bluuebunny/crossref_metadata_2025_split huggingface dataset:
Preparing the Site with Explosives to Recover Heavy Oil by Solvent Injection
Authors: Miller J.S. , Johnson F. Sam , Jones Ray A. 
Published: December 2007

Abstract
An explosive fracturing technique has been developed by the Bureau of Mines for preparing wells to recover heavy oils by solvent-heat methods.
A 50-ft by 50-ft five-spot pattern was drilled along with two shot wells and an observation well. Three of the pattern wells and the two shot wells were explosively fractured between 300 and 360 ft, with 15,000 lb of pelletized TNT, using wellbore shots.
Preshot and postshot cores were obtained. The preshot core indicated no fracturing of the formation, and the postshot core indicated fracturing of the formation resulting from the shooting. Measurements of permeability, porosity, water saturation, and oil saturation porosity, water saturation, and oil saturation were obtained from plugs taken from the preshot core.
Preshot and postshot airflow tests were made. Preshot tests indicated that no communication existed between wells. Postshot tests showed that communication was established between wells. The solvent injection well was chosen from results of these tests.
A postshot impression packer survey was run between the depth of 300 and 346 ft in a pattern well not explosively fractured. pattern well not explosively fractured. Wellbore irregularities obtained on the rubber sleeves indicated fracturing results from the explosive shot.
Water-injectivity tests on the four outside wells of the five-spot showed that communication had been established to the pattern wells pattern well

Introduction
This report describes a continuation of the Bureau of Mines research program on developing methods of explosive fracturing to improve the ultimate recovery of oil from tar sands and heavy oil reserves. The purpose of this research is to study the factors involved in the efficient and economic recovery of heavy oil from a consolidated sandstone petroleum reservoir by the use of explosives, solvents, and other supporting techniques.
A review of the literature revealed little information about the depth of worldwide deposits, the areal limits, or the economic possibilities of tar sands and heavy oil. Ball possibilities of tar sands and heavy oil. Ball Asso. reports 42 counties in Kansas, Missouri, and Oklahoma contain 40 percent of the recognized oil-impregnated occurrences in the United States. Many of these deposits occur at depths less than 500 ft and would be ideal for recovery of this oil by in-situ and heat and/or solvent methods.
Deepwater Riser Technology
Authors: Carter B. A. , Ronalds B. F. 
Published: December 2007

Abstract
The development of oil and gas reserves in water depths greater than 450 metres has seen a clear trend develop in the types of platform selected for production purposes. Floating production systems (semi-submersibles and floating production, storage and offloading facilities, FPSOs), spars and tension leg platforms (TLPs) dominate this trend.
Until recently, the use of flexible marine risers has been largely unquestioned when floating structures have been employed to develop offshore oil and gas reserves. A major advantage of using a flexible riser was seen to be its compliancy with a vessel's motion. In deeper water, however, the ratio of a vessel's vertical movement to the water depth decreases. This reduces the effective strains applied to a riser due to a vessel's motion and allows alternative riser configurations to be adopted.
Steel catenary risers (SCRs) and, to a lesser extent, hybrid risers are favourable configurations for use in deepwater for both production and export purposes. Flexible pipe is inherently expensive to manufacture and is restricted in the range of environments in which it can be employed (including high temperatures and for chemically aggressive product). The use of steel, and materials such as titanium, for these alternative configurations can overcome many of the disadvantages associated with flexible risers and offer promising solutions for marine risers in deeper water.
The Importance of Petrophysical and Geochemical Data in Oil Recovery Studies
Authors: Rousselet Daniel C. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
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, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The part played by petrophysical and lithological characteristics in recovery studies is well-known to all petroleum engineers. However, we found that physics-chemical and geochemical data e.g. physics-chemical and geochemical data e.g. oil composition, natural surfactant concentration, proportion of organic materials included in the matrix, are also to be carefully considered. They concern water-oil and fluid-matrix interactions, which influence the static equilibrium between oil and water in fields as well as microscopic displacement flow during waterfloods.
Some examples concerning fields operated by ELF-RE in foreign countries are presented, they provide a better understanding of the conditions provide a better understanding of the conditions necessary for an efficient waterflood, which include in particular :–Anomalous saturation distribution, which can be explained by palynology.–High water production from carbonatedfields, even when the in situ oil saturation measured seems high.–Low oil recovery during waterflood, which is ascribed to a high organic sediment content in the porous medium.–Reduced imbibition due to high concentration in kerogene and carbonates.
1 –

Introduction
All persons working on mechanics concede that Darcy's equation conveys globally, and with accuracy, the isotherm flow of a Newtonian fluid; this fluid, whose composition assumed to be constant, circulates at low velocity in a permeable medium of uniform composition, without any physico-chemical reaction as regards to the fluid, other than liquid-solid adhesion.
This equation also gives a satisfactory insight in the following cases :–polyphasic flow of immiscible liquids by extension of Darcy's law)–flow of miscible fluids with diffusion–convection phenomena
Interpretation of Horizontal-Well Production Logs: Influence of Logging Tool
Authors: Ozkan E. , Sarica C. , Haci M. 
Published: December 2007

Abstract
This paper investigates the influence of production-logging tool on wellbore flow-rate and pressure measurements. The focus of the investigation is on the disturbance caused by the production-logging tool and the coiled tubing on the original flow conditions in the wellbore. An analytical model is used in the investigation and single-phase liquid flow is assumed. The influence of the production-logging tool on the measurements is substantiated by the deviation from the original flow-rate and pressure profiles. It is shown that the influence of the production-logging tool manifests itself in low-conductivity wellbores. High production rates further amplify the effect of the production-logging tool. It is concluded that the effect of the production-logging tool may be ignored if dimensionless well conductivity exceeds 500 and the Reynolds number is lower than 100000. Results indicate that a production log run in a low-conductivity horizontal well may not indicate the low-permeability zones along the well.
Evaluation and Prediction of the Performance of Positive Displacement Motor (PDM)
Authors: Li J. , Tudor R. , Ginzburg L. , Robello G. , Xu H. , Grigor C. 
Published: December 2007

Abstract
Positive displacement motor (PDM) has been used extensively in the drilling operation. Motor performance is essential to ensure drilling success. In the traditional way, the performance of a PDM can be described by pressure drop versus torque and the rotational speed. For a particular type of motor, the RPM curves are different at different flow rates. Due to the limited test results, the performance of the motor can not be fully described. The prediction of the motor performance is very important for both motor design and operation. In this paper, analysis of the test results of PDMs collected using various PDMs from different PDM suppliers and the different correlations developed to describe the motor performance pumped with incompressible drilling fluid are discussed.
Modelling Scale Inhibitor Squeeze Treatments in High Crossflow Horizontal Wells
Authors: Mackay E. J. , Sorbie K. S. 
Published: December 2007

AbstractModelling scale inhibitor treatments in horizontal wells is emerging as an important field of research due to the need to reduce the cost of treating wells that may be thousands of feet long. Simulation studies performed using recently developed modelling tools have led to recommendations that have reduced the risk of chemical upsets at the wellhead and extended squeeze lifetimes downhole.However, as an increasing number of "problem wells," such as high crossflow wells, need be treated to prevent scale formation, these models have to be adapted to enable them to capture the complex range of properties that make these systems so problematic. Diverter technology is being developed to enable optimal placement of chemical inhibitor, but to study the impact of the diverter on the squeeze performance, the fluid flow properties in the near-wellbore region must be modelled accurately. This is done by using a full-field reservoir simulation model that includes sufficient detail in the near-well formation not only to capture the fluid flows, but also to model accurately the chemical placement and recovery. The model can assess the impact of various placement strategies, as well as assist in determining the optimal fluid and chemical volumes.A case study from the North Sea where a gel diverter was selected to assist inhibitor placement is presented. The study demonstrates the types of calculation that can be made, and what information can be usefully supplied to the field engineer designing squeeze treatments.
Experimental Study on the Productivity of Complex Well Configurations
Authors: Yildiz Turhan , Deniz Ozer 
Published: December 2007

Abstract
This study presents experimental results for the productivities of complex well configurations. The experimental study covers the productivity measurement for selectively completed vertical wells, horizontal wells with multiple flow entries, duallaterals, multilaterals including chicken-foot well configuration, perforated wells, and hydraulically-fractured horizontal wells. Inasmuch as an analogy exists between electrical and fluid flow, an electrolytic analog apparatus was constructed to perform the experiments. The apparatus was basically composed of a 100×100×50-cm Plexiglas tank, a variable voltage source, and several ammeters and voltmeters.
Experimental results were used to verify the analytical productivity models. In all cases, excellent agreement was established between the experimental and analytically calculated productivity values.
The experimental data presented in this study is very useful for engineers and researchers to verify their analytical productivity models and the computer codes.
Unusual Logs in an Unusual Formation: NMR in Athel Silicilyte
Authors: Looyestijn W. J. , Alixant JL , Hofman J. P. 
Published: December 2007

Abstract
The log evaluation of an expelling source rock is notoriously challenging because the kerogen and the generated oil coexist in the source rock. The Athel silicilyte is both an overpressured light-oil reservoir and a world-class source rock. In this unique geological setting found in the South Oman Salt Basin, reservoir characterisation is intimately associated with source rock evaluation.
In the absence of any direct geological analogue, the initial petrophysical model was calibrated against extensive core analyses. Porosity interpretation was then based exclusively on wireline bulk density measurements. The limitations of this approach only became apparent as attempts to reconcile data from various sources failed. While efforts aimed at obtaining representative core material and establishing reliable core analysis procedures, in-situ calibration of the petrophysical model was also actively pursued. NMR logging was primarily introduced to reduce uncertainties affecting density-derived porosities in the presence of variable, unknown organic matter content.
The first NMR log run in a silicilyte well could not be fully reconciled with density data. Laboratory NMR confirmed the log measurements, but more questions were raised when significant NMR signal was recorded on dry, cleaned samples at the time when new field data could not be explained.
Athel silicilyte is unique, and with no reference to confirm or to invalidate new data and interpretation, consistency and integration are key to improving our understanding of the rock. A thorough review of NMR acquisition procedures and processing algorithms was undertaken with logging contractors; job planning was improved, new logging procedures were implemented, tool malfunctions were identified and remedied, processing methods were upgraded. Laboratory procedures were revisited, and NMR core measurements were complemented with additional, independent core analyses.
Whereas the initial emphasis was on "effective" porosity determination, NMR logs and core measurements provided new insight into the Athel silicilyte rock. This includes: (i) strong indications that the rock may be mixed-wet; (ii) encouraging results in the area of permeability estimation; and (iii) indeed higher confidence in the assessment of effective porosity. A TOC (Total Organic Carbon) log can also be derived, which could find further application in source rock evaluation and the characterisation of organic-rich reservoirs. Integration of all available log data using a statistical approach now provides a consistent reservoir description, with limited core calibration requirements. Having successfully integrated NMR data to unravel the organic content of the rock, the improved petrophysical model provides the basis for sound reservoir characterisation, the foundation for better exploration, appraisal and development decisions.
Dirty Sand Consolidation Technology for Gas Wells
Authors: Cobianco S. , Lezzi A. , Massara E. Previde , Pitoni E. 
Published: December 2007

Abstract
Italian gas fields are usually composed of many sand layers, which must be produced separately: therefore, multiple completions are very common in Italy. Shallower layers, the most prone to produce sand, are completed with sand control techniques: open hole gravel pack and inside casing gravel pack installed above fracturing pressure (frac pack)1–3 are the most popular completions. Sometimes shallower layers can not be completed in sand control just because the uppermost selective gravel pack on short string was installed in a deeper, more prolific, sand layers. Conventional completion (without sand control) is the only possible technique applicable in these layers.
Formation sand can not be consolidated with standard chemical treatments (e.g. resins) because of the high clay content (25–50%) and the low permeability (10–200 mD). The use of frac pack with resin coated proppant is not allowed by the thin thickness of sand layers where the fracture can extend toward close water layers. A novel sand consolidation technique especially suited for prevention of dirty sand influx in gas wells has been developed. Laboratory testing of the new sand-control system gives a minimum 70–80% permeability retention and the resulting compressive strength is sufficient for an effective sand control. The cementing materials, as shown by SEM (Scanning Electron Microscopy), can be described in terms of precipitation of amorphous silica and migration of clays.
This paper reports the laboratory testing and results: the novel system is able to consolidate very low dirty permeable sands (&lt; 1 mD) containing high concentration of clays (up to 50%) and carbonate materials (up to 20%)
This technology has been employed in field trials with positive results.
Slaying the Myth of Infinite Reactivity of Carbonates
Authors: Gdanski Rick , Van Domelen Mary S. 
Published: December 2007

Abstract
The simplifying assumption that limestones essentially have infinite reactivity has been a powerful and useful tool in helping our industry understand and model the acidizing process of carbonate formations. However, over the past few years, considerable work has shown that this assumption need not be used. In fact, use of this assumption can lead to incorrect conclusions regarding optimized acidizing of carbonate formations. This paper builds upon the historical foundation of understanding the acidizing process and brings together the reactivity studies using a number of different reactors to show that carbonates do not have infinite reactivity. It also shows the results of using proper reactivity data and proper reactivity theory for treatment designs.
Alba Northern Platform-Produced Water System Improvements
Authors: Turnbull David 
Published: December 2007

Abstract
The Alba Field is operated by Chevron UK Ltd and located in the central North Sea. It came on stream in January 1994. As water production levels increased, it became progressively more difficult to maintain the oil in water overboard figure below the statutory requirement of 40 ppm. Process investigations included a full system fluids characterisation study which identified a mean oil droplet size of 8–10 micron in the produced water. The original platform design assumed a larger oil in water droplet size and this low value produced a correspondingly low removal efficiency from the existing produced water hydrocyclone facility. Initial side stream trials led to the development and installation of a 20 tonne ‘interim’ produced water polishing vessel to enhance the existing facilities for oil in water separation. A Computational Fluid Dynamics programme was utilised to model fluid flow in the new vessel and support the planned design of a full size vessel with the capability of treating 390,000 BWPD (3 times the present produced water rate) to fully meet the platforms predicted needs. A programme of specific chemical product screening singled out a newly developed dithiocarbamate chemistry as being highly effective in meeting the demands of limited chemical contact time and the short vessel residence time available. This combined chemistry and engineering design approach resulted in the platform meeting the 40 ppm oil in water discharge specification and thus avoiding the serious threat that continued non conformance posed to the current high oil production rates.
This paper describes the essential stages of this work and discusses the results and remedial action taken from the initial investigation through to the successful resolution of this problem. The paper content presents this from both an engineering and chemical treatment perspective.
An Empirical Correlation Between Reservoir Temperature and the Concentration of Hydrogen Sulfide
Authors: Håland Kjersti , Barrufet Maria A. , Rønningsen Hans P. , Meisingset Knut K. 
Published: December 2007

Abstract
The problem addressed in this paper was to establish an empirical correlation between the H2S concentration in reservoir fluids and the reservoir temperature. The work is based on data from a large number of exploration wells drilled in sandstone reservoirs on the Norwegian continental shelf. It is shown that with few exceptions, the H2S concentration in the produced fluid is close to zero, when the reservoir temperature is below a threshold temperature of about 220°F (105°C). Above this threshold, an exponential temperature dependency is shown to exist.
The empirical correlations developed in this work allow a reasonably accurate estimate of the expected H2S in produced gas. They are considered of particular importance for early planning of H2S control strategies and production management, especially in cases where only wireline formation tests have been conducted.
Oil Production, Past Commitments, and Increasing Returns
Authors: Heitmann George 
Published: December 2007

Heitmann, George The Pennsylvania State University and the Ruhr-Universitt Bochum

Abstract:
The proposition that the oil industry operates under conditions of increasing costs is fundamentally correct, but must be properly qualified. In circumstances where complete input variability cannot be assumed, the "burden of the past" can impose constraints on investment decision alternatives such that demand induced increases in production will be achieved under decreasing cost conditions.
One of the recurring "myths" in the oil industry is the proposition that production takes place under conditions of proposition that production takes place under conditions of increasing returns (i.e., decreasing costs). As Adelman has put it: "this vision of decreasing costs and natural monopoly in oil is held clear across the political spectrum," to which he immediately adds, "perhaps it is just as well - or perhaps very bad - that we must reject the one opinion that seems common to all". That the oil industry is not a natural monopoly is fundamentally correct; however, there are some sound reasons for believing that incremental costs may indeed decrease over certain relevant ranges of production increase. The purpose of this paper is to outline some of the circumstances that will result in increasing returns. Part I summarizes the cost consideration associated with crude oil production, and particularly examines the development cost concept. In Part II the critical distinction between the short and long run is examined, and the nature of the decreasing returns argument is outlined. Part III introduces and appraises conditions under which increasing Part III introduces and appraises conditions under which increasing returns can be expected, and suggests that "myth" properly interpreted, may be reality.An oil field, to produce oil, must first be discovered and equipped for production.
Test and Research on the Commingled Development of Two Kinds of Low Efficiency Oil Reservoirs
Authors: Chao Huaqing , Fang Baocai , Pang Yanming , Xu Yunting , An Cheng 
Published: December 2007

Abstract
The interzonal interference of the commingled production of Putouhua and Fuyu oil reservoirs with large vertical distance (about 400m) and large permeability difference (air permeability of 118 X 10 -3 m 2 for Putouhua oil reservoir, 1.16 X 10 -3 m 2 for Fuyu oil reservoir) is solved, by theoretical analysis and field pilot test based on seepage mechanics. After one-year field pilot test, the production situation of each oil reservoir of the commingled reservoirs is coincident with the situation of single-reservoir production a line. These make the best use of the production capacities of these two oil reservoirs and provide experience and technology for economically and effectively developing the large overlaping area of Putouhua and Fuyu oil reservoirs in future.
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