bluuebunny/crossref_metadata_2025 huggingface dataset:
DeepLook: Toward the Common Goal of Reservoir Characterization Through Collaboration
Authors: Chawathé Adwait
Published: October 2008

In its illustrious 150 years history, the oil industry has conjured up ingenious methods to predict fluid flow behavior around the extended vicinity of the wellbores. In the past decade or so, this effort got a real shot-in-the-arm with the advent of high-speed computers. Despite this monumental development, petroleum engineers and earth scientists still struggle to merge various data sources and technologies to achieve the paramount objective: Reservoir Characterization. The DeepLook collaboration, an idea originated by BP, was contrived to address the same objective; but uniquely, through inter-company partnership.

The DeepLook Fluid Imaging Collaboration-formally initiated in 1997-is currently supported by seven oil and six service companies. The collaboration seeks to define and investigate technologies that could provide a fundamental improvement in the oil industry's ability to measure reservoir fluid and rock properties, and monitor fluid movement, at distances of 10 to 200 meters from existing wells. The goal is to achieve significant reliability in spatial and temporal fluid imaging, thus enabling substantial increases in the recovery efficiency. This challenge is being addressed through identification and sponsorship of promising breakthrough technologies which are being developed for applications outside the oil industry, by what have been termed "farmarket" high-technology organizations. This paper is a progress report of the DeepLook collaboration achievements.

The collaboration was launched with an "Oil Industry Outreach" workshop to inform interested potential far-market technology providers of our current practices in fluid imaging and reservoir management. Three DeepLook technical teams-Detection, Monitoring, and Prediction-were specifically established towards the objective of disseminating the information as well as guiding the needs and challenges of reservoir management and fluid imaging.

The "far-market" technology organizations normally operate outside the realm of the oil and gas industry. At present, the suppliers comprise four United States government Department of Energy laboratories and NASA's Jet Propulsion Laboratory. This paper will briefly discuss the retro-fitting of the following state-of-the-art technologies developed by these labs to the oil industry:Using Artificial Neural Networks and Genetic Algorithms for Optimal Well Design.Adaptive Forward-Inverse Modeling of Reservoir Fluids Away from WellboresSwept Frequency Acoustic Interferometry for Fluid Identification Each of the projects has an agreed-to work-plan, with specified milestones/deliverables.

A multi-company collaboration as complex as DeepLook is expected to encounter growing pains. Along with the technological advances, the paper also addresses some of the challenges encountered and the pro-active measures taken to overcome the management issues.
A New Approach to Derrick Barge Design
Authors: Goren Yoram
Published: October 2008

In most cases derrick barges are forced to suspend operations when wave heights exceed five feet and, in many cases, as low as three feet. This severe limitation called for a new approach to derrick barge design.

Close analysis of the life span of a typical heavy duty barge shows that during about 85 percent of her life, the barge negotiates lighter loads than her maximum capacity. Before and after setting a package weighing as much as 500 to 800 tons, the barge will spend time driving piles, assisting construction and hoisting small weights which, in most cases, will not exceed 100 tons. The objective of this design was to build a column stabilized derrick barge capable of handling up to 800 tons on the crane or 2, 000 tons on the shear leg when hull borne and up to 250 tons when column stabilized in waves exceeding 10 feet. The further objective of this design was to build a vessel which is competitive in cost with existing vessels of similar capacity.

The above objectives were realized by an extensive development program which was conducted in two phases. The first phase was the preliminary design phase in which system operational considerations, such as self-sustaining characteristics, crane load, accommodations, machinery, towing speed, etc., were pitched against engineering considerations, such as CG, weight distribution, natural periods, etc. The result of the preliminary evaluation was a twin hull, variable draft, column stabilized derrick barge having a beam of 106 feet, to enable it to pass through the Panama Canal, and a length of 400 feet.

The next phase in the development was a series of three tank tests. A preliminary one, conducted in General Dynamics Electric Boat Division, and two additional ones conducted at The Netherlands Ship Model Basin in Wageningen, The Netherlands. The purpose of these tests was to analyze the vessel's motions, to evaluate mooring forces, to determine various dimensions and to assess the bending moments imposed on the vessel. Most important, the above tests made it possible to evaluate the operational feasibility of the proposed design.

In conclusion, it may be stated that this paper demonstrates a way to approach and solve a complex engineering and economic problem, one of many encountered daily in the new and expanding field of offshore technology

Introduction

Recent developments in offshore construction have brought about an increase in size and capacity of derrick barges in order to satisfy the demands of the industry and make it possible
ABS Guide for Synthetic Ropes in Offshore Mooring Applications
Authors: Lee Ming-Yao , Flory John , Yam Rod
Published: October 2008

The ABS Guide for Synthetic Ropes in Offshore Mooring Applications [Ref. 1] is developed to assist the industry with standardized criteria covering all aspects of the use of these advanced materials for offshore moorings. Synthetic ropes have many advantages in deepwater moorings, but their unique properties must be accounted for in the mooring system design process. For example, synthetic rope moorings rely primarily on rope elasticity for restoration forces, but the elasticity is nonlinear and changes with time.

Emphasis is given to identifying the primary differences between the conventional steel components and their synthetic counterparts with regard to the influence of rope properties on the mooring system performance. Sufficient details will be provided to determine these properties through rope testing and to account for them in the mooring design process.

This paper describes the ABS classification/certification approach on synthetic ropes, which covers mooring design and analysis; rope design, testing and manufacturing; rope handling and installation; and rope inspection and maintenance. To provide an industry-wide acceptable standard, ABS formed an Ad Hoc committee consisting of operators, designers, rope manufacturers, installation contractors and governmental agencies to provide advisory comments to the Bureau on the development and future enhancement of the Guide.

Introduction

With the advent of deeper water exploration and production, it has become necessary to seek alternative materials for economical and/or suitable mooring solutions. This is reflected in the offshore industry's initiative to adapt synthetic fiber materials such as polyester, aramids and HMPEs for these purposes.

Synthetic ropes may be used as mooring line segments in steel catenary systems, or in taut leg mooring systems. In the taut leg system, the elasticity of the synthetic line provides the restoring force traditionally supplied by the geometry of the catenary system. Other differences from that of the steel wire/ chain mooring systems include the non-linear stiffness, minimum tension requirements, location of synthetic rope segment to be away from fairlead and seafloor, creep phenomenon, and handling of the larger sized rope.

Where synthetic ropes are used, it is possible to reduce the mooring footprint, and hence reduce overall spread of the subsea installation. Other advantages include the reduction of mooring line weight, better corrosion resistance, and in some cases lower vessel offset and simpler installation techniques.

A systematic investigation on the use of synthetic fiber materials for deepwater moorings only began in the early 1990s [Ref. 18]. The publication of the "ABS Guide for Synthetic Ropes in Offshore Mooring Applications" marks an important step the industry is taking to advance this new technology, and reflects the need for a consolidated written design guidance.
Multicomponent Analysis of OBC Data
Authors: MacLeod M.K. , Hadley M.J. , Reynolds K.J. , Tura A.
Published: October 2008

In early 1998, Chevron acquired one of the world's first fullfieldfour-component ocean bottom cable surveys at the Alba field in the central UKNorth Sea. The primary objective of the survey was to use converted shear wavesto image the top of the reservoir and internal shales within the reservoirinterval. The secondary objective was to map water movement in the reservoirafter four years of production and water injection by comparing the P-wave OBCdata with the original 1989 streamer data. Our interpretation shows that bothobjectives were achieved with dramatic results - the converted shear wave dataprovide the clearest image of the Alba reservoir sands ever seen and productioneffects are obvious on the new P-wave OBC data.

Introduction

The Alba field is located in the central North Sea at an average subsea depthof 2000 meters. The reservoir is a poorly consolidated Eocene turbidite sandchannel that can be up to 100 meters thick1. The main channel isroughly 9 kilometers long and 1.5 kilometers wide. The channel containsintra-reservoir shales that can cause significant drilling and productionproblems. Oil production is from horizontal wells drilled from a platform atthe northern end of the field. Development drilling is ongoing and severallong-reach and re-drill wells are planned.

Since December 1993, the Alba field has produced 130 million barrels of oil. The field is currently producing 83,000 barrels per day of 19–20 degree API oilfrom 15 horizontal wells. Pressure is maintained by water injection from 5injector wells.

For efficient reservoir development, it is vital that the horizontal wells beplaced as close to the top of the reservoir as possible. Therefore we needaccurate maps of the top of the oil-filled sandstone and the location of theintra-reservoir shales. This mapping is extremely difficult on the existing1989 seismic data because there is a weak, inconsistent seismic event at thetop of the reservoir and the intra-reservoir shales are often seismicallyinvisible. This has led to some surprises in recently drilled wells -encountering shale bodies and the top reservoir off depth from theprognosis.

Furthermore, as we drill more wells close to producer and injector wells, anunderstanding of water movement becomes critical. For example, two recentlydrilled wells were found to have anomalous water saturation profiles. In onewell, waterwet sands were encountered above a sand with primary oil saturation. In the other well, partially oil-saturated sands were found below the originaloil-water-contact.

In this paper we first review the pre-survey technical evaluation used to helpjustify acquiring a 3D OBC survey at Alba. Then we describe 2D field trialresults that supported using the OBC method to achieve the objectives of thesurvey. Finally, we present some results from the new survey.

Methods

On conventional streamer seismic data at Alba field, we observe a weak, inconsistent seismic reflector at the top of the reservoir and intra-reservoirshales and a strong reflector at the oil-water contact.
Economic Benefits of FPSO Construction and Deployment in the Gulf of Mexico
Authors: Pike William J.
Published: October 2008

As oil and gas production in the Gulf of Mexico has moved to larger fields farther offshore, increased logistical and technical difficulties have mandated selection and utilization of increasingly complex floating production systems. Yet to be adopted, but viable candidates for developing fields in increasing water depths, are Floating Production, Storage and Offloading (FPSO) units whose practical application has been proven in most other offshore producing provinces worldwide. While questions have arisen about the timing of FPSO deployment in the Gulf of Mexico, it is likely that several units will be employed in the near to medium term as field conditions, project economics and logistical considerations warrant their selection.

Given current concerns about pollution risk, it is almost certain that FPSO's deployed in the Gulf of Mexico will, by regulatory mandate be double-hulled, double-bottomed, new-build units. It is also likely that a substantial number of these units will be of primarily U.S. construction due to pressure for local content; availability of construction finance underwriting from the U.S. government (loan guarantees approved under the federal ship financing program know as Title XI and administered by the Maritime Administration [MARAD]); availability of Gulf Coast building and outfitting yards; and local competence in Gulf of Mexico production parameters. Construction and outfitting of an FPSO and possible associated shuttle tankerage on the Gulf of Mexico will require expenditures of approximately U.S. $159 to U.S. $239 million. These funds will, in turn, generate economic benefits to the region of U.S. $463 to U.S. $720 million (with shuttle tanker construction) using an industry accepted economic multiplier of 2.0 to 2.5. These funds will be dispersed to the economy through direct and ancillary employment; local, regional and federal taxation; and increased demand for capital and consumer goods.

FPSO Development Scenarios in the Gulf of Mexico

At present, there are approximately 40 discovered fields in the deepwater Gulf of Mexico that might be candidates for development by FPSO. In most cases, the fields are outside reasonable reach of an established pipeline infrastructure, making an FPSO's tanker offloading system an attractive alternative to deepwater pipeline installation.

Since recovery ratios, production rates, fluid and reservoir conditions, and logistical requirements vary from field to field, a generic FPSO development scenario was developed for this paper to illustrate an economic benefit analysis format rather than an economic benefit analysis for a specific Gulf of Mexico asset. With regard to a generic development analysis of a field within the limits of those noted above as possible candidates for FPSO development, the following development assumptions were made for the purpose of this paper.
The Siri Production Jack-up Platform
Authors: Bærheim Morten , Manschot Dirk , Olsen Torgeir , Eide Henning
Published: October 2008

The Siri field is located in 60 metres water depth in the Danish sector of the North Sea. It was developed by a purpose built three legged jack-up standing on the top of a steel storage tank. The tank was installed in May 1998 and the jack-up was installed six months later.

The reservoir development requires a maximum of 12 well slots, and these will be placed inside a wellhead tower connected to the side of the storage tank and hinged to the deck.

This paper will give a brief technical description of the field development and highlight the challenges in design and installation with an emphasis on the steel structures.

Introduction

The licence for exploration and production of the Siri Central / North structures was given medio May 1995 to the Statoil Group. The group consist of the following companies :Statoil E & P A/S (operator) 40.0 %Enterprise Oil Ltd. 20.0 %Dansk Olie og Gasproduktion A/S 20.0 %Phillips Petroleum Company 12.5 %Denerco K/S 7.5 %

The first exploration well in Siri Central was spudded at the end of November 1995, with a second appraisal well drilled in August 1996 on Siri Central. The two wells gave the basis for establishing the reserves for the field development studies. A third appraisal well was drilled on neighbouring Siri East proving non-commercial reserves in that area.

A "fast track" field development strategy was established in February 1996. Screening studies of alternatives were done, and the first feasibility study of what later became the selected field concept was initiated in July 1996. Conceptual studies linked with competitive bidding with three contractors for a full EPCI bid for the complete platform including an oil offloading system was concluded at the end of December 1996. After some further development work, the EPCI contract was signed with Kvaerner Oil and Gas (KOGAS) at the end of March 1997. The storage tank was installed medio May 1998, after which drilling started with the Noble George Sauvageau jack-up drilling rig operating in cantilever mode. The 8700 t jack-up production deck was installed medio November 1998 after 7 weeks waiting on weather. This gives a time span of 18 months from signature of EPCI contract to deck ready for towage, which is considered to be very quick for a project of this size.

The Siri field

The Siri field is located in block 5604/20 in the northwestern part of the Danish sector of the North Sea, some 220 km from the coast line. The field is marginal, and various development options were investigated in the middle of 1996 to find an economically attractive solution. These included:Jacket full process platform with storage tankerConcrete full process platform with storageCombinations of steel and concrete solutionsCombinations of wellhead and process platformsFPSO ship with sub sea wellheadsConverted jack-up platform with storage tankerNew built jack-ups with storage tanker
The Development of the First Expandable Sand Screen
Authors: Metcalfe Paul , Whitelaw Calum
Published: October 2008

Eliminating the annulus between sand screens and the wellbore allows the well to be slimmed down by one casing size. This can result in dramatic well cost savings.

Wells that require numerous casing strings to reach their objective, such as those in deep water environments, could benefit from such screens because they liberate an additional casing string for the same surface casing size.

Once installed against the wellbore, an expandable screens would allow enhanced reservoir management activities. Zone isolation or treatment would be possible because of the elimination of the annulus.

This paper describes the development of the first expandable sand screen from its concept to its successful application in producing wells. An expandable screen construction was developed using slotted tubes encased in filter strips. A filter media was chosen for the screen that offered the best balance between plugging resistance and sand retention efficiency.

New manufacturing techniques were developed to produce the screen in commercially viable quantities and with the required quality.

The screens were applied in both cased and openhole applications in offshore and land environments. The trials proved that the screens could be expanded to eliminate the annulus present in traditional sand control equipment applications. The system proved easy to install and reduces the likelihood of screen failure due to plugging and erosion.

Introduction

The decision to install sand control means in petroleum wells must take into account many varied factors; It is often difficult to predict from core analysis and production testing whether a particular field development will require sand control or sand management during its producing life. If the decision to install sand control equipment is taken, it can have a large impact on the design and operation of the well. There are numerous techniques for controlling sand production, but by far the most common techniques involve the installation of screens of varying design.

Some disadvantages associated with the installation of sand control equipment in a well are:-–Higher equipment capital costs–Increased well installation time.–Reduced ability to modify or treat the reservoir inflow Profile.–Modification of the casing scheme to achieve the optimum screen internal flowing diameter.

The authors believe that the major disadvantages of current screen related techniques are those associated with the presence of the annulus between the screen and the wellbore. The existence of the annulus results in a larger casing scheme design than ideally required and severely limits the ability to control the reservoir inflow profile. In some instances the screens are surrounded by a highly permeable gravel (gravel packs). Even with this technique, the permeability contrast between the gravel and the surrounding formation means that the gravel still acts as an empty annulus in terms of the ability to control the reservoir flow from within the screen.
The International Legal Environment for Ocean Exploitation
Authors: Browning David S.
Published: October 2008

There are numerous unresolved international legal problems which may affect the exploitation and investigation of the ocean. Most of the uncertainties probably will not be resolved for several years. There will be increasing international discussion and negotiation regarding the law of the sea in the future. United States industry and government should continue to analyze the issues involved and begin to formulate positions on some of the key issues. The recent report of the Commission on Marine Science, Engineering and Resources is a significant part of this process.

A number of different legal frameworks govern the use of different areas of the world's oceans. For the purposes of this discussion, the following frameworks will be distinguished:internal and territorial waters,continental shelf,contiguous zone, andhigh seas, including the bed and subsoil.

These distinctions are significant for the exploitation of mineral and living resources of the sea, as well as for the conduct of scientific investigations at sea. [1]

Internal Waters and Territorial Sea

The coastal nation generally has full control over the exploitation of mineral and living resources, and the conduct of scientific investigation, within its internal waters and territorial sea, including the resources of the seabed and subsoil of these areas. Except as may be limited by treaty, under international law each coastal nation may establish or enforce its rules of law in its internal waters and territorial sea. The coastal nation may exclude anyone from exploring or exploiting any resources in these waters. These claims of the coastal nation are recognized even with regard to living resources which usually live in the high seas, so long as such resources are found in the territorial waters.

The International Convention on the Territorial Sea and the Contiguous Zone provides that the sovereignty of the coastal nation extends beyond its land territory and its internal waters "to a belt of sea adjacent to its coast, described as its territorial sea" and "to the air space over the territorial sea as well as to its bed and subsoil." [2] The Convention does not specify the breadth of the territorial sea, and national claims vary from three nautical miles to 200 miles or more. The position of the United States has been that no claim to a width greater than three miles has received sufficient acceptance to be a rule of international law. However, there are some indications that the United States may be moving toward a 12-mile limitation for purposes of the territorial sea. This would generally be in accord with the majority of nations which agrees that the width of the territorial sea is no greater than 12 miles. [3]

The coastal nation's "internal waters" consist of the waters "on the landward side of the baseline of the territorial sea," as well as the rivers, lakes, and canals within its land area. [4]

The "normal baseline for measuring the breadth of the territorial sea is the low water line along the coast."
World's First TLP to Achieve Classification
Authors: Major R.A. , Frazer G.R. , Taylor J.E. , Mercier J.A.
Published: October 2008

Figure 1 Sir Douglas Morpeth TLP, installed at Ewing Bank Block 921 (Available in full paper)

The Sir Douglas Morpeth Tension Leg Platform (TLP) became the first TLP in the world to achieve classification in September 1998. British-Borneo Exploration, Inc. (British-Borneo) contracted with the American Bureau of Shipping (ABS) for this function. This step is a major part of British-Borneo's overall quality management program for both the project and the continuing operation of this TLP. While all of the TLPs presently operating in the Gulf of Mexico have had their structural adequacy verified by ABS acting as CVA, British-Borneo added reviews of all marine systems, enabling the vessel to be classed. Reviews of the Atlanta Offshore Limited design covered the complete hull structure, the truss-type deck structure, the tendon mooring system, the quarters, the electrical power supply, the marine piping systems and all other aspects needed for safe operations except the process plant itself. Regulatory requirements were considered simultaneously with those of class to speed the review process. Besides classification and verification the project used selected special studies to check critical elements of designs and analyses. The marine activities on the project were scrutinized by Global Maritime, acting as marine advisors and warranty surveyors. The approach described in the paper enabled a small oil company to effectively manage the quality requirements of an advanced deep-water development by bringing highly qualified outside resources to bear within the stringent time scale of the project.

Introduction

This paper seeks to answer:What is classification?What is the process by which it is achieved?What is different with classification from previously un-classed developments?What was done during the Morpeth Project to manage the process?What other quality assurance techniques were employed in this project?

Last year, a paper was presented to OTC which proposed a number of advantages to the classification of floating production systems for the Gulf of Mexico1. This year, we are pleased to describe the first application of that process to a TLP.

Description of the TLP Sir Douglas Morpeth

The Sir Douglas Morpeth is a single-column TLP that British-Borneo used to develop its Morpeth field in Ewing Bank Blocks 921, 964 & 965 in the Gulf of Mexico. Figure 1 shows the TLP installed on location. The designer, Atlantia Corporation (now Atlantia Offshore Limited) has designated this design "SeaStar®".
Analytical and Experimental Study of the Dynamic Response of Cable Systems
Authors: Goeller Jack E. , Laura Patricio A.
Published: October 2008

Segmented cables of steel and nylon are frequently used in oceanographic applications to support a suspended payload. This report contains an experimental and analytical study of the dynamic response of nylon rope and stranded steel cables with a suspended payload under simulated conditions of ocean wave motion. A generalized distributed mass model was developed for a segmented cable made up of two viscoelastic materials including internal damping and linear external damping of the payload and cable. Viscoelastic behavior was simulated by a two-parameter Voigt model. Linear viscous damping was used for the payload and the cable, but an approximate method was developed for taking into account nonlinear damping effects. The phenomenon of impact loading due to initiation of slack in the cable was modeled on the analog computer for elastic cables, and by a digital computer for segmented cables of two viscoelastic materials. Nonlinear water damping was included in these models.

Theoretical calculations of force in the 1/4-in. nylon rope during simulated ocean wave motion agreed reasonably well with experimental results for both air and water tests. Internal damping of the nylon rope was determined experimentally from free oscillation tests. Tests on stranded steel cables indicated snap loads due to cable slack are extremely important. Snap forces as high as nine times the static payload force were encountered. It was shown that these forces can be significantly mitigated by the addition of a short length of nylon rope added to the bottom of the cable. The predicted force response agreed very well with the experimental value.

INTRODUCTION

Nylon rope and stranded steel cable are frequently used in oceanographic cable systems. Nylon is highly desirable for buoy systems, mooring systems and other oceanographic applications because of its light weight, relatively good strength and ease of handling. However, in cases where fishbite is a problem1, steel stranded cable is used in the upper portion of the cable while nylon is used in the lower portion. Many applications involve the suspension of a payload by a segmented cable of steel and nylon where the upper end is excited by longitudinal oscillation due to ocean wave motion. This problem was studied analytically2 by approximating the wave motion as a sinusoidal displacement function. The cable segments were considered as distributed masses with viscoelastic behavior including internal damping and also external damping due to fluid viscosity. The purpose of this paper is to compare experimental data with theoretical prediction using this model and a second analytical model which approximates viscoelastic behavior of nylon rope by a three-parameter model frequently referred to as a stranded linear solid. Lumped parameter models were also developed to predict the cable force during a snap condition caused by slack in the cable.
Some Notes on Static Anchor Chain Curve
Authors: Korkut M. Deha , Hebert E.J.
Published: October 2008

This paper offers fundamentals necessary to solve many of the problems posed in the design and evaluation of mooring systems for offshore operations. In addition to considering the mooring system requirements in place, the actual operational requirements of "running" anchors, dropping, etc., are also considered. Other aspects of mooring systems such as pile anchors and catenary "sinkers" are also covered. Special attention was given to anchor line stretch.

INTRODUCTION

To those involved in the offshore operations of mobile drilling units, derrick barges and pipe laying barges, the evaluation and design of mooring systems is an ever-present problem. The questions to be answered about any offshore mooring situation are many. Guidance in finding these answers is presented in this paper.

Included are fundamentals necessary or selection of proper number of anchor lines, proper fluke area, anchor type and anchor location. In addition, problems related to setting out anchors are considered dropping distance of anchors, type of dropping, required workboat pull requirements. The subject matter of this paper is relatively new and, of course, subject to discussion at the conference.

EQUATIONS OF CATENARY

Differential Equation and Solution the catenary is the curve in which a flexible chain or chord of uniform weight will hang when supported by its ends [Fig. 1].

Differential equation of the catenary can be obtained as follows: let an element of catenary ds, have Forces T and T t o acting at ends, as shown in Fig. 2.

Because any element with a force w.ds acting downward is in equilibrium, we can construct the force diagram, as shown in Fig. 3.[Ho is constant at any point on the curve.] From Fig. 3, it is easily seen that d tan ? is equal to [w.dS]/Ho or d[dy/dx], since:(Available in full paper)

Determination of The Tension in Field

Often it is required to know the tension in an anchor chain or cable of mooring systems or offshore drilling barges when it is impossible to measure the length of the chain. From experience, it has been found that existing tension measuring devices cannot provide accurate readings because of the friction developed in the hawse pipes. Eq. 14 gives an accurate value for tension when the water depth and the angle at the top of the chain are known.
The Application of Underwater TV and Video Tape Recording in Supervising and Documenting Offshore Operations
Authors: Hartdegen Fred W.
Published: October 2008

This paper deals principally with the application of underwater television and video recordings applied to the underwater operations of drilling and inspecting. The approach to workover operations is also touched upon.

The emphasis of the paper is centered around the value of documenting underwater operations. The method of applying the documentary techniques in conjunction with the use of floating drilling rigs, divers, and submersibles is discussed.

Factors to consider in the selection and utilization of underwater television and photographic equipment are briefly discussed.

UNDERWATER DRILLING

Underwater drilling has been going on for almost a decade now. Such a drilling operation can be performed from almost any type offshore rig especially if the water depth remains less than 150'.

At present underwater drilling in water depths of 300' or more requires the use of very large floaters. The semi-submersible rigs are one type that have proved quite effective. The available number of such rigs is relatively small at present, numbering less than one hundred. This factor has contributed to the scarcity of deep water drilling. In addition to this, the need versus expense of very deep water drilling has made such drilling far from routine.

However, improvements in technology and logistics should make deep water drilling a more common occurrence in the near future. This, or course, will be dictated by market needs and field potentials. At any rate, the consensus seems to indicate that drilling in 300' or more of water will eventually become routine practice.

An invaluable tool for this type of drilling is underwater TV. The placement of the wellhead assembly, the running of the casing, the positioning of the casing hanger, the connecting of the BOP stack, the running of the kill-lines and many other facets of the drilling operation canall be aided by the use of underwater TV. At present, most of these procedures are done by guide lines and "feel". The use of underwater TV adds the element of sight. The added feature of Its "sight" means increased efficiency. Efficiency means savings in rig time and this means money saved.

Semi-submersible rigs range in price from $500/hour to $700/hour. At this rate, if the use of underwater TV can save 2 hours per month then the TV has more than paid its way on a month-to-month rental. When you consider that there are 720 hours in a 30-day month, this means that 2 of these hours is about one-fourth of one percent of the total time. From an economic investment point of view it is reasonable to assume that the proper USE of UTV will always save more than this amount of operating time.

Many people are aware of the economic value of utilizing UTV in drilling operations and are in fact taking advantage of the technique. However, one vital aspect of using UTV in drilling operations has been greatly neg1ected. This is the aspect of documenting the operation by use of video type.
Wave-Exciting Forces and Moments on an Ocean Platform
Authors: Kim C.H. , Chou F.H.
Published: October 2008

The authors describe a new method of predicting the wave-exciting forces and moments acting on an ocean platform restrained in oblique seas. Procedures -are "based on strip theory.

The wave-exciting forces and moments on restrained cylinders have been investigated before, in beam seas as well as in oblique seas, but the cylinders were always Lewis cylindrical forms. In this study, the two-dimensional method developed by Frank is extended to the calculation of wave forces and moments, and the strip method devised by Grim is applied to obtain the three-dimensional forces and moments. The results of the numerical calculations for a Series 60 model are compared with the results of the latest experimental work by Lalangas. The results of an experiment conducted for the present study, on a rectangular light-drafted barge restrained in quartering seas, are compared with theoretical predictions. Theory and experiment are in generally good agreement in both cases.

INTRODUCTION

The vertical wave-exciting forces on Lewis cylindrical forms restrained in beam seas were calculated by Grim in 1960. 1 His method was later applied 9Y Tamura2 to the calculation of sway- and roll-exciting forces and moments on Lewis cylinders restrained in beam seas. Tasai then performed approximate calculations of the lateral wave-exciting forces and moments in oblique waves according to Watanabe's strip method. 3 Grim and Schenzle, in 1968, further refined the calculation of lateral exciting forces and moments on a ship restrained in oblique seas, by applying the strip method [crossflow hypothesis]. 4

Grim's method is based on the assumption that the disturbance of an incident wave caused by the ship's body is represented by the potential used in describing the water flow around the body when the body is oscillating harmonically in the calm water surface. This potential, together with the incident wave potential, constitutes the potential that describes the flow around the body under restraint in waves. In the present study, we select for disturbance the potential used by Frank. 5 His method enables us to compute hydrodynamic forces and moments not only for the non-Lewis cylindrical form, but also for the widely varying configurations of ocean platforms of the semisubmersible type.

To determine the degree of reliability of the prediction method, theoretical values are compared with Lalangas' latest experimental results for a Series 60 mode16 and with additional experimental results for a rectangular barge obtained in the present study

COORDINATE SYSTEMS

Let o-XYZ and o-xyz be the right-hand rectangular coordinate systems) as illustrated in Fig. 1. Coordinate planes o-XZ and o-xz lie on the calm water surface) and the Y- and y-axes point vertically upward.

Let the incidence of the wave be designated by µ and let the wave progress in the positive X-direction. Then the wave profile is.
Overview of the Gemini Subsea Development
Authors: Coleman Eugene , Isenmann Gregg
Published: October 2008

This paper presents an overview of the Gemini subsea development that was brought on stream in June 1999, sixteen months after project sanction. The field is located in Mississippi Canyon Block 292 (MC 292) and was developed by Texaco as operator with 60% working interest and partner Chevron with remaining 40% working interest.

The paper describes the early project decision making process and defines the basis for the selected development option. The fast track schedule adopted for the project required that a significant amount of flexibility be incorporated into the design to accommodate late changes to rig schedules and third party installation vessels.

An overview of the execution of the project highlights the team structure and contracting strategy required to maintain project quality and cost control under the fast track schedule constraint. The project results reflect success in the three critical areas of schedule, budget, and system performance.

Overview

The Gemini Field is located in Mississippi Canyon Block 292 (MC 292), approximately 90 miles southeast of New Orleans in a water depth of 3400 ft. The field was discovered in 1995 with the drilling and subsequent testing of MC 292 Well No. 1. The field is part of the three block Gemini prospect in the Mississippi Canyon area, MC 247, MC 291 and MC 292.

The Gemini Field is a subsea development tied back to the Viosca Knoll (VK) 900 Platform located 27.5 miles northwest of MC 292 in 340 ft of water. Chevron is operator of VK 900 with 75% working interest and Texaco holds the remaining 25%.

The subsea development consists of three production wells tied into a 4-slot cluster manifold, each well being located approximately 50 ft from the manifold. The manifold has two headers connected together via a pigging loop. Rigid pipeline jumpers connect the manifold to dual 12" flowlines that transport the produced fluids 27.5 miles to the host platform. The subsea system is controlled from the host via an electrohydraulic control system through a steel tube umbilical with electrical conduits. Fig. 1 illustrates the field arrangement.

The project marks a milestone for both partners, Texaco and Chevron in that it extends their experience base into greater water depths and longer offsets than any previous developments in which they have participated. This is illustrated in Fig. 2.

Discovery

Gemini is a subsalt field that was discovered in 1995 with the drilling of the MC 292 Well No. 1 rank wildcat. The discovery well encountered 120' net of lean retrograde gas condensate pay in the Allison reservoir. The Allison interval is a thin-bedded, channelized slope deposit located beneath a 2900' thick tabular body of salt. Also discovered in the Dean interval was a laminated, low resistivity, rich gas condensate sand. This well also encountered three other hydrocarbonbearing intervals: the Barry, Erin, and Luis/Marilyn. A total of approximately 160' TVT pay for the well was determined from log analysis. See Fig.3.
ISO Standards: Value?
Authors: Wisch David J.
Published: October 2008

ISO has been working to develop standards for the oil and gas industry for almost 10 years. With the recent events in the oil industry including the low oil prices of the recent past coupled with the consolidation of companies and role of national oil companies, the question of value is often asked.

This paper will discuss many of the issues surrounding development and use of standards in light of the recent events. It will draw upon the past, trends eminating from observation and draw conclusions as to value eminating from the ISO offshore standards efforts.

Introduction

Oil field standards started to appear in the early stages of the 20th century. Prior to standards in the early days, products serving the same function were not interchangeable often leading to costly and sometimes unsafe solutions for repairs and/or extensions, as well as additional costs. The American Petroleum Institute (API) started to address standardization of various aspects of the industry with a policty statement that read in part:

"API standardization activities identify and support proven, sound engineering and operating practices, ans safe interchangeable equipment and materials, for use in the petroleum industry..."

Until the 1970's, the API standards were generally the defacto standards utilized in various parts of the world. With the advent of the North Sea activities in the seventies, additional standards generated within various regions started to appear. This tendency of regional standards continued through the 1980's. With the formal joining of European Union in sight, some industry leaders started the process of reactivating a dormant international standards committee, ISO TC 67, in 1989. Concurrently, the oil industry was starting to undergo a transformation to a more global industry where many of the historically regional focused companies were becoming more and more global. A third change factor was the continued emegence of new oil producing contries as key participants in the oil industry at large.

The offshore standards parallel the overall standards with the key exception that it was the 1960's before the offshore industry had standards covering the key areas. As the offshore arena rapidly expanded in the late 1960's and 1970's, offshore standards garnered significant attention and many were initiated with many more expanded and extended as the knowledge increased.

The offshore industry, for the most part, has been a selfregulating industry. One of the biggest challenges facing the industry will be to what extent it will continue to be predominantly self-regulating. Development of standards that meet the needs of the industry at large, all of the stakeholders, is the principle means in achieving that objective.

One of the most common questions around standards has been, "What value does an ISO standard bring?" A oft heard corollary is "The existing standards are fine so what's in it for me?"

This paper will be focused on offshore facilities standards. To varying degrees, other sets of oil field standards can be viewed as being parallel.
Pierce Field Development by FPSO Solution
Authors: Hayes M.R. L. , Tangvald T.B.
Published: October 2008

The Pierce field, which is located in the UK sector of the North Sea, has been developed using a Multi-Purpose Shuttle Tanker (MST) converted into a field specific Floating Production and Storage Offshore (FPSO) facility. First oil from the development was achieved in early 1999. This paper describes the overall field development from reservoir through to export solution. Pierce is an oil field associated with twin salt diapirs with ultimate recoverable reserves of 110 million barrels of oil and 182 billion cubic feet (bcf) of gas located in Palaeocene sands in the North Sea Central Graben. The field has been developed using horizontal drilling technology with complex directional trajectories and long reservoir sections up to 6,500 ft in length. These well lengths were necessary to optimize recovery from the steeply dipping beds of the reservoir formation.

Six oil producers and two gas injectors have been drilled from two sub sea templates located 2.2 km from the FPSO. The "Berge Hugin" FPSO is of the MST design equipped with modular topside facilities. The subsea concept has enabled the use of a small innovative turret system totally enclosed within the hull of the FPSO.

Introduction

Field History.

The Pierce field lies within licence blocks 23/22a and 23/27 in the Central North Sea, 280 km east of Aberdeen in 272 feet of water. Enterprise Oil is responsible for operating the field on behalf of the Pierce owners: Enterprise Oil, Ranger Oil, MOC, Agip and Petrobras.

The Pierce South accumulation, previously known as Pierce, was discovered in 1975 by Ranger Oil with well 23/27-3. The discovery well encountered oil in Palaeocene sandstones and Palaeocene/Cretaceous chalks on the western flank of the Pierce South diapir. The well tested oil and gas at 3000 bopd and 2.1 mmscfgpd from the Palaeocene Forties Sandstone Member.

Several appraisal wells were drilled on Pierce South following discovery. Three wells were drilled from 1978-83, but all penetrated the Forties sandstones below the oilwater contact. The first appraisal well to encounter hydrocarbons was 23/27-8, drilled in 1991. The well encountered Palaeocene sandstones and Palaeocene / Cretaceous chalks on the western flank of Pierce South. The well had a maximum test rate of 5700 bopd and 5.1 mmscfgpd from Forties sandstones.

The remaining Pierce South appraisal wells are 23/27-9, - 10, and -10z. Well 23/27-9 was completed in 1992, having penetrated Palaeocene sandstones and Palaeocene / Cretaceous chalks on the northern flank of Pierce South. The 23/27-10 well was drilled on the southern flank of Pierce South in 1996, and again penetrated Palaeocene sandstones.

Pierce North, formerly known as Medan, was discovered by BP well 23/22a-2 in early 1990. The well encountered wet gas in a thin section of Palaeocene sandstones and Palaeocene/Cretaceous chalks on the western flank of Pierce North. An appraisal well, 23/22a-3, was drilled in 1991 on the eastern flank of the Pierce North diapir.