bluuebunny/crossref_metadata_2025_split huggingface dataset:
Drilling And Completion Of Buchan Field
Authors: Pinchbeck R.H. , Powell S.E. 
Published: December 2007

Abstract
The economics of oil and gas production in the North Sea are now leading the industry towards increasing use of subsea technology for the development of the smaller fields. The Buchan field, located some 150 kms NE of Aberdeen in 120 m of water, and with estimated recoverable reserves of the order of 50 million barrels, typifies the North Sea "marginal field". This paper describes the drilling and completion phases of Buchan development, and is presented as a companion paper to Geological aspects of the drilling Buchan field. The paper highlights the methods by which the potential hazards of drilling the highly-overpressured reservoir were overcome, outlines the evolution and implementation of the well completion methods adopted, and discusses problems encountered and lessons learned.

PROJECT OVERVIEW PROJECT OVERVIEW

The production system
Owing to the uncertainty about the performance of the tight and fractured reservoir and the low figure of recoverable reserves Buchan is a truly marginal field. The projection is that it will produce 50 million barrels over a period 5 years but the range of possible recoveries is wide and financial in the venture high. In the light of this risk any development scheme had to incur minimum expenditure and provide production at the earliest possible date. The scheme adopted, subsea completions with a floating production platform and tanker export, meets these criteria. Figure 1 shows the production system: oil is produced from seven subsea wells, (a central cluster of five at a template and two satellite wells) through a subsea manifold at the template and individual risers, to a semisubmersible production vessel. Degassed crude is then pumpted down the production vessel. Degassed crude is then pumpted down the manifold again through the 12 in. riser and out along the seabed for export via a CALM loading buoy.
Experiences With Surface Controlled Subsurface Safety Valves (SCSSV)
Authors: Agnew I. 
Published: December 2007

Agnew, I. Shell UK Exploration and Production UK

Introduction
The surface controlled subsurface valve (SCSV) is the final means of maintaining control of a well when all surface controls no longer function. Although it is seldom necessary to call upon the full services of this value it is essential that it does respond with 100 percent reliability whenever the need arises. When a completion is being designed particular attention should be placed on the selection of the SCSSV to ensure that the best choice of valve is made to suit the well conditions.

Summary
This report outlines the reasons behind the selection for the hydrostatically balanced SCSSV used by Shell Expro for their Northern Sea operations with particular reference to the Brent field. The main problem encountered with this valve was the very poor reliability due to elastomer seal failures. Initially the external chevron "Vee" packing came under close scrutiny and a wide range of materials were tested and tried with very little success. Internal "O" ring seals were also investigated and it was found that the combination of elastometer hardness, diameter clearance between sealing surfaces, surface finish and pressure differential across the "O" ring was critical to enable the seal to perform satisfactorily "T" seals the reliability of the valve is beginning to improve. The practicality of balanced type of SCSSV's is not very promising. Problems have occurred with live balance lines, promising. Problems have occurred with live balance lines, gased up balance lines and increased failure probability due to the extra seals which have to be used. The balanced type ball valve does have the added advantage of being able to cut piano wire, but this does not compensate for its poor reliability. piano wire, but this does not compensate for its poor reliability. Valve setting problems have been encountered but it is anticipated that they could be overcome by improving the techniques being adopted.
The Installation Of An Eight Point Permanent Mooring System In The Piper Field
Authors: Lowe E.A. 
Published: December 2007

The installation of an eight point permanent mooring system in the Piper permanent mooring system in the Piper field

Abstract
The need for support vessels alongside North Sea platforms during offshore construction programmes has platforms during offshore construction programmes has focused attention on the problems of mooring and maintaining station in this service. In the past mooring systems subject to storm situations have been primarily designed for open ocean applications and primarily designed for open ocean applications and have not catered for the requirements of operating and surviving alongside a fixed platform. In addition, anchor handling and dragging of anchors had been seen to be the primary causes of damage to submarine pipelines.
The Piper field, located in the 58 degrees north sector of the North Sea, experienced these mooring difficulties compounded by poor top soil conditions, which led to the design and installation of a fixed permanent anchor pile mooring system around the platform. permanent anchor pile mooring system around the platform.

System Description
Eight anchor piles 60 in. diameter × 2 1/2 in. wall thickness × 94 ft long were driven with an HBM 1500 underwater hammer in a symmetric pattern around Piper 'A' providing suitable anchorage for construction vessels with operating draft displacements in excess of 40,000 L.T. Each pile was positioned 4,000 ft from the platform and has 1,010 ft of 3 1/2 and 4 in. chain attached for mooring. The free end of each chain is retrievable by pendant wire and buoy during connect/disconnect pendant wire and buoy during connect/disconnect operations.

Installation vessel choice
Pile and hammer handling capabilities Pile and hammer handling capabilities Early in the design stage, the use of stabilized lowering device such as the drill string of a drilling vessel was recognised as the optimum method of handling the hammer/follower/pile assembly. Pile/hammer stability calculations indicated the need for a sophisticated stabbing template to be pre-installed on the sea bottom if conventional unstabilized lowering devices were used. Since the template method would add considerable time and cost to the installation programme, our vessel search concentrated mobile drilling rigs.
Is There Enough Oil?
Authors: McAfee Jerry 
Published: December 2007

Abstract
Various recent energy studies and estimates of ultimate petroleum reserves, especially in the United States, make a realistic evaluation of the future petroleum supply and demand situation on a world-wide basis both pertinent and timely.
Adequate energy supplies are obviously of critical importance in maintaining, to say nothing of increasing, the world's living standards. Oil and natural gas now supply most of the U.S. energy requirements and a large part of the energy requirements of the entire Free World. The proportion supplied by petroleum in the Free World will probably continue to increase for at least another generation. A comparison with the U.S. is helpful in forecasting future Free Foreign requirements, in which natural gas will probably play an increasingly important role. Py 1975, U.S. consumption should be about 13 million B/D and Free Foreign consumption about 24 million B/D.
To supply these requirements and maintain a safe margin of reserves and producing capacity, about 200 billion barrels must be added to Free World proved reserves over the next 12 years. The ability of the U.S. to supply even 80% of its 1975 crude oil requirements from domestic sources at present prices is debatable, but other sources of oil are available and no world-wide shortage is likely. Free Foreign productive capacity and reserves will be more than adequate to supply Free Foreign requirements and to supplement U.S. domestic supplies as necessary, if the oil companies operating internationally are permitted a reasonable degree of freedom to discover new oil deposits and to match supplies against demands.
Numerical Simulations Of The Combined Effects Of Wellbore Damage And Partial Penetration
Authors: Saidikowski Ronald M. 
Published: December 2007

Abstract
There is considerable disagreement in the literature concerning the interpretation of wellbore damage (the skin effect) in partially completed wells. The skin factor is composed of two components, one of which is indicative of actual formation damage and the other of which results from an additional pressure drop due to the partial completion. The skin factor measured in a buildup test does not reflect the simple sum of these two components. Rather, the effect of the actual damage is accentuated by the partial completion. A method is presented to aid in the interpretation of well tests which yields estimates for both contributions to the skin factor.
Analysis techniques are derived for steady-state flow and these are corroborated for transient flow by using simulated well test results. The simulations also provide a basis for comparing the various correlations for determining the skin factor due to partial penetration. The importance of the ratio of vertical to horizontal permeability is considered in the analysis. An example illustrates the application of the method.

Introduction
An altered zone of reduced permeability surrounding a wellbore is quantified in terms of the skin factor, s. This factor is related to the excess steady-state pressure drop1,2 in a flowing well as:Equation 1
The flow efficiency, E, is expressed in terms of Î"ps and the total drawdownÎ"pw, as:Equation 2
The skin factor has been related3 to an altered zone near the wellbore (Figure 1). If a zone of reduced permeability, ka, extends a distance, ra, into the formation, then the skin factor, s, is:Equation 3
where rw is the wellbore radius and k is the bulk formation permeability.
It is the skin factor described by Equation 3 that is a measaure of the true formation damage caused by drilling and completion practices and other factors. This type of flow impediment is the target of acid treatment and other workover procedures. Thus, in order to evaluate completion practices and to recommend workover procedures, it is necessary to accurately determine the 'true' skin factor due to formation damage. In subsequent discussion this skin due to true damage will be designated as sd. The value of sd can be somewhat difficult to measure directly.
A well is often completed over only a portion of the producing formation (Figure 2). This leads to a flow construction which is detected as an additional pressure drop or skin effect. Several authors4,5,6,7,8 have developed analytical descriptions of the skin factor, sp, due to partial penetration in an otherwise undamaged reservoir. In particular, Nisle9 has developed a formulation for simulating well tests within an infinite acting reservoir with a partial completion. The concept of a skin factor is not introduced.
Successful Gas Cycling Of South Louisiana High Pressure Multi-Accumulation Reservoir
Authors: Schnerk George C. , Eckles W.W. 
Published: December 2007

ABSTRACT
The Gillis-English Bayou Field is a multi-pool retrograde gas condensate reservoir. Fourteen years of gas cycling has shown that elaborate engineering-management techniques can deter inter-pool flow, and increase liquid recovery. Recoveries prior to blowdown have exceeded seventy percant for swept portions of this reservoir.

INTRODUCTION
Can multi-pool reservoirs with good communication between pools be gas cycled? The literature abounds with papers written about cycling retrograde condensate reservoirs. The vast majority of these papers deal with simple single zone accumulations or pools. The Gillis-English Bayou Field in Calcasieu Parish, Louisiana is not simple. It consists of four separate sands folded and faulted into nine distinct hydrocarbon pools, all underneath an overlying unconformity. PVT analysis indicated that severe retrograde condensation would occur below 7050 psia (48600 kPa), and gas cycling was initiated.
It soon became apparent the unconformity was a path for gas flow if a pressure difference developed between pools. This was recognized by Sun, and an elaborate reservoir management system was initiated and carried out over a fourteen year period. This has minimized inter-pool flow and resulted in highly successful liquid recoveries.

INITIAL HANDICAPS
The driller's bit first penetrated the Upper Hackberry sands in 1961, at 9000' (2750 m) depths. More than one dry hole established the extremely erratic limits of production. A cross section of the reservoir is shown in figure 1. Four layered sands have an overlying unconformity and plunge down structure to water. The structure map for the Hackberry 1 sand, figure 2, shows separate pools or accumulations for each sand. Figure 3, a vertically, extended diagram, demonstrates the size and shape of nine pools, and the locations of all wells drilled. Some wells cut more than one accumulation, but no pool has over four wells.
Basic reservoir data is shown in table 1. The sands generally have non-uniform permeabilities ranging from 200 to 1800 md. Early PVT data indicated that eight of the nine accumulations were in the gas phase, with dew points ranging from 7050 psia (48600 kPa) to 6645 psia (45800 kPa). The last pool, 1NE, was in the oil phase with a 7290 psia (50300 kPa) bubble point. Initial production from all zones tested about 3500 CF/BBL (62 m3 gas/m3 liq.) gas-liquid ratio.
Further experimentation showed severe retrograde condensation took place when the reservoir pressure was allowed to decrease (table 2). Calculations using laboratory data indicated that only 16 percent of the condensate would be recovered by conventional depletion methods. Production through 1964 had decreased the average reservoir pressure from an initial 7290 psia (50300 kPa) to 7060 psia (48800 kPa), just above the dew point.
Development Of Gachsaran-Kharg Island Pipeline And Oil Handling Facilities At Kharg Island
Authors: Schlabach E.J. 
Published: December 2007

1961 Middle East Regional Meeting; Dhahran, March 27–29, 1961
One of the more significant activities in the Middle East and Persian Gulf petroleum industry in recent years has been the planning-development and construction of the Gachsaran Field and Kharg Island Oil Loading Terminal. In fact, few projects rank in scope, magnitude and accomplishment within the entire petroleum industry worldwide over the past several years.
The activity in bringing this project to conclusion officially culminated in its inauguration on 8th November, 1960 by His Majesty The Shah-in-Shah of Iran.
Apart from the physical prominence and range in scope from production facilities, a surface or band pipeline and submarine pipeline, to tank farms, tanker loading facilities and jetty plus supporting facilities the project was characterized by a uniquely organized international construction force made up from a group of construction companies staffed with Iranians Dutch British French and American technicians artisans and laborers. The work performed by this polyglot group was sponsored in turn by a larger group of the worlds leading oil companies known as the Iranian Oil Operating Companies or colloquially as the "Consortium" in cooperation with the National Iranian Oil Company. Few construction projects have ever involved so many nationalities or have been so complex in their organization.
Acid Leach Of Uranium Ore: In Situ Conditions
Authors: Hardwick T.J. 
Published: December 2007

Abstract
Core samples from a property in Wyoming were tested for amenability to in situ leaching by acid ferric sulfate. In tests, about 95% recovery of the uranium was achieved. The ore is fortunately low in carbonate, and sulfuric acid consumption of 15#/T is expected using feed solutions of pH 1.8.
Factors significantly affecting the yield of uranium are temperature and ferric ion concentration in the lixiviant. Acid concentration, within the pH limits 1.5-2, is significant only in the time required to acidify the formation. Flow rate affects the rate of leaching, but such increase in production rate is balanced by the requirement of handling proportionately larger amounts of more dilute production solution.
Some information has been obtained on other ions leached by the process, and an attempt has been made to relate the information to possible changes in clay structures. Certain reactions, such as the conversion of K-feldspar to kaolinite, have been shown to occur very slowly under leach conditions.

Introduction
A site potentially suitable for in situ leaching of uranium from sandstone was selected from various candidates. Core samples were obtained and blended to give a composite considered representative of the ore. Care was taken to avoid exposure of the ore to oxygen, but subsequent experience showed this precaution to be unnecessary. All tests were performed on this composite sample.

GEOLOGY AND MINEROLOGY
The ore zone consists of a fluvial sequence of arkosic sandstone and silty claystone, and lies well below the local water table.
The majority of the uranium occurs as uraninite, with minor amounts of coffinite. It is believed that the uranium was desposited by the reducing action of humic acid released by compacted sediments. Most of the uranium occurs in hematitic coarser sandstone faces that once contained organic carbon. Its location is related to lithological changes particular to scour and fill environments.
The dominant clay is a vermicular kaolinite, with occasional concentrations of chlorite, illite, and montmorillonite. In some areas, kaolinite can be seen altering to illite.

APPROACH
The leach experiments were primarily designed to provide practical information on stream concentration-history to be expected in field operation using a recycling system. Whenever possible, measurements to elucidate mechanisms were carried out.
Inevitably, hindsight has shown a number or desirable measurements not made, but the series of experiments has allowed a definition of a schedule to be followed in testing a uraniferous sandstone ore for its potential for acid ferric sulfate leach. Many auxiliary experiments delineating the behavior of clays, can be suggested; they are particularly necessary to define programs required for studies in site restoration.

TECHNIQUES FOR LEACHING
The most difficult decision is the kind of experiment to perform.
Practical Application Of Non-Newtonian Transient Flow Analysis
Authors: Ikoku Chi U. 
Published: December 2007

Abstract
Recent studies on the transient flow of non-Newtonian fluid in porous media have proposed new well test analysis techniques for non-Newtonian injection wells. This paper extends these new techniques to non-Newtonian injection well falloff testing. The practical use of this well test analysis method is practical use of this well test analysis method is demonstrated. The limitations of the techniques also are addressed. Examples of field data are used to demonstrate how this analysis can aid in well test interpretation and provide data and insight for the design and operation of enhanced oil recovery projects. projects

Introduction
The transient pressure behavior in wells receiving non-Newtonian fluids is of considerable interest because of the large number of enhanced oil recovery projects now in operation. As a result of a number of studies over the past 2 or 3 years, an increased understanding of non-Newtonian fluid behavior in petroleum reservoirs has been obtained. It is generally believed that most of the non-Newtonian fluids used in enhanced oil recovery processes are pseudoplastic in nature and their processes are pseudoplastic in nature and their rheology can be approximated by a power-law model.
Pressure falloff testing is probably the most common well testing method. This is true particularly when tertiary recovery projects are being particularly when tertiary recovery projects are being considered or are in progress. When injection wells receive expensive fluids like polymer solutions, micellar solutions, and surfactant solutions, their ability to accept these fluids uniformly for a long period of time is important to the economics of the period of time is important to the economics of the tertiary recovery project. The mobilities of these fluids are important parameters in flood design. Also, wellbore damage must be monitored and corrected.
Refs. 1 and 2 provide detailed studies of the theory behind the non-Newtonian flow model to be used in this paper. These references also present new well test analysis techniques for non-Newtonian injection well pressure-buildup testing. The purpose of this paper is to extend this analysis to non-Newtonian injection well falloff testing, provide necessary engineering forms for use of the non-Newtonian flow results, and illustrate applications.

FALLOFF TEST ANALYSIS
The principles of superposition enable us to analyze changing rates of flow from the solution of a constant terminal rate case. The partial differential equation describing the flow of a slightly compressible power-law fluid in an ideal radial system is given in dimensionless form as
(1)
where
(2)
(3)
(4)
and
(5)
Gas Storage Problems And Detection Methods
Authors: Knepper Glenn A. , Cuthbert J.F. 
Published: December 2007

Abstract
The use of underground reservoirs for the storage of natural gas during the warm months, for delivery to users during the winter, has grown from a single experiment in 1915 to an extensive industry. Today, gas-storage reservoirs supply on peak winter days more than half the natural gas consumed by a given area. Because of the large seasonal variations in gas pressure in these reservoirs, the wells are subjected pressure in these reservoirs, the wells are subjected to severe stresses. The early detection of problems in storage wells has therefore become a critical need of the industry. The use of case-hole logs, together with inventory-control procedures and careful monitoring of well pressures, is serving to detect many of the common problems. problems. This paper surveys these methods and describes a study of the problems observed in wells of a gas storage system, how they were detected using the above methods, and how they were corrected.