bluuebunny/crossref_metadata_2025 huggingface dataset:
Using the singularity analysis of seismic traces for improving resolution
Authors: Cao Yuming
Published: October 2008

By the convolutional model of the seismic trace, the convolution of a seismic wavelet, which has a starting point, with the reflection series, a series of spikes, brings about the singularity features of the seismic traces. The detected singularity of seismic traces can improve resolution of seismic data visibly. As a result, it should expose more geological phenomena on seismic section and benefit sequence stratigraphic studies, accurate correlation of reservoir tops and bottoms and detailed delineation of reservoir structures. The results also lie a good foundation for lithological prediction. In this paper, a wavelet package constructed with a scaling function differing from the literatures is used to detect it. The synthetic example shows the procedure of singularity analysis, and the practical example shows the validity and reliability of the algorithm.

Introduction

Today whether the exploration or the reservoir description and manage, it starves for high resolution of seismic data, but can't now. There are problems in two aspects.

The first, because seismic wavelet isn't well and truly pick up and there is some change of the wavelet with the space and time both, after the deconvolution, that now is good for improving resolution of seismic data, always a residual wavelet is leave behind. The band-limited residual wavelet badly restricts the resolution of seismic data.

The second, on one hand maybe people is restricted by the viewpoint of band-limited seismic data, which insists on that the bandwidth of seismic data is a deadline of the resolution, so processing must be all-pass in frequency domain (Li, Q., 1993). On the other hand because low resolution is so easy to process and interpret, and higher resolution is more difficult, maybe people prefer easy to difficult (Kerekes, A. K., 1998).

It is believed by a lot of successful experiment of the coherency slices, that there is plenty geologic information in the singularity feature of the seismic data. The coherency slices character the singularity of seismic data in spatial domain (Marfurt, M. J., et al 1999), whereas in temporal domain it is not yet sufficiently understood and used so far. My work (Cao, Y., 1996) exposed the fact that seismic data in temporal domain have abundant singularity too. And thed-spline function was used to construct a wavelet package for singularity analysis of seismic traces. Then the singularity analysis alternates with deconvolution, the residual wavelet was compressed availably and the resolution of seismic section could be improved visibly. In this paper, a formula of detecting singularity is used as scaling function to construct a wavelet package to get over the problem of residual wavelet. It is equivalent to the revised d-spline fitting of the regular component of a seismic trace in substance.

The singularity of a seismic trace

There are many interfaces of layers, faults, change of epositional facies and so on inside the earth.
Case History: First Coiled-Tubing-Conveyed Live-Well Intervention Run From a Semisubmersible Platform in Brazil to Increase Perforation Length in a Deepwater Horizontal Wellbore
Authors: Rosetto Ilton , Scott Martin Schoener , Etcheverry Carlos Fulvio , Almeida Jose
Published: October 2008

Coiled tubing has been used to deploy perforating guns for several years, and use of this technology has enabled many operators to complete high-angle wells with optimum completion designs. Until recently, however, this perforating method was not used in Brazil because of the complexity and risks involved, particularly on offshore platforms (semisubmersible rigs and/or drill ships) where daily costs are extremely high.

This paper will describe the first experience of coiledtubing-conveyed perforating (CTCP) performed offshore in a horizontal well in this South American country.

The first CTCP job was to be performed not only to obtain the well objectives needed for the well but also to be used as a "learning curve" for a major job that was to be run subsequent to this job using the same method. The second job was to be in a water depth of 968 ft. and more than 1,000 ft. of guns would be run. Both jobs will be discussed, along with the advantages gained on the second job from the first experience.

The first procedure required perforating of a 262-ft. interval in a 92-degree horizontal well using 2 in., 6 SPF super deep penetration scalloped guns that would be coiled-tubing deployed through 3−½ in. production tubing. The operation was to be performed from a semi-submersible platform, and the running and retrieving of the perforating guns would have to be accomplished without killing the well so that damagingcompletion fluids would not come into contact with the reservoir. Requirements for the job were that a safe method be used and that equipment and operational costs be kept at minimum so that a greater return on investment could be realized.

Operational conditions included the following:Perforation was to be conducted with the well in an underbalanced condition so that no formation damage would be sustained.The operation had to be run from a semi-submersible platform that was set in a water depth of 430 ft. (2nd d job performed in a water depth of 968 ft.)The gun assembly would have to pass through a 2.81-in. minimum ID.

Introduction

For twenty years, Petrobras has been developing state-of-theart technology for deepwater environments in order to determine best practices to realize the most efficient production. From the time of its first oil production in 1977, the Campos Basin, located off the northern part of the state of Rio de Janeiro has been proving its potential as a major oilproducing province. Already responsible for three-quarters of the country's production, Campos is by far the main production area in Brazil. During those twenty years, 66 fields have been discovered, and exploration and drilling operations have been ongoing. (See Fig. 1)

This paper will cover the two CTCP jobs that were performed in the Moreia and Albacora Fields.
Acoustic Re-Entry And The Deep Sea Drilling Program
Authors: Sims Darrell L.
Published: October 2008

High resolution scanning sonar can be used in water depths up to 15, ODD to locate a target and guide a drill string to that target.

The bit (or tool) end of the drill string can be placed over the 16 foot diameter cone target by moving the drill ship so that the bit can be lowered into the cone.

The latest sea trials indicate interrupted operations can be scheduled for bore holes in deep water without having a mechanical connection from the drill ship to the riser.

Valuable core samples for the scientific party were recovered that could not have been reached with only one bit.

Introduction

The coring equipment that went to sea on the Glomar Challenger was designed to drill and core soft sediments with minimum recovery in the basement.

It soon became apparent increased coring capabilities would be required to penetrate the unexpected hard formations that were encountered at most of the sites. In addition, the scientific community was expressing interest in deeper penetration into the basement.
Ceiba Field Development: Fast Track to Early Cash Flow Management's Perspective
Authors: Garrett Marvin M. , Drinkard Don M.
Published: October 2008

The Ceiba Field development offshore Equatorial Guinea has proven to be a success for Triton and its partners Energy Afric aand the Ministry of Mines and Energy of Equatorial Guinea. A brief background of the Ceiba Field will be presented, however the main focus of the paper is Triton management's perspective of the development. Management's objectives for the project will be discussed, as will the phased approach to development. This approach led to use of an early production system to develop a major deepwater field on a fast track basis. The management perspective will detail the project drivers and achievement of the desired results.

Introduction

Triton Equatorial Guinea, Inc.'s discovery of the Ceiba Field in October 1999 opened the door for the company to build a sizable business in West Africa. With an entrepreneurial organization and flexible operational philosophy, company management put Ceiba development on a fast track, targeting an aggressive timeline for the project that moved from discovery to cash flow in 14 months. The company employed a phased approach to realize the opportunity presented by Ceiba. Parallel processes and off-the-shelf technology were utilized to optimize field production and the value of Triton's holdings while managing risk.

The Triton team completed the first development phase (Phase 1) and achieved first Ceiba production in November 2001. Full field development infrastructure for the Ceiba project (Phase 1A) was completed in January 2002, with the promise of more solid development ahead.

Equatorial Guinea: Prolific Oil Stronghold

Equatorial Guinea, where Triton (acquired by Amerada Hess Corporation in August 2001) strongly believed there was substantial opportunity offshore in deep water, ranked high among the company's drilling prospects. The Republic of Equatorial Guinea lies in the heart of the active West Africa region. It has been a country of growing interest to E&P companies since the first major discovery was made there in the mid-1990s. This small Spanish-speaking country comprises Bioko Island, the home of the capital city of Malabo, and the Rio Muni area on the mainland.

Great Discovery Well

The foundation for the Ceiba project was a great discovery well. Ceiba-1 was drilled to a total depth of 9,700 feet in about 2,200 feet of water on Block G about 22 miles offshore Rio Muni. Wireline logs and other test data indicated a gross oil column of 742 feet and 314 feet of net oil-bearing pay in four zones. The high-quality turbidite reservoirs have excellent porosities ranging from 20%-30% and permeabilities up to 1 Darcy. This excellent reservoir was confirmed with a well test of 12,400 BOPD of 30 degree API oil from one zone.

Ceiba-2 Proves Commerciality

Triton's next mission was to appraise Ceiba to prove its' commerciality while proceeding with development planning that anticipated success. With the thickness and quality of the Ceiba reservoirs, it was easy to set the development on a fast track.
Ceiba Field Subsurface Considerations
Authors: Weaver R.A. , Dailly P.A. , Lamar A.T. , Lowry P. , Mees C.G. , Monson G.D.
Published: October 2008

This paper describes some of the subsurface considerations that were involved in Triton Equatorial Guinea, Inc. (Acquired by Amerada Hess Corporation in August 2001) rapid development of the Ceiba field.

Introduction

The Ceiba Field is located offshore Equatorial Guinea approximately 75-km southwest of the port city of Bata and 275 km south of the city of Malabo (Figure 1).

The Ceiba Field was discovered in September 1999, with the drilling of Ceiba-1. The first appraisal well, Ceiba-2 was drilled in November 1999 approximately 1.6-km southwest of Ceiba-1. Ceiba-1 and Ceiba-2 were drilled based on interpretation of 2D seismic data acquired between 1984 and 1998. Open-hole logs, cores, pressure data, and a DST of Ceiba-1 indicated that both wells contained Cretaceous sands of very high quality, capable of producing high rates of oil. Ceiba-1 was drill stem tested at rates as high as 12,400 barrels of oil per day. Ceiba-2 was not tested because of the excellent reservoir quality indicated from the open-hole logs, cores, pressure data, and the oil samples recovered. Figure 2 shows the general stratigraphic section from the Rio Muni Basin, which was encountered in both wells.

In December 1999, the Ceiba Field Plan of Development Phase 1 was submitted to the Equatorial Guinea Ministry of Mines and Energy. The Plan detailed the work necessary for early, initial production from the Ceiba Field. The Plan of Development Phase 1 was approved in December 1999.

A 3D seismic survey was completed over Block F and Block G in March 2000. A portion of the survey that encompasses the primary Ceiba reservoir was processed and interpreted to determine the location of appraisal wells necessary to confirm the extent of the field. Results of the 3D seismic survey were used to select the placement of three further appraisal wells, Ceiba-3, Ceiba-4 and Ceiba-5.

These additional appraisal wells were drilled in June and July of 2000 and confirmed the presence, connectivity, and quality of the reservoirs encountered in the Ceiba-1 discovery well. The locations of the drilled wells are shown on Figure 3.

Concurrent with the drilling of the appraisal wells, construction of an early production system consisting of a converted oil tanker was initiated. In November 2000, only 14 months after initial field discovery, the Sendje Berge FPSO was installed in the Ceiba Field and production commenced from the Ceiba-2 well.

Geologic

Ceiba Field is located on the present day continental slope in approximately 700m of water. The depth to the crest of the structure is approximately 2125mSS at the Top Campanian reservoir level. The depth to the free water level is 2471mSS giving the field a gross-oil-column-height of 346m. The field sits within a NE-SW trending belt of salt-cored structural highs, interpreted as base of slope compressional features, in the Rio Muni Basin.
Images of the Base of Gas Hydrate Stability, Northwest Walker Ridge, Gulf of Mexico
Authors: McConnell Daniel R. , Kendall Beth A.
Published: October 2008

The gas hydrate stability zone, the zone below the seafloor where gas and water should form gas hydrate is predicted to be present in the tophole sections in deepwater areasaround the world including the deepwater Gulf of Mexico. Few, if any, bottom simulating reflectors (BSR) or other manifestations of the gas hydrate stability zone have been interpreted in the Gulf of Mexico. This paper presents convincing images of the base of the gas hydrate stability zone extracted from exploration 3-D data in Northwest Walker Ridge in the Gulf of Mexico from the upper 1,050 m of sediment. This area is on the margin of an uplifted and compressed mini-basin and in the vicinity of numerous giant gas mounds at the seafloor. Interpreted tophole stratigraphy includes laterally extensive, steeply dipping basin floor silts and sands. This paper shows images of hydrate-trapped gas at multiple reflectors at depths that are coincident with the predicted base of the hydrate stability zone if modeled with a geothermal gradient of 19.6 ± 0.5 °C/km. A BSR is seen in the seismic data in vertical section, but the more convincing images of the base of gas hydrate stability are seen in map view.

We expect that the subsurface conditions here are not unique and the hydrate stability zone is similarly imaged, but perhaps has not been recognized, in similar settings in other parts of the Gulf of Mexico and elsewhere in the world.

Recognition of hydrate-trapped gas can aid in better decision making for shallow-gas avoidance strategy for exploration drilling and optimal design and placement of conductor strings for deepwater development wells. The possible concentrations of gas hydrate reservoirs in the updip margins of hydrate traps should also be of interest to those that are evaluating the feasibility of commercial exploitation of gas hydrates.

Local Geologic Setting

Figure 1 shows the study area in the northwestern part of Walker Ridge in the Gulf of Mexico. The focus of the study is in an uplifted and compressed minibasin with giant gas mounds to the northeast and a large salt wall with shallow buried salt or salt cropping out at the seafloor to the south. Thrust faults within the mini-basin have seafloor expression (Figures1 and 2). The source of compressive stress is apparently from shallow salt movement north-to-south on the northern margin of the minibasin. A larger, deeper salt withdrawal basin (not shown) is oriented northwest-to-southeast, northeast of the giant gas mounds. Both of the salt withdrawal basins filled with Pliocene and Pleistocene sediments transported from the shelf-edge towards the central Gulf of Mexico Basin. The minibasin is filled with typical deepwater sedimentation cycles composed of debris flows, basin floor splays, channels, thin turbidites, and hemipelagic clays.
Ils- A Passive Insulation Solution To Answer Cool Down Time Challenges On Deep Water Flowlines
Authors: Hallot Raymond , Couprie Stephane , Chomard Angele
Published: October 2008

Flow assurance issues are driving more and more the design of Deep Water Flowlines, and Cool Down Time requirement has a major impact on the global system design for most West African subsea field developments.

A new thermal insulation solution has been developed, named ILS (Liquid solid Insulation), based on the use of phase change materials (PCM). This paper presents the principle of the ILS solution and the main results achieved through the development program, from the theoretical analysis to the qualification tests.

In normal flowing conditions, the PCM liquefied by the oil's heat flux acts as a heat accumulator. During production shutdowns and resulting cool down, the phase change material's crystallization restores partially this stored heat to the flowline. Therefore, such an insulated coating produces a significant thermal inertia to the flowline and the cool down delay before hydrates formation is 2 to 4 times longer with regard to the existing insulation technologies.

Due to the incompressibility, the low density and the low cost of chosen phase change materials, ILS is able to deal with deepwater & ultra deepwater flow assurance requirements and to compete with existing pipe-in-pipe or syntactic thermal insulation.

INTRODUCTION

Deep offshore flow assurance issues

It is now obvious that construction and exploitation of deep sea and ultra deep sea offshore fields induce specific and novel concerns, with regard to conventional shallow water offshore. One of the more critical problems is flow assurance at such water depths, for both steady state production and shutdown / restart conditions.

The first deep sea flowlines characteristic is their need to be efficiently thermally insulated, in order to preserve a sufficient production temperature on the FPSO topsides, and also to avoid solid deposits on the pipe wall : actually, deep offshore fields whose exploitation is forecast to be profitable are often spread over very large areas, which implies longflowline layout on the sea bottom, in low temperature sea water. Moreover, due to the depressurisation inside high deep offshore risers, the gas phase expansion and the light cuts vaporization produces a severe cool down ofproduced effluents.

Another specific concern about deep sea flowlines is the risk of gas hydrate plug formation, at relatively high temperature under high pressure, especially during production shutdown and restart episodes. The cool down time to reach the hydrate formation temperature in shutdown condition is a major requirement of deep sea flowlines ; it must be sufficient enough to allow the completion of flowline emptying operations, or to start a dedicated heating feature.

In order to fulfill these requirements, the current or emergent technical solutions can be sorted in the following two categories :

Passive thermal insulation : Pipe-in-pipe technology or syntactic foams, ensuring simultaneously the insulation function and the cool down time function.
Controlling Hydrocarbon Fires in Offshore Structures
Authors: Chamberlain G.A.
Published: October 2008

This paper reviews improvements in the understanding of fire hazards and protection in offshore structures since the Piper Alpha disaster in 1988. Important new knowledge on fire development, spread and escalation have come about through a number of industry sponsored initiatives, which have also demonstrated how to control and mitigate fire hazards by good design and effective protection. The most notable gains in knowledge have been in the areas of unconfined two-phase hydrocarbon jet fires, confined jet and pool fires (compartment fires), and understanding the value of area deluge for fire mitigation.

Background

The Piper Alpha disaster was a tragic milestone in influencing the Safety Case regime [1]. Since then there have been a number of Industry sponsored initiatives, which have contributed to significant advances in the science and understanding of the consequences of accidental hydrocarbon fires in offshore structures and the engineering of safe design. While some uncertainties remain, the application of this knowledge, via a Hazards and Effects Management Process or appropriate Standard (e.g. ISO 13702:1999), is normally sufficient to improve design and operation of plant in a cost efficient way.

A short review of the fire hazard aspects of the Piper Alpha disaster helps to focus on credible scenarios. Next to each event are some pertinent questions asked of the main fire hazards and the effectiveness of possible protective barriers that could be brought to bear in safety studies and design:The initial blast ruptured oil lines in the adjacent module. How severe was the resulting fire? To what extent does the surrounding congestion and confinement affect the severity? How toxic is the smoke?The Tartan riser failed on the outboard side of the emergency shut-off valve resulting is a full-bore jet fire. What protection should be applied to risers and valves? Is passive fire protection (PFP) adequate? Will PFP age with time and then be less effective against fires? Is a sub-sea isolation valve effective against rise fires? How close to the platform should it be located?The water deluge system did not operate. How effective are water-based systems in controlling different types of fire?How effective are blowdown systems against different types of fire? What strategies should be adopted? The Blast and Fire Engineering for Topside Structures (BFETS) Project [2,3] started in 1990 was the first major initiative to provide interim guidance on how to reduce the potential for such disasters. This project also identified gaps in knowledge and recognized the need for full-scale experiments and further guidance, which have been addressed in numerous follow-up studies and other Joint Industry Projects. In this paper I review the considerable progressmade to address the questions raised above.

Fire Hazards

An accidental release of flammable hydrocarbon results in a variety of fire consequences, dependent on the type and initial state of the hydrocarbon.
Vessel to Vessel Fluid Transfer Line Alternatives and Costs for the Gulf of Mexico
Authors: Mungall J.C.H. , Mattern M.A. , Bhat S.U. , Compton C. , Jackson D. , Steube C.H. , Noble P.G.
Published: October 2008

The transportation of stabilized crude by shuttle tankers instead of by pipeline offers cost and market flexibility advantages. The stabilized crude is stored on an FSO for periodic offloading to shuttle tankers. Fluids are transferred between Dry Tree Units (DTUs) such as Tension Leg Platforms and Spars and the FSO by means of Fluid Transfer Lines (FTLs). Additional cost benefits can be obtained by splitting the facilities between weight sensitive Dry Tree Units and the FpSO. An overview is presented regarding the practicality, cost and selection of vessel to vessel FTLs for use in the Gulf of Mexico. Four different FTL configurations are investigated: Flexible and steel W-Wave (near-surface) risers, Flexible Freehanging catenaries, and a Steel Catenary Riser (SCR) and Steel Lazy-Wave Riser (SLWR) combination that extends to the seabed. Installation and material costs are presented. Attention is focussed on flow assurance-especially as regards pipe sizing and insulation requirements. A base case is selected, and sensitivity studies are carried out for three vessel separations and for three water depths.

Introduction

The conclusions of the 2001 OTC paper on shuttling in the Gulf of Mexico serve as a starting point for this paper, (Ref. 1).

The conclusions were that:Given the current world energy market and the US demand for energy resources, deepwater exploration in the Gulf of Mexico (GOM) will continue at a rapid paceThe active GOM exploration programs will likely identify substantial discoveries spurring field development technology.These discoveries will be located further from existing field infrastructure requiring additional existing infrastructure and development of new transportation systems.Shuttling is a proven offshore transportation technology that is in use globally operating in both benign and harsh weather conditions.Both pipeline and shuttling transportation systems will be essential to meet the volume requirements of the Gulf of Mexico and energy demand of the US.

The type of field layout that is particularly suited to the employment of shuttle tankers is shown in Figure 1. The goal is to minimize DTU cost by placing as much of the processing facilities on a FpSO. The storage offers the developer the option of offloading stabilized crude to a shuttle tanker-increasing infrastructure independence and lowering cost, while avoiding the need to tie into an oil export pipeline system. (There is still the need to tie into a gas export pipeline system.)

One of the keys to reducing costs is to transfer the maximum amount possible of facilities from the DTUs to the FpSO on account of the reduced cost of FpSO "real-estate." This requires the presence of FTLs, for which there are a number of alternatives. Separations between the platforms can be significant because the FpSO must be turret moored. The separations will be of the order of 2000m or 3000m unless the vessels are coupled through their moorings.
Failure Analysis of Texas Tower No. 4
Authors: Jin Z. , Bea R. , Sharples B.P. Malcolm
Published: October 2008

The Texas Towers were a series of platforms installed off the U.S. East coast in the 1950's to support early warning radar facilities. Texas Tower No. 4 (TT4) was installed in a water depth of 185 feet in 1957. At this time, TT4 was heralded as an ‘engineering marvel’, a major innovative ocean engineering accomplishment. However, problems in the structural integrity of the platform developed after the installation. In spite of vigorous efforts trying to save the platform, TT4 failed during a storm in January 1961 with the loss of the lives of all 28 personnel that were onboard at the time. This was one of the famous incidents during the early age of Ocean Engineering. In 2000, a study was undertaken by the authors together with the American Bureau of Shipping who pooled their resources of information and insights into platform behavior and experience to revisit the failure of TT4. The objective of this study was to see if with modern ocean engineering technology (storm forces, structure capacities), the details of failure of the structure could lead to a better understanding of behavior of current platforms where there is a paucity of actual failure. This paper summarizes the results from this study and the associated study of human and organizational factors in the life-cycle of what was, at the time, an innovative deepwater structure.

INTRODUCTION

The Texas Towers were a series of platforms installed off the U.S. East coast in the 1950's to accommodate early warning radar facilities. Texas Tower 4 (TT4) was installed in a water depth of 185 feet in 1957. At this time, TT4 was heralded as an ‘engineering marvel’; a major innovative ocean engineering accomplishment. But, shortly after it was installed, unusualmotions and sounds were reported by personnel onboard the platform. Studies were commissioned to measure and analyze the dynamic motions. The second author was a graduate student at this time and assisted with the analysis of the motions of TT4 conducted by Brewer Engineering Laboratories[6].

Studies of the dynamics indicated that bracing and joints were not as effective in stabilizing the platform as had been anticipated during the design of the platform. Pinned joints and some damaged braces were identified as likely responsible for the excessive motions. Underwater inspections later confirmed these results and supplemental bracing was installed in an attempt to stabilize and strengthen the platform. In September 1960, a hurricane further damaged the platform; fracturing underwater braces and joints. In December 1960, the decision was made to evacuate TT4 for repair, but before this could be done the platform was hit by a winter storm in January 1961 and collapsed into the sea with the loss of the lives of all personnel onboard.

Subsequent to the failure, extensive underwater surveys identified many of the factors that were responsible for the failure of TT4. These were presented into a Congressional Committee hearing evidence investigating the collapse[1,2,3].
Alternatives for Deepwater Field Developments: A Real Option Approach
Authors: Dezen F. , Morooka C.
Published: October 2008

Option-pricing theory has moved from the financial markets mainstream to the decision making process for upstream projects in the petroleum industry, taking shape as Real Option Valuation (ROV) techniques. It is proposed herein to employ option-pricing theory for selecting the best alternative among different execution plans (or competitive technology) for an offshore oilfield development.

Introduction

Current economic models that support the decision-making process are not always capable of indicating and accounting for the benefits of flexible field development plans (ref 1). The economic result of a project is not usually predictable, and therefore future uncertainty plays an important role into the valuation exercise. Hence a technology that possesses greater flexibility should be more attractive than a less flexible alternative.

For some time managerial intuition has been alone in stating that flexibility is more attractive from an economic standpoint, not anymore. Real Options Valuation techniques are used to assess and inform management the correct value of flexibility. Flexibility to react to new information as it arrives has a considerable value to the company so it is not locked to an execution path that has been set maybe several years ago.

A methodology that supports the decision-making process for selecting the optimum field development plan for an offshore oilfield is proposed in this paper. In this methodology ROV is presented as a tool that builds on the Discounted Cash Flow (DCF) techniques used extensively for economic evaluation. It highlights ROV's importance when comparing different technologies and field development plans for developing an offshore oilfield, and why it should be used instead of simple DCF analysis.

Discounted Cash Flow

DCF techniques are used to calculate the Present Value (PV) of a certain future income or expense. The most common approach to evaluate a field development plan is to elaborate for a given project its cash flow, where the future project expenses and revenues are accounted for (ref 2). All different alternatives to develop a field will have its cash flow built and be represented by its DCF parameters, usually the project Net Present Value (NPV).

The project's NPV represents the sum of all expenditures and all revenues that the project will generate during its life. In this case the future inflows of cash generated by the sales of the field's products are positive values, whereas the expenditures to develop the field and to operate its facilities are negative values. If the company uses DCF only it will choose the alternative that possesses the largest NPV as the one to proceed to the execution phase. This is a completely static analysis that disregards any uncertainty to the future values presented in the DCF analysis.

In order to assess the future uncertainty of the project's value the DCF techniques would employ other tools such as Monte Carlo simulations, decision trees, scenario analysis, etc.
Determination of the Strength of an Ice Sheet From Small Sample Data
Authors: Maser Kenneth R.
Published: October 2008

The results of various types of tests on small-scale samples of ice are discussed and compared. Some of the results, particularly those associated with varying load rates, are explained by introducing the effects of time dependent plasticity and grain size. A simple model is presented which explains some of the load rate effects in uniaxial specimens, and on the basis of this model, a more refined computer model has been developed which simulates small-scale sample tests, the sample being developed from an assembly of grains. The potential application of small-scale tests to predicting strengths of ice sheets is discussed.

INTRODUCTION

Due to the great difficulty and expense associated with performing full-scale tests on ice sheets, many investigators have sought to supplement these limited results with the results of tests on small samples. It is assumed that the results of these small-scale tests, when properly interpreted, can help to predict. the strength of an ice sheet and its dependence on the parameters of temperature, salinity, load rate, and thickness. Unfortunately, many of the reported small-scale results fail to agree amongst themselves and with some reported full-scale results, and these inconsistencies have yet to be adequately explained.

This paper presents the preliminary results of a study designed to improve the understanding of small-scale test results on ice, with the intention of applying the results to full-scale ice sheets. Of primary interest is to determine just what the stress distribution is, in what amounts to an inhomogeneous inelastic material. This is quite a difficult problem in itself, and must be tackled first before small-scale test results can be applied to the prediction of strengths of ice sheets.

PREVIOUS TEST RESULTS

The types of tests which have received the greatest attention are uniaxial tensile and compressive tests, ring tensile tests, Brazil tests, and flexural tests. These tests are shown schematically in figure 1. In all cases the maximum stress at failure has been computed assuming that the sample is a linearly elastic, homogeneous solid. With the exception of the uniaxial compression test, maximum tensile stress is generally assumed to govern failure. The general trend for these results has been uniaxial compression +ring tensile + flexural uniaxial tension in order of decreasing stress at failure. The most desirable test for tensile strength is the uniaxial tensile, since it produces the most uniform stress field. In addition the uniaxial tensile data of Peyton2 and Dykins3 seem to produce better agreement with full-scale beams cut out of ice sheets, as reported by Dykins4 and Tabata than do any of the other tests. Unfortunately, the uniaxial tensile test is not suited for field work, whereas the ring tensile test, which has yielded the most unrealistic values for tensile strength, is the simplest to perform.
Troll Pilot Technology- The Next Step
Authors: Rasmussen Andreas W.
Published: October 2008

Short introduction to Troll Pilot-The world's first subsea separation of oil/water/gas with re-injection of produced water.

Presentation of the main drivers and benefits of subsea processing in Deep waters

Presentation of the new technology introduced on Troll Pilot.

Presentation of the next steps of subsea processing for increased benefit and application of the technology.

Norsk Hydro is the operator at the Troll Field where also Statoil, Shell, TotalFinaElf, Conoco and Petoro are partners.

Introduction

Troll Pilot-The worlds first subsea separation station of oil/water/gas has been in operation on the Troll field since August 2001. The Troll field is located 80 km west of Bergen, Norway in the North Sea. Norsk Hydro is operator and the other partners are Statoil, Shell, TotalFinaElf, Conoco and Petoro.

The Troll Pilot is tied back to Troll C (Semi) which is located 3.3 km away. It is located at a water depth of 350m. The well stream comes into the subsea station from 4 subsea wells. On the seabed the stream is separated in a gravity separator into 3 phases Oil, Water and Gas. The oil and the gas is mixed at the separator outlet and sent back to Troll C in one flowline, while the produced water is being re-injected by a dedicated water injection pump into a water reservoir. The produced water is not used for pressure support on the Troll field.

The production can also bypass the separator via a separate flowline.

The Station consists of the following main modules that are all fitted on the same structure: Horizontal Gravity separator, Water injection Tree, Water Injection Pump, Manifold and Covers.

The Troll Pilot has a liquid capacity of 60.000 bbl/d. Water Injection capacity up to 55.000 bbl/d (Max 1000ppm Oil in Water). Oil capacity up to 35.000 bbl/d (Max 10% Water in Oil). Gas Capacity 28MMscf/d. Its installation weight is in range of 400t with liquid filled separator.

Drivers and Benefits in Deep waters

There are several drivers for subsea separation in general, but for deep waters there are in particular 2 effects that can make large financial impact. This will be illustrated below.

Increased recovery/Reduced back pressure

Water has higher density than oil. By removing the water from the production riser, the pressure that the reservoir would meet would be less than during untreated well-stream. This effect increases with water depth.

As an illustration, we can see the following scenario: We have a water depth of 1500m and an 8" production riser which is 3000m long. Assuming a water-cut of 80% which is not abnormal when the reservoir is in tail-end production and a 15.000 bbl/d of oil production, the pressure reduction at the wellhead could be increased by as much as 70 bar by removing the water.
A new drilling system that safely allows a significant reduction of drilling costs- Environmental Safe Guard (ESG)
Authors: Kotrla John E. , Johnson Joe S. , Williams Vance
Published: October 2008

This paper outlines the history of traditional offshore drilling with subsea Blowout Preventer (BOP) stacks and conventional riser and then illustrates the new method of surface stack drilling using the Environment Safe Guard (ESG).

Introduction

With the high cost of drilling in deepwater (greater than 2,500 feet/760 meters) and the limited number of available rigs with the capability of drilling in these water depths, a new approach to deepwater drilling was needed to try to reduce drilling costs to a more manageable level.

As the water depth capability of new rigs increased, so have the costs. These high costs have resulted in many small, deepwater fields being rendered uneconomical to produce. In an effort to bring these fields back to economic viability, drillers have tried several ways to reduce their deep-water drilling costs. One of the most promising of these methods is to relocate the subsea BOP Stack to the surface and replace the large bore, low pressure drilling riser with conventional casing as the high pressure riser between the seabed and the rig. However, use of this method must be limited to the most benign sea state and weather conditions because of the risk of damage to the casing riser, which could result in environmental contamination.

Surface Stack drilling has been successfully implemented in the south Pacific, but only during the summer months. In this area and under this weather window limitation, exploration drilling costs have been reduced by up to 35% with only a few emergencies arising.

In order to continue and broaden the use of this proven cost saving drilling approach, a means of increasing the safety of the overall system, by reducing the risk in case of riser failure was required. If the riser could be sealed off at the seabed, the risk of riser failure could be completely eliminated. Also, if the riser could be disconnected just above the seabed sealing mechanism, overall rig safety could actually be increased beyond current levels. This is easily achieved using an assortment of existing, field proven components located on the seabed.

Background

The idea of locating a BOP Stack on the ocean surface to provide well control while drilling for offshore oil is not new.

Figure 1, Typical Jack-up Rig

When the first land rig was mounted on a barge decades ago, these systems were common. Later, Jack-up rigs (Figure 1) were outfitted with such systems. Jack-up rig evolution allowed their water depth capability to be expanded to 650 ft. Then, Semi-submersible rigs (Figure 2) and Drillships were developed and the BOPs were moved to the sea floor allowing a relatively low-pressure (and thus, less expensive) riser to transport the drilling mud returns back to the mud processing equipment located in the rig by way of the Riser annulus. This seabed BOP configuration facilitated the original water depth expansion to 1500 ft. with second generation rigs, and later to 3,000 ft. with third generation rigs.
Hole Quality: Gateway to Efficient Drilling
Authors: Chen David C-K. , Gaynor Tom , Comeaux Blaine , Glass Kevin
Published: October 2008

A high-quality wellbore is generally considered to have (1) a gauge hole, (2) a smooth wellbore, and (3) a wellbore with minimum tortuosity. This paper will demonstrate that wellbore spiraling is the primary contributor to poor hole quality and that almost every well contains some degree of spiraling unless specific actions are taken to prevent it. Hole spiraling was first studied by Lubinski et al. in the 1950s, and they described it as a "crooked hole." Although the symptoms have been well recognized in the industry, only recently has a solution been proposed and tried specifically to cure hole spiraling. To implement the concept, two new drilling systems (a steerable motor and a rotary steerable) have been developed. Field data indicate that generating a straighter, high-quality wellbore has improved almost every aspect of drilling. These improvements include lower vibration, better bit life, fewer tool failures, faster drilling, better hole cleaning, lower torque and drag, better logging tool response, and better casing and cement jobs. Several case studies will be discussed to demonstrate the positive economic impact of producing a high-quality wellbore.

Introduction

Hole quality can have a profound effect on the total well construction time and cost and sometimes even determine the success of drilling a well. The importance of good borehole quality increases as extended-reach and offshore wells become more common, as they have in recent years.1, 2 In general, a good hole quality is measured by (1) hole gauge, (2) wellbore smoothness, and (3) total tortuosity. While some hole problems are a function of wellbore stability and must be addressed with proper mud weight, others arise as a result of poor wellbore geometry. For example, how accurately does the borehole itself follow the surveyed path? Does it follow a more or less helical path around the centerline of the planned well trajectory like a spiral? Poor wellbore geometry is an area that is often overlooked, but it is important that the following questions be addressed: Is hole spiraling prevalent? If it is, why haven't we known it? And what is a high quality hole worth?

Hole spiraling is not easy to detect because MWD surveys are usually at least 30 ft apart. Because the collars will lie on the low side of the wellbore, the survey data would show very little trajectory variation. However, a sinusoidal form of borehole can be clearly seen by a wireline imaging log (see Fig. 1) or the formation evaluation logging tool data (see Fig. 2). Nieto et al.3 report that it is quite common to see boreholeinduced "sinusoidal" noise on logging tools, especially those relying on contact or proximity to the wellbore wall.

Some pieces of data would indicate that spiraling is prevalent in many wells. One is a study4 that showed that wells drilled with a new steerable drilling system produced friction factors significantly lower than conventional steerable systems.
Developed Wellbore Abandonment Grout with Fly Ash
Authors: Cho Hyun , Shah Subhash N. , Jeong Yeon-Tae
Published: October 2008

The primary importance of plugging to abandon a well is to prevent contamination of groundwater aquifers by surface water, oil or gas seepage, or brine formations below the groundwater aquifers. Cement grout is the present material used in plugging. Fly ash is known to have properties very similar to cement and can be produced with strength similar to cement. Presently, only about half of the fly ash produced by the various coal-fired power plants is used and the rest must be treated as a waste product and disposed of in landfill. Much of this fly ash is the higher lime content, more cementitious, Class C fly ash.

The present research has been funded by Integrated Petroleum Environmental Consortium (IPEC). This research reveals Class C fly ash can be retarded like cement when slurried and it can be pumped and placed like cement with coiled tubing instead of employing a rig. To ensure a comprehensive understanding fly ash grout characteristics as a cement material, the extensive experiments were performed. These involved chemical compositions, size distribution, compressive strength, thickening time, durability, and rheology of fly ash slurry. Effects of the various additives on the characteristics of fly ash slurries were investigated by the extensive experiments. Frictional pressure loss tests were also performed with field size equipment in order to apply coiled tubing technology in placing fly ash slurry to the downhole of wellbores. Fly ash formulations chosen as the best candidates were pumped through a 2000 ft reeled of 1 ½-in. tubing and a 20 ft straightened 1 ½-in. tubing to determine frictional pressure characteristics. This paper specifically describes a process developed by the Well Construction Technology Center at the University of Oklahoma to formulate the best fly ash grout. This research results provide a cheaper, environmentally friendly, and more economical method of plugging wells.

Introduction

The use of fly ash has been studied to a certain extent in the past, however, pursuit of its use was not of extreme importance due to availability, familiarity and cost of cement. Its' use as an additive only has been studied extensively, however, stand-alone cementation with fly-ash has not been studied due to regulations specifying cement grout as the material that must be used. Much of this fly ash is the higher lime content, more cementitious, Class C fly ash. It is important to highlight the fact that fly ash does not have any harmful material among its components, which could make it hostile to subsurface environment.1–3 Fly ashes or any of their components are not included as harmful materials in the Identification and Listing of Hazardous Waste from the Environmental Protection Agency (EPA).4

A fly ash grout formulation has been developed based on the fundamental research. The physical characteristics of this formulation have been verified and it is found that the formulation can be applied as a plugging material and can be a substitute for cement.