bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analysis of Statistical Methods used in Studying Reservoir Behaviour
Authors: Old R.E. , Saidi A.M. , Zarghamee M.S. 
Published: December 2007

Abstract
The authors have noted that statistical methods in use by some reservoir engineers are biased and can lead to erroneous results. These methods occur particularly in the "fitting" to past history or in the simultaneous solutions of the material balance and water drive equations.
The statistical methods used by various authors are discussed, and a method is suggested to arrive at an umbiased solutions in a particular case. As for the general case, a method is presented that is believed to possess little bias. possess little bias. The bias in other methods is discussed. The mathematics and numerical examples are given showing the weighting factors used in one biased method.

Introduction
Reservoir simulation models and modern high speed digital computers have relieved reservoir engineers of many long tedious hours of punching a desk calculator. This technology has become a mixed blessing, however. There have been evident trends in recent years that has become disturbing -not only in reservoir engineering but in other fields using sophisticated computer simulating programs. One of these trends has been to substitute a programs. One of these trends has been to substitute a mass of computer runs for the usual process of "thinking". The authors have seen several examples where an hour or so of thinking about the mathematical or engineering principles could have obviated hours of program preparation principles could have obviated hours of program preparation and computer time. Sometimes attempts to develop theory by a mass of computer runs have been made; the reversed procedure would be more logical. procedure would be more logical. Another trend that can be seen, particularly in reservoir engineering, is to make these computational systems "empirical tools" - forsaking the excellent theory and logic that was used to develop them. The "fitting" to past history tends to forsake conventional statistical methods to determine basic constants of equations and has instead become a search of wide ranging variables and trends that ends up in a "fit" that may be a complete physical absurdity. This is particularly possible if a biased correlative technique is used.
It has come to the authors attention that some reservoir engineers, are using correlative techniques of minimizing a summation of squared deviations of quantities which may range several hundred folds in magnitude through the field history. These techniques place an uncontrolled bias on one end of the data and virtually ignores the other end of the data. These techniques of masking the effects of one end of the data give a false sense of security amidst the errors of the basic data.
In-Situ Remediation of Oil-Contaminated Soils with Surfactants: Laboratory and Pilot Studies
Authors: Baviere M. , Bocard C. , Ducreux J. , Monin N. , Muntzer P. , Razakarisoa O. 
Published: December 2007

M. Baviere, SPE member, C. Bocard, J. Ducreux, N. Monin, Institut Francais du Petrole, and P. Muntzer and O. Razakarisoa, Institut Franco-Allemand de Recherche sur l'Environnement (IMF-CNRS) Copyright 1997, Society of Petroleum Engineers, Inc.

Abstract
A surfactant-flooding technique is described for the remediation of soils contaminated by semivolatile and nonvolatile petroleum products, such as crudes and diesel oils. It consists of injecting a surfactant slug into contaminated areas to mobilize oil trapped in both vadose (unsaturated) and capillary-fringe zones, and of depleting the groundwater level to collect this oil.
To deal with contamination by diesel oil, a procedure to select a surfactant formulation was applied, based on (1) the phase behavior of the water-oil-surfactant system, (2) an appraisal of surfactant-soil interactions, namely ion exchange with clays and surfactant adsorption, and (3) the measurement of the surfactant efficiency for extracting the contaminant from 1D and 2D sandpacks. With a mixture of anionic and nonionic surfactants more than 90% of the residual oil was recovered.
The process was implemented in a large-scale experimental site of 900 m3, packed with slightly clayey sand and locally contaminated by a spill of 476 L of diesel oil. Two successive surfactant injections were performed in order to treat: first, the vertical oil-migration zone; secondly, the horizontal oil-extension zone in the capillary fringe. Based on soil-core sampling after the surfactant flood, the high displacement efficiency was confirmed: about 80% after the first injection. However, it appeared that the mobilized oil was not entirely recovered at the pumping well: about 50% of the residual oil, probably due to insufficient hydraulic confinement. The same observations were made after the second injection. The removal of diesel oil and surfactants from the effluents was performed on-site, before sewage disposal, by centrifuging, precipitation and finally by biodegradation.

Introduction
The remediation of soils and aquifers contaminated by petroleum products is now proving increasingly essential in the protection of human health. To palliate the poor efficiency of conventional pump-and-treat processes, due in particular to capillary trapping and the low water solubility of contaminants, alternative in-situ restoration strategies have been developed, such as venting, biodegradation, and surfactant flooding. The latter is particularly promising when semivolatile and nonvolatile contaminants are involved.
The use of surfactants is investigated here in the framework of a modular process: the DHBP (Drainage HydroPneumatique Bioactif). It consists of implementing one stage of surfactant flooding and one stage of surfactant-enhanced biodegradation. P. 481
Information Obtained by Correlating Probable Values of the Geological Reserves and of the Influx Constants
Authors: Baldini G. 
Published: December 2007

Abstract
The correlations between probable values of the reserves, the invasion constant and the dimensionless time constant are obtained for oil or gas reservoirs with infinite or finite, radial or linear aquifer, by superposing the effects due to a succession of uniform declines of the pressure at the initial gas-water (oil-water) contact.
The behavior of correlations deduced for the considered reservoir-aquifer system at each material balance calculation, is successively analyses and found as giving useful information. In fact, when represented in linear diagrams, they can be the basis to evaluate with a good approximation the geological reserves, the properties of the water influx and, also, to find the pressure values in the past production history which have the worse influence on the results of the material balance.
This is useful in the initial phase of reservoirs exploitation giving information to predict earlier their future behavior, when the instrumentation and evaluation errors in the reservoir pressure can be of the same order of the pressure drop in the corresponding time intervals.
The correlations can also provide a method for the simultaneous determination of the unknown parameters of the aquifer-reservoir systems which can be used in any case in combination with the usually methods, to give more complete results.

Introduction
We will assume, as usually: an homogeneous and istropic aquifer with constant thickness (linear or radial, finite or infinite); a deplacement front undeformed by fluids different densities; the absence of collateral phenomena as the compaction of the surrounding shales or the oversaturation of the oil; uniform conditions in all zones of the reservoir; the pressure at the initial hydrocarbons-water boundary equal to the average pressure of the reservoir until the last calculating time; always a sufficient number of wells.
Moreover, we prefer to express the water influx by superposing the effects of the pressure variations at the reservoir-aquifer boundary as due to successive linear declines in every production interval. We do this with the formulation 1).
Influence of the Viscoelastic Properties of the Overlying Rocks on the Behaviour of the Deep Aquifers
Authors: Brighenti G. 
Published: December 2007

Abstract
The pressure variations in the aquifers, consequent on the production, of an oil or gas field or on gas injection for the production, of an oil or gas field or on gas injection for the underground storage, causes variations of the tensions being both in the permeable medium and in the overlying strata.
This fact, as we know from the literature about this argument, causes both permeability and porosity variations of the medium, influencing therefore the water influx, and remarcable deformations in the enclosing rocks which might cause subsidence phenomena too.
In the note, we are going to present, the phenomenon is studied in all these aspects through the Finite Elements Method, taking in consideration the results obtained in the Mining Science Institute of the Bologna University.
The behaviour of the water-bearing stratum and of the overlying rocks was namely studied unitedly. After dividing properly, the medium into finite elements, both the pore properly, the medium into finite elements, both the pore pressure distribution and the consequent tension variations pressure distribution and the consequent tension variations as well as the deformations through the time, were studied at the same time through an iterative process; the viscoelastic medium was represented according to the Kelvin-Voigt generalized model.

Introduction
1. The developing of the reservoir engineering compelled the researchers to the requirement to always know more thoroughly the characteristics of fluids and reservoir rocks.
As far as reservoir rocks are concerned, it has been thought to be necessary, already since many years, to take into account their compressibility and the variations of their physical characteristics when reservoir pressure changes, especially in the case of liquid one phase expansion; on this subject several studies have been performed. From these researches the importance aroused to wholy study the phenomenon, by taking into account not only reservoir rocks or the aquifer, but also all surrounding rocks. As regards the above said, the important conclusions reached by Geertsma, Van der Knaap and Van Vlis, and Evangelisti and Poggi are mainly aimed to detect the subsidence phenomena.
Under this note, the attention is particularly called upon the influence of a variation of the reservoir pressure both on the whole medium strain and on the fluid influx in case of overlying rocks with a viscoelastic behaviour. To this purpose, we took as a basis the results obtained from the research in course at the Instituto di Scienze Minerariein Bologna, performed by means of funds from Consiglio Nazionale delle Ricerche.
Chemical Study of Organic-HF Blends Leads to Improved Fluids
Authors: Shuchart Chris E. 
Published: December 2007

Abstract
Organic-HF blends have successfully stimulated sandstone formations with corrosion concerns, HCl-sensitive mineralogy, and/or crude oil incompatibilities, three conditions in which the use of typical HCl-based fluids can result in severe damage. Despite the success of such blends, very little work has been published on the reactivity of organic-HF fluids with aluminosilicates. Recent work on the chemistry of HF acidizing focused on HCl-HF systems.1 This paper discusses the chemistry of organic-HF systems as determined by laboratory reactivity tests, 19F nuclear magnetic resonance (NMR) studies, and organic-HF flowback analyses.
Laboratory reactivity testing revealed severe precipitation problems associated with the currently used acetic-HF and formic-HF systems. Flowback analyses after organic-HF field treatments fully supported the laboratory results. A 19F NMR spectroscopic study of the fluoride distribution throughout the primary, secondary, and tertiary reactions helped explain the precipitation and when it might occur. From this work, new organic-HF systems were developed that prevent precipitation while maintaining all the advantages associated with the acetic-HF and formic-HF fluids. The retarded nature of these systems is discussed in this paper.
Permeability Impairment due to Asphaltenes During Gas Miscible Flooding and its Mitigation
Authors: Turta Alex T. , Najman Joseph , Singhal Ashok K. , Leggitt Shelley , Fisher Douglas 
Published: December 2007

Introduction
During miscible flooding of oil reservoirs by light hydrocarbon gases, deposition of asphaltenes inside reservoirs, and injection and production wells, can cause severe problems thereby adversely affecting the economics of oil recovery. In spite of this, very limited information regarding the asphaltene adsorption/deposition within porous media during gas miscible flooding, is available.
In the present work, the flow of oil-solvent mixtures through porous media during a gas miscible flood was mechanistically studied in the laboratory under simulated reservoir conditions. The tests mimic the phenomena occurring within a small pore volume encroached by increasing amounts of solvent, in the course of a miscible flood.

Experimental
Two Canadian crude oils, known to be prone to asphaltene deposition in the field, were selected for this study: one from the Pembina Nisku pool in west-central Alberta and the other from Rainbow Keg River field in north-western Alberta.
Both these oils have an asphaltene content of about 2%.
For studying asphaltene related effects inside porous media during miscible flooding, a high pressure coreflood equipment was constructed (Figure 1). Berea cores were used as porous media during this investigation. The lengths of the cores were over 20 cm and the diameters, 1.9 cm. The porosity was 16-17%. The effective permeability to oil was in the range of 36 to 116 mD; these values were measured at a residual water saturation of 27–28% and were used as reference values for the subsequent flow of oil-solvent mixtures. Reservoir brine was used to initially saturate the core; a subsequent oil flood reduced the brine saturation to the residual brine saturation.

Results
Variations in effective permeability ratio (Kef/Kefo) upon flow of Rainbow Keg River oil-propane mixture are presented in Figure 2; here Kefo is the original value of effective permeability (for oil), while Kef is the current value for a given propane concentration in the mixture. All the concentrations are expressed in vol. %. The reduction of Kef begins as soon as propane is injected, that is, at a concentration of 15% propane, and it continues until propane concentration, reaches 100%. As a matter of fact, when injecting pure propane, the Kef is reduced to almost zero, implying a total blockage of the porous medium. There are two rates of permeability decrease with increasing propane concentrations, corresponding to two distinct ranges of propane concentrations. The first range is up to 51% for which the decrease is very steep. For propane concentration higher than 51%, the decrease is less severe. At the end of the first range, the Kef had decreased to 26% of its original value.
P. 703^
The Critical Water-free Production Rates of Interfering Wells
Authors: Lehner F. 
Published: December 2007

Abstract
The critical rate is defined is the steady or semi-steady production rate of oil or gas under a drawdown just small enough to prevent water production from an existing layer of bottom water. production from an existing layer of bottom water. Critical rates are determined theoretically for fully perforated wells, assuming a horizontal cap-rock perforated wells, assuming a horizontal cap-rock boundary and allowing the permeability to vary with depth. A generalised 'Girinskii Potential' is defined and used to formulate the three-dimensional free-surface flow of a real gas as a problem in plane flow. A formal analogy with plane incompressible flow is thereby established. As an example, Muskat's results for the flow capacities of small groups of interfering wells are reinterpreted in terms of critical oil or gas production rates.

Introduction
The occurrence of bottom water in oil or gas reservoirs imposes restrictions on water-free withdrawal rates, since a well will cut water above a certain critical rate. This critical rate is associated with the well-known phenomenon of upconing bottom water. The phenomenon depends essentially on the perforation and intake provisions (position of the tubing-intake level) at the well. To ensure a finite critical rate, these provisions must be such as to allow i water cone to rise a finite distance above an initially flat oil/water contact without immediately reaching the perforated interval or the tubing-intake level inside the well. A steady state can then exist in which the water remains stagnant up to line critical rate and, due to its greater density, hydrostatically balances the pressure gradient in the foil or gas which passes over it towards the well. passes over it towards the well. The assumption of steady-state conditions and of fully segregated fluids separated by a macroscopically sharp interface form the starting point for the majority of investigations concerned with the determination of critical rates. Among these, a further distinction can be drawn between studies dealing with partially penetrating (or partially perforated) wells and those dealing with fully perforated) wells and those dealing with fully penetrating and fully perforated wells, i.e. wells penetrating and fully perforated wells, i.e. wells perforated over the total pay thickness. perforated over the total pay thickness. This article deals with the case of fully perforated wells. perforated wells. The critical production rate of a fully perforated well sited in the centre of a horizontal perforated well sited in the centre of a horizontal circular reservoir, assuming steady incompressible flow, can be determined with the help of Dupuit's famous well-discharge formula upon giving the proper interpretation to the quantities involved. proper interpretation to the quantities involved.
A Patch-Type Adaptive Local Grid Refinement Technique and Its Application to Horizontal Wells
Authors: Vikas Shree , Ertekin Turgay 
Published: December 2007

Abstract
A three-dimensional, three-phase black oil simulator is developed which incorporates both static and dynamic patch-type local grid refinement procedures; and is capable of handling both horizontal and vertical wells. In static local grid refinement the refined grids are embedded within the coarse grids during the entire length of simulation. This refinement scheme has been used around the wellbores where large pressure and saturation changes are anticipated. The dynamic local grid refinement algorithms identify various sections of the reservoir undergoing large pressure and/or saturation changes at each timestep. A pre-determined uniform refinement is applied to these patches; and local grid simulation is performed. The local grids and the base (coarse) grid interact with each other through a specially developed data transfer method; in which the local gridblock pressures are arithmetically averaged to get updated coarse gridblock pressure, and capillary pressure is used to back calculate phase saturations. Once all the patches are solved then the corresponding coarse gridblock pressure, saturation and flowrate entries are updated from the entries of the local grids.
The performance of the developed model is examined through several different scenarios. These cases include sealed reservoir, bottom water drive, and edge water drive utilizing horizontal wells. The proposed refinement algorithms provide good estimates of bottom-hole flowing pressures, WOR and GOR values and flowrates for all the configurations. The run-time for the dynamic grid runs is about 100–200 folds less than that of the fine-grid model, and is comparable to the run-time of conventionally refined grid model. Local grid simulation in various patches of the reservoir do not share or transfer data among each other at a particular timestep. Hence, this technique can be easily implemented on machines having parallel processors. Such applications would drastically reduce run-time.
Developing a 10 billion barrel reservoir with modern techniques
Authors: Joiner D.S. , Myers C.E. 
Published: December 2007

Abstract
A high volume water injection pressure maintenance program was initiated in the Defa Field of the Libyan Arab Republic soon after production began, to maximize oil recovery. As development of this large reservoir proceeds, the injection system can be expanded to a capacity in excess of 400,000 BWPD to support oil production rates of about 350,000 BOPD.
Development of Defa contrasts with that of older large fields due to the abundant use and application of modern tools and technology. Computer model studies predicted the need for pressure maintenance and were used to plan the pressure maintenance and were used to plan the large bottom-water injection system which was designed, constructed and put into operation in the Libyan desert only 20 months after the Field was put on production. Thirty-four months after the Field went on production, 163,000,000 barrels of oil had been produced from, and 80,000,000 barrels of water injected into, the Defa reservoir. This water injection program is expected to increase oil recovery at program is expected to increase oil recovery at least 300 percent from about 1 billion barrels to over 3 billion barrels.

Introduction
The Defa field in the Libyan Arab Republic contains oil-in-place of about 10 billion barrels; however, computer model studies predicted the need for pressure maintenance predicted the need for pressure maintenance early in the producing life of the field. The studies showed that the under-saturated crude would quickly drop below the bubble point and institute an inefficient, solution point and institute an inefficient, solution gas expansion drive without some type of pressure maintenance program. A large-scale pressure maintenance program. A large-scale water injection system, designed with the help of the computer model studies, is predicted to increase oil recovery 300 percent from about 1 billion barrels to over 3 billion barrels.
This paper reviews the development of the field and studies leading up to the initiation of water injection, with particular emphasis on the use of modern tools and technology. Such advances in technology reduced the time spans required for major development decisions. This 10 billion barrel field was put on production 500 miles from Tripoli in the Libyan desert only 23 months after development commenced. Twenty months later, a 240,000 BWPD water injection system was in operation.