bluuebunny/crossref_metadata_2025_split huggingface dataset:
Determination of Original Gas in Place in Ballycotton, Offshore Ireland
Authors: Chu Wei-Chun , Fleming C. H. , Carroll K. M. 
Published: December 2007

Abstract
This paper presents a new approach for determining OGIP early in the field life of an edge-water drive gas reservoir. The approach is applied to Ballycotton gas accumulation. Ballycotton was discovered in March 1989 adjacent to the nearby Kinsale Head Field, a major gas accumulation in the Celtic Sea, Ireland. Ballycotton and Kinsale Head have a common aquifer. Kinsale Head Field was put on production in 1978 using two platforms Alpha and Bravo. From July 1991, Ballycotton produced gas as a subsea-completed satellite of the Kinsale Head Field, tied back to the Bravo platform at Kinsale Head. A permanent gauge was installed on the subsea tree in 285 feet of water. Using continuous pressure and rate measurements, we routinely interpreted well data using superposition techniques. Within the first six months of production, an accurate estimate of original gas-in-place (OGIP) was established from the data. This is in contrast to the p/z versus Gp material balance approach, which is seldom accurate early in the life of the field.
This case history clearly illustrates the benefit of utilizing continuously measured pressure and rate data to obtain an accurate original gas-in-place early in a field's life. In addition, this paper demonstrates the benefit of permanently installed pressure gauges in subsea-completed satellite fields.
Application of Fracture Technology in the Hanoi Trough, Vietnam
Authors: Cipolla C. L. , Mayerhofer Michael , Wilson B. L. 
Published: December 2007

Abstract
This paper presents a detailed case history of the evolution of fracture technology in the Hanoi Trough, Vietnam. The target formations are stacked fluvial channel deposits that occur at depths of 10,000 to 12,000 ft with permeability ranging from to 1 mD. The first three wells drilled in 1996-97 were fracture stimulated, but only one of the three treatments was successful. Three more wells were drilled in 1999 and significant improvements in completion and hydraulic fracture technology were implemented. This paper presents a comprehensive data set, which includes the evaluation and integration of pre-& post-fracture well tests and log data with detailed fracture modeling analyses to understand and improve fracture performance in this complex environment.
Petroleum Sulfonate Utilization in Enhanced Oil Recovery Systems
Authors: Knaggs Edward A. , Nussbaum Marvin L. , Carlson James B. , Guenzani Robert C. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Petroleum sulfonates are currently being evaluated extensively in surfactant enhanced oil recovery processes in laboratory studies, pilot field trials, and in semicommercial field tests. Consideration of surfactant manufacturing, product availability projections, product properties and laboratory oil recovery tests among available types of petroleum sulfonates establish that those produced directly and economically from abundantly available petroleum refinery feedstocks can be petroleum refinery feedstocks can be produced in volume to meet oil industry produced in volume to meet oil industry requirements. The diversity of crude oils ana reservoir constraints make it desirable to tailor surfactant systems to optimize oil recovery.

Introduction
Most of the many hundreds of currently existing U.S. patents directed to surfactant enhanced oil recovery processes disclose the use of petroleum sulfonates singularly or in various surfactant combinations. In spite of this plethora of petroleum sulfonate use claims, the technical literature is almost devoid of comparative information relative to the various types of available petroleum sulfonate products — those derived as low yield sulfonation "by-products" and those by direct higher yield petroleum sulfonation in which the sulfonate is the primary product — and to processes for their manufacture. Accordingly, this paper, addresses itself to filling this need, with greatest emphasis being placed on the comparison between placed on the comparison between conventional petroleum mahogany sulfonates and the newer petroleum sulfonates produced by direct petroleum sulfonation recently developed by the present authors and their associates.
It is apparent that for the most part the oil industry's main technical thrust has been primarily directed towards developing the complex oil recovery process technology, whereas surfactant product and process development has been a secondary process development has been a secondary consideration, with some notable exceptions to be sure. While it has recently been reported (1) that crude oil sulfonate is now being produced by SO sulfonation, the resultant low yield sulfonate is directly converted to a dilute surfactant "slug" system and is thus beyond the scope of this study.
Effect of Chemical Treatment Upon Formation Clays is Revealed by Improved SEM Technique
Authors: Thomas R.L. , Crowe C.W. , Simpson B.E. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
A number of commonly used stimulation and clay stabilization treatments have been investigated using an improved and more definite Scanning Electron Microscope technique. This technique involves photographing individual groups of clay platelets within a sandstone specimen at high magnification using the Scanning Electron Microscope and then chemically treating the sample. Following the treatment, the same set of platelets is located and again photographed under identical conditions of framing and magnification. By comparing the two SEM photographs, in addition to Energy Dispersive X-ray analysis of the platelets before and after treatment, it is platelets before and after treatment, it is possible to detect even minute changes in the possible to detect even minute changes in the structure and chemical composition of the clay minerals. The SEM technique used in these studies is described in detail.
Systems studied include clay stabilizing agents such as hydroxy aluminum and zirconium oxychloride. The effect of various acids including hydrochloric acid, Mud Acid and Self-Generating Mud Acid have also been investigated. These studies clearly show how chemical treatments modify the clays present within the rock. Test results indicate that clay stabilizing agents work by either ion exchange or topochemical reactions. Hydrolyzable metal ions such as zirconium and hydroxy aluminum may not form the same kind of layer on the surface of the clay, but both materials effectively desensitize the clays. Core test data correlates well with SEM.

Introduction
Swelling and migration of clay minerals in sandstone formations has long been a problem in oil and gas production. Dispersed problem in oil and gas production. Dispersed or swollen clays can plug-the narrow pore openings within the formation, thus restricting both liquid and gas flow. It is believed that dispersion and migration of formation clays isoactually a greater problem than clay swelling. The dispersion of a small amount of non-swelling but migratory clay can cause a much greater reduction in permeability than an identical quantity of a swelling clay. Kaolinite and illite are two of the most commonly occurring non-swelling migratory clays, while montmorillonite is the most common swelling clay.
Various treatments have been developed to prevent or minimize swelling and migration prevent or minimize swelling and migration tendencies of formation clays.
Analysis of Pressure Transient Data in Naturally Fractured Reservoirs With Spherical Flow
Authors: Ershaghi Iraj , Rhee Shie-Woo , Yang Hsun-Tiao 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc,

Abstract
Methods for analysis of pressure transient performance in homogeneous reservoirs with performance in homogeneous reservoirs with spherical flow have been presented by others in the past. This work extends the art to the case of naturally fractured reservoirs with uniform fracture distribution. A reservoir model similar to the double-porosity system described by Warren and Root is employed. The fundamental differential equation and the solution of the equation by the application of the Laplace Transformation serves as the theoretical foundation.
A method is then presented for estimation of an average spherical permeability and static reservoir pressure. Also the procedure for estimation of total fluid capacitance (2C2+ 1C1) and the fraction of which being contributed by the fracture network () is discussed.

Introduction
If in a naturally fractured reservoir only a small interval of the upper portion of the zone is open to production, the flow regime has a vertical component and cannot be considered cylindrical. The existence of the vertical flow component gives rise to the establishment of a hemispherical flow system, Fig. 1.
The problem of spherical flow in homogeneous porous media has received a fair treatment by porous media has received a fair treatment by others. Muskat derived the general equation for potential distribution in a spherical flow system. He showed that for a steady state system under spherical flow the pressure gradients are much more concentrated about the wellbore than in the case of radial flow. He further noted that for such systems the flux is independent of the shape and the size of the drainage boundary as long as the external boundary radius is large compared to the wellbore radius. Moran and Finklea were the first to present the pressure buildup equations for analysis of pressure data obtained form wireline formation testers. They showed that for thin beds the early stages of pressure buildup tend toward spherical flow. The later stages, however, approach cylindrical flow.
Chatas considered several flow problems of importance to reservoir engineering where spherical geometry serves as a better approximation than the cylindrical.
The Development and Application of a Novel Scale Inhibitor for Deployment in Low Water Cut, Water Sensitive or Low Pressure Reservoirs
Authors: Collins I. R. , Jordan M. M. , Taylor S. E. 
Published: December 2007

AbstractWater-in-oil emulsions have been developed which have been shown to be a credible means of deploying scale inhibitors in a non-aqueous medium. Furthermore, the use of slowly degrading emulsion systems provides a means of trapping scale inhibitor within porous media and allowing subsequent controlled release of the chemical. This has been demonstrated using sandpack and coreflood experiments where the lifetime of the inhibitor, as measured by pore volumes of brine eluted to a given inhibitor concentration, has been extended by up to (and possibly beyond) four times compared with the base case non-emulsified product. No permeability damage has been observed for the emulsion systems. The use of emulsion droplets to provide chemical reservoirs within the formation also considerably reduces the wastage of non-retained chemical observed with conventional squeeze treatments. The non-aqueous nature of the emulsion system potentially allows ingress of the scale inhibitor into parts of the reservoir normally denied access to an aqueous-based formulation and so can improve contact between the scale inhibitor and the reservoir fluids on production. Furthermore, the whole treatment can be non-aqueous allowing oil continuity to be maintained during the treatment affording rapid well clean up post treatment.
Simplified Performance Prediction Method for Vertically Fractured Gas Wells
Authors: Strubhar Malcolm K. , Fitch John L. , Uhri Duane C. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
A procedure is outlined for calculating the performance of a vertically fractured gas well contained within a square drainage area. Constant production rate and the constant well pressure cases are included. Because it is not pressure cases are included. Because it is not a numerical simulator, calculations can be performed practically on small computers. performed practically on small computers. Predicted comparisons with published reservoir Predicted comparisons with published reservoir simulator results and with actual production data from two massive hydraulically fractured wells were made. Agreement in both comparisons was very good.

Introduction
In recent years the concept of massive hydraulic fracturing (MHF) has been developed with particular interest in its application to gas recovery from very low permeability reservoirs. While several factors determine the profitability of applying this technology, one of the most important is the gas recovery rate. Adequate predictions of productivity behavior are imperative for proper economic evaluation. As has been illustrated by Morse and Von Gonten, transient flow effects exist for long periods of time (many years) in these low-permeability reservoirs. Therefore, productivity behavior during this transient productivity behavior during this transient period must be properly assessed in order to period must be properly assessed in order to perform meaningful evaluations. perform meaningful evaluations. Our own interests in MHF technology began several years ago as an integral part of studies considering multiple vertical fractures. At that time, there were no productivity prediction techniques available productivity prediction techniques available that would cover the spectrum of conditions of interest. The work of McGuire and Sikora adequately predicts, for the semisteady-state period, productivity improvements resulting period, productivity improvements resulting from vertical fractures in a bounded reservoir. Prats et al. expressed vertical fracture Prats et al. expressed vertical fracture performance in terms of an effective well performance in terms of an effective well radius. This concept predicts that, for infinitely conductive fractures of up to 50-percent penetration to a circular drainage boundary, there is a hypothetical well radius that would result in the same well performance as the fracture. This effective well radius is approximately equal to one-half the fracture penetration. This idea was shown to apply at penetration. This idea was shown to apply at all times except the very early transient period. The method reported here was developed period. The method reported here was developed to apply to fractures of any penetration with the ability to predict production rate for any time.
Developments in PhosphonoMethylated PolyAmine (PMPA) Scale Inhibitor Chemistry for Severe BaSO4 Scaling Conditions
Authors: Singleton M. A. , Collins J. A. , Poynton N. , Formston H. J. 
Published: December 2007

Abstract
This paper describes the development of a PMPA scale inhibitor chemistry, for potential ‘squeeze’ application, to provide scale inhibition under severe Barium Sulphate scaling conditions. Phosphonate type inhibitor chemistries have been applied in ‘squeeze’ treatments as they have the desired adsorption characteristics to protect the near wellbore formation, perforations and production strings for a significant period of time (known as the ‘Squeeze’ Life). These chemistry types, however, are not the most efficient means of preventing scale deposition in some severe, low pH BaSO4 scaling situations. Polymeric inhibitor species, in particular PolyVinylSulphonates (PVS) and sulphonated co-polymers (VS-Co), are sometimes more suited to these types of conditions, but they do not typically posses the necessary retention characteristics to achieve the desired ‘squeeze’ lifetimes. This paper discusses the development of a new experimental PMPA chemistry which has demonstrated improved inhibition performance under harsh BaSO4 conditions, whilst retaining the adsorption and retention characteristics of earlier PMPA chemistries and could potentially result in considerably longer ‘squeeze’ lifetimes than those currently achieved with the polymeric inhibitors.
Squeezing Aqueous Based Scale Inhibitors into a Water Sensitive Reservoir - Development of a Squeeze Strategy
Authors: Poynton N. , Tidswell R. , Steele J. , Wood Jonathan , Early R. 
Published: December 2007

Abstract
The squeezing of scale inhibitors into the near well bore region of oil producing wells is a recognised solution to downhole scale prevention. In many cases, this downhole application leads to an initial decrease in the well productivity, which can recover to the pre squeeze level with time. However, in some reservoirs this recovery does not happen, and the well suffers a permanent loss in productivity after the squeeze.
Following such a loss in well productivity caused by an initial squeeze treatment, this paper details the development of a successful squeeze treatment for a water sensitive reservoir in the North Sea using an aqueous based sulphonated co-polymer scale inhibitor.
The paper summarises the additional core plug testing undertaken to evaluate the damage mechanism, the modifications made to the treatment design to minimise the damaging effects and culminates with the successful results from the application of the modified squeeze treatment. These results show that well stimulation and extended squeeze lifetime were achieved compared to the initial squeeze and to other previous applications of this inhibitor in similar water sensitive reservoirs.
Eliminating the Need for Scale Inhibition Treatments for Elf Exploration Angola's Girassol Field
Authors: Vu Van Khoi , Hurtevent Christian , Davis Roy A. 
Published: December 2007

Abstract
In the development of Elf Exploration Angola’s Girassol field located approximately 200 km west of the coast of Angola in 1,500 m of water depth, 390,000 barrel per day of seawater will be needed for a waterflood operation. Formation water analysis indicate both barium and strontium levels of approximately 230 mg/l. By the injection of normal seawater containing 2,800 mg/l sulphate, scale tendency calculations indicate the possible formation of more than 320g barium sulphate per m3 of coproduced water. Conventional scale inhibitor squeeze treatments were not considered to be a reliable and cost effective scale control technique due to: 1) Girassol’s "daisy chain" concept with network of wells producing in the same gathering line and subsequent difficulties in monitoring residual inhibitor levels, 2) difficulties in the placement of inhibitors in the reservoir which has high permeability and long perforation intervals, and 3) the deep and remote subsea wells. The high risks using scale inhibition for such a large scale waterflood project in a deepwater environment were considered unacceptable. After the extensive screening of all possible technical alternatives, Elf chose to remove the sulphate from the seawater using a selective nanofiltration membrane process previously used in the North Sea1,2. However, unlike the North Sea operations where scale inhibitors were originally used in combination with low sulphate seawater, Elf chose a specifically designed sulphate removal process with stringent high performance requirements that allows for the initial injection of seawater with approximately 20 mg/l sulphate for the leading edge of the waterflood. This will be followed by low sulphate seawater with approximately 40 mg/l sulphate. Based on 1) the initial low sulphate level in the injection water, 2) the projected scaling kinetics, and 3) the partial precipitation of barium and sulphate in the reservoir before the seawater approaches the production bore, the calculated scale potential is essentially eliminated.
An Improved Method for Analyzing Complex Declines of Wells Completed in Compartmentalized Meander-Belt Systems
Authors: Branagan P. T. , Brown T. D. , Prouty J. L. 
Published: December 2007

Abstract
Effective production-decline analysis is crucial to the successful management of declining oil and gas wells. From analysis of declines caused by reservoir conditions, engineers can generate valuable information such as reserve estimates (useful for property value appraisal) and production forecasts (useful for generating cash-flow forecasts). In short, a production-decline analysis is at the heart of many economic decisions about the future of a well or property.
Because decline analysis is so important, engineers are faced with a significant problem when the conventional methods of analysis break down. For example, wells completed in fluvial, meander-belt systems such as those found in the Piceance basin, Colorado often do not follow the conventional production decline patterns established with exponential and hyperbolic equations. Rather, the decline reflects the complex interaction arising from compartmentalized, point-bar reservoirs that are commingled at the wellbore. This paper presents an improved method of analyzing these complex declines using a numerical simulator.
Central to this method is the definition of six different reservoir types, each of which can be subjected to different boundary conditions and hydraulic fracture options (i.e., with or without fracture, different fracture orientations, different fracture lengths, etc.). While there are other configurations available in nature, these reservoir types form a sufficient representation for modeling purposes of the compartmentalized reservoirs likely to be encountered and produced.
The modeling itself is done in two steps. The first step is to model the individual responses of the reservoir types and superpose the responses in various combinations until a rough match of actual production history is achieved. This best-match combination is then used as a starting point for the second step: modeling the complete system allowing commingling at the wellbore. Further model runs are made until an acceptable match is found. This match is the basis for predicting future performance.
Producing Characteristics and Drainage Volume of Dakota Reservoirs, San Juan Basin, New Mexico
Authors: Sunde Arild , Chen Her-Yuan , Teufel Lawrence W. 
Published: December 2007

Abstract
Approximately 500 wells from the low-permeability, tight-gas Dakota formation in San Juan Basin, New Mexico, were analyzed to characterize the producing/flow characteristics, to delineate the drainage volume/area, and to infer the infill potential. Production data is from both commercial and public database. Decline-curve analysis is the primary method. Results indicate that Dakota wells started producing after seventies generally have very steep decline during transient flow period. This is due to the negative-skin effect resulted from well stimulation. During boundary-affected flow period, the production decline tends to be exponential-decline-like (low decline exponent). Estimated gas permeability is in the order of 0.01 md. Drainage pore-volumes of the wells started producing during early eighties are slightly smaller but more uniformly distributed than the wells started producing during sixties and seventies. Drainage areas, however, appear to be less dependent on the date of production than the pore-volumes. Productivity index is highly variable over both basin and time, suggesting a highly heterogeneous flow/permeability field in the Dakota reservoirs.