bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Engineering Analysis of Microbial Enhanced Oil Recovery
Authors: Bryant Steven L. , Lockhart Thomas P. 
Published: December 2007

SummaryWe assess processes for enhancing oil recovery by means of microbes (MEOR) from the perspectives of reservoir and reaction engineering. In this work, MEOR refers to recovering incremental oil by increasing displacement and/or volumetric efficiency; it does not include well stimulation treatments. MEOR processes address the same physical parameters as chemical enhanced oil recovery (EOR) processes; hence, they are subject to the same technical difficulties: identifying and locating the target oil and retention, dissipation, and consumption of chemicals in the formation. The essential difference between MEOR and chemical EOR resides in the method of introducing the recovery-enhancing chemicals into the reservoir.Although quantitative measures of microbial performance (reaction rates, stoichiometry, required product concentrations) are lacking, it is possible to demonstrate quantitative relationships between microbial performance, reservoir characteristics, and operating conditions (well spacing, injection rates, residual oil saturation). These relationships are the focus of this paper. From them, we conclude that MEOR is potentially a "high risk, high reward" process, depending on whether it can use residual oil as an in-situ carbon source for the production of recovery-enhancing chemicals. The reward in this case is that the difficulty and the logistical costs of implementing the process would approach those of implementing a waterflood. The risk is associated with the many and severe performance constraints that a microbial system would have to satisfy to take advantage of an in-situ carbon source. The current state of knowledge fails to provide satisfactory evidence that existing systems can meet the constraints identified in this study; thus, an ambitious program of research and development would be required to determine MEOR feasibility.
Influence of Differential Displacement in Invaded Oil and Gas Sands on the Induction Log
Authors: DeWitte A.J. 
Published: December 2007

It has been observed that upon invasion of a sand containing oil or gas and connate water by mud filtrate the hydrocarbons are more rapidly flushed by the filtrate than is the connate water. In time, it appears that the following displacement pattern emerges: oil (or gas) is being swept ahead by connate water which, in turn, is pushed by invading fluid. Eventually the connate water may have "banked up" sufficiently to form a zone of appreciable thickness leading the invading front. In the extreme case, Fig. 1 shows how the situation will develop:
Immediately adjacent to the borehole (radius r) there is a zone, the invaded zone proper, where the connate water has been flushed out completely and which contains only residual oil or gas and mud filtrate. This zone (extending out to a radius ri) grades more or less abruptly into the next (thickness ?,), which contains only residual hydrocarbon and connate water. Beyond it, again more or less sharply bounded, extends the virgin formation with the original interstitial water saturation Sw. The various saturations are indicated in Fig. 1.
The three zones generally will be marked by resistivity contrasts owing to their different fluid contents. As the connate water is usually more saline than the invading fluid, the second zone having a high connate water saturation forms a concentric cylindrical ring or annulus of low resistivity Rl around the borehole. It will be referred to as the "low zone." Fig. 1 shows schematically the resistivity profile.
It is clear that the phenomenon of a low zone could not occur in invaded water sands. The presence of a low zone, therefore, would be a qualitative indication of a hydrocarbon-bearing formation. Granted that the phenomenon is real, if it were pronounced enough to be detected, one might thereby have a means of locating oil or gas in the ground. This is the aim of the "displacement logging" method. In any case, the presence of a low resistivity zone will affect the reading of electric logs. Using conventional log interpretation techniques, one must be aware of this and, if necessary, correct for it.
Oil and Gas Separation IS a Science
Authors: Worley M. Steve , Laurence Lawton L. 
Published: December 2007

Introduction
Some oil and gas separations are simple while others are very complex. The oldest forms of separation were manual operations. Observation of physical differences in the components of the mixture to be separated, (color, size, shape, etc.) formed the basis for the action. The actual Separation was then accomplished by applying some force or influence to get the "sheep" into one pen and the "goats" in another.
All separations rely on some physical or chemical difference in the things to be separated. The type and amount of force or influence necessary to effect the separation is determined by these differences. Application of known physical laws of nature are very helpful. Where the known physical laws are inadequate, experience is necessary, often resulting in relatively inefficient cut and try methods with many tests. When the conditions of the separation process change, it is often necessary to drastically change the force or influence causing separation in order to maintain a high efficiency.
Oilfield lease separations vary from removing slugs of oil from gas to dehydration and hydrocarbon fractionation. However, this paper will be limited to a discussion of the mechanical separation of gases and liquids. No matter what the cause of gases and liquids occurring together, their separation cannot ever be complete. The design of separation equipment then becomes a question of balancing cost with desirable or necessary efficiency.

General Description of Types

Vertical
The most general classification of separators in the oilfield regards their shape. The first and still most popular type of separator consists of vertical cylinder with appropriate internals. The inlet is near the center of the vessel with the gas outlet near the top and the liquid outlet near the bottom. It is a very versatile separator due to its flexibility in operation.

Horizontal
Larger gas capacities can be handled in a horizontal cylinder than in the same diameter vertical cylinder. However, higher gas throughput usually leaves less space for liquid surge and for the accumulation of mud, sand and paraffin. The application of this type separator is very satisfactory for known flowing conditions in a moderately clean well-stream.

Spherical
Recently spherical separators have gained considerable popularity. The shell consists of two hemispherical heads with appropriate internal construction. They have operating versatility comparable to the horizontal separator and are very compact and easily hooked up.
A Note on Transient Two-Phase Flow Calculations
Authors: Wallick G.C. 
Published: December 2007

Introduction
Since the appearance of the paper, "Solution of the Equations of Unsteady State Two-Phase Flow in Oil Reservoirs," by W. J. West, W. W. Garvin, and J. W. Sheldon," a twofold investigation of this subject has been carried out. One objective of the investigation has been to determine the feasibility of solving such problems on a medium-size computer such as the Datatron, and the other objective has been to investigate the application of such calculations to experimental and theoretical petroleum reservoir research. In the first Datatron calculations, the fluid and rock properties published by West, et al, were used, together with the published equations describing the system. Details of the formulation not given in the original paper are discussed in the Appendix to this note. Reference should be made to the subject paper for the complete equations and definition of symbols.
An unexpected result of this investigation was the discovery that the linear solution published by West was in error. Thus, in addition to describing the Datatron solutions and to discussing certain numerical difficulties which will be encountered if one uses the published method of solution, the purpose of this note is to indicate the nature of this error.

Linear Flow
Since the linear case requires a minimum amount of scaling, a fixeddecimal point Datatron program was written for the one-dimensional flow problem and an attempt was made to duplicate the solution described by West.
As a check on the accuracy of the solution, the cumulative production at each time step was calculated using the two methods described in the Appendix. Satisfactory agreement was observed with the differences in these two values of the order of two parts in 50,000. It should be noted that the mass balance check as described is of questionable value, particularly with regard to the well pressure and saturation. This is especially true in the radial solution where pressure and saturation values near the well bore would make only a negligible contribution to the numerical integration.
Implementation of a Flux-Continuous Finite-Difference Method for Stratigraphic, Hexahedron Grids
Authors: Lee Seong H. , Tchelepi Hamdi A. , Jenny Patrick , DeChant Larry J. 
Published: December 2007

Summary
In this paper we present a 3D flux-continuous finite-difference formulation designed for flow simulation of models with nonorthogonal hexahedron grids with general tensor permeability. Our development follows that of Aavatsmark et al.,1 but we do not operate in transformed space. The new 27-point discretization formula has been implemented in a finite-difference reservoir simulator. This stencil has many desirable properties, including collapsing into a consistent form in two dimensions. We demonstrate that there are many practical situations in which neglecting the influence of nonorthogonality and general tensors results in firstorder errors in flow predictions. A rigorous implementation for this 27-point difference operator as a control-volume finite-difference method determines the upwinding of convection terms associated with multiphase computations. Results and issues associated with implementation of this operator in a conventional finite-difference reservoir simulator are discussed. As an alternative to directly solving the linear matrix associated with the 27-point stencil of the flux-continuous operator, we examine iterative methods that split the matrix into a 7-point stencil part and a remainder. The 7-point stencil part is solved by a direct or iterative method, with the remainder part updated from the previous timestep or iteration. This split operator may permit retention of the linear solver for the standard 7-point formulation while retaining nonorthogonal grid and tensor information.
A Comprehensive, Practical Approach For Wellbore Instability Management
Authors: Chen X. , Tan C. P. , Haberfield C. M. 
Published: December 2007

Summary
In the northwest shelf, a region of growing importance for oil and gas production in Australia, drilling delays and well suspension before reaching targets have occurred frequently because of wellbore instability. As a result, the economic benefits from new drilling technologies are significantly reduced because of high additional drilling costs. To improve drilling efficiency and minimize drilling costs, it is crucial to develop and apply a practical approach for optimizing wellbore instability management.
This paper initially presents guidelines, in the form of design charts, for efficient wellbore stability analysis and wellbore profile design. A comprehensive, practical approach that uses the design charts for wellbore profile design is described subsequently. The application of the design charts is demonstrated through field case studies for a range of in-situ stress regimes.
Generalized Pressure-Volume-Temperature Correlations
Authors: Glaso Oistein 
Published: December 2007

Empirical equations for estimating saturation pressure, oil formation volume factor (FVF) at saturation pressure, and two-phase FVF were derived as a function of reservoir temperature, total surface-gas gravity, producing GOR, and stock-tank oil gravity. These equations should be producing GOR, and stock-tank oil gravity. These equations should be valid for all types of oil/gas mixtures after correcting for nonhydrocarbons in surface gases and paraffinicity of oil.

Introduction
Pressure-volume-temperature (PVT) correlations are Pressure-volume-temperature (PVT) correlations are important tools in reservoir technology. These measurements form the basis for estimating the amount of oil in the reservoir, production capacity, and variations in produced gas/oil ratios during the reservoir's production life. PVT relations also are a requirement for calculating the recovery efficiency of a reservoir. Especially during the prospection phase, when only produced fluid properties are available from flowing tests, one can resort to empirically derived PVT relations. It is, of course, of great importance PVT relations. It is, of course, of great importance that such estimations be as accurate as possible. From PVT correlations published until now, Standing's work is perhaps the most widely used. His correlations were developed for California oils and make no corrections for oil type or nonhydrocarbon content. Other PVT relations developed for oils from other parts of the world, based on Standing's work, yield "best-fit lines" ordinarily parallel-shifted. Their differences can be understood from two factors not included in Standing's original correlations:crude oils from other regions have different paraffinicity - i.e., they contain varying amounts of paraffinic oil components (saturated hydrocarbons in open chains), andthe surface gases from some reservoirs contain relatively large amounts of nonhydrocarbons (CO2, N2, and H2S).
By considering the variation in these parameters, this paper develops generalized PVT correlations:
(1)
(2)
(3)
These equations were derived from laboratory data, exclusively sampling North Sea oils. However, they should be valid for all types of gas/oil mixtures after correcting for nonhydrocarbons (CO2, N2, and H2S) in the surface gases and paraffinicity of the oil as defined by the Kuop factor.
Procedure Procedure PVT Measurements PVT Measurements Six reservoirs fluid samples were made from two North Sea separator liquid and gas samples. These reservoir samples were labeled A1, B1, and C1 and A2, B2, and C2. Fig. 1 shows the experimental procedure used in the PVT analysis. procedure used in the PVT analysis. JPT
P. 785
Gas Injection Performance Review of the LL-370 Reservoir in the Bolivar Coastal Field, Venezuela
Authors: Edison T.O. 
Published: December 2007

Abstract
The Conservation Plant Tia Juana No.1 began pressure maintenance operations of the LL–370 area of the Bolivar Coastal field in Oct., 1954. Gas is being returned to the B–6 Eocene sandstone via seven injection wells.
During the first two years of operations, the average injection rate has been 133.9 MMcf/D. This represents a small excess of gas injected over hydrocarbon volume withdrawals. In the third quarter of 1956, average production was 77,583 BOPD, with a producing gas-oil ratio of 876 cu ft/bbl. Fifty-nine wells were classified as producers.
Production characteristics of the LL–370 area under pressure maintenance have been very satisfactory and superior to predicted behavior. There has been no evidence of excessive gas channelling. The vertical segregation of oil and gas in the reservoir continues to play an important part in the production mechanism. As a result, required high-gas shutoffs in up dip areas continue to be successful with the isolation of upper high-gas saturated zones by squeeze cementing and the return of the lower portion of the sandstone to low gas-oil ratio production. The average reservoir production decline is nil, with the production decline of individual wells balanced by production increases in others.
Not only will this project result in a much greater recovery of oil from the reservoir, but also a huge quantity of gas is being conserved for the future.

Geology and General Reservoir Characteristics
The LL–370 area is located in Lake Maracaibo 7 miles from the community of Tia Juana which is on the northeast shoreline of the lake. The oil-bearing formation consists of a truncated monocline of Eocene sandstone called the B–6. The total surface area covers 11,048 acres and is subdivided into four reservoirs by faults, which are only partial pressure barriers. The area is bounded by major faulting to the northeast and southwest, the Miocene-Eocene unconformity to the west at the top of the formation, and a water leg to the southeast. Additional Eocene productive units overlie and underlie the B–6, but these are isolated by extensive shale barriers and only local communication probably exists.
Chemical Analyses of Brines From Four Imperial Valley, CA, Geothermal Wells
Authors: Needham P. B. , Riley W. D. , Conner G. R. , Murphy A. P. 
Published: December 2007

Abstract
A brief report is given of studies of brine chemistry on both high- and low-salinity geothermal fields in support of a field corrosion testing program being conducted by the USBM in the Imperial Valley, CA. Specific results are reported for four geothermal wells: Mesa 6-1, Mesa 6-2, Magmamax No. 1, and Woolsey No. 1. These results demonstrate the necessity for careful reporting of the specific well operating conditions and brine sampling techniques under which the brine analyses were obtained. In particular, information related to recent well shut-in periods, total stabilization time, recent production engineering, brine flow rate from the well, and identification of nonturbulent-structure brine-flow configurations must be documented carefully with any reported analyses.
The Development and Application of a Novel Scale Inhibitor Deployment System
Authors: Collins I. R. , Jordan M. M. , Taylor S. E. 
Published: December 2007

SummaryWater-in-oil emulsions have been developed that have been shown to be a credible means of deploying scale inhibitors in a nonaqueous medium. Furthermore, the use of slowly degrading emulsion systems provides a means of trapping the scale inhibitor within porous media and allowing the subsequent controlled release of the chemical. This has been demonstrated with sandpack and core-flood experiments in which the inhibitor's lifetime, 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, nonemulsified 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 nonretained chemical waste observed with conventional squeeze treatments. The nonaqueous nature of the emulsion system allows the potential ingress of the scale inhibitor into parts of the reservoir normally denied access to an aqueous-based formulation, so it can improve contact between the scale inhibitor and the reservoir fluids on production. Furthermore, the whole treatment can be nonaqueous, allowing oil continuity to be maintained during the treatment and affording rapid well cleanup post-treatment. The efficacy of the emulsion system is illustrated with the results of a successful field trial performed on the Forties field in the U.K. sector of the North Sea.
Investigation of Sulfide Scavengers in Well-Acidizing Fluids
Authors: Nasr-El-Din H. A. , Al-Humaidan A. Y. , Fadhel B. A. , Frenier W. W. , Hill D. G. 
Published: December 2007

Summary
This paper describes the development of acidizing systems that use several different aldehyde-based sulfide-suppression chemicals in conjunction with new acid-corrosion inhibitors. Specific combinations of these chemicals have allowed the acid to dissolve the FeS and suppress the formation of H2S, yet still enable acid inhibition to industry corrosion standards.
Experimental results were compared with previously published data.1 Field acid treatments were accomplished successfully, and they resulted in large increases in gas production.
The new chemicals and procedures will allow the operators to safely remove large amounts of fouling deposits while controlling the toxic and corrosive effects of H2S much more effectively than with previously used products.
New Well-Testing Methods for Rod-Pumping Oil Wells—Case Studies
Authors: Guoynes John , Azari Mehdi , Gillstrom Robert , Friend Bret , Fairbanks Mike 
Published: December 2007

SummaryA new well-testing method that provides high-resolution bottom-hole pressure (BHP) measurement has been developed for use with rod-pumping oilwell completions. This new well-testing technique is conducted by running a high-resolution downhole pressure gauge in a specially designed carrier assembly with the downhole pump. The gauge assembly is run on the rod string without pulling the completion packers or tubulars. With the new method, a down-hole pressure system is in place while the well is flowing during the entire well test. High-resolution downhole pressure data can then be recorded during all flow and shut-in periods of the well test, providing more accurate pressure data and enhanced capability for reservoir analysis.Traditional techniques use wireline-conveyed pressure gauges, tubing-conveyed pressure-recording devices, and surface pressure-monitoring systems with an advanced fluid-level measurement to record data from pumping well completions. These methods are limited in their ability to provide accurate test results when low-pressure conditions prevail. The new method allows operators of low-pressure oilwell completions to use advanced well-testanalysis software to analyze actual pressure data to obtain reservoir properties and quantify skin damage. Data can be acquired from many types of rod-pump completions, including wells with downhole gas separators. Excellent pressure resolution has been obtained from this new testing technique with either of two downhole assembly designs depending upon the completion configuration.The results and the ensuing well-test analyses in several pilot pumping wells will illustrate that the new process permits more flexibility in well testing and allows for greater accuracy and better interpretation of data in low-pressure rod-pumping oil wells.