bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advances in Heavy Oil and Water Property Measurements Using Low Field Nuclear Magnetic Resonance
Authors: Bryan J. L. , Manalo F. P. , Wen Y. , Kantzas A. 
Published: December 2007

Abstract
Low field NMR of fluids can be used to measure physical properties of water and oil such as viscosity and diffusion coefficients. Remarkably accurate measurements can be obtained from simple and fast measurements in a beaker. Algorithms for the determination of heavy oil and bitumen viscosity have been previously developed that can provide first order estimates over a variety of viscosity ranges (100-107 mPas) covering variable temperatures, water/oil ratios and oil compositions. When the algorithms are tuned for single oils, then the accuracy increases dramatically and the predictions are as accurate as direct viscosity measurements.
In this paper, the aforementioned algorithms are extended to predict NMR response and viscosity predictions for live vs. dead heavy oil samples, and virgin vs. solvent-diluted heavy oil samples. The viscosity predictions of oils in beakers are compared to the predictions of the same oils while in reservoir conditions (i.e. in-situ). The proposed algorithms can be used in reservoir characterization and on-line viscosity measurements in heavy oil reservoirs.
A NMR based water cut meter was recently introduced for accurate measurement of oil and water cut values. The instrument appears to be superior to conventional measurement devices since it does not seem to be affected by salinity, emulsion characteristics or temperature to date. Extensive field measurements have proved the above claims. The principles of this water cut device are further extended to the measurement of water cut oil cut and gas cut under laboratory conditions. Mixtures of heavy oil and bitumen with water and air were prepared in the laboratory and their NMR characteristics were identified under a broad range of saturations. The results were compared against mass balance measurements. It is demonstrated that the two-phase measurement algorithms can be extended to three phase systems. Thus the first step towards accurate multi-phase measurements can be achieved.
Fully Coupled Chemico-Geomechanics Model and Applications to Wellbore Stability in Shale Formation in an Underbalanced Field Conditions
Authors: Wang Yarlong , Lu Baoping 
Published: December 2007

Abstract
Time-dependent wellbore stability has been observed in the field. Yet, a combined effect of pore fluid advection, swelling shale, and thermal diffusion may not be sufficient to explain and simulate this process adaquately. A coupled chemico- geomechanics constitutive model combined with a model with an ion-concentration dependent strength is developed in this paper. Strength reduction due to water hydration seems to dominate the time-dependent process in wellbore collapse. The ultimate borehole instability is proposed to be determined by the damage radius not the onset of wellbore wall mechanics failure, the latter is usually practiced. A field case is analyzed, and from experimental testing and simulations, it is concluded that the time-dependent nature is dominated both by the time- dependent strength reduction and damage zone propagation.
Cerro Negro Development: A Success Story...From Inception To Execution
Authors: Vasquez Milton 
Published: December 2007

Abstract
The Cerro Negro project, located in the Orinoco oil belt of Eastern Venezuela, first began in 1997 with the drilling of an appraisal program and the longest horizontal section ever drilled in Venezuela. This startup led to a 1½ year drilling campaign that resulted in 121 drilled and completed wells, and up to 129,000 BOPD (UCO) flowing down the pipeline. New technologies in drilling, completion, and artificial lift were applied to extended reach horizontal wells to efficiently develop the Cerro Negro field. Applications of these technologies include: 1) development of two fit- for-purpose rigs capable of skidding between well slots and spudding a new well in 1½ hrs; 2) implementation of a stratigraphic well program to define difficult geologic targets utilizing a coil tubing drilling unit; 3) development plans for 2-D and 3-D wells drilled as stacked forks into three distinct reservoir sands; 4) application of the latest geosteering technology; and 5) development of high capacity progressing cavity pumps for artificial lift. The concept of a learning curve approach was also implemented by setting target and stretch performance goals for the project. Key success factors for the program include a strong communication system between the operator and all suppliers, continuity of services and manpower supporting engineering and operations including dedicated equipment and an inhouse directional drilling representation, continuous improvement of operations, and application of dynamic benchmarking concepts. This program has achieved a 30% reduction in drilling and completion (D&C) costs and a 38% reduction in D&C time.
Floating Production Systems
Authors: Hamilton Jack Rayburn , Barrack James White 
Published: December 2007

Abstract
This paper considers some of the major problem areas which are being encountered in offshore oil and gas developments. The case is then presented for the consideration of floating production systems as an alternative to fixed platform solutions.
Floating production has been in operation for some years. The concept has been demonstrated as being both practical and economically attractive. The principal basis for development has been the use of converted offshore drilling vessels. Such proven technology is now being supplemented by a number of proposed designs based on specific application and wider ranging production capability. A review is given of the available structures.
The principal component parts of floating production systems in general are considered. Principal requirements, limitations and areas which require development are given with a view to the achievement of improved design and performance.
In conclusion the advantages of floating production systems are summarized and recognition is given to the potential which they present for marginal field development, early production and deep water applications.

Introduction
In the face of the continually recurring challenges of deeper (Fig. 1) (Ref. 1), rougher water and rapidly rising costs, the offshore oil and gas industry is moving towards a new generation of production systems. These are the floating production systems (FPS) where rigid support from the seabed has been replaced by a flexible mooring system which creates less sensitivity to water depth, economic attractions and a new marriage of offshore technologies aimed at solving some current offshore problem areas.
With the original single-purpose piled steel platforms as the first generation of offshore structures, the later multi-purpose steel or concrete platforms as the second generation, so floating production platforms may be viewed as the third generation of this family tree.
Such a shift in the development emphasis from fixed to floating platforms is a fundamental variation in the philosophy of offshore field development. Competition and reaction against high costs have initiated a need for change and what had become conventional fixed structure offshore technology is likely to be joined by floating systems, subsea systems and hybrid combinations of these. Fixed structures gained their foothold in shallower waters. They are likely to retain their application in such areas but in the move into the recovery of deeper water reserves, floating production systems have large potential advantages.
The FPS concept can be defined as a buoyant platform structure moored over seabed wellheads with the two connected by a flexible production riser. The platform may be either a conversion of a floating structure built for some other purpose or one which has been designed and built to specification. Currently the former (semi-submersibles or tankers) have been established due to availability, established performance and low relative cost while the latter exist on many drawing boards awaiting acceptance by the industry.
Some Engineering Aspects Of Offshore Loading Systems
Authors: Olbjorn Egil Hans , Torset Odd 
Published: December 2007

Abstract
The presented paper covers essential aspects and requirements for offshore loading systems.
Response characteristics of typical concepts and associated design forces for the mooring and anchoring systems will be discussed. The need for model tests compared to anchoring and mooring systems in respect to strength and durability.
The governing factors for the lifting efficiency including operational limitations with respect to weather conditions are considered.
The paper concludes with some considerations from the certification point of view.

Introduction
Offshore loading systems for the initial temporary or permanent solution to the transportation of production to the shore is receiving increasing attention from operators in the North Sea.
Offshore loading of oil as such is well known to the Industry, however, sufficient experience from hostile environments like the North Sea hardly exists.
The few systems operating in the North Sea must be regarded as prototype and the next generation of offshore loading units now being developed will be able to incorporate a number of the valuable lessons learned. Reliability and efficiency are key words in selection of the most suitable system and this paper will focus on a number of engineering aspects of importance in this context.
Figures and tables are purposely made in a schematic and general format to indicate the tendency rather than actual measured or calculated values.
Articulated buoyant towers without storage capacity and large volume floating anchored storage vessels will be the main types of offshore loading systems discussed in this paper as there appears to be a tendency in the industry towards these types of concepts.
A number of refined concepts utilizing one shuttle and one storage tanker whereby the latter is remotely connected to the buoy in different ways, articulated towers with two universal joints, one semisubmersible, etc., are proposed or even in use, but will not be subject to detailed comments here, as this is regarded as being outside the scope of this paper.

Concepts
The general concept which has proven successful for offshore loading is the single point mooring (SPM) idea. The tanker is moored with bowlines to a single point only, allowing the vessel to rotate freely (weathervane) around the buoy.
The different developments may be divided into two main groups on the basis of the type of fixation used; CALM and SALM (see fig. 1).
The catenary anchor leg mooring buoys (CALM) are the most commonly used offshore loading system. The simplest and most widely used being the single buoy mooring buoy (SBM).
Underwater Non-Destructive Testing
Authors: Lafferty Cyril F. , Watt Ian 
Published: December 2007

Underwater Non-Destructive Testing is a highly complex and emotive subject about which many thousands of words have been written by eminent and extremely knowledgable people. Apart from touching on a few of the fundamentals as a way of introduction, it is not the intention of this paper to enter into the continuing discussion on the philosophy and reasoning behind, or implications of, NDT on underwater structures per se. Rather, its purpose is to relate how one particular company, Vickers Oceanics Limited, set about tailoring an NDT system around a diver lockout submersible in order to utilize certain advantages that this vehicle has over other alternatives at present in use in the North Sea.
In short, the article will not be presented from the platform of an NDT inspector, it will represent the viewpoint of an engineer, whose task was to produce a system to meet a market requirement, based on his experience with the underwater environment and his knowledge of the problems, both mental and physical, of the working diver.

Introduction
In the very early life of a platform there is the need to carry out overall regular inspections. This is to allow the owner to obtain sufficient information and data to build up the story of any progressive deterioration of his structure. The most generally accepted level of inspection at this stage, would simply be detailed video and high resolution photography, combined with measurements of cathodic protection levels and material thickness.
As experience and records show the necessity, the level of information obtained may have to be altered. With age the structure may have to be examined in more detail to discover stress or damage areas not immediately apparent in visual or video inspection, therefore more sophisticated NDT procedures would have to be applied.
At present the most efficient, and very often only, method of applying the more sophisticated NDT sensors to an underwater structure, is manually by a diver. The alternative being unmanned or conventional manned submersibles including JIM type suits, where access and/or manipulative dexterity may prove to be insoluble problems.
Fiscal Reliefs For The Exploration Of Marginal Oil Fields In The North Sea
Authors: Kemp Alexander George , Crichton David 
Published: December 2007

Abstract
The impact of the oil taxation packages introduced by tile U.K. and Norwegian Governments in 1975 on the exploitation of marginal fields is examined in this paper. The effect on the viability of operations depends on several factors such as the timing of the development of a field, future oil price and exploitation costs, and in the case of the U.K. whether the new field forms part of a multi-field development. Various fiscal incentives for encouraging development are examined. All of them are considered in the context of the existing fiscal framework and involve no radical alterations to the tax structures.
INTRODUCTION.
In both the U.K. and Norwegian sectors of the North Sea there is currently in existence a number of oil and gas fields which are regarded as marginal by the operators. Development decisions have still to be finalised in several cases. A marginal field cannot be defined by an academic observer or indeed by a civil servant drawing up tax schedules. It can be defined only by the exploiting company as it reflects the minimum return acceptable to the operator. It is also quite likely that different operators will demand different minimum rates of return which further complicates the definition. The situation is further complicated by the fact that oil exploitation takes place under conditions of uncertainty and the returns are really only expected ones when the key decisions are made.
Despite these problems Governments have set themselves the task of taxing oil exploitation with a view to taking for the state a share of the expected profits. There must therefore be a danger that actual tax packages will produce adverse consequences. So far as marginal fields are concerned there are two main general possible effects. The first is that the tax burden is so high that it leaves the expected post-tax return below the minimum acceptable by the operator and the field is not developed at all. The second is that later in the life of a field the tax burden is such that the field is prematurely abandoned. (This effect could of course be present in non-marginal fields as well). A tax system might produce other allocative effects. Thus, depending on the type of taxes the rate of depletion of a reservoir could be accelerated or decreased. The capital intensity of the technique of exploitation could be altered by the tax provisions and this could in turn change the rate of extraction.
Stabilized Foamed Acid, A New Stimulation Technique For Carbonate Gas Reservoirs
Authors: Briscoe Harold R. 
Published: December 2007

Abstract
Fracture acidizing of deeper Delaware Basin gas producing carbonate rocks, employs a number of techniques and acid formulations. A recently developed technique makes use of a stabilized foamed acid to achieve increased stimulation along with fast clean up. The quick recovery of treating fluids results in early stabilized flow permitting accurate testing and early gas sales.
Deeper gas zones with abnormally low bottom-hole pressures present a special problem when acid fracturing. New replacement wells and new wells drilled in older producing reservoirs, such as those in the deep Gomez Ellenberger Field, encounter partially depleted pressure conditions. Conventional fracture acidizing requires extensive, costly jetting with nitrogen and coil tubing to remove treating fluids and 'kick off' the well. Foamed acid stimulation treatments have not required jetting to initiate gas production.
Once acid in a stable foamed conditions gets into the created fracture it provides reduced leak off and reduced acid reaction rate with the soluble carbonate formation. This allows greater fracture penetration along with increased fracture conductivity throughout the fracture length. Adequate injection rates are possible, even with the reduced hydrostatic pressure of the foam column because of the low friction properties and reduced frac gradients in these reservoirs.
A number of foamed acid stimulation treatments in carbonate formations are detailed along with tabulation of production increases.

Introduction
The stimulation of deep carbonate reservoirs is greatly affected by acid spending times and fluid leakoff rates. To achieve adequate stimulation, a deep penetrating fracture with high conductivity must be created. Abnormally low bottom-hole pressure conditions, relative to depth, present a special problem for the return of stimulation fluids.
Foamed acid provides a new approach to reducing acid reaction rates with highly soluble carbonate rocks, along with achieving control of acid leakoff into existing hairline fractures. A great deal of energy, in the form of nitrogen gas, is induced into the reservoir to aid in the return of fluids to the well bore. A foamed flush fluid will greatly reduce the hydrostatic pressure of the fluid column in the tubing. Wells under these conditions will 'kick off' and flow, where otherwise they would not.

Fracture Aciding with Foamed Acid
The deeper gas zones with abnormally low bottom-hole pressures present a special problem when fracture acidizing. Fracture acidizing with conventional fluids requires jetting with coil tubing and nitrogen to remove treating fluids and 'kick off' the well. This involves a great deal of time and money. The evaluation of the well is delayed due to long cleanup time. Gas sales and subsequent revenues are delayed. If the rig is still on the well, costs are increased even more.
Considerations Relative To The Selection Of Sub-Surface Safety Valves A Guide To The Options
Authors: Dines C.A. , Calhoun M.B. 
Published: December 2007

Abstract
This paper attempts to outline the principal criteria relevant to the selection of a surface controlled subsurface valve for a known application. Since the sub-surface safety valve is arguably the most important element of any completion, careful consideration should be given to its selection: this is especially true of an offshore installation since the safety the effective performance of this valve. The considerations and parameters discussed in this paper cover valve type and design options whilst keeping paper cover valve type and design options whilst keeping in mind constraints imposed by well conditions, production requirements and safety philosophies.

Introduction
The primary function of the downhole safety valve in a well is to contain that well in a safe condition in the event of a catastrophe, any other attributes must be considered as secondary. This philosophy must be rigorously applied not only to the selection of the valve itself, but also to ancillary items such as locking mandrels, landing nipples, service tools, control lines etc. Virtually all of the offshore operators and regulatory bodies around the world today specify the use of hydraulically actuated, surface-controlled sub-surface safety valves (SSSV) which in most cases interface with the platforms emergency shutdown system-the scope of this paper will therefore be confined to such surface controlled valves and furthermore is limited to discussion of valves which are currently in common use.
Use Of Clear Brine Completion Fluids As Drill-In Fluids
Authors: Conners James H. 
Published: December 2007

Abstract
Clear brine completion fluids have been used successfully as "drill-in" fluids in recently drilled California wells. Brine fluid or saltwater drilling is not an uncommon practice, however, brine water is primarily used, when practice, however, brine water is primarily used, when actual drilling muds are not required, because of its economic advantage over muds.
Distinct differences exist between saltwater drilling and the brine fluids implemented in California. These wells used calcium chloride/calcium bromide clear brines with densities in the 1.62 to 1.63 kg/dm 3 (13.5 to 13.6 lb/gal) range. The object of using the brine fluid was to enhance production rates by minimizing formation or "skin" damage, production rates by minimizing formation or "skin" damage, which in turn greatly offset the initially higher cost (in comparison to conventional drilling muds). The brine is called in drill-in fluid in these cases because conventional muds were used to drill the wells prior to reaching the production zones.
Casing was set, muds were displaced by the calcium chloride/calcium bromide brine, and the production zones were drilled. The production zone, the Stephens formation, is an extremely low-permeability, 9.9 × 10(-6) to 4.9 × 10(-4) m2 (.1 to .5 millidarcy), arkosic sandstone. The brine fluid was selected because formation plugging in previous wells had been attributed to conventional mud systems, resulting in less than anticipated production rates.
The application of these brines necessitates careful consideration of formation type, expected formation pressure, and bottom-hole temperature. Drilling with pressure, and bottom-hole temperature. Drilling with the brines requires modifications of drilling practices such as fluid system hydraulics, surface circulating system design, and drilled solids removal equipment. Preliminary data from in-progress product evaluation Preliminary data from in-progress product evaluation of these wells appear favorable.

Introduction
The Cal Canal Field is located approximately 35 miles west of Bakersfield, CA. It was discovered in September 1977 by Oxy Petroleum, Inc., in partnership with Chevron U.S.A., Inc., with the drilling of well Cal Canal No. 1. The well was drilled to a total depth of 3604 m (11,325 ft) and was completed flowing initially 5.4 × 10(4) m3 (1.9 MMcf) of gas per day plus 79 m3 (500 bbl) of condensate per day from Stevens Sands, silt points, and shales at approximately 3505 m (11,500 ft). Successive wells were drilled on a 16-ha (40-acre) spacing: 15 more by Oxy and 4 by Getty Oil Co., bringing the total to 20 wells (including one dry hole). Normal drilling and completion time was 70 to 80 days at a cost of approximately $1.8 million.
The Stevens' most productive section was about 213 m (700 ft) thick and was made up of sands, very dirty sands, siltstones and shales. Net pay at Cal Canal was extremely difficult to determine from well logs.