bluuebunny/crossref_metadata_2025_split huggingface dataset:
Characterization of the Austin Chalk Producing Trend
Authors: Chen H. Y. , Poston S. W. , Wu C. H. 
Published: December 2007

ABSTRACT
Fracture patterns and reservoir dual-characteristics are presented for a portion of the fractured Austin Chalk producing trend. The production histories of 1,235 wells from Giddings Field covering portions of Lee, Burleson, Washington, and Fayette counties were analyzed by decline curve analysis. Production of the average Austin Chalk well is usually characterized by an early rapid decline and a later slow decline. The average initial effective decline rate is about 90% per year, and lasts about six months to one year. For the later, less dramatic decline, the average is about 35% per year.
Statistical results of well performance indicate no difficulty in finding oil in the Austin Chalk producing trend. However, areas of high fracture density must be encountered for a well to be profitable. A contour map of the iso-reserves was prepared for a better understanding of the fracture system and reservoir characteristics. Besides the general northeast-southwest production trend, the map shows anomalies in the fracture system and reservoir characteristics. A simple, rapid technique to estimate reservoir parameters directly from the double-decline behavior of log (rate) versus time curves is given. Values of flow capacity, storage capacity, dimensionless fracture storage parameter (ω), and dimensionless interporosity flow parameter (λ) can be estimated by this technique.
Evolution of a System Approach to the Design and Organization of Oilfield Producing Facilities
Authors: Kretzschmar K.H. , Smith M.A. 
Published: December 2007

Abstract
The usual approach to the design and organization of producing facilities results in inefficient utilization of equipment and manpower. A more effective approach is suggested, in which all facilities related to the producing, gathering, processing and transportation of reservoir fluids are regarded as constituting a single, integrated system. System design concepts are outlined, and three case histories are presented to show how these concepts have been successfully applied to large scale operations.
It is concluded that a further extension of the system approach to its ultimate objective must inevitably lead to a functional reorganization of the various corporate identities engaged in finding, producing and exploiting sources of oil and gas, with benefits to all concerned.

Introduction
The development of oilfield producing facilities in a given field normally parallels very closely the course of development drilling in that field. The location of production centers or batteries, at which testing, treating, storage and custody transfer take place, is usually determined on the basis of geographical apposition with a conveniently sized group of wells and the pipe line gathering facilities. As development drilling proceeds, duplicate production centers are added in the same manner.
This approach encourages redundancies in facilities and equipment. These redundancies result in overall development costs which are excessive in relation to production volumes. Utilization of labour is inefficient and operating costs are higher than necessary in relation to the functions performed. Flexibility to meet changing conditions is poor, and a significant improvement in operating efficiency can only be achieved through a comprehensive reorganization of the existing facilities.
It is the purpose of this paper to demonstrate how an integrated system approach to the design of producing facilities can forestall involvement in these problems, or help to solve them effectively where they already exist.
Gel Surface Filtration from Polymer Solutions During Gravel Packing
Authors: Torrest R. S. , Marcano F. 
Published: December 2007

ABSTRACT
Gel filtration from hydroxyethyl cellulose polymer solutions at the inlet face of formation sand can rapidly build a low permeability layer that dominates system behavior. Laboratory experiments with dilute solutions show the nature of this build-up as well as behavior with subsequent water flow. Pressure response and fluid placement during gravel packing and pack quality may be strongly affected.
Compositional Simulation of the Block 31 Field and Surface Facilities
Authors: Ireland M. M. , Boiling J. D. 
Published: December 2007

ABSTRACT
The Block 31 reservoir in west Texas was studied using a full-field compositional reservoir simulator coupled to a compositional facility model. The first-ever miscible EOR project, a vaporizing-gas drive, was initiated in 1949 and is still underway at Block 31. The objective of the study was to update past performance predictions of previous studies by Warner et al.1,2 and optimize future reservoir production.
A compositional model of both the reservoir and field facilities was required due to the complex fluid phase behavior and intricate coupling of reservoir performance with the surface facilities. The convergence pressure technique was used to model fluid phase behavior in the reservoir. Core and log data were used to construct a reservoir description of the multiple Devonian zones. Forty years of field history were then matched. The initial decline in reservoir pressure under primary drainage was matched by adjusting reservoir pore volume. To account for the large model grid blocks and match the rise in GOR after primary, the relative permeability to gas was changed. The oil, NGL, and gas production rates from the model were all within 3.0% of field values at the start of 1985.
To improve operational reliability and reservoir performance, predictions looked at replacing the 20 year old flue gas plant with an air separation plant producing nitrogen. Also, the construction of additional gas processing facilities to increase NGL production was investigated. The results showed the flue gas plant should be replaced to increase liquid reserves, but additional produced gas processing facilities were unnecessary. Additional insights gained into field operations are discussed including optimizing future gas sales, recognizing the importance of strict reservoir surveillance, and realizing the opportunities for improved sweep efficiency in the field.
Foam as a Diverting Technique for Matrix Sandstone Stimulation
Authors: Burman J. W. , Hall B. E. 
Published: December 2007

Abstract
It is often difficult to adequately treat the entire perforated interval in a damaged, gravel packed well. Foam was evaluated in the laboratory as a diverting technique for hydrofluoric acid treatments, and encouraging results led to field evaluation of foam diverting in 12 wells in the Gulf of Mexico. Generation of stable foam at low pump rates was aided by the use of a coil tubing unit, which further enhances treatment results by enabling the various fluids to be spotted at or below the perforated interval. Two different techniques were used in these treatments: staged foam injection and foam injection during the first third of the treatment. Production data was used to evaluate the foam diverting technique. Also, temperature logs were run before and after one treatment to provide further information on the benefits of foam. Advantages and disadvantages of foam diverting as well as treatment design procedures, laboratory data, and production data relating to foam diverting in matrix hydrofluoric acid treatments are presented in this paper.
A Novel Economical Approach for Accurate Real-Time Measurement of Wellbore Temperatures
Authors: Jones R. R. 
Published: December 2007

ABSTRACT
A measuring device and technique are described for an accurate and economical determination of the bottom-hole circulating temperature (BHCT) in a well-bore while drilling, completing and/or at any time prior to cementing.
Accurate determination of the BHCT is very important during the drilling and completion of a well, and is crucial to effective cement slurry design and cement job results. Methods for this determination include a variety of tools, charts, tables, logs, mathematical computation, etc. Unfortunately, these methods are often expensive, require specialized equipment, interfere with normal operations, and are often applied when well conditions do not simulate those prior to cementing. Inaccurate temperature measurements attribute to poor cement slurry designs and poor cement job results usually due to improper slurry retardation. Data are presented to dramatize the effect of temperature on cement slurry design and application.
The device described is designed to be circulated in a wellbore at any time during normal completion operations whenever tolerances in the wellbore exceed 0.375 in. (0.952 cm). The approach provides real-time temperature data for the operator and requires no specialized equipment, nor costly, unnecessary delays in the well program. Case studies are presented in this paper to emphasize the ease of application, accuracy and economic feasibility of this novel approach.
Assessment of Variable Temperature in Gas Storage
Authors: Steele A. E. 
Published: December 2007

ABSTRACT
The assumption of constant reservoir temperature is widely used in reservoir analysis and has generally been extended to Gas Storage Engineering. However, this assumption may not be applicable to all storage fields, particularly for those high rate fields that cycle large volumes of gas through a small number of wells. A study investigating storage reservoir temperature was initiated to determine (1) if there is a significant cyclic variation in gas temperature, and (2) if there is a long term cumulative heat effect from gas storage operations.
To evaluate cyclic temperature variations, electronic temperature surveys were run in several wells during both minimum and maximum content shut-in periods. A cumulative gross heat balance was performed for the reservoir to estimate the temperature effect of 20 years of gas storage cycling. The results indicate that variable reservoir temperature is possible.
The impact of including variable reservoir temperatures in gas storage engineering calculations may be significant for high rate (peaking) fields, which are frequently the critical fields in a storage system. Small variations in temperature will affect maximum storage content, pressure-content modeling and, most importantly, the conclusions of gas inventory analysis.
Inverse Modeling in Gas Reservoirs
Authors: Fasanino G. , Molinard J. -E. , de Marsily G. , Peleé V. 
Published: December 2007

ABSTRACT
The distribution of permeability or transmissibility is of interest to the engineers for several reasons. These reasons may be related to design, operation, development or understanding of reservoir performance. In order to determine the distribution of the permeability, in general, several sources of information are available. These include: Transient tests in individual wells which give estimates of local permeability in the surrounding matrix,Longer term interference tests which relate to the influence of permeabilities around several observation wells,Geological information about the formation which involves statistically significant representation hereby referred to as ‘geostatistics’,And, finally, observations made during the operation of the field.
The first three items above relate to reservoir description while the fourth relates to reservoir performance.
The paper describes a procedure developed for determining the distribution of permeability by an inverse modeling technique.
The procedure combines the data from various sources of information listed above in a manner which compatibly reconciles local observations with spatially structured reservoir properties, and recorded pressure history.
It was implemented through a computer program cal led MAGHY (Modèle d'Ajustement de Grandeurs HYdrauliques). It applies to reservoirs or aquifers subject to the flow of slightly compressible liquids (oil or brine), or compressible gases in single phase, in two dimensions.
Two examples are included as application of the procedure. One involves an aquifer study where the flow field was in single phase liquid. The other presents validation of the procedure through a hypothetical case where a pre-determined permeability distribution was converged upon through the use of computer program implementing the inverse modeling technique. It was based on single phase gas flow.
Selective Plugging and Oil Displacement in Crossflow Core Systems by Microrganisms
Authors: Raiders R. A. , Maher T. F. , Knapp R. M. , McInerney M. J. 
Published: December 2007

ABSTRACT
The ability of bacteria to divert fluid flow from a high permeability sandstone layer to a low permeability sandstone layer by selective plugging and the ability of these bacteria to recover residual oil was studied. A crossflow system consisting of two layers of Berea sandstone were placed in capillary contact. Pressures were monitored in oil-brine and brine saturated systems to determine pressure gradients within the layers and estimate flow behavior. A mathematical simulation model was developed and used to analyze the results.
Changes in crossflow patterns were observed in the systems. During the treatment process, up to 60% of the production from the system was from the low permeability layer. Injectivity into the low permeability layer increased by a factor of three from initial conditions, relative to constant flow into the high permeability layer The greatest decreases in permeability, and thus the largest increases in potential gradients, occured in the high permeability layer, due to preferential microbial growth. Estabilishment of a mobile gas phase by biogenic gas production also assisted flow diversion. Large amounts of gas were produced from the high permeability layer once permeability reduction occured.
These results extend the previously published data obtained using parallel cores not in crossflow, and show that preferential plugging and oil release from high permeability regions do occur in crossflow systems. Oil recoveries comparable to those achieved in earlier linear core experiments were observed in the crossflow experiment. Thus, microbial metabolism apparently improves flow patterns in laboratory crossflow experiments and leads to the recovery of residual oil from waterflooding.
A Method for Controlling Numerical Dispersion in Carbon Dioxide Flooding Simulation
Authors: Potempa T. C. 
Published: December 2007

ABSTRACT
The phenomenon of numerical dispersion is due to the finite grid size in simulators. This effect can severely influence the results of simulations of displacement of oil by carbon dioxide. Mathematical techniques for controlling such spurious dispersion are described. The resulting scheme is compared to the industry standard upstream weighted finite difference method for gas drives which are: (a) immiscible, (b) have limited miscibility by a vaporizing gas drive mechanism, (c) exhibit developed miscibility, and (d) are fully miscible.
The results presented are of value for the following reasons. First, we discuss modifications that we have made to implement methods developed for mathematical model problems in a compositional simulator. Second, we have shown that such techniques represent an improvement from the state-of-the-art. Our particular contribution is the method by which we modify a central difference approximation to insure monotonie behavior. Third, we provide direct comparisons between the standard scheme and our modified scheme. Fourth, we show that, to obtain a specified level of numerical dispersion, at minimum a threefold reduction in computer costs is realized by our scheme with respect to the industry standard method. Last, we show that this estimate of benefit is conservative, as we can obtain up to a fiftyfold improvement in some cases.
Interference Well Testing to Predict Early Water Breakthrough in Naturally Fractured Reservoirs
Authors: Najurieta H. L. , Robles O. O. , Edwards D. P. 
Published: December 2007

ABSTRACT
Secondary recovery projects in dual porosity reservoirs with high transmissivity fractures must be carefully managed to avoid early water break-through into producing wells. If water production does begin in an injector/producer system, the origin of the water channelling must be identified so that remedial changes can be made in the injection-production schedule.
This paper shows that pressure interference testing between injection and producing wells, is a better method for locating problem injectors than the alternative technique using radioactive tracers.
Furthermore, information derived from interference tests can be used to prevent water break-through in water-flood projects.
Calculations of the interference response before and after break-through are shown in an example. A simple graphical method is used to illustrate water advancement.
Dimensionless Pressure of a Vertically Fractured Well Surrounded by Offset Wells
Authors: Stein M. H. 
Published: December 2007

ABSTRACT
A superposition model was developed to study the effect of offset wells on pressure transient tests for vertically fractured wells. The principle of superposition was found to be a valid tool.
For the situation in which a vertically fractured well was surrounded by production wells, there was no difference in the portion of the data used for the analysis of pressure buildup data when the offset producers were shut-in and when they were left on during the buildup test. This result implies that for a fieldwide situation in which the offset wells are left on during the buildup test radial flow is not achieved and the formation flow capacity calculated from a semilog plot has to be corrected. There may be limitations to the accuracy of the correction factors in multilayer reservoirs.
Analysis of pressure buildup or falloff data for a pressure maintenance project with a vertically fractured well in the middle of a five-spot pattern can yield different results depending on the operation of the offset wells during the pressure transient test. For a fieldwide situation in which the offset wells are left on during the pressure transient test, radial flow might be achieved, in which case the formation flow capacity calculated from the semilog plot should not be corrected. If radial flow is not achieved either due to interference from offset wells or the test not being run long enough, the data can be type curve matched to determine formation flow capacity.
Predicting Uniaxial Compressive Strength from Log Parameters
Authors: Tokle K. , Horsrud P. , Bratli R. K. 
Published: December 2007

ABSTRACT
Models for prediction of in-situ rock behaviour often suffer from lack of relevant input data, especially rock strength data. Rock mechanical testing of cores provides only discrete data points. This paper presents a method which produces a continuous plot of uniaxial compressive strength. The method is based on correlating standard log parameters with laboratory measured rock strength data. When a correlation has been established, it can be applied to new wells in the same field, giving a strength plot by computer processing of the necessary logs.
The method has been applied to two wells in a North Sea field, resulting in a statistically significant correlation. Proper depth adjustments between core depth and log depth are essential. It is further important that the lithologies of interest are represented among the core material.
Pipeline Transportation of High Pour Point New Zealand Crude Using Pour Point Depressants
Authors: Slater Grant , Davis Ann 
Published: December 2007

ABSTRACT
The Petroleum Corporation of New Zealand Limited discovered New Zealand's first major oil field in 1980. Production is currently 1590 m3/d (10,000 bpd), which represents about 14% of the country's requirements.
The crude has a high pour point (32°C) and a high wax level (35%). A major factor in development of the field was the selection of appropriate technology to overcome transportation problems via a 40 km pipeline from the process plant to port storage with ground temperatures of 11°C (52°F). Technical and economic considerations resulted in the selection of a chemical pour point depressant rather than thermal cracking, dilution with condensate, or maintaining the crude oil temperature above its pour point.
Selection of a suitable pour point depressant was made using laboratory studies done by various prospective suppliers. Product performance was based on pour point and yield value for the crude using a simple simulation of pipeline cooling.
The first year of pipeline operation was essentially troublefree and the following key points were noted. The actual pipeline dosage rate was considerably lower than laboratory predicted rates. By careful experimentation during pipeline shutdowns of varying duration, it has been possible to devise a management plan which minimizes difficulties during start-up.
The paper discusses how the adoption of pour point depressant technology, in conjunction with pipeline design, has resulted in an essentially trouble-free system which enables the crude to be successfully transported by pipeline.
Drilling Performance in Turbodrilled and Rotary-Drilled Khuff and Pre-Khuff Wells in Bahrain Field
Authors: Alqassab M. H. , Fathalla M. 
Published: December 2007

ABSTRACT
This paper discusses the performance of turbodrilling the Khuff and pre-Khuff wells in Bahrain field. Data obtained from these wells and earlier rotary drilled wells are analysed and compared in order to optimize the application of turbodrilling. Recommendations are made for selecting intervals best suited for turbodrilling.
New Techniques in Horizontal and Drainhole Drilling Optimization: Lehrte 41 Lateral Drilling Project
Authors: Prevedel B. 
Published: December 2007

Abstract
In order to optimize hydrocarbon recovery, more and more research work has been carried out in the last few years, especially in the field of drainhole drilling-, production-, and reservoir technology.
PREUSSAG's lateral drilling project Lehrte 41 in a partly by edge water drive depleted oil reservoir can be addressed as one step further towards an increased oil production especially with respect to current oil prices.
The objective of the workover operation in question was to bring the well back to an economical production by sidetracking and building up the angle of inclination to 120 deg with the Articulated Drillstring (ADS).
After reaching total depth, the well was cased with standart slotted tubings and the top formation successfully cemented
Oil production was resumed with a surface rod pump and showed a significant increase.
Optimized Operations Significantly Reduced Drilling Time and Cost in Gulf of Suez October Field
Authors: Khalaf F. 
Published: December 2007

ABSTRACT
This paper discusses the improvements in the drilling techniques and procedures that optimized the drilling operations in Gulf of Suez October Field. The improvements include all aspects of the operation: the drilling plans, the drilling procedures, the drilling equipment, the support services, and the supervision. Optimization greatly increased penetration rate, improved hole stability, and reduced time of all operations. With these results, the last group of wells were drilled almost three times faster than the early wells, and at half of their cost.
Evolution of Bahrain Field in Relation to Western Arabian Gulf Basin
Authors: Samahiji J. A. , Chaube A. N. 
Published: December 2007

ABSTRACT
The Bahrain Field, on the edge of the stable Arabian Platform, is a prominent salt related anticline. Growth analysis indicates active growth in the Triassic – Lr Jurassic, Up Cretaceous (Turonian and Maestrichtian) and early Tertiary Hydrocarbon localisation is noticed at many levels in Paleozoic, Jurassic and Cretaceous. Likely source intervals are Lr Khuff for Khuff gas and the Oxfordian-Kimmeridgian Hanifa – Lr Jubaila for Mesozoic oils. Hydrocarbons were emplaced in the present trap in Up Cretaceous – Tertiary. With tectonic breaching of the Hith seal, these remigrated from Jurassic to the numerous Cretaceous intervals. Periods of growth and oil migration conform to those postulated for the region.