bluuebunny/crossref_metadata_2025 huggingface dataset:
A Method for Characterizing Costs and Benefits of Future Regulatory Requirements on the U.S. Natural Gas Industry
Authors: Godec M. L. , Becker A. B. , Smith G. E. , Pauling Gene
Published: December 2007

At the same time that natural gas is being promoted as an environmentally preferred fuel with expectations of rising use, future environmental requirements may constrain U.S. supplies. A desire to reconcile contradictory environmental objectives has led the U.S. natural gas exploration and production (E&P) industry to call for a better understanding (and better balancing) of the costs and benefits of environmental requirements that may confront it.

The use of systematic "cost/benefit analyses" is one approach that many claim can assist in characterizing explicitly and quantitatively (and ultimately balancing) the environmental and economic impacts of environmental initiatives. This paper presents a methodology, currently under development by the U.S. Department of Energy (DOE), that could allow the costs and benefits associated with alternative environmental compliance requirements affecting natural gas E&P operations to be more systematically and comprehensively analyzed within a total market context, while still accounting for the site-specific geological and engineering aspects affecting operator economic decision-making. Through presentation of this developing analytical capability, the authors hope to begin a dialogue on potential methods for considering the costs and benefits of proposed future environmental requirements on the U.S, gas industry.
An Analysis of Forecasts of Energy Supply, Demand, and Oil Prices
Authors: Skov Arlie M.
Published: December 2007

Throughout the history of the oil and gas industry, forecasts have been made of energy supply, future rates of production, energy demand and of oil prices. These forecasts are used for a wide variety of purposes including the oil industry itself, financial institutions, public policy planners, nations, and groups of nations (OPEC).

Most forecasts are incorrect after only a few years, but they are often updated without a fundamental under-standing of why the earlier predictions were in error. This leads to painful disruptions and redirections not only within the oil industry but also in public policy debates and decisions on a national and global scale.

This paper reviews some of the more significant forecasts of energy supply, demand, and oil prices made in the last 25 years, and identifies the basic premises used and why they led to incorrect forecasts. Usually the premises have been too narrowly based. A broader basis is proposed, which includes continuing changes in technology, national goals, public attitudes and environmental concerns. Extrapolation of past trends is a poor basis for forecasts. Hence, a broader understanding of the changing world is essential and must be incorporated meaningfully into forecasts.
Managing Oil and Gas Price Risk
Authors: Edwards Thomas K.
Published: December 2007

This paper presents a review of managing oil and gas product price risk with the basic types of derivative products available to producers. Introducing the futures markets, basic types of hedges and factors affecting prices will be covered. Several case histories will be discussed in detail from the initial decision making process to actual performance to date.
Tax Credits Stimulate Gas Drilling Without Decreasing Federal Tax Revenue: A Win-Win Situation
Authors: Cline Scott B. , Stanley Brian J.
Published: December 2007

The long-term U.S. natural gas resource base (1300+ TCF) exists. The challenge is the timely conversion of that resource base to proved, deliverable reserves. Tax credits stimulate the transfer of the natural gas resource base to deliverable proved reserves by effective price enhancement and through the discovery, application, and dissemination of technology. Tax incentives act as net price increases to gas producers as long as all companies have roughly the same tax rate and all are able to utilize the credit. Tax incentives can thus be merged with gas price for statistical purposes. This paper demonstrates how the existence of the §29 credits stimulated drilling, increased relatively clean burning gas reserves, resulted in new technological advances and possibly increased federal tax receipts with no upward pressure on gas prices. New tax-stimulus mechanisms are introduced that will help ensure that tax credits both stimulate drilling and increase tax revenue.
Cost Functions For Oil Well Drilling, Lease Equipment And Well Operation In Texas
Authors: Beike Dieter , Holtz Mark H.
Published: December 2007

Regression modeling of Texas oil well drilling, equipment and operating costs was performed with the price of oil being the only independent variable. Cost functions were established for West Texas and South Texas for three different depth intervals. Cost comparisons were made possible on a regional and depth basis as well as on a process basis (primary vs. secondary recovery operations - the latter for West Texas only). Best results were achieved for mid-range and deeper West Texas oil drilling costs, West Texas secondary lease equipment costs and West Texas and South Texas operating costs.
The Cost of Not Using 3D Seismic Technology: A Case Study
Authors: Walsh P. R. , Borsato R. A.
Published: December 2007

After purchasing a producing gas field from a major Canadian utility, Lagasco completed a 3-D seismic program over the pool to explain discrepancies associated with gas-in-place determinations. Utilizing the Coveny pool as a model, the results confirmed the economic benefits of 3-D seismic technology.
Development and Management of Complex Dulang (E14) Reservoir, Offshore Malaysia: A Simulation Case Study
Authors: Sonrexa Kartikay , Aziz Azly , Bandal Malvinder
Published: December 2007

The Dulang Unit Area covers the central part of the highly heterogeneous Dulang Field which is located offshore Peninsular Malaysia. The Unit Area consists of 19 stacked shaly sandstone reservoirs which are divided into about 90 fault blocks containing multiple fluid contacts. The estimated Original-Oil-In-Place (OOIP) is in the vicinity of 700 million stock tank barrels (MMSTB). Production commenced in March 1991 and is currently maintained at more than 50,000 barrels of oil per day (BOPD). Reservoir simulation is one of the vital tools which has been employed from the very beginning to develop as well as manage this challenging field. This paper documents a case history dealing with the construction of numerical models of two distinct fruit blocks in one of the major reservoirs (E14). The simulation studies led to the consolidation of the development plan as well as reservoir management strategies. They also greatly aided in improving the reservoir characterization.
Arun Field: Model for Successful Gas Development
Authors: Myers S. D.
Published: December 2007

Economically and industrially, the Asia Pacific region is the fastest growing area in the world. Demand for energy to support this rapid expansion is expected to more than double over the next 15 years.

Natural gas, which can be found throughout the Pacific Rim, will play an important and growing role in the years ahead, both to fuel the development of local economies, and as a valuable product for export.

An excellent example of the value that can be achieved from developing and marketing natural gas resources is the Arun Field in North Sumatra, Indonesia. Arun is the largest producing gas field in Indonesia and accounts for nearly one-fourth of today's Pacific Rim LNG trade, together with substantial sales of condensate and LPG. Three local industrial facilites in northern Sumatra also depend on Arun fuel gas for plant operation.

This paper traces the history of Arun through field development, plant construction, and building of infrastructure in a remote and environmentally sensitive area. Focus is on the importance of technology to insure project success — reservoir management, drilling, well completions and highgrading of plant and field facilites to maximize gas sales.
Slim Hole Drilling Technology – Past, Present, Future
Authors: Millheim K. K. , Prohaska M. , Thompson B.
Published: December 2007

Slimhole drilling in one form or another has been used by the mining and construction industry, and the oil and gas industry since the 1940's. Drilling a slimhole borehole is the standard way of drilling for the mining and construction industry. Whereas, the oil and gas industries, in spite of its potential major cost savings, rarely drilled slimhole wells; when they did it, was only because there was no other choice. However, since the late 1980's, the oil and gas industry has been experimenting on a continuous basis with the use of slimhole drilling technology to reduce drilling costs and improve exploration results.

The first part of the paper presents the evolution of slimhole drilling since 1989 from the oil and gas industry point of view. The next section of the paper covers the state of the art of slimhole detailing its technical accomplishments and remaning challenges.

The last part of the paper presents the slimhole drilling system and dynamics that are taking place. From this systems analysis, a view of the future of slimhole drilling is possible. Can slimhole drilling technology drastically reduce cost? Improve exploration? Be used offshore? Can the contracting, service, and manufacturing industries respond and provide slimhole drilling technologies? Will companies be able to change their thinking? All these questions will be discussed in this paper.
Drilling Fluid Programmes Can Reduce Hole Erosion And Minimise Hole Problems: Case Histories Offshore Vietnam
Authors: Twynam AJ , Collins PM , Jackson MD , Forman P
Published: December 2007

AJ Twynam, PM Collins, MD Jackson, P Forman

This paper describes technical studies undertaken at BP Exploration Technology Provision Centre and the application of these studies along with transfer of best practice and local knowledge to solve two specific problems encountered in drilling offshore Vietnam.Hole instability in shallow clastics: hole problems related to drilling shallow claystone sections with water based muds were being encountered; tight hole, bit balling, stabiliser balling, overgauge hole. This was causing lost time and increased costs. A technical audit involving the BPX Technology Provision Centre, Dowell IDF and BP Vietnam along with technology transfer from the North Sea Operations allowed the drilling fluid used on the problem section to be modified/optimised resulting in much improved drilling efficiency.Hole erosion in deeper clastics : the hole erosion encountered in deeper clastic sections of wells can lead to several problems, namely the failed attempts to secure adequate wellbore evaluation information in the reservoir section. Cores were available from problem formations and these were used in geomechanical and chemical analysis to ascertain the cause of the problem. Based on the findings it was possible to make recommendations to the drilling fluid programmes and drilling practices, which have lead to enhanced drilling efficiency and much improved wellbores.

Introduction

BP Exploration commenced drilling offshore Vietnam in December 1992 operating in Block 5.2, 6 and 118. Several technical challenges were experienced in the drilling of these wells, In an attempt to optimise on drilling performance, several studies were undertaken. This paper details two such studies undertaken by the BP Technology Provision Centre in Sunbury, UK. The first study was to carry out a technical audit on drilling fluids being used in an attempt to improve drilling performance in shallow clastic formations. The second study concerned the observed problem of washed out holes in the deeper clastic formations which had resulted in problems with adequate formation evaluation, This paper describes the problems as identified, the methods used to determine the cause of the problems and discusses the conclusions and recommendations resulting in improved performance.

HOLE INSTABILITY IN SHALLOW CLASTICS

One of the more problematic hole sections on wells in Vietnam (excluding the loss control problems in the carbonates) is the 17" /17-1/2" section through the shallower clastics. These sections were originally drilled using a gel/CMC system which was gradually upgraded to a KCL/Polymer (PHPA) system.

Problems encountered on this section were due to water base mud" being used to drill shallow clay stones. (Bit balling, tight trips, reaming, shaker blinding, stabilisers caked up). This was leading to expensive mud bills, compromised drilling performance and poor quality hole.
Technology Leading the Way to Mukhaizna Heavy Oil Development
Authors: Lievaart L. , Al Hinai K. M. , Al Khabori K. J. , van Wunnik J. , Masson D. , Al-Kindy I. H. , Mul P. J.
Published: December 2007

Mukhaizna was discovered in Central Oman in 1975. The field contains large volumes of 15° API crude (STOIIP 375 mln m3, in situ viscosity 1700 mPa.s). During the mid 80's it was established that production rates from initial vertical wells were marginally economic, both primary and on steam soak. In recent years the introduction of new technology, especially the drilling of horizontal wells, has significantly advanced the fields potential for commercial development:

A pilot project using five 1000 m long horizontal wells was started in August 1992. The wells were produced with progressive cavity pumps, with production being trucked to a production station at 60 km distance. Productivity improvements of a factor 4 over (cold) vertical wells were obtained. The project demonstrated that owing to the high pore compressibility of the shallow, unconsolidated Gharif reservoir rock, associated with grain crushing, and the field-wide presence of a Middle Gharif shale, satisfactory primary recoveries of 100,000 m3 or more can be obtained from horizontal wells at acceptable (lateral) distances to the oil-water contact.

Theoretical studies and numerical simulations have shown the dry individual well recoveries to increase proportionally with increasing distance to the oil-water contact, Reservoir performance during dry production is characteristic of increasing pore compressibility with increasing rock stress. Significant hysteresis is observed between the increasing and decreasing rock stress cycles. Core plug measurements and pressure recordings in a dedicated observation well have served to validate the results of the modelling study. Based on the results of the pilot, the fields expectation ultimate recovery was increased from 5.3 to 11.0 mln m3.

As a next step towards full field development, a strategic development project has been formulated aimed at narrowing down remaining uncertainties with respect to reservoir performance. Production from ca. 10 horizontal wells will commence in 1996, Dedicated early production (satellite) facilities will be used, to which the oil will be evacuated with admixed water through a 30 km, large diameter pipeline under downhole pump pressure. The current project planning basis includes a number of technology applications aimed at increased cost effectiveness, such as a revised casing scheme, alternative subsurface pumping systems with high output pressure rating, coriolis flow meters and telemetry, Targetting of the additional project wells will be based on a 3D seismic survey acquired during the second half of 1994.

Following a successful project, Ml field development may proceed early in the next century.
A Proposed Dynamic Model for Foamy Oil Properties
Authors: Sheng J. J. , Hayes R. E. , Maini B. B. , Tortike W. S.
Published: December 2007

To simulate foamy oil flow, it is first important to calculate foamy oil properties properly. Several previous investigators have made such an effort. However, their approaches do not account for the time (or rate) dependent changes in foamy oil characteristics. This paper proposes a methodology for including the dynamic processes in the calculation of foamy oil properties, using molar variables. The issues of bubble nucleation, growth and decay are also reviewed and discussed.

The basic foundation of this model rests on the theoretical results and experimental observations of nucleation, bubble growth and decay. The model is verified by matching the calculated results with experimental data.

The results calculated from this model show how the foamy oil properties vary with pressure and time. The non-equilibrium processes of both bubble growth and decay are important for the calculation of foamy oil properties. However, the rate of decay for the entrained gas is most significant in foamy oil flow.

This method of calculating foamy oil properties provides the basics for developing numerical simulation models of foamy oil flow. The results from this model may also be useful for well testing analysis in foamy oil reservoirs.
Economic Field Development in Venezuela Heavy Oil Fields Using Multiphase pumping Technology
Authors: González Rubén , Guevara Emilio
Published: December 2007

Multiphase pumping is a technology in fair development and usage in the oil industry. The multiphase transport of oil, gas and water produced in offshore and onshore fields, and/or at long distances from the production units is not longer an impossibility or a non profitable enterprise. Therefore, the exploitation of marginal fields or those located at long distances, as well as new developments, are about to become a feasible reality.

The exploitation of heavy oil fields in Venezuela is, more than ever, the future of the oil industry in this country, since its is very well known that more than half of the world total heavy and extra heavy oil reserves are located in Venezuela.

Studies on the technical and economical feasibility of the application of Multiphase Pumping are being carried out by INTEVEP, S.A. together with the operating affiliates of PDVSA, aiming, at testing and consolidating this technology with minimum investment and reduction in production costs. One of these surveying studies was performed for the ARECUNA FIELD of CORPOVEN, S.A. located in the Orinoco Oil Belt. The reduction of investment and production costs in substituting traditional flow stations for handling heavy and extra heavy oil by a multiphase pump was focused.

The objectives of the paper is to present the technical and economical conclusions of the above mentioned feasibility study, and the performance and operational experience obtained with a twin-screw multiphase pump during five months of field operation.
The Commercial Potential of Steam Assisted Gravity Drainage
Authors: Donnelly John K. , Chmilar M.J.
Published: December 2007

John K. Donnelly* and M. J. Chmilar

Steam Assisted Gravity Drainage (SAGD) is the key to the economic exploitation of over 40 billion barrels (6.35 × 109 m3) of bitumen from the McMurray formation. The SAGD technology has been proven in two stages of piloting and is ready for commercial application. Engineering and economic studies indicate that the SAGD technology can be applied at a unit cost that is substantially below the market price for bitumen which has been at an average often dollars per barrel at the field gate over the last few years.

Based upon the premise that SAGD recovery is feasible throughout the Athabasca area, in reservoirs whose quality equal or exceed that found at the SAGD pilot site, an evaluation study was undertaken. The objective of the study was to map projected bitumen recovery and steam oil ratio as determined for a conceptual commercial SAGD recovery scheme.

The study applied geological and engineering criteria based on current projections of SAGD performance and a conceptual commercial recovery scheme, to analytically derive predictions of cumulative steam oil ratio (CSOR) and bitumen recovery. The study involved evaluating models for estimating SAGD CSOR and bitumen recovery; applying the most suitable model to generate CSOR and bitumen recovery predictions using screened geological data from an Athabasca well data base; then plotting contour lines representing the predicted CSOR and recovery values on a surface map of the Athabasca deposit. The contoured maps outline areas where it is expected that a CSOR of 3.5 m3/m3 or less and a bitumen recovery of greater than 10,000 cubic meters (63,000 barrels) per hectare which is equivalent to an average bitumen production rate of 250 barrels (40 m3) per day over a five year well life from 800 meters long well pairs spaced 90 meters apart.

The maps highlight locations in Athabasca where the best reservoir performance would be expected and delineates the areas which should be studied in detail for commercial application of the SAGD technology.

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Stresses and Displacements Around Hydraulically Fractured Wells
Authors: Wood D.B. , Junkin George
Published: December 2007

The stress and displacement fields around hydraulically fractured wells have been calculated. These calculations, which are based on the linear theory of elasticity for homogeneous isotropic media, lead to two useful conclusions:

1. Hydraulic fracturing significantly changes the stress state around the well, removes the stress concentration caused by the wellbore, and reduces the maximum compressive stress in the rock matrix.

2. If a small fraction of the near wellbore region of a fracture is left unpropped, the fracture will close at the wellbore due to elastic deformation of the unpropped rock.

Introduction

This paper deals with two questions related to the application of the widely used well stimulation technique, hydraulic fracturing:

1. Does hydraulic fracturing remove the stress concentrations which exist due to the presence of the wellbore and the perforations? perforations?

2. How much of the near-wellbore region of the fracture can be left unpropped without the potential stimulation of the well being lost?

It is convenient to consider these two questions in the same paper because they can both be analyzed with the same theoretical calculation.

In some deep, abnormally pressured wells, it is necessary to limit the drawdown to avoid producing formation fragments caused by the producing formation fragments caused by the failure of the rock due to the very high stresses induced near the wellbore. These high stresses occur because of the borehole and the perforations. Hydraulic fracturing can decrease the stress around the wellbore by increasing the productivity index of the well and reducing the drawdown necessary to obtain a given production rate.
Development of Heavy Oil in Liaohe Oil Field
Authors: Tiejun Dun , Qingshan Tang
Published: December 2007

The Liaohe oil field, which is buried at a depth of about 1000 m, has abundant amount of heavy oil. With thermal development by steam injection, it is the most productive heavy oil field in China.

In this paper, the observation of lithological and mineralogical change in the process of steam injection is discussed. Significant dissolution caused by water/rock interaction was observed for the minerals such as quartz and feldspar in the clastic reservoir rock. This caused changes within the pore structure in the rock. A computer program to predict the dissolution loss and precipitation of various minerals in water-rock reaction has been developed. The mechanism of steam displacement is also investigated.
Advanced Process Control Of Extraction: Sensors And Models
Authors: Kresta Jim
Published: December 2007

Jim Kresta

Process Control of the Hot Water Extraction Process is still relatively limited, largely because critical process measurements have not been available. Over the last few years, Syncrude has been endeavouring to address this through the development of process specific sensors. Recent implementation of these sensor developments is providing a new look at the process and offers a cost effective route to improving process operation.

This paper will describe recent advances in Extraction on-line process measurement systems; the oil sand analyzer, froth quality meter, and gamma spectrometer. These instruments allow us to examine for the first time, the short-term effects of variability in oil sand ore and process conditions on bitumen recovery and product quality.

An understanding of the relationships among incoming ore, processing conditions and product parameters is required to optimize the Extraction process. Multivariate data analysis techniques are allowing us to examine these relationships in detail and will provide the basis for an improved process control strategy. Some of these relationships are examined and their implications discussed.

Introduction

Producing Syncrude Sweet Blend (SSB) is a three stage process of mining oil sand, extracting bitumen from the sand and upgrading the bitumen. In the extraction process, oil sand ore is conveyed to the tumbler where it is conditioned with steam, caustic, hot water and mechanical energy. The resulting slurry is fed to the Primary Separation Vessel (PSV).

P. 611
Visualization of Deformation in Unconsolidated Athabasca Oil Sand
Authors: Leung S. K. , Kry P. R. , Wong R. C. K.
Published: December 2007

Dense unconsolidated Athabasca oil sand exhibits significant dilation in triaxial compression tests at low confining stresses of 5 to 750 kPa. This paper presents an innovative method which can visualize and calculate the porosity distribution in a sheared sample.

Thin sections from the sheared sample were made to quantify the porosity within and outside the shear zones. Porosity was determined using image analysis on back scattered scanning electron microscopy (SEM) images of the thin sections. These porosity data were used to calibrate computer assisted tomography scan (CAT scan) images of the whole core sample so that the porosity distribution in the sheared sample could be mapped. The calculated average porosity of each of the four samples agreed very well with porosity measured by Dean-Stark analysis.

In the CAT scan images, shear dilation was seen to be concentrated along and within multiple, localized shear bands. However, the porosity distribution within each sample had a very narrow range compared to the overall increase in porosity, implying the sheared samples were essentially uniformly dilated.
Design, Preparation, and Operational Aspects of the First Horizontal Subsea Trees Installed from a Jack-Up
Authors: Ferguson R. A. , Stewart D. R. , Holland B. , Thompson A.
Published: December 2007

The Johnston Gas Field lies in blocks 43/26a and 43/27 of the UK sector of the Southern North Sea, 11 km to the Northeast of the Ravenspurn North production platform (Figure 1). The water depth at this location is approximately 145 feet. The field was discovered in April 1990 by the 43/27-1 well and successfully appraised in July 1991, by the 43/26a-8 well.

The field (Figure 2) is formed by a structural trap bounded to the Southwest by a NW-SE trending fault and by structural dip to the north and east. The reservoir itself comprises Permian Lower Leman sandstone exhibiting excellent porosity and permeability characteristics. Recoverable reserves are estimated to be in the range of 155 to 195 BCF. The gas sales contract requires a DCQ of 53 MMSCF/D for a six year plateau, with a peak rate of 90 MMSCF/D. Two wells located near the crest of the structure satisfy the production contract requirements, however a third well may be required in the third year of production. The overall field life is expected to be 13 years.

This paper describes the selection, design and installation, in this field, of the first horizontal subsea trees to be installed from a jack-up.
Multi - Platform Drilling Operations Utilising One Rental Top Drive - The Commercial and Technical Benefits
Authors: King Ian M. , Douglas David
Published: December 2007

The introduction of the top drive into the international drilling market constituted one of the industry’s major technological advances during the 1980’s. One disadvantage of the conventional top drive is the rig modifications necessary to support the torque generated, particularly on drilling units equipped with masts. In an effort to alleviate this disadvantage, an integrated drilling system (IDS) has been developed, utilising a torque tube in place of the normal fixed rails. The impact of introducing an overhead drilling system into an operating drilling unit has therefore been greatly reduced.

This paper will focus on the benefits of one such application in the northern North Sea. It will stress the technical and commercial benefits seen by the Operator and concentrate on the portability of the system, allowing one rental IDS to be utilised on more than one platform. By employing the IDS the Operator has been able to efficiently upgrade the platform rigs and drill extended reach wells which may not otherwise have been possible.

This paper will conclude that a rental overhead drilling system is a viable option to meet the changing demands of drilling programs in mature basins.
Changes to Regulation of Drilling and Workovers in UK Sector by Removal of Prescription
Authors: Powell T. A. F. , Dobson J. D. , Dykes C. E.
Published: December 2007

The regulation of the United Kingdom's offshore oil and gas industry is undergoing radical restructuring, abandoning the traditional prescriptive approach. The final part of the restructuring programme is to introduce a non-prescriptive regime for drilling and other well operations. In future, the safety of drilling and well operations in UK waters will be enforced through review of a combination of safety cases and notification of well operations, backed up by a programme of inspections and audits. The regime will be supported by goal setting regulations which establish performance standards for wells and well operations.
J Block Drilling Operations: Continuous Improvement leads to Record Performance
Authors: Parry N
Published: December 2007

Phillips Petroleum Company United Kingdom Limited has recently completed drilling 17 development wells on the Judy and Joanne Fields (J Block) in Block 30/7a. Twelve wells were drilled at the template/platform location using the jack up "Galaxy", and 5 wells were drilled at the subsea manifold location using the jack up "Magellan".

A clear record of continuous improvement has been demonstrated. Drilling performance shows a steady increase in penetration rate (overall feet per day) over the project. Perhaps the most visible indicator of this has been in 1214" hole. The maximum footage drilled in a 24 hour period has increased from 3600 feet on the first well, PI, to a world record 8631 feet on well P11.

All the team involved in the operation, Phillips, drilling contractor and service company personnel both onshore and offshore, have contributed at some point to achieving this success. This paper discusses the many innovations, equipment improvements and procedural changes that have led to this steady increase in overall feet per day.
Geological Steering Assists Cost Effective Exploitation of Marginal Reserves
Authors: White J.
Published: December 2007

Carefully positioned horizontal wells are helping to maximise recoverable reserves from both new and mature North Sea producing fields. In many cases, the economic performance of these wells is very sensitive to position within the reservoir. For example, displacing the horizontal section in some reservoirs by five or ten feet TVD is sufficient to significantly change the asset value of the well.

To achieve ideal drainhole positioning, the surrounding formation must be sensed while drilling, and the hole trajectory modified accordingly. This geological steering, or geosteering, becomes particularly important when targets are small and the exact geometrical position of the target cannot be accurately determined from surface seismic or offset well data.

Drilling horizontal wells to almost pinpoint accuracy relative to surrounding geology has tremendous potential to unlock otherwise uneconomic reserves of oil and gas. The steering techniques reviewed in this paper are central to this process, and represent a new and challenging role for multi.disciplined field development teams in the coming years.
Preparing for Decommissioning of the Heather Field
Authors: Hustoft R. , Gamblin R.
Published: December 2007

This paper presents some of the issues which have influenced the decommissioning planning for the Heather Field facilities. The paper is based on the results of conceptual and pre-engineering work performed to date, and covers the following: –brief background on the Heather Field development and production history, field facilities, and achievements in extending field life to date,–considerations and constraints which have shaped Unocal's approach to the planning of the Heather Field decommissioning project, and–discussion of the stages to be undertaken in performing the decommissioning of the field facilities, concepts and options which exists for these stages, and operational and technical considerations applicable to each stage. The stages addressed include engineering and planning, well plugging and abandonment, topside systems cleaning and preparation for removal, pipelines decommissioning, topside facilities removal and disposal, and platform structure removal and disposal.
Development of a Marginal Field Through Leased Facilities
Authors: Kieft T G
Published: December 2007

Fife is a small offshore field that is remote from existing infrastructure and offers the potential to recover some 34 mmbbls of 34° API crude oil over an anticipated life of 4 years. Capital investment in the full field development facilities cannot be amortised to provide an economic development in this timeframe. This paper addresses the application of leased production facilities to enable commercial development of the reserves and examines the relationship necessary between oil company and contractors to achieve a successful project.
The Two Phase Development of the Hudson Field
Authors: Fielding MP
Published: December 2007

Development of the Hudson field took place over the period December 1992 to January 1995. This was a time of generally low oil prices and one in which the combined effects of oil price, smaller discoveries and diminishing reserves but increasing development and operating costs, were being faced by the industry.

The Hudson field development was conceived under these circumstances and demanded that a cost effective solution be identified in order to make the development viable. Initial studies of conventional stand-alone and tie-back options, whilst endorsing the commerciality of the project, failed to maximise its economic potential or to meet the business-driven objectives of the co-venturers. In light of this, an innovative two-phase development was devised, utilising a leased FPSO for the first phase of production and a subsea tie-back to the Tern platform for the second phase. This gave the benefits of an optimised reservoir development plan for the second phase, minimum capital outlay at the front end and early production and generation of cash-flow, which effectively financed the main field development.

In addition to this novel facilities solution, the development also implemented many of the concepts which have since become synonymous with the industry's CRINE initiative, most notably the use of functional specifications, standard components, minimum operator intervention in contractor/supplier activities, minimum size of operator's management team and a novel contracting strategy, giving greatest opportunity for cost savings.

The net result of these various initiatives was completion of the facilities installation and commissioning two months ahead of the targeted first oil date and at a cost of 29% below the original budget.
How a North Sea EPS was Fast Tracked to Achieve First Oil 19 Weeks from Project Sanction
Authors: Kozicz J. R. , Unsworth M. , Oldfield G. A.
Published: December 2007

A semi-submersible based Early Production System (EPS), currently exporting production via subsea flow line to a dynamically positioned tanker was on-line 19 weeks after receiving project sanction. This paper describes the process by which this was achieved.
Safety Research for the Offshore Industry: Progress with Implementation of HSE's Strategy
Authors: Sharp J V , Supple W J
Published: December 2007

Introduction

Research has played an important role in helping ensure safety in the offshore oil and gas industries and will continue to do so. It has always been a high priority in Offshore Safety Division (OSD) with the objective of keeping the Division aware of all developments with a potential bearing on the health and safety of the offshore workforce. Consequently, the Health and Safety Executive (HSE) is currently funding a major research programme aimed at increasing safety offshore by investigating a broad range of factors which govern the integrity of engineering design, technology, management and operations. Annual HSE expenditure on this endeavour is of the order of £6.5m but taking into account that about one third of the projects are funded jointly with the offshore industry the combined programme consisting of over 300 live projects has a value exceeding £50m. The large majority of the research is undertaken by external contractors based in the UK and abroad.

The main objectives of this offshore safety research programme are to: assess the extent and nature of the risks involved in work offshore;support specific enforcement activities, policy initiatives or accident investigations;produce information to develop technical guidance to support legislation;inform national and international standards making;validate models (including computer models) enabling risk calculations to be made and inform regulatory decisions;produce necessary health and safety information where the structure of the industry prevents it being produced by the industry (at least in an appropriate timescale).
Operating Emerald – The Experience and Lessons of a Marginal Field
Authors: Pollard Ian C.
Published: December 2007

Midland & Scottish Resources PLC (MSR) is a company which was established to exploit production opportunities in marginal fields, with a combination of reusable facilities and a management structure which directs and responds through short and effective lines of communication. As owner and licensed operator of the Emerald Field, MSR's wholly owned subsidiary Midland & Scottish Energy Limited (MSE) had to develop and apply realistic strategies for ensuring safe and stable operations in the face of a declining asset The paper deals frankly and openly with the experi-ence gained and lessons learned from developing and applying innovative techniques to meet this challenge.

From the outset, the Safety Case and a Total Quality Management System were used as both focus and drive for a company strategy that demanded change in both workforce attitude and management practice. It provided an opportunity for fostering workforce involvement but tech-niques and procedures had to be developed in order to demystify terms such as ALARP and to make them usable in the workplace. A system was conceived and developed by the company to enable workplace risk assessments to be performed and demonstrated. This approach has not only improved risk management but also led to generation and continuous renewal of operating procedures that are effec-tively targeted to critical activities and visibly linked to the Safety Case.

Innovations in the production and treatment of safety management system documentation, that enabled their active ownership, were also deyelnned. These were intended to facilitate accurate translation of policy into practice and underpin the Safety Case by ensuring it faithfully reflected operational activity.

Difficulties arose for some, in the acceptance and understanding of devolved authorities and in determining the appropriate authority ieveis for certain decision making. Cautionary lessons were also learned when certain innova-tive changes to safety management practices were misund-erstood. The paper concludes by outlining the next stages of development for the management systems in order to deliver improved mechanisms for change control, performance standards and competency.
Preparation of Combined Operations Safety Cases: Experience and Lessons Learnt
Authors: Hart P. M. I. , Smith D. W. , Thomas E. J.
Published: December 2007

This paper describes the experience of a North Sea operator in preparing a combined operations safety case. The safety case structure and work done to develop the combined operations description, safety management system and carry out hazard identification and risk assessment are described. Success factors are identified.A streamlined methodology for more rapid hazard identification and risk assessment is described for future application.
Leman Field Facilities Rationalisation
Authors: Palmer R. T. , Hall R. N. , Hall A. V.
Published: December 2007

This paper describes the re-configuration of the Shell Expro operated part of the Leman gas field in the UK Southern North Sea. The substantial modifications implemented will enable the field to be operated safely and cost-effectively through its post plateau decline. Identification of a new Op-erations Philosophy, subsequent demanning of production satellite platforms, the rationalisation of compression facilities and contracting strategies are discussed.
The Emerald Field Operating Experience
Authors: Galloway G. T.
Published: December 2007

The UK, North Sea, Emerald Field is a marginal oil field that has not lived up to expectations. A combination of disappointing reservoir performance and equipment start-up problems resulted in lower than anticipated daily oil production. This paper describes the experience of Midland & Scottish Energy in managing the reservoir and operating the field facilities.
Cost Effective Methods to Maintain Gas Production by the Reduction of Fouling in Centrifugal Compressors
Authors: Guinee M. J. , Lamza E. W.
Published: December 2007

Fouling of centrifugal compressors can dramatically reduce the gas throughput of a production platform. Deposition of solids within compressor internals has reduced flow and, in extreme circumstances, resulted in total seizure. Substances deposited include iron carbonate and salt.

The fouling can affect the ability to meet gas sales agreements with potentially severe financial penalties. Significant operating expense is also incurred to remove fouling material.

A mix of proven and innovative fouling control techniques has been applied including; well management, process modifications, selective use of corrosion inhibitor, internal coating of the compressor internals and on-line water wash systems.
Snubbing Units: A Viable Alternative to Conventional Drilling Rig and Coiled Tubing Technology
Authors: Hodgson R.
Published: December 2007

Several North Sea Operators are now using Snubbing Units to undertake operations previously regarded as only within the scope of a drilling rig (such as the running of 7" completions and the undertaking of gravel-packing operations).

Snubbing Units are also increasingly being used to access and service horizontal and extended reach wells which coiled tubing cannot access.

With the use of a Snubbing Unit, through-tubing sidetracking and underbalanced drilling is no longer limited by the technology of Coiled Tubing Drilling. Additional margins are available if a ‘SnubdrilT option is adopted and these are quantified with the presentation of the results a ‘SnubdrilT Case Study.

Snubbing Units can therefore now be regarded as an established means of providing an Operators with a versatile and unique device which offers many advantages over both Derrick Equipment Sets and Coiled Tubing Units.
Tubing Conveyed Perforating in the Greater Ekofisk Area using the Halliburton Select Fire System
Authors: Kleppa E. , Nilsen R. , Bersaas K.
Published: December 2007

Required safety factors in pressure activated perforating systems have in practice limited the number of independent gun sections on one run to at the most two. The Halliburton Select Fire System eliminates this limitation by allowing as many gun sections as desired to be independently activated by applying the same level of activation pressure each time. Potential cost savings derived from the system can be divided into two groups; reduced operational time due to reduced number of runs, and greater versatility of the perforating system, allowing for new approaches in planning and execution of the perforating operations.

The paper reviews three different cases were the system has been used in the Greater Ekofisk Area.
Well Completion Design and Operations for a Deep Horizontal Well with Multiple Fractures
Authors: Chambers M. R. , Mueller M. W. , Grossmann A.
Published: December 2007

Economic development of deep tight gas reservoirs is a challenge our industry has struggled with for many years. This paper describes how a very deep (15688', 4783 m TVD) well with a horizontal section (over 86°) of over 630 m (2,066') was completed for stimulation with multiple fractures. Multiple packers and sliding side doors provided isolation for 4 separate fracs and a 5th zone containing 52m (171') of perforated interval in the 7" casing. Extreme overbalance perforating techniques using tubing conveyed perforating guns and high pressure nitrogen were used to perforate and break down each of the 0.6m (2') of perforated intervals for the 4 fracs and 853 perforations in the 5th unstimulated zone. To achieve a high shot density, a special perforating tubing anchor was designed to allow two different perforating guns to perforate exactly the same interval in one trip. An open annulus treating system was used with a 4½ frac string for observation of the bottomhole treating pressure during fracture operations. A total of over 2 million pounds of high strength proppar.t was pumped into the 4 fracs at rates in excess of 5.6m’/min (35 BPM). High bottomhole temperatures (290°F, 143°C), reservoir pressures (9000 psi, 620 bar), and bottomhole treating pressures (16000 psi, 1100 bar) added to the complexity of design and operation of equipment. Over 5,700m (18,70001 of ¾" coiled tubing was run to TD and used in conjunction with a downhole force generator to open and close the sliding side doors.
Novel Techniques for Monitoring and Enhancing Dissolution of Mineral Deposits in Petroleum Pipelines
Authors: Gunarathne G. P. P. , Keatch R. W.
Published: December 2007

This paper presents a summary of work carried out and the results achieved in developing novel ultrasonic techniques for monitoring and enhancing dissolution of mineral scale deposits in petroleum pipelines. Problems of conventional ultrasonic techniques with respect to testing pipes are analysed. The development of mathematical and experimental models to extract the characteristic features from ultrasonic scans representing the acoustic properties of the mineral deposits beneath the pipe wall are described.

These properties are compared with stored data to identify the type of deposits and hence assess their growth which aids performance optimisation of remedial scale dissolver and preventative scale inhibitor treatments. The process of de-scaling is further enhanced by ultrasonic irradiation and methods for monitoring the dissolution process in real-time are proposed.