bluuebunny/crossref_metadata_2025_split huggingface dataset:
Planning and Construction of Storage Caverns in Salt Deposits
Authors: Wockenfuss A. 
Published: December 2007

Abstract
Difference in the drilling concept between wells planned for underground storage purposes and those for crude oil or gas are discussed. The completed wells are investigated by means of a series of logs to analyse the quantitative mineral composition of the salt. The method avoids most of the expensive core drilling. The results gained by the computer-calculated interpretation of the log have been confirmed by observations made during the leaching process.
The well-known mineral composition enable the planning of a detailed leaching program for every envisaged cavern. It contains among other things the number of washing stages in every cavern, the intervals for sonar logging and the time required to create the desired volume.
Together with a description of the technical installations used a report on experiences with material and equipment is given.
The performance and supervision of the leaching process is discussed, especially the different methods to determine the cavern volume created. It has been found that, depending on the shape of the cavern, major differences in volume sometimes occur due to the different calculation methods used.
To enable permanent control of shape development of the cavity during the leaching process, a procedure has been introduced using the field data obtained.

Introduction
For many years storage caverns for natural gas and LPG in salt deposits have been built and used, especially in USA. In Germany the first cavern for seasonal storage of butane with a capacity of about 125,000 bbls. was completed in 1963.
In recent years an ever increasing number of caverns have been planned and built for storing crude oil or fuel oil. Especially since several European countries have promulgated laws obligating petroleum refiners to maintain petroleum stocks, a growing interest in this type of storage has become apparent. In case of favorable geological and topographical conditions storage in caverns is superior to all other methods from an economic standpoint. Since 1968 various projects for creating storage capacity to meet the stockpiling obligation are under construction in North Germany.
In the following the storage project of Sottorf near Hamburg serves as an example to report on experience gained and methods used during the construction of this project.
How To Optimise A Dynamic-Stationing System
Authors: Zunderdorp H.J. , van der Vlies J.A. 
Published: December 2007

Abstract
After a short description of the general principles of dynamic-stationing systems, a method principles of dynamic-stationing systems, a method of optimising the controller is described. In the past, dynamic stationing has been regarded as a past, dynamic stationing has been regarded as a solution only for deep-water operations. Complete simulation of the behaviour of the vessel, the controller and the thruster units under the influence of current, wind and irregular waves now enables us to optimise the system in such a way that stationing is even possible in as little as 200 ft of water.
A description and some results of such simulations, which can be performed equally well on digital and hybrid computers, are given. As a result of these studies, the need for two further improvements became apparent. The first is a form of filtering technique to remove the cyclic component from the steering signal of the thrusters, so allowing improved control, higher efficiency and less wear and tear on the thrusters. The requirements for such filters are given. The second improvement is the feeding forward into the control system of a signal proportional to the wind force to enable quick response to wind gusts, so reducing Use deviations from location that would otherwise result.

Introduction
Very few dynamically stationed vessels have been built to date, although the principles involved are very simple. The vessel is kept on station with the aid of a servo system, rather than by mechanical means. To accomplish this, the deviation from Be origin is measured and translated into command signals, which activate propulsion units in such a way as to compensate for the deviation.
Thus this is in fact a normal control system, of a type used in many engineering fields. The difference between this and normal control applications, however, is the size of the mass to be controlled and the magnitude of the outside disturbing forces. These forces are delivered by wind, waves and current; the first two of these are irregular in character and only the third one remains stable over a restricted period of time. The sum of these forces may be larger than the restoring forces that can be delivered by the propulsion units, and it is only because of the cyclic nature of (especially) the wave forces that control is still possible. It will be clear that the nature of these possible. It will be clear that the nature of these forces will influence the design of the control system substantially.
Pipeline Gas Reserves And Availability
Authors: Buck J. Randolph 
Published: December 2007

Buck, J. Randolph, Member AIME, Northern Natural Gas Co., Omaha, Nebr.
Publication Rights Reserved
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and considered for publication in one of the two SPE magazines with the paper.

Abstract
This paper is directed to the significance of gas reserves and the availability of such reserves to natural gas pipeline companies. Various uses for these computed data within a gas supply department and a transmission company as a whole are suggested.
Sources of basic data, the treatment of gas well and casinghead gas, the development of area specialists, together with general procedures followed in the active prosecution of reserves work are indicated.
A distinction is made among the terms availability, deliverability, and potential. Each may be considered from the individual well, total field, gathering system, or total company points of view.
The problem of gas well stabilization, with particular regard to the ability of wells to maintain certain flow rates under continuous production, is emphasized from the standpoint of the regulatory necessity for a pipeline company to demonstrate an adequate gas supply to meet requirements of the presently proposed or future sales. Very practical problems are involved in the extreme case of low deliverability and high reserves on a per-well basis. The demonstrated difficulty of a pipeline company to maintain a 12-year availability life without creating a condition of oversupply, or bulge gas, is reviewed.
General requirements and procedures followed in a certificate application proceeding before the Federal Power Commission are briefly discussed. Meanings for the terms "reserve life index" and "availability life" are included with a review of the effect of an unrealistic availability life control on the industry.

Introduction
In the state of Texas, petroleum engineers qualify themselves in the field of petroleum and natural gas. Although oil and gas constitute one basic industry, many engineers, particularly the older ones, have devoted the large portion of their time and effort to problems relating to the production of oil. The realignment of a sizeable proportion of the emphasis to problems peculiar to gas has been a development of the past decade wherein the marketability of gas has increased tremendously. The continually expanding sales of gas has been achieved by the pipeline segment of the total oil and gas industry in a complex process involving producers, consumers and certain regulatory bodies. Because of the present magnitude of the gas industry in light of its more recent rapid growth, it is believed not too late to set down a synopsis of how and why gas transmission companies actively engage in and rely upon reserves and availability studies.
Interpretation Of The Results Of The Back Pressure Testing Of Gas Wells
Authors: Govier G.W. 
Published: December 2007

Publication Rights Reserved
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and considered for publication in one of the two SPE magazines with the paper.

Abstract
The origin and limitations of the conventional and empirical equation for the interpretation of the results of back pressure tests on gas wells are discussed. Difficulties in data interpretation arise from many causes., including lack of flow stabilization,, uncertainties in connection with the friction calculation, and the effect of turbulence near the sand face in the reservoir.
A procedure is developed to account for the turbulence effect. This is based upon the theoretical equation for laminar steady-state flow and current knowledge of turbulent steady-state flow. The procedure involves the expression of the equation for combined laminar-turbulent steady-state flow in terms of a turbulence contribution factor. This factor is shown to be dependent mainly upon the flow rate per unit of pay thickness and the reservoir permeability.
The method of interpretation permits the use of judgment based upon the theory and present day understanding of laminar-turbulent flow and is considered an improved method for interpretation of stabilized flow or isochronal data, particularly in cases where high flow rates per unit of thickness are encountered.

Introduction
Since 1935 when E. L. Rawlins and M. A. Schellhardt of the U. S. Bureau of Mines published their Monograph 7, their methods have served as the primary guide to the gas industry in the conduct and interpretation of back pressure tests on gas wells. Over the years an increasing awareness of the need for carefully calibrated equipment and meticulous care in the conduct of the field test has developed. The extreme importance of conducting the test either under "stabilized" conditions or as an isochronal test has been clearly shown by Cullender and others. Improved theoretical understanding of the calculation of bottom-hole pressures from measured tophole pressures, together with reliable compressibility factor data has permitted modifications and improvements in the procedures of Monograph 7 for these calculations. The important role of the relative roughness of the flow string in determining the friction component in the calculation of the flowing bottom-hole pressures has been realized and methods superior to that of Monograph 7 [involving the Weymouth friction factor correlation] have been developed and are in increasingly common use. [Notwithstanding these better methods, however, lack of knowledge of the actual roughness of the pipe remains a serious practical problem.]
Peninsular Malaysia Gas Producing System : Upstream Security of Supply Study
Authors: Othman Hasliza , Christensen T. G. 
Published: December 2007

Abstract
An increase of gas utilization in Peninsular Malaysia causes an expansion of upstream gas producing facilities. As the number of the facilities increases, it becomes important to predict the reliability of the integrated system to ensure sufficient delivery of gas to meet the consumer needs while maintaining economical investments. Due to the complexity of the system, a joint study between PETRONAS, Esso Production Malaysia Inc. and PETRONAS Carigali Sdn. Bhd. was conducted to analyze the gas supply system reliability and determine the overall system capability to make-up for production losses due to failures of equipment within the system.
The study was conducted in two phases. Phase 1 of the study involved the assessment of the existing facilities and also the facilities that are in advanced stage of development to determine the system availability. Phase 2 utilized the same concept as Phase 1, but models were created for long term development options to better define future design and sparing philosophies.
This paper describes how the upstream gas system model was setup using a statistical simulation software specifically designed to model process systems. The general layout of the offshore gas platforms and the onshore receiving facilities and the basis used in setting up the model are discussed briefly. Examples of results obtained for the existing system and the applications of model to help assess future competing development options will also be discussed.
Technology-Driven Infill Oil Development Planning of a Mature Offshore Area, Brunei Darussalam
Authors: Fah Yap Kong , Carter R. R. , Walton W. , Hupje R. 
Published: December 2007

Abstract
Maturing remaining undeveloped oil reserves into robust profitable development projects while aiming to achieve significant reduction in the unit technical costs are the key challenges facing the further development of mature oil fields in Brunei. Rising costs and flat oil prices have made conventional development uneconomic or marginal at best. The success of future development efforts relies heavily upon improving the key development drivers including well reserves, production rates and development costs. These are often challenging tasks, especially in Brunei Offshore Fields, where reservoirs are located in areas of significant stratigraphic and structural complexity. Development opportunities are also constrained by limited conductor slots from fixed platform locations.
This paper describes the current initiatives in BSP to mature the remaining undeveloped oil reserves in the shallow reservoirs of the Champion Field, Offshore Brunei, into robust profitable projects through a focussed approach of improving the key development drivers. We describe the application of state-of-the-art technology in 3D reservoir modelling to provide better infill development locations and improved production forecast estimates, together with the use of more innovative development options. The aim is to maximise well reserves and production rates, and minimise development costs. This will significantly improve the economics of subsequent development projects which would otherwise be uneconomic if the historical norm of conventional development would continue.
Peninsular Gas Utilisation Project: Planning And Challenges to Meet Customers Demand From the Perspective of a National Oil Company
Authors: Seong Chen Kah , Abdullah Mohamad bin 
Published: December 2007

Abstract
This paper presents the challenges faced by PETRONAS in ensuring a secure and sustainable gas supply to meet the market demand for the PGU project. Key to the success are good knowledge and understanding of gas demand trends, integrated long term gas fields development planning, and early identification of future gas supply challenges.
Gas demand projections and current observed trends, trends of existing gas development projects and environments surrounding future gas development are discussed. Technologies and strategies that are expected to have a positive impact on future developments are also discussed.
The information provided in the Paper supports the following observations and conclusions; (1) realistic gas demand forecast is essential to ensure that supply capacity matches the demand; (2) integrated long term gas fields development planning requires consideration of gas market, available delivery capacity, technical readiness of the field, available pipeline and processing capacity ullage to tie-in other fields, ability to provide security of gas supply to meet demand fluctuations, requirement to provide infrastructure for possible tie-in of future gas fields; (3) the challenges of future gas supply are to develop smaller gas fields, gas fields located in remote location, gas fields having high CO2 content and enhancing reliability of supply.
Cementing Practices - 1972
Authors: Johnson Robert M. , Garvin Thomas R. 
Published: December 2007

Abstract
This paper presents a review of experience for successful cementing in oil and gas wells. Recommendations and considerations for use of various cements, flushes, control additives and placement techniques are given for best results in placement techniques are given for best results in zone isolation and support of pipe in wells. Recommendations for control of difficulties with gas migration, mud contamination, high temperature retrogression, small annular clearances, and displacement of drilling fluids are described.
The purpose of this paper is to describe the latest advancements in oil and gas well cementing.

Introduction
As drilling operations become deeper and more costly, the significance of zonal isolation in cemented wells cannot be overemphasized. High temperature strength retrogression of cements and inefficient displacement of contaminants from small annular clearances has become more critical for economical exploration. Use of specially formulate cements, special control additives, and well planned programs for cementing have largely alleviated the programs for cementing have largely alleviated the basic problem of cementing failures, i. e., channeling.
With basic cements, additives are used that control filtrate loss, control retardation of hardening, provide desired hydrostatic column weight, and assist placement of permanent bonding materials to help prevent fluid migration and communication. Other additives stabilize hardened cement strength and maintain low permeability in cement even under extreme conditions of temperature and pressure associated with deep drilling. The problems of cementing in complex geometries and narrow annuli have been combated by perfecting techniques of slurry placement through rheological design, use of effective washes and flushes, and improving the mechanical aspects by using pipe movement with centralizers and scratchers. The delayed set technique for cementing has also been introduced to overcome some of these complications.
This paper describes these cements, additives and techniques as they are currently being used for successful cementing.
GideGard - The New Molded-On Epoxy Bit Protector Promises Longer Bearing Life
Authors: Moore Roy N. 
Published: December 2007

Introduction
What is a Gide Gard? It is a new rock-bit protector that saves drilling money. The protector that saves drilling money. The development of this "molded on" epoxy rock-bit protector promises longer bearing life for the protector promises longer bearing life for the bit and offers maximum protection to the blow-out equipment, casing, liner and walls of the borehole.
Until the new rock-bit protector was developed, the bit had a poor chance of reaching the bottom of the hole without some impact damage to both the borehole and the bit bearing. A mute witness to this fact is the violent dance of the weight indicator hand as the unprotected bit is being pushed, gouged and bounced through the many formation seams. Although the new bit protector may soon become standard on all rock bits, the major breakthrough here is that progressive drilling people have recognized the fact that costly people have recognized the fact that costly hazards do exist in placing a rock bit on bottom.

HISTORY OF THE BIT CUTTER PROBLEM
For years, the driller demanded a rock-bit bearing that would withstand the unknown geology, higher drilling weights, faster rotary speeds, and the hostile environments of the hole. To meet this demand, the manufacturing engineers designed new rock bits with both seal bearings and friction bearings. Very little consideration was given to the bearings that may have been damaged while tripping the rock bit to bottom.
But the problem was real; the finest bit ever manufactured was being damaged going in the hole, and the most sophisticated instruments were unable to predict the minimum bearing life. A further study of many dull rock bits showed the bearings on one cutter to be worn two or more grading points more than the bearings on the other two cutters-and not always on the same cutter. To compensate for this, the drillers began to impose safety limits on the maximum depth and the maximum revolutions of a rock bit.
As more reliable bit data was accumulated, it became obvious that depth, condition of the hole, hardness of the formation seams, and the speed at which the bit was being lowered into the hole were the major causes of premature rock-bit failures. It also lent credence to an old rule of thumb, i.e., the revolutions of the bit on bottom are generally proportional to the "trip-in-hole" speed; or the more time used to go in the hole, the more drilling time on bottom; or a bit damaged going in the hole will turn fewer revolutions.
Four and One-Half Years - Discovery to Unitized Operation of the Major, Multi-Reservoir Bell Creek Field
Authors: Farnham Frank E. , Haddenhorst Fred A. 
Published: December 2007

Abstract
Unitization of the Bell Creek Field in Montana is believed to be unique in that a Working Interest owners Association was formed and dedicated to achieving that goal. Through this vehicle the seventy-eight participating owners were not only able to participating owners were not only able to expedite the unitization work, but collectively financed $444,100 of preunitization expenses. Bell Creek is also unique in that it is the first waterflood in the Rocky Mountain area to exclusively use turbine engines directly coupled to centrifugal pumps. Each of these units is rated at 1100 HP and will deliver 27,000 BPD at 1500 psi. Ultimate field injection will be approximately 120,000 BPD.

Introduction
Discovery of the Bell Creek field occurred in June, 1967. Unitization proceeding began with an operators meeting in January, 1968, but little progress was made until an association of all the working interest owners was formed in December, 1968. Under the auspices of this Association an Engineering and Geological Subcomittee began intensive studies which culminated in the delineation of some 26 individual productive sands and the formation of six secondary units. The first unit became effective April 1, 1970 and the last two units became effective January 1, 1972.
Initial oil-in-place for the entire field area is estimated to be 243 million STB. The ultimate primary recovery is estimated to be 48 million STB or 19.8%. Of the potential secondary recovery processes, potential secondary recovery processes, straight waterflooding yielded by far the best rate of return. The calculated additional recovery as a result of waterflooding is 44 million STB or an additional 18.1% of the initial oil-in-place.