bluuebunny/crossref_metadata_2025_split huggingface dataset:
Alternatives for Deepwater Field Developments: A Real Option Approach
Authors: Dezen F. , Morooka C. 
Published: October 2008

Abstract
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

ABSTRACT
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.
Effective and Holistic Approach to produced Water Management for Offshore Operation
Authors: Georgie W.J. 
Published: October 2008

Abstract
The disposal of produced water from offshore operations in the North Sea, the Gulf of Mexico and other seas worldwide becomes an important and critical issue to the operators concerned, governmental and regional organizations as well as to the environment. In order to establish a better understanding of the produced water management and handling issues and to determine the optimum solution in dealing with increased volume of produced water discharged into the sea, a better approach and tool for evaluating the different options are necessary.
Handling and treating produced water should be dealt with from the source of the problem. Therefore a holistic approach is needed in order to address the problem more effectively.
From operation experience, it has been established, an effective approach in dealing with the produced water problem should include all relevant upstream facilities, including design of the process system and separators, method of operating the plant and the configuration and routing of the different fluid streams. Different parts of the process equipment can play a major part in either improving or reducing the overall efficiency of produced water.
In addition, understanding the characteristic of both the produced fluid chemistry and all other production chemistry aspects of the system will be a critical part in achieving an effective produced water management.
Therefore it is fundamental to the whole process of produced water management to have an integrated approach to deal with the undesirable water. This approach should include from the early stage of development as well as later production, design aspects, selection of equipment and instrumentation as well as a clear understanding of all produced fluid issues.
Although produced water handling issues are crucial to any operation onshore or offshore, this paper will address primarily the offshore aspects of handling produced water. However, the principle of treatment and the design basis of produced water handling facilities should not be any different regardless if it is related to onshore or offshore operation. In many respects the onshore operation will have the benefit of endless space for locating equipment and required facilities, whereas the offshore operation does not have this advantage. However, overall the disposal of produced water onshore can be just as challenging if not more complicated in certain geographical locations.
Using past and current experiences as well as a full understanding of operation limitations of different technologies, the means to troubleshoot and optimize produced water systems and to establish an effective management approach for the long term can be established on the understanding of the holistic approach to produced water management offshore.

Introduction
Produced water is a secondary product that oil and gas producers worldwide have to deal with both onshore and offshore. There are equal challenges if not more complicated in dealing with this secondary product onshore as well as offshore.