±2 meters at ranges of up to 50 Kilometers. Some 2500 hours of operational experience have been accumulated, and the reliability of the system has proven to be excellent.
SEMO FPU: The Efficient Floater
Authors: Haereid Kaare O. , Landbo Trond
Published: October 2008

This paper presents a concept for floating production, the SEMO (Semi-submersible MOnohull), an extremely flexible concept with regard to water depth, payload, storage capacity and fabrication site. The efficiency and robustness of the concept has been verified through conceptual design, structural and hydrodynamic analyses, mooring analyses and fabrication studies including cost and schedule.

The SEMO FPU was developed in response to the requirements for more cost efficient field developments. The SEMO can replace Dry Completion Units (DCUs), such as TLPs and Spars, as well as semi-submersibles and shipshaped FPSOs. In essence the SEMO is a monohull, different from the conventional floating monohulls used today. Due to the shape of the hull the issue of fatigue, which often is a challenge for TLPs, semis and FPSOs, is almost eliminated.

The SEMO can operate in a wide range of water depths and provide storage when required. The symmetric hull is spread moored and eliminates costly items in the traditional FPSO such as turrets and swivels. The favorable seamotion behavior and the very stiff and large deck area result in less sophisticated and cheaper process utility and simpler and cheaper topside structure. The seamotion behavior can be optimized to allow for surface wells, also in areas with harsh environment.

The shape of the SEMO hull gives a simple, robust, and cost effective platform with short construction time compared to traditional floaters. This is essential in today's "fast track" market. Fabrication does not require any "hard to find" facilities. The SEMO is a product with extreme flexibility that can be used for almost any field development. This gives the industry an increased opportunity to produce multiple units, taking the advantage of a learning curve in engineering and fabrication. Sensitivity to cost driving changes during project execution is minimized due to the robustness.

Introduction

Operators and oil companies are forced to cut cost to be competitive in today's Oil & Gas industry. A current trend is going into deeper water, and new and more efficient concepts for floating production is one possibility to reduce cost. Despite a rapid development of subsea and downhole technology there will be a demand for Floating Production Units (FPUs) also in the future.

Why do FPSO's have to look like a ship?

People in the oil & gas industry have asked this question for years. From an operational point of view there are no reasons why an FPSO, which is to be permanently moored, should be shipshaped. A possible exception is the factor of offloading using a tandem mooring system, however there are other options for offloading that will not depend on a shipshaped design. The idea of shipshaped FPSOs was related to conversion of old tankers, and to the efficiency of the shipbuilding industry worldwide. The history has shown that FPSOs are different from ships and need to be designed differently.
Gas Disposal Systems for Offshore Platforms
Authors: Gunn B.G. , Gueringer S.L.
Published: October 2008

The different methods used in handling gas effluent from offshore platforms are discussed in this article. The presentation is directed toward the type of system to select for gas disposal based on production, location, and safety factors for an offshore site.

Some of the means of gas effluent disposal to be discussed are vents, flares, and mechanical devices. The selection of the particular method for use would be dictated by the type of equipment used, water depth, ambient conditions, and the type of crude produced. Alternate applications of the methods such as undersea venting, local venting, or remote venting are reviewed to determine the best application for a particular platform.

Safety factors which affect gas effluent are examined. A few of these items are the amount and type of gas to be released, type of equipment, and location.

Introduction

Offshore production platforms are built to provide a working area to separate water, liquid hydrocarbon and gas. Separation is required offshore because of the extremely large pressure drops experienced due to two (2) phase flow of liquid hydrocarbon and gas being shipped together by pipeline. The dissolved gas would also require a large storage system for barge or tanker transportation of crude oil. Separation of crude oil and gas then is made offshore to allow single phase transmission of crude and gas through their separate transportation systems.

Means of handling the gas offshore have developed slowly as producers have tried many ways to safely and economically process the crude. Some of the various ways that have been used in the past are presented in this article. Factors used in the selection of a particular means of gas disposal are presented to assist operators in offshore operations. Safety and economics are the two yardsticks used to evaluate gas disposal applications. These two yardsticks are presented briefly in the following discussion.. But to arrive at the optimum system for gas disposal, the complete platform should be developed and studied.
Dubai Khazzan - Pioneer of Large Undersea Storage System
Authors: Curtis L.B. , Shepler James C.
Published: October 2008

Like most applied concepts similar in nature to the huge submerged storage unit placed on the bottom of the Arabian Gulf off Dubai in 1969, it was born of need. With an oil discovery some 60 miles from the Dubai shore and located in moderately deep water, the projected costs of a pipeline, pumping system and shore terminal facilities were of such magnitude as to warrant study and application of less costly methods of storing and offloading crude oil. Since the ensuing application of the large submerged storage unit was unique, it was necessary to thoroughly analyze all areas of design, operation and environmental conditions under which the system would be functioning. Even with this very thorough investigation, there remained a residual risk, normally inherent in a new idea, which had to be equated with potential economic gain.

Wide margins of safety were established and the design parameters, both structural and operational, were maintained well within the limiting environmental probability boundaries. Perhaps the most critical of all design factors was the piling system employed to fix the tank to the sea floor and ensure long trouble free operation. Extensive testing and data collection were required to quantify critical relationships pertaining to soil mechanics and bonding.

Now operational the tank has performed fully as anticipated. This unique system offers some distinct advantages both from an operations view point and also in the construction and placement of large structures. It is indeed an international achievement as a multinational partnership was involved in the entire project.

INTRODUCTION

Dubai Petroleum Company, a Wholly owned Subsidiary of Continental Oil Company, as operator for a group of international companies composed of Dubai Marine Area Ltd. (Compagnie Francaise des Petroles and British Petroleum), Deutsche Erdol-Aktiengesellschaft, Dubai Sun Oil Company and Continental Oil Company discovered commercial oil in June, 1966, 'offshore in the Shiekdom of Dubai. Hispanoil has now replaced British Petroleum as a partner of the OOMA group. The shiekdom of Dubai is one of seven Trucial States on the southern end of the Arabian Gulf (Figure 1). It is an established center of commerce for coastal shipping operating out of a shallow water port. However, its shoreline has no natural deepwater area near shore which is essential for crude oil export in deep draft tankers.

The discovery well, Fateh A-l, flowed 30° API crude from the Lower Cretaceous Ilam and Thamama at 7,500 to 8,500 feet. Two confirmation wells were drilled two miles to the southwest and two miles to the northeast on either side of the original well and along the major axis of the structure. These first three wells confirmed the presence of the Fateh field some 60 miles offshore in water depths ranging from 110 to 180 feet(Figure 2) and triggered a number of feasibility studies to determine the optimum development method.
Titanium for Marine Applications
Authors: Feige N.N.
Published: October 2008

Titanium alloys have had increasing application in marine structures over the last three-year period. The four principal areas of application have been its strength per weight advantage, its complete immunity to corrosion by sea water, heat transfer capabilities, and its high corrosion fatigue design limits in both low and high cycle fatigue. Present experience with high performance structures fave further defined its area of applicability and has pointed out the distinct design advantages of incorporating titanium in composite or mixed material structures. The author reviews a series of designs and relates service experiences encountered back to the initial design of the units.

INTRODUCTION

Titanium is a material developed in the early 1950's to meet the needs of the then emerging jet aircraft engine market. The suitability of its use in aircraft engines, airframes, and space structures is a high strength-to-weight ratio, good corrosion resistance to aircraft structure environments and temperatures and a moderate modulus of elasticity. Titanium has well met its expectations in this area and has shown increased usage both in total pounds and per cent weight on airframes.

Early interest and support in titanium was expressed by U. S. Navy investigators in 1950, (1) and its property advantages were well delineated by J. E. Cotton in 1956. (2) At that time metal availability and price prevented its serious consideration for many commercial applications. It was not until1963 when a need existed for a hull material for deep diving submersibles that further engineering work was done in this area by Navy investigators.

By 1966 the industry had sixteen years of maturity and had developed sufficient production volume and product diversity to sharply reduce raw material prices and increase odd lot availability of the mill product. Also, during the period there has been a significant increase in capable fabrication shops to handle titanium and its alloys. In this latter period, however, the greatest motivation to utilize titanium has been the rapid expansion of sophisticated structures in the sea more highly stressed which required the use of titanium to obtain the desired performance.

The present market is going through an evolution of 1963 experiments into production applications and is growing at a rate in excess of 15-per cent per year.

In the consideration of titanium versus the competitive structural materials in use in marine service, there are four general areas where it will be selected:Strength density advantage, such as a research submarine hull for a 20,000-foot diving depth.A corrosion critical machined surface which cannot be painted and which cannot corrode, such as the ball in a ball valve.A corrosion fatigue limited structure, either in the low stress or low cycle, high stress range. A ship's propeller blade or a mast structure on a boat are examples of this design.
AUV Applications Within E&P
Authors: Schostak Brian
Published: October 2008

In February 1999 Shell examined the current state of AUV development and evaluated the usefulness of the technology for enhancing our ability to explore for and produce offshore oil and gas. Our study addressed four questions:Can AUV's resolve our present problems?Will AUV's deliver a business benefit?Does AUV technology lend itself to easy implementation in the near future? AndWhat actions can we take to help catalyze the market?

Two separate types of AUV were identified for use within E&P: a survey class vehicle for data acquisition, and an engineering class vehicle for underwater intervention. For each type, this paper will describe the answers to the questions above; addressing the problems we hope to solve, our estimate of the feasibility of using AUV's to solve them, the business case for AUV's, and our analysis of the state of the market today.

A description of desirable attributes will be given for each type of AUV for a minimal case and a realistic ideal case.

Introduction

In late 1998 and early 1999 Shell conducted an internal study of Autonomous Underwater Vehicle (AUV) technology. The purpose of the study was to evaluate the usefulness of the technology for enhancing our ability to find and produce offshore oil and gas. As the name implies, an AUV is a robotic vehicle capable of independent actions underwater. Using sophisticated artificial intelligence software integrated with sensors that give it an awareness of its surroundings, the vehicle can carry out pre-programmed tasks and react to unexpected conditions.

We identified two separate types of AUVs for use within E&P. The first is the survey class vehicle for seabed data acquisition and the second is a work class vehicle for underwater inspection, repair, and maintenance (IRM). For each type of AUV, we examined four questions:Can AUV's resolve our present problems?Will AUV's deliver a business benefit?Does AUV technology lend itself to easy implementation in the near future (5 years)?What actions are necessary to catalyze the market?

Seabed Survey Problem

The use of appropriate seabed survey data affects the cost of offshore developments by providing information necessary for correct design and installation. Good survey data ensures that the local environment is fully understood so unnecessary safety factors are not incorporated into design. The data also helps to ensure minimal environmental impact and that there are no unforeseen hazards.

Survey data should allow for interpretation and identification of seabed morphology, natural and man-made seabed features, seabed soils, subsurface soils and features, and subsurface hazards. Data necessary to make these interpretations are obtained from a variety of sensors such as swathe bathymetric systems, sidescan sonar, and subbottom profiler. Additionally, magnetometer data and coring or sample data are used. Other information about the sensor platform and immediate environment is also needed to correctly use the data obtained from these sensors. The location, orientation, and attitude of the sensor must be measured.
Theoretical and Ohserved Performance of Mobile Rig Footings on Clay
Authors: Gemenhardt J. Peter , Focht John A.
Published: October 2008

The observed foundation performance of eleven different jack-up mobile drilling rigs at 120 locations in the Gulf of Mexico was compared to their predicted theoretical performance. The foundation elements supporting all rigs included in the study are individual tank-type footings. The near-mudline soils at each rig location were clays; in addition, the soil shear strength and other properties were known (or could be estimated. Reasonable predictions of footing penetration were found to be obtained using the Skempton equation for the bearing capacity coefficient, N1c and strength data from unconfined compression tests on good quality undisturbed samples. Useable estimates of footing penetration were also shown to be possible for the Louisiana continental shelf by extrapolation of soil data on the basis of geologic and other evidence; the potential error tends to increase rapidly with increasing distance from the point where soil properties are known.

INTRODUCTION

Jack-up mobile drilling rigs with individual tank-type footings and a general configuration as shown in Fig. 1 constitute about 40 percent of the nearly 200 mobile rigs now in service(l). The number of footings ranges from 3 to 14, the footing diameters vary from 16 to 45 ft, and the nominal operating water depths range from 80 to 300 ft. In its operation a jack-up mobile unit floats to location with its legs lifted. At the drilling site, the legs are lowered to the mudline and jacked down into the seafloor soils until the total footing resistance becomes equal to the rig weight. Then the rig begins to lift itself out of the water. The drilling deck continues to climb the legs in order to reach a desired operating height above water level. A rig operator would like to know in advance that the sum of the air gap below the hull (G), the water depth (W), and the footing penetration (D), as shown on Fig. 1, will be less than L1, which is that portion of the total leg length (L) that can safely extend below the hull bottom. Since G and Ware fixed for a specific location and L1 is a constant, the unknown factor needed for advance determination of rig suitability for the location is the probable footing penetration, D.

The study reported here was to determine if the penetration of jack-up rig footings into clay could be predicted reliably by conventional or modified soil mechanics procedures. The investigation consisted of a retrospective analysis of actual footing penetration where soil conditions were known or could be inferred.

SCOPE OF STUDY

Sources of Data. When this study was conceived in 1964, it was re-cognized that the approximate character of performance measurements, coupled with the lack of soil information for many locations, would require the assembly of a large body of data that could be analyzed on a statistical basis.
Amplitude-Preserved Subtraction of Multiple Events
Authors: Spitz S.
Published: October 2008

Any technique aimed at subtracting the multiple wavefield from the seismic data can be seen as a two step process. In the first step the multiple events are predicted. In the second step, the predicted wavefield is subtracted from the input data. This paper proposes a new approach to the subtraction of the predicted multiple events. This approach is based on the spatial predictability of the coherent events in the frequencyspace (or time-space) domain. Unlike the standard attenuation techniques, this new approach is able to subtract the coherent noise even in the presence of strong cross talk between the signal and the multiple components of the input data.

Introduction

A crucial issue when processing seismic data is the ability to remove coherent noise while preserving at the same time the amplitude of the signal component. It is indeed well known that multiple reflections, which interfere with the primary reflections, lead to incorrect pre stack attributes and to an erroneous interpretation of the final images at target level. Standard techniques for the attenuation of this coherent noise often fail, especially in case of strong interference, or when the noise field is spatially aliased.

Because the multiple wavefield is generated by a specific physical mechanism, it is sometimes possible to predict this wavefield without any a priori velocity model (Refs. 1 and 2). This is the case for instance for a marine 2-D acquisition. Thus, the removal of the multiple events can be seen as a twostep process: prediction and then subtraction of the predicted events from the input data.

The minimum energy assumption

Suppose that an input trace d is made of signal s and noise n. Suppose also that m, a realization of the noise component is known, and that this realization is a filtered version of the actual noise in the gather.

(Mathematical equations available in full paper)

It follows that at each frequency the quantity (n*s) is zero. In the time domain, the cross correlation between the noise and the signal vanishes. In other words, the minimum energy assumption estimates only that part of the signal that is uncorrelated with the noise.

The generalization to a gather d of N traces d1, ..., dN made of primaries and multiples is straightforward. If the gather m of N traces m1, ..., mN contains a prediction of the multiples such that mi = w* ni, i = 1, ..., N, the minimum energy assumption estimation of the scalar w produces primaries that are uncorrelated with the multiples.

The over simplistic approach based on the minimum energy assumption (adaptive subtraction) cannot account for the possible cross talk between primaries and multiples and gives distorted results when the primaries and multiples interfere. To solve the possible interference between primary and multiple events, predicting the multiples is simply not enough. Some information has to be given on the primary events themselves.
Operating Experiences With the Captain FPSO
Authors: Bradley Roger , Sanders Christopher J.
Published: October 2008

The Captain Field in the UK North Sea is a shallow heavy crude reservoir, which has been successfully developed using ESP's, long reach horizontal wells and an FPSO installation. The Field has been in production since the early 1997 and has maintained a high uptime during this period. However, there have been some notable occasions when production has been interrupted. Uptime data is presented and the reasons for production losses and the improvements made are discussed. The competence of FPSO crews has been the subject of concern to Operators and the Regulatory Authorities in the North Sea, and the system developed for the Captain FPSO is illustrated. Since the commencement of production, there have been some significant safety, health and environmental challenges associated with the Captain FPSO. These have been the result of design as well as operational constraints. A comparison of the Captain SH&E data with the rest of the industry is presented.

Introduction

The Captain Field is a heavy oil (19 degrees API) development in the Outer Moray Firth area of the North Sea. The Field facilities consist of a wellhead protection platform (WPP 'A') and an FPSO. A schematic of the field facilities is shown in figure 1. The installation of the existing facilities was completed early first quarter of 1997 and production commenced on the 1st April 1997. An extension to the existing facilities is planned to be installed in mid 2000 to recover the reserves from the eastern part of the field (Area B) and will consist of a subsea template tied back to a platform bridgelinked to the WPP 'A'. Production from these additional facilities is planned to commence in the December 2000.

The WPP 'A' is the drilling centre for the western part of the field (Area A) and well fluids are transferred to the FPSO for processing by a series of pipelines. All the wells have electrically powered submersible pumps and downhole chemical injection of demulsifier and corrosion inhibitor. A hydraulic submersible pump was installed on the WPP 'A' as part of the testing of equipment for Area B. The process system on the FPSO consists of a single two-stage separation train and an electrostatic coalescer. A schematic of the process is shown in figure 2. The process fluids are heated to approximately 90 degree's centigrade between the 1st and 2nd stage separators. Pressure support to the reservoir is provided by water injection facilities located on the FPSO, excess water may be discharged overboard. The FPSO generates all the electrical power for the Field through five tri-fuel generator sets.

The FPSO has an oil storage capacity of 550,000 bbls arranged in 3 sets of wing tanks and 2 centre tanks, and two slops tanks are available for the storage of liquids which are not of exportable quality. The vessel itself has all the normal equipment that is found on a tanker, eg. inert gas generator, ballasting systems etc.
Jack-up Response Measurements and the Underprediction of Spud-Can Fixity By SNAME 5-5A
Authors: Nelson Keith , Smith Pharr , Hoyle Mike , Stonor Richard , Versavel Thomas
Published: October 2008

Measurements of dynamic behaviour and environmental conditions have been gathered since 1992 on three of Santa Fe's jack-up units operating in the North Sea. These measurements have been analysed to provide data on natural frequencies of response for these units operating in a range of water depths and storm loading conditions in the Central North Sea. The units have been placed at a variety of sites with both clay and sand seabed conditions. Some locations consisted of layered soils conditions.

The response of the units at these locations and the implied levels of fixity have been compared with predictions based on the SNAME T&R 5-5A method of jack-up assessment. The trends observed in the measured and theoretical results show generally good agreement, but there is strong evidence that the theoretical methods significantly under-predict the actual seabed fixity available to this type of unit.

The paper reviews the differences found between measurements and predictions and discusses the implications for the effective use of the SNAME T&R 5-5A methodology in the future.

Introduction and Background

There has been considerable effort over the last decade to improve the understanding of the structural behavior of jackup platforms. Much of this work has been reflected in the SNAME published document on Site Specific Assessment of Mobile Jack-up Units. The first edition of this document was published in 1994 and a revised version in 1997 (Refs 1 and 2). This assessment document was developed from a jointindustry-funded study and its development is described in a paper by Jones et al (Ref 3).

A fundamental influence on the way in which jack-up units perform is the assumption made about the support provided at the seabed. It has long been realized that if the legs of the jackup experience soil fixity a number of benefits will follow. Figure 1 shows the leg of a jack-up unit and the moment distribution up the leg as the hull is moved sideways under the influence of environmental loading. If the spudcan is pinned at the seabed there will be no moment at the bottom of the leg. If the leg is fully fixed at the seabed the moment at the lower guide (ML) will be equal but opposite to the moment at the spudcan (MF) assuming the hull flexibility is negligible. If some lesser level of seabed fixity is present the leg bending moment distribution will lie between the fixed and pinned conditions. Spudcan fixity has the benefit of reducing lower guide bending moment, reducing loads on rack chocks and/or pinions and reducing hull motions.

Another impact of seabed fixity is on the natural frequency of the platform for hull motion in the horizontal plane. This is also shown in Figure 1, which illustrates the higher natural frequencies that are found when a jack-up unit has moment fixity at the seabed. If complete fixity is not achieved, then a condition of partial fixity can be said to exist as represented by the jack-up with rotational springs located at the seabed.
Effects of Soil Information on Economics of Jackup Installation
Authors: Geer David A. , Devoy S. Douglas , Rapoport Vladimir
Published: October 2008

The authors address economic impact of quality and availability of site soil information on safe jackup installation. Preload operations based on sufficient and on limited (or insufficient) soil data are analyzed. Reliability and applicability of a variety of soil information sources are discussed.

Preloading

In order to prevent jackup settlement during drilling or during storm conditions, the jackup unit is preloaded during the initial stages of the installation procedure. The preloading of a three leg unit is normally performed by elevating up to a 3-5 feet air gap. Ballast water is then gradually added to preload tanks until the weight of the unit loads the soil under the spud cans to a level equal to or in excess of the anticipated spud can loads for the design storm conditions. During the preload process, increasing rig weight usually causes the legs to penetrate deeper until the bearing capcity of the soil becomes equal to or greater than the spud cans loads. One of the main potential problems during preloading is a sudden uncontrolled leg penetration caused by (a) a spud can punching through the stronger soil layer into the underlying weaker soil, or (b) by unit leaning instability in uniform soft clays.

The results of uncontrolled penetrations can be disastrous. There are some preloading strategies that can lessen or even eliminate the magnitude of uncontrolled penetrations and reduce the possibility of rig leg damage. One strategy is to preload at zero air gap (also termed "preloading in the water"). As preload is applied and the spud cans penetrate into the soil, the rig draft increases. However, to achieve full preload, the draft of the rig hull typically must be limited to about 2 feet. At drafts greater than this, the buoyancy of the hull will not allow full spud can loading. As shown on the Fig. 1, this procedure can significantly reduce the potential peak value of the soil loading during punch through, and resulting differential leg penetrations.

Another strategy to lessen the magnitude of uncontrolled penetrations is to sequentially preload each leg of the rig. Because the total weight of the rig is reduced, the load during the punch through is also reduced. Also, the other legs, due to lower load can be jacked during a punch through to lessen the out-of-level condition of the rig, and lessen the load increase on the punch through leg. When this procedure is used together with zero air gap, dramatic reductions in spud can loading during punch through can be achieved, as illustrated in Fig. 2.

SUBSURFACE INFORMATION AND MODU SITE ASSESSEMENT

To plan preloading operations, expected rig foundation performance should be evaluated. This information requires subsurface soil data including soil stratigraphy and engineering properties. The following information is typically gathered to assess MODU foundation stability:Geological information for the area, to understand physical environment.Site bathymetric data, to provide accurate water depth and seabed topography.
The cost efficiency of the new marine seismic technology.
Authors: Berteussen Karl-Andreas
Published: October 2008

In this presentation we describe marine 4C seismic. We will present our opinion as to where and how this technology will be applied and how it will affect the industry in the future. Finally we try to evaluate its cost efficiency. In particular for high cost environments, like deep water fields, we conclude that it is indeed very cost efficient in that it moves the risk from long term and often costly drilling to short term and in this context relatively inexpensive seismic.

Introduction.

In the 19th century, we found oil by seepage, in the 20th century by drilling and in this century we will find it by geophysics. The background for this statement is the progress that has been made in geophysics, in particular with the now well established 3D technique. In addition there are a number of new seismic techniques being introduced like 4D, 4C, and VC. Behind these sometimescryptic acronyms, lie a considerable amount of investments in equipment and experiments.

Opinion surveys evaluating which technologies have had the greatest impact on the industry, typically ends up with seismic at-or near the top. Still, there is generally a feeling that these new seismic methods have taken more time than expected to become established products. Why is the industry so slow in adapting these methods?

I believe that sea bottom 4-component seismic is the best example to use in this discussion. Possibly marine 4D is a hotter topic in many ways, but I feel here the roles are fairly simple; i.e. to the extent 4D is repeated marine streamer, the "tools", like acquisition and processing are basically ready and free to be used by the oil companies. Of course there are some important aspects as to how to interpret these data, but that is not a cost intensive topic.

Then 4D might develop into the "electrified oil field", i.e. fixed installations. In that case both the technology and the business models are so immature that it is too early to judge the cost efficiency and the impact on the industry. For VC (Vertical Cables in the sea) we are evaluating the results of surveys already done. If they are found positive enough this will be applied as ordinary, although very high resolution P-wave data for particular problems.

As mentioned, at the moment I therefore feel that the best case to evaluate this on is 4C seismic. This technology has come so far in its development that we already can make an assessment as to its possible impact on the industry. The list of achievements is impressive and we also know relatively well what the cost of applying this technology will be. By now we should therefore be able to make a judgement, is this just being pushed by technology-fanatics or is it really a cost efficient method that the industry should apply on a large scale?

In the following I will describe marine 4C seismic.