bluuebunny/crossref_metadata_2025 huggingface dataset:
A Novel Approach to Identify Reservoir Analogues
Authors: Bhushan Vikas , Hopkinson Simon Christopher
Published: December 2007

The identification of reservoir analogues if often an important step in planning the development of a new play, particularly when it poses difficult technical challenges or when appraisal information is limited. One of the strengths of an E&P company with a large and diverse portfolio is its potential to utilize a broad base of knowledge gained from past experience to aid in future development and decision-making. A critical enabler in being able to leverage this knowledge effectively is the ability to access relevant information quickly and efficiently. This paper presents a new approach to identifying analogues systematically through the novel application of an artificial intelligence technique called case-based reasoning.

The key lies in characterising each reservoir by a set of attributes which describe the reservoir and can be used to differentiate it from other reservoirs. Case-based reasoning is then applied to search for reservoirs which are similar (i.e. are potentially good analogues), but that do not necessarily match up exactly on any individual attribute. Further, this method quantifies the degree of similarity and permits users to focus their search on any specified set of reservoir attributes. These characteristics differentiate this method from others currently in use.

The implementation of this method to create a versatile knowledge sharing tool, called the "Smart Reservoir Prospector", will be described. Recently developed artificial intelligence technology incorporating case-based reasoning algorithms within a flexible java-based architecture has been applied. The result is a web-based system that permits users in any Shell operating unit to search through thousands of reservoirs in milli-seconds to locate reservoir analogues, and then to access additional detailed information about the reservoirs of interest. The application of this tool within Shell to address important business issues, including scope for recovery and reserves justification, recovery factor benchmarking, and reservoir knowledge sharing, will be discussed.
Dual Flow Well Technique for Produced Water Management
Authors: Davis L. , Frorup M. , Farias L.
Published: December 2007

The Dacion field, located in the eastern Venezuelan basin, came on production about 50 years ago. In the early years of development, more than 300 wells were drilled and production reached a peak of 45000 bbl/D of oil around 1958. Subsequently, the field was operated on a rate maintenance basis, with a drastic reduction in drilling activity. By 1997 the rate had fallen to approximately 10000 stb/D, and the field was included in the Venezuelan third licensing round. Lasmo Venezuela was awarded the management of the Dacion asset, and started an aggressive drilling program of additional replacement and infill wells. This led to production tripling in 2 years, associated, however, with increasing water production. Unconventional treatment options had to be considered for managing the water, due to the reservoir complexity.

The Dual Flow concept is one of such techniques. It is based on perforating both oil and water layers and producing from each set of perforations separately. Reservoir simulations showed the viability of the technique by allowing an increase in the critical production rates. Controlling the cone leads to a reduction in water production from the upper set of perforations and hence the water processing requirement. The implementation and the results from the first pilot well are presented, including the lessons learned. A comparison with predicted performance is provided. The pilot study highlighted a number of critical issues for produced water management, including the impact of permanent monitoring and control.
Chemical Flooding: A Comparison Between Alkaline And Soft Saline Preflush Systems For Removal Of Hardness Ions From Reservoir Brines
Authors: Campbell Thomas C.
Published: December 2007

Brine displacement studies using Berea sandstone cores were undertaken to compare the effects of alkaline and soft saline preflush systems on an equivalent basis. The alkaline chemicals used were sodium orthosilicate, sodium hydroxide, sodium silicate (2.0 ratio of SiO2/Na2O) and sodium carbonate. The soft saline solutions used ranged in concentration from 3% NaCl to 10% NaCl. The effects of the various preflush systems were measured by titration of the effluent for hardness ion levels. In some of the experiments dilute surfactant was injected following the preflush to determine the effect of surfactant on elution of hardness ions.

Results are presented which show that the highly alkaline chemicals, sodium orthosilicate and sodium hydroxide, were very effective in removing the hardness ions from connate brine. Further elution with soft brine following the highly alkaline preflush showed that essentially no ion-exchange occurred and the hardness ion level remained at zero in the effluent. This same effect was observed with the 2.0 ratio sodium silicate, but higher volumes of solution were required to reduce the hardness ion levels to zero in the effluent. With high salinity and sodium carbonate preflushes a high ion exchange peak was observed. Continued elution reduced the hardness ion levels considerably, but not to zero.
Wellbore Sinuosity and Its Effect on Production and Recovery from Horizontal Wells Along the Cummings/Dina Channel Trend in Senlac and Winter Saskatchewan
Authors: Miller Karl A. , Cameron Bill , Qing Lu , Hayes Lew A.
Published: December 2007

Over 500 horizontal wells have been drilled into the Cummings/Dina channel trend between Senlac and Winter since 1990. These wells produce 13 – 14 API oil with a gas free viscosity of 3600 cp from a depth of 700 meters. Production peaks at about 20 to 60 m3/d oil with 10% water and 1.5% sand. Oil production eventually declines as water cut increases. Sanding events can limit oil production rates and recovery.

Wellbore trajectory control has improved significantly in the last 10 years, the latest improvement being ‘inclination at the bit.’ Selected wells were analyzed to determine the key factors between sinuosity and production rate and ultimate recovery, and the changes in the effect of these key factors over the last 10 years. Incentive and methodology for development of current flatter wells is discussed, and predictions for production from current flatter wells are given.
Magnetic Ranging Technologies for Drilling Steam Assisted Gravity Drainage Well Pairs and Unique Well Geometries - A Comparison of Technologies
Authors: Grills Tracy L.
Published: December 2007

Magnetic ranging refers to the determination of the relative position of one well with respect to another using magnetic measurements. Magnetic ranging is used for several oil field applications including positioning blow-out relief wells, steam- assisted gravity drainage and heavy oil applications, and planned intersection of one well with another. The procedure is also applicable to horizontal distance measurement and TVD correlation between observation wells and nearby horizontal wells. This paper is a discussion of the theories, methodologies, and pro’s and con’s of both "active" and "passive" magnetic ranging.

A comparison of a number of specific technologies currently available in the marketplace will be presented. The paper will discuss the following trademarked and proprietary items: Magnetic Guidance Tool™, Single Wire Guidance™, Rotating Magnet Ranging Service™, MagTraC , and Parallel Well Tracker™. The paper also includes a discussion of potential future directions in magnetic ranging.

Field experience and history will be presented as well as methodology for each technology. The paper will focus mainly on technologies that are currently available with discussions of the theory of operation of each technology, operation parameters, specifications, experience with drilling different types of wells with the various technologies, and finally, the advantages and disadvantages of each technology will also be discussed.
New Insights into Water Control - A Review of the State of the Art – Part II
Authors: Di Lullo Gino , Rae Phil , Curtis James
Published: December 2007

It could be argued today that oil companies would be better described as water companies. Total worldwide oil production averages some 75 million barrels per day and, while estimates vary, this is associated with the production of 300 – 400 million barrels of water per day. These values of approximately 5 – 6 barrels of water for every barrel of oil are quite conservative. In the United States, where many fields are depleted, the ratio of water-to-oil production is closer to 9 to 1. In some areas around the world, fields remain on production when the ratio is as high as 50 to 1.

Water production is a harbinger of problems in an oil well. It can cause scaling problems in susceptible wells, induce fines migration or sandface failure, increase corrosion of tubulars, and kill wells by hydrostatic loading, amongst other things. Thus, while water production is an inevitable consequence of oil production, it is usually desirable to defer its onset, or its rise, for as long as possible.

Numerous strategies, both mechanical and chemical, have been employed over the years in attempts to achieve this. Simple shut-off techniques, using cement, mechanical plugs and cross-linked gels have been widely used. Exotic concepts, like relative permeability modification (RPM), have also been applied with varying degrees of success.

This paper is a continuation of a previous one, which reviewed the traditional techniques and proposed some new methodologies and technologies that can be used in the design of RPM treatments, in particular.1 Additional new insights offered in this paper include the extension of matrix RPM treatments to more extreme well conditions, such as heavy (viscous) oil and low pH environments. It also introduces the concept and reviews several case histories of the usage of RPM systems to perform hydraulic fracturing treatments to simultaneously stimulate oil and control water. This conformance-fracture technique could significantly impact the development strategies of many fields worldwide.
PVT and Viscosity Measurements for Lloydminster-Aberfeldy and Cold Lake Blended Oil Systems
Authors: Frauenfeld Ted W. J. , Kissel Gerald , Zhou Shibing (Wendy)
Published: December 2007

A solvent-assisted gravity drainage process (Vapex) for recovery of heavy oil or bitumen offers high recoveries and promising rates of oil production. In order to predict process performance, data on solvent-oil solubility and on the viscosity of solvent-oil mixtures must be obtained.

The solubility of selected gasses in Lloydminster Aberfeldy oil and in a Cold Lake oil was measured. The gasses used were: CH4, C2H6, C3H8 and CO2. Measurements were done at reservoir temperature. The data were regressed using the Peng-Robinson equation of state, which was used to generate k-values expressing the solubility of the gas-oil systems. Regressing the Peng-Robinson equation to the measured data generated interaction coefficients for the systems measured. These coefficients were used with the equation to generate k-value or solubility tables at other conditions. Measured viscosity data were used to confirm the usefulness of the Puttagunta viscosity correlation for propane-based heavy oil systems. The work confirmed the formation of two liquid phases in the oil-propane system at high solvent loading. The measurements also confirmed the large viscosity reductions available (100:1 – 200:1) by saturating oil with light hydrocarbons. A viscosity increase in one oil-propane system was observed at high solvent loading, suggesting possible asphaltene precipitation and/or deposition on the walls of the capillary viscometer tube.

These observations confirmed the need to study phase behaviour and asphaltene deposition in the oils at high solvent loading, as well as obtaining solubility and viscosity measurements. The data have been used to perform numerical simulations of Vapex and other solvent-based processes, and to perform predictions of field process performance.
Observations Relating to Non-Condensable Gasses in a Vapour Chamber: Phase B of the Dover Project
Authors: Aherne A. L. , Birrell G. E.
Published: December 2007

Non-Condensable Gasses (NCG) are gasses such as carbon dioxide, hydrogen sulphide, methane and nitrogen which can be present in a SAGD steam chamber but do not condense into the liquid phase to any large degree. Recent theoretical and laboratory work has shown that these gasses can enhance the thermal efficiency of SAGD without a significant reduction in productivity. In the laboratory, NCG has been shown to finger into the bitumen ahead of the main steam chamber, bringing with it heat and pressure.

This paper looks at temperature and pressure data from the world’s most mature SAGD pilot, Phase B of the Dover project, to determine whether naturally occurring NCG in the form of solution gas can be detected fingering ahead of the main steam front. The paper looks at the propagation of the steam chamber front by examining thermocouple data from observation wells drilled within and outside the SAGD pattern. The steam chamber propagation velocity, which also determines the velocity of the pressure front, is calculated. The pressure build-up profile is used to determine the pressure diffusivity constant, which in turn determines where the pressure front would be located without any NCG fingering.

The actual pressure front is compared to the predicted. In every case the actual pressure front travels between five and twelve meters ahead where one would expect it from the theory.
Integrated Optimization of Horizontal Well Performance
Authors: Tian Shubao , Zhao Gang , Zhang Qi
Published: December 2007

It is crucial to accurately predict the horizontal well flow performance so that the optimum production can be achieved. The horizontal well flow performance has generally been conducted under the assumption of uniform-influx profile along the horizontal wellbore, which neglects the pressure loss in horizontal wellbore and can cause an unreasonable well design. This paper developed a model to optimize the horizontal well performance by integrating the fluid flow in reservoir, the flow in sand control zone near wellbore, the flow in horizontal wellbore and tubing into an integral hydraulic system. The variable mass multiphase flow characteristics in the horizontal wellbore and the fluid lifting behaviors in tubing are also taken into account. In addition, the effects of reservoir properties, fluid properties and wellbore characterisrics and different well completions, involving open hole, slotted linear, pre-packed linear and gravel pack, on well performance are analyzed. The optimum well design is determined accordingly following the criterion presented.

It has been shown that the integrated model enables not only the better understanding of the complexity of the interaction between reservoir and wellbore, but also the overall optimum and coordinated operation of the whole system. For example, in the case of accurate prediction of the liquid-gas flow characteristics in wellbore, it is necessary to build detailed flow pattern model because the liberation of a large amount of gas can significantly affect the overall pressure loss, tubing lifting and production. Another example is that most pressure in the whole hydraulic system is consumed in tubing lifting, therefore effective tubing lifting design also helps obtain the optimum production. Using our integrated model we have identified the different effects among different kinds of sand control well completion methods. We have also shown that the well length, wellbore diameter and producing gas-oil ratio are the major factors affecting the well production.
Laboratory Simulation Of A Two-Phase Geothermal Reservoir
Authors: Castanier Louis , Bories Serge
Published: December 2007

An experimental simulation of a two-phase flowing geothermal reservoir was conducted using a bench-scale model. Twenty runs were performed, using unconsolidated sand as the porous medium in the first step, and the data were verified using a lumped-parameter numerical model. The collection of thermodynamic data, including temperature, pressure, enthalpy, and liquid saturation, yielded interesting results for energy extraction efficiency in the process of in-situ vaporization and for the influence of the following physical parameters on the behavior of a two-phase geothermal parameters on the behavior of a two-phase geothermal reservoir:–porosity–speed of decompression–heat influx–initial liquid saturation

Introduction

This study deals with some aspects of fluid flow and energy transfer in porous media, with emphasis on the behavior of a geothermal reservoir in two-phase flow. Although much experimental work has been done on this subject during the last ten years, different approach in the design of experimental apparatus allowing simultaneous; knowledge of all the physical parameters of the porous media seemed indicated. parameters of the porous media seemed indicated.

REVIEW OF THE PARAMETERS THROUGH A MATHEMATICAL MODEL

This mathematical model is a classic adaptation of the work of Luikov. Its purpose is to determine the physical parameters which influence the heat and mass transfer during in-situ vaporization. The following assumptions were made:the porous medium is homogeneous and deformable,fluids and porous medium are supposed to be a fictitious equivalent continuous medium,friction is neglected, andcapillary effects are neglected, except as included in relative permeabilities.

The basic equations are:

Continuity:

Flow:

Enthalpy:

Equations of State:

For a definite fluid, heat and mass transfer will depend on:–porosity,–nature and grain size of the porous medium,–initial thermodynamic conditions,–liquid saturation, and–exploitation conditions.

EXPERIMENTAL APPARATUS

The apparatus was designed to check the influence of the physical conditions on the behavior of a piece of porous medium of simple geometrical shape, in which the heat and mass transfer during the self-vaporization process are monodirectional (see Figs. 1 and 2). A typical experiment can be described as follows:–The porous medium and the thermocouples were introduced into the cylindrical cell.–The ends of the cell were closed.
Description Of The UK Christchurch Bay Wave Force Project And Some Initial Results-Part 2
Authors: Bishop John R. , Holmes Patrick
Published: December 2007

Preliminary results of spectral and Preliminary results of spectral and probabilistic analysis of wave and wave-induced loads probabilistic analysis of wave and wave-induced loads on the main tower and wave staff of the Christchurch Bay experiments are presented. The results obtained to date show reasonable agreement with linear random-wave solutions and the influence of the non-linear drag element of the loading is apparent. The data needs to be expanded with particular reference to fluid kinematics in the presence of waves and currents, and their effect on wave loading.

Introduction

Part II of this paper discusses the results obtained to date from an analysis of the Christchurch Bay data in spectral and probabilistic terms.

Again, it is noted that the results presented here are interim in that further analysis and cross-checking of the data is continuing.

2. THEORETICAL BACKGROUND

2.1 The Wave Conditions

A method of predicting wave induced forces on offshore structures which has found increasing application to design problems in recent years is based on the concept of considering the wave motion as a stationary random process.

Incident wave conditions are expressed in terms of the surface-elevation spectrum, Sn(w), such as the Pierson-Moskowitz or Jonswap formulations. These Pierson-Moskowitz or Jonswap formulations. These can be related to the usual parametric descriptions of wave conditions in terms of the significant wave height, H1/3, and the zero-crossing period, Tz, and it is sometimes appropriate to use a 'spreading-function' giving a two-dimensional spectrum Sn(w, 0) representing a three-dimensional sea-state.

In parallel with the spectral formulation are the probabilistic properties of the surface-elevation which, under certain assumptions, can be considered as a Gaussian process with probability density function, (p.d.f):

(1)

It has been shown by several authors, notably Longuet-Higgins, that for certain conditions the p.d.f of wave-height is approximated by the Rayleigh density function which in cumulative form is given by:

(2)

Thus the wave condition can be described by the spectrum, the Gaussian p.d.f of surface-elevation and the Rayleigh p.d.f of wave height.

2.2 The Loading Model

Morison's equation for the in-line horizontal force per unit length on a vertical cylinder represents the total force as the sum of a non-linear drag component and a linear inertial component.

(3)

where

being the density of sea-water; Cd and Cm are the drag and inertia coefficients, u is the horizontal water particle velocity and u is the acceleration. particle velocity and u is the acceleration. There are obviously deficiencies in this representation, for example, transverse forces are not included and the coefficients Cd and Cm are considered to be constants. However, the wide-spread use of the Morison equation in design and, as yet, the absence of a reliable alternative justify its use as the 'core' of spectral and probabilistic extentions.

P. 187
Experience With Surface Controlled Sub-Surface Safety Valves
Authors: Medley Edward L.
Published: December 2007

Medley, Edward L., Amoco (UK) Exploration Company

There are 92 surface operated, wireline retrievable sub-surface safety valves installed in Amoco (UK) Exploration Company's portions of the Leman, Indefatigable and portions of the Leman, Indefatigable and Rough Fields. These valves are fail-safe in operation and offer a back-up shut-in safety system to all other safety shutdown devices on a platform. Therefore, each valve is function tested monthly.

There are three types of valves in use in these fields, the bypass type, the ball type and the flapper type. Records covering an eight year period were reviewed to provide data to determine a failure rate provide data to determine a failure rate for each type of valve. Individual graphs were prepared showing each time a valve was pulled, and these were reviewed and summaries given to show how failure rates were determined.

Based on the review, the following failure rates were determined:

Type No. of No. of Failure Valve Tests Failures Rate

Bypass 3472 28 0.8%

Ball(old 595 68 11.4%type)

(new 172 4 2.3%type)

Flapper 1651 26 1.5%

Introduction

Amoco has been producing gas from the southern North Sea since April 1969 and until July 1977, 101 development wells had been completed in the Leman, Indefatigable and Rough Fields. The fields produce from the Rotliegendes Sandstone from depths ranging from 6600' to 8500'. In these fields two completion schemes are used, one with 4 1/2" tubing, the other with 5 1/2" tubing. The 4 1/2" tubing was used in 36 wells on the first three platforms in the Leman Field, but all later completions used 5 1/2" tubing.

As part of the completion equipment, a surface operated, wireline retrievable, subsurface safety valve is set in the tubing, approximately 100' below the sea bed. These valves are referred to as mudline safety valves (MLSV). These are fail safe, since hydraulic pressure from the surface must be maintained to keep them open. A concentric tubing/casing annulus is used to transmit this hydraulic control pressure. Due to the type of operation and the location of these valves, they provide a back-up to all other safety shut-in devices on a platform. They will automatically close if any of the surface hydraulic control equipment is damaged, or if the Christmas tree is damaged, and due to their location within the well, they should be immune from any damage above the sea bed.

Each MMSV is function tested once per month. This test is conducted in the following manner:With the well flowing, the hydraulic annulus pressure is bled off, causing the MLSV to close.

P. 257
Legislation And Its Application To The Control And Use Of Submarine Pipelines On The UK Continental Shelf
Authors: Paddock Kenneth F.
Published: December 2007

Introduction

Prior to the introduction on 1 January 1976 of the Petroleum and Submarines Act 1975, there was no legislation under which the design and operation of submarine pipe-lines could be effectively controlled. There was however legislation which had to be complied with - as it still does with some modification to the application - and which wasCoast Protection Act 1949 - as extended by the Continental Shelf Act.Dumping at Sea Act 1974.

The Coast Protection Act 1949 is administered by the Department of Trade, (the Marine Division being those most involved), and is the department having the responsibility for the safety of navigation. The consent of the Secretary of State for Trade was originally required for the entire route of the pipe-line, but it has now been agreed with them that in waters deeper than 100 feet (33 metres) no hazard is offered to any vessel by a pipe-line and so no conditions are imposed by that department if the pipe-line is in water exceeding that depth.

The Dumping at Sea Act 1976 is administered by the Ministry of Agriculture, Fisheries and Food (MAPF) in English waters, and in Scottish waters, taken as north of latitude 56 °, it is administered by the Department of Agriculture and Fisheries for Scotland (DAFS). In the offshore context these offices have the interest of the fishing industries to consider.

The Petroleum and Submarine Pipelines Act 1975 now embraces for submarine pipe-line purposes the requirements of the Dumping at Sea Act 1974 but it is important to point out that only that which is to form a part of the pipe-line, including anything intended to give it protection or insuring stability, is covered by the Act. Anything disposed of over the side of a lay barge or other vessel engaged on pipe-line work is obviously not within the category of part of the pipe-line, and so such disposal would constitute an offence under the Act. On the other hand any chemically treated water - inhibited test water for example - is not part of the pipe-line and although a consent is required before it is ejected into the sea, the consent in this case is given under the Petroleum and Submarine Pipelines Act 1975. The view being taken that it is part of the integrity testing and so connected with the safety of the pipe-lines.
Monitoring And Structural Response Of Steel Offshore Structures
Authors: Brown David R. , Huckvale Stephen A.
Published: December 2007

There are many different levels at which the performance and response of a steel structure can be studied. This paper reviews various schemes and outlines the results of recent work in the North Sea.

The scope of the work includes a theoretical dynamic analysis of the structure, the design, installation and performance of a vibration monitoring system and the computer analysis of measured vibration spectra for the purpose of evaluating the technique as a means of monitoring the structural integrity of the installation.

The system described is an offshore platform inspection tool capable of utilizing the divers time more effectively by directing them to areas of structural concern.

Vibration spectral energy distributions for a N. Sea platform are presented as well as a more convenient form of presentation designed to aid the handling and interpretation of the data.

The Need for Monitoring

For some time, it has been clear that it is very desirable to develop systems of remote monitoring to enhance diver inspection techniques: when the statistics are studied, it is evident that such schemes are really essential. There are 52 fixed steel jacket structures in the British sector alone in the North Sea, the great majority of which are in water depths greater than 50m. Within the certification requirements there is a demand for re-certification every fifth year and a programme of annual surveys. In practice this is often replaced by a fairly steady and systematic series of annual surveys by divers. There are three main causes of failure, corrosion, fatigue and accidents, and it is very difficult to select areas that are most likely to have suffered. Finding that 10% of the structural members are in good condition is only superficially reassuring.

The real point is to see if instrumentation can concentrate diver and other inspection activity on areas of greatest vulnerability. In the British sector of the North Sea, there are about 600 nodes on steel jackets that are below the 50 metre depth. This depth is generally recognized as the limit of air diving. With an average length of 23m of weld per node, this suggests about 14km of weld that requires inspection. The estimated cost of saturation diving, manned and unmanned vehicles used in the northern North Sea is about £50 million in 1977 and about 40% of this is concerned with inspection of members: the rest is concerned with items such as scour, anodes, cleaning of marine growth, etc. (statistics on maintenance requirements are taken from Ref. 1).
What Should Oil Managements' Goals Be To Satisfy Investors?
Authors: Fourton Leslie K.
Published: December 2007

I am highly honored to have been asked to participate in your National SPE meeting and to have the opportunity of discussing with you some of the factors which we in Wall Street feel influence the attitudes of investors toward petroleum equities. The securities of your companies vie with those of companies in other industries and their investment appeal is influenced in many ways.

Your committee chose the title for this paper because it felt that a discussion of management goals with equity valuation as a basis of orientation might be particularly useful and timely. The fact that oil securities are selling at 12 to 15 times earnings compared with 19 times for the Dow Jones Industrial Average shows the decline in investor favor in recent years. I believe, nevertheless, that you represent an investment group which offers the same outstanding values and opportunities today as it has in the past. The question is what causes this undervaluation of your industry and what can be done about it.

I have asked many widely-recognized senior petroleum analysts both in Wall Street and in institutions such as mutual funds, insurance companies and banks how they would approach this subject of management goals to satisfy investors. It was almost amazing how similar were the replies. Everyone said: "They should pay higher dividends." These replies were not as facetious or superficial as some may think, although I don't believe higher dividends is the only or the most important way to look at this subject.

Now, irrespective of what final position we may take, there is a broad fertile area we may explore in attempting to more precisely satisfy investors. To do this, each of you must first determine what kind of stockholders you wish to attract and satisfy. There are decidedly different methods of appealing to institutional investors, the individual sophisticated investor and the small stockholder. Since there is insufficient time, however, to discuss the desires of each type of investor, it may be best to proceed in a general sense.

First, we should examine the aspects of the petroleum industry which are of particular concern to investors in general. Second, we could briefly examine the fundamental position and prospects of the industry itself. Third and lastly, knowing what is of concern and what there is to work with, we may be able to develop some constructive thinking on management goals which may satisfy investors.

I believe there are eight major areas of concern to investors and it may be helpful at this point to review them briefly.
Economic Benefits To The UK Of North Sea Oil
Authors: Ferguson Carol Cecilia
Published: December 2007

Economic study of the North Sea has applications for Government and Industry. For Government. quantification of North Sea benefits influences policy in diverse areas such as taxation levels. exchange control and economic management in general. Loosening of economic restraints may benefit industry by reducing taxation levels, restoring business confidence and stimulating investment.

INTRODUCTION

This paper identifies three important areas where the UK benefits from North Sea Oil production. These are:Balance of PaymentsUK Gross National ProductNew Offshore Oil Service Industry

The paper quantifies the contribution of oil to the UK economy where possible and evaluates the impact of changes in the exchange rate and the oil price. The likely effect of Government refinery policy and depletion policy are also reviewed.

The main conclusions are positive - that the UK economy will enjoy a higher rate of growth in the medium term. Economic management will be less constrained by Balance of Payments and exchange rate considerations. Energy self-sufficiency will also have important political implications. The UK will develop expertise in oil exploration. production and related services to enable it to compete effectively overseas, particularly in the more hostile offshore areas. There are also some dangers to the UK economy, with the possibility of sterling becoming overvalued, thus accelerating the decline of the UK's traditional industries.

RESERVES AND PRODUCTION

It is a little over a decade since the first commercial North Sea oil discovery was made. Production is now being obtained from nine UK fields and a further eight are under development. Total recoverable reserves from these seventeen fields are estimated to be a little over 9.5 billion barrels. Additional reserves of 1.7 billion barrels will probably be recovered from a further ten fields which are likely to come under development over the next three or four years or so enabling them to start contributing to UK production from late 1980 onwards. New that production is building up, the North Sea can be said to be maturing as an oil province, although by comparison with other producing zones, it is a relatively unexplored area. It is very likely therefore that although it is believed that most of the largest structures have been identified and tested, that the North Sea will continue to produce further commercial discoveries in the future.
Protecting Wellheads And Maintaining Platform Integrity During Offshore Well Fires
Authors: Hansen A. Boots , Matthews E.O. Coots
Published: December 2007

The risk of offshore blowouts and of pressure fires is considerable. and dangerously unpredictable. Such blowouts and fires are so dangerous and so expensive, that owners and operators of offshore structures are well advised to consider expending effort and money to do everything they can in advance that will reduce damage, lost time and the costs of capping the blowouts and extinguishing the pressure fires.

Getting back into production after such an accident on one Gulf Coast platform required several months for one operator. Elsewhere. a platform emergency involved ten wells set on fire after one blow out on a 64 slot platform being worked. Capping such blowouts and cutting off such pressure fires is not at all the same as coping with ordinary hazards and accidents. Nor is it substantially the same as coping with the same emergencies onshore.

Every professional in the oil industry has some knowledge of what equipment should be used and what precautions must be taken to prevent blowouts and pressure fires. This technology has been around for many years. Many professionals also have considerable knowledge about fighting offshore fires knowledge they very likely gained at considerable cost! But both equipment and procedures are different in each field. Fighting offshore fires, capping blowouts in remote and hostile environments, particularly in areas like the North Sea, is still rather new. We believe that the people who are most concerned about avoiding such disasters, and about reducing the damage and cost of any outbreak that does occur, do not have an adequate picture of the best approaches. Much knowledge has become available piecemeal. Only in recent months have those professionals most concerned with it put together a complete perspective and recommendations.
Tecnomare Steel Gravity Platforms For Marginal Fields
Authors: Lalli D. , Vielmo P.
Published: December 2007

Introduction

The world economic situation characterized by the energy crisis created by the oil shortage and consequent oil price rise, has in the last decade, and more particularly in the last five years, determined the oil particularly in the last five years, determined the oil industry's entry into a more expensive exploitation of offshore oilfields. This trend is being pursued by means of considerable research and development activities in the following areas:Achievement of technologies and exploitation systems suitable for oil/gas production in verydeep waters, in severe meteoceanographic condition seven in arctic environment.Achievement of technologies and systems for the economic extraction of oil/gas from fields of moderate size and production remotely located or not easily linkable to major production complexes.Rationalization of the development programme of the oilfield exploitation systems by means of techniques and components which may require lower investments and quicker recovery.Optimization of design of the exploitation system components implementation of their operating efficiency achievement of high operating safety standards.

A particular interest is being expressed by oil companies in the development of the so called marginal oil/gas fields. That is those fields which due to their expected production, their location and environmental characteristics, were considered not economically exploitable with the conventional systems, mainly based on fixed piled platforms. In the present paper the technical and economical problems posed by the development of marginal fields will problems posed by the development of marginal fields will be considered and the various solutions proposed by Tecnomare in this regard will be presented.
A High Pressure Riser Within An Articulated Column
Authors: Moinard M. , Dupont B.
Published: December 2007

Subsea development schemes for oil and gas Fields require reliable riser systems to control production wells and handle high pressure effluents from the sea bottom to floating processing supports. A permanent high pressure multiline riser has been designed to be installed in articulated structures. The riser is able to sustain the more adverse sea conditions of the North Sea without any need for disconnection. The technology of such a riser has been developed in detail. Fatigue and life endurance tests have been performed on full scale protoeype component parts. Test performed on full scale protoeype component parts. Test results confirm that the design may be applied with confidence to industry. The ability to pass high pressure pipelines through the articulation is the specific feature of a riser connected to a column. The technique is based on deflecting pipes passing through an annular universal joint. These pipes are passing through an annular universal joint. These pipes are arranged in a bundle configuration and extend from top to bottom of the column inside a central stack. Deflecting steel pipes are expected to last several years and can easily be replaced from the top deck of the column. The reliability of this riser design led to comprehensive studies for diverse uses of the column: * The use of an articulated structure as a logistic platform to permit daily control and maintenance of subsea wells. * The use of a column acting as a permanent riser an single mooring point for a floating production vessel with the possible alternative of installing production facilities on an isolated column. Water depths up to 400m can be reached with a single articulated structure.

Introduction

The development of the offshore oil and gas industry now advancing in water depths of 100–350m.
High Accuracy Directional Surveying Of Wells Employing Inertial Techniques
Authors: Morgan D.G. , Howe N.
Published: December 2007

Drilling of multiple wells from offshore platforms has increased the accuracy requirements for directional surveying. To meet this need a 3-dimensional method of surveying wells to within one foot to 13 3/8 in. casing shoe has been developed. The basis of the equipment is an inertial system which consists of a gyro stabilized instrument cluster with three accelerometers measuring the displacements. The advent of inertial techniques has provided a means to complement monitor and improve provided a means to complement monitor and improve conventional survey techniques.

Introduction

The increased density of wells being drilled from offshore platforms, particularly in the North Sea has emphasized a need for more accurate directional survey techniques. Safe practice necessitates an increasing loss of production during concurrent drilling and production operations due to the uncertainty of hole position. The need to define bottom hole position is essential to avoid loss of well control. There has existed a source of concern arising from doubts about the accuracy of conventional surveys and the doubt that the position of a deep well could be defined with a horning device.

TECHNOLOGY

Given a doubt about the accuracy of conventional surveys there has been a need to define alternate systems. Inertial navigation systems have been developed for application in all weather combat aircraft and missiles. More recently they have been applied as survey equipment in artillery and topographical surveys. The navigation performance for aircraft is typically one nautical mile per hour - accuracy sufficient to assist transatlantic crossing - the system is, however capable of increased accuracy under different operating conditions.
Offshore Processing Plants A Systematic Approach To Weight Saving
Authors: Loge P.G. , Brekke T.
Published: December 2007

Weight and space requirements of offshore processing facilities can be used as parameters indicating a relative cost level of the installation. Of the two, weight is the easier to quantify. The operating weights of certain such production facilities are presented in this paper. The overall weight is broken down into a limited number of sub-groups, and the results are compared. Based on these results some ways and means of reducing the weights are discussed. All data used in this paper are as-built weights from North Sea installations. The paper further highlights the importance of keeping good control over platform weights, not only by keeping within weight estimates, but by looking at weight minimizing as a worthwhile optimization exercise.

Introduction

The overall function of a primary producing facility whether on land or offshore, is to produce hydrocarbons in a sound and economic way. Offshore, platform size is one important parameter affecting costs of an installation and keeping the size down will generally help projects economics. This size will, by common sense, be dependent on platform function, but often the physical dimensions of a platform bear little relation to the functions of the platform. Indeed, when looking at the weights of some recent North Sea projects, it is difficult to see any sensible relationship between platform capability and the weight of the facilities. Nevertheless, little has been done to carefully investigate why, consequently, certain platforms become too heavy.

In a number of engineering disciplines optimization is common. The object thus being to find, not only one way of doing it, but the best way of doing it. With the cost of the platform in mind, how to do it smallest and lightest, ought to be regarded as an optimization study in itself. Because most certainly, by looking at some past projects, the size varies considerably, and there past projects, the size varies considerably, and there is room for savings in most of them.
Experiences From The Removal Of Platform WE
Authors: Brookes M.A.
Published: December 2007

Background

Structure description

Platform WE was a small four leg unmanned platform located in BP's West Sole gas field. The jacket carried a deck comprising a helideck with two cellar decks beneath for production equipment and supported a single 30 in. (760 mm) conductor tube together with an 8 in (200 mm) riser. Figure 1 gives a general view of the structure in service. The general arrangement of the jacket is shown in Fig. 2. The jacket was sited in a mean water depth of about 25 m and had plan dimensions of 32 ft (9.8 m) square at the top, tapering to 57 ft (17.4 m) square at seabed level. It was supported on four 30 in. diameter piles driven through the legs into hard boulder clay and welded to the top of the jacket. The annular space between shear capabilities at the nodes.

Service History

The platform was originally designed to support the West Sole discovery well drilled by the ill-fated jack-up 'Sea Gem'. When 'Sea Gem' collapsed in December 1965, the well was lost and the then fabricated platform was stored in Holland. Subsequently the jacket was modified and used at the WE location in July 1966. The platform was designed according to the best standards applicable at the time. These owed much to Gulf of Mexico experience with some necessarily limited local environmental data.

In 1973 a major structural reappraisal of all the West Sole platforms took place and as a result some strengthening of the platforms was carried out. In the case of WE it was estimated that its fatigue life could be of the order of a further 5 years. No strengthening of the platform was undertaken, however, as it was economically difficult to justify.
Review Of Drilling Operations Montrose Field
Authors: Medely E.L.
Published: December 2007

Medely, E.L., Amoco (UK) Exploration Co., Scotland and Dent, W.F., Amoco (UK) Exploration Co., Scotland

This paper reviews the drilling operations on the first 16 wells drilled by Amoco (UK) Exploration Company on the Montrose Alpha platform. Initial wells were plagued by numerous problems associated with bad hole conditions and complicated completion procedures. The average time to drill and complete the first six wells was 67 days at a cost of $3,500.000 each. After the sixth well major changes were made in both the drilling and completion programmes which resulted in substantial savings in time and well costs. The average time to drill and complete the next ten wells was 38 days at a cost of $2,400.000 each.

This paper describes the drilling and completion philosophy and practices adopted by Amoco to reduce philosophy and practices adopted by Amoco to reduce costs by 1.1 million dollars per well.

Introduction

The Montrose field is located 125 miles east of Aberdeen in 300 ft of water. It was discovered in September 1969, and development drilling began in April 1976 from an eight leg steel platform. By October 1978, 16 wells had been drilled from the platform, 14 producers, and 2 water injectors. Drilling and production operations have been conducted simultaneously on the platform since June, 1976. Therefore, each well is completed and placed on production as drilling is finished. The maximum combined producing rate from the 14 wells has been 41,700 bopd. producing rate from the 14 wells has been 41,700 bopd. Oil is transported from the platform by tanker loading through an SMB. Production from the field is from the Palaeocene sand, with the sand top at 8,100 ft subsea. Palaeocene sand, with the sand top at 8,100 ft subsea. All wells from the platform have been directionally drilled with the longest step-out being a well with a displacement of 8,978 ft at 8,961 ft TVD reaching a total measured depth of 13,375 ft. The maximum hole angle was 69 degrees. Penetration rats are generally very fast, with instantaneous rates up to 900 ft/hr.