bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Transient Testing in Reservoir Management
Authors: Kamal M.M. , Freyder D.G. , Murray M.A., 
Published: December 2007

Summary
Transient tests can be used throughout the life of the reservoir to manage and to optimize recovery of hydrocarbon fluids. This paper shows applications of various well-testing methods during the exploration, appraisal, and primary and secondary recovery phases of field projects. Single-well tests [e.g., drillstem tests (DST's) and buildup tests] are primarily used during the various stages of field development and primary recovery, whereas multiple-well tests (e.g., interference tests) are most often used during secondary recovery. A clear understanding of the type of information obtained from well tests is essential if this information is to be used properly in managing the reservoir. Examples are the different values of permeabilities calculated from single-vertical-well, horizontal-well, and multiple-well tests; the values of average reservoir pressures; and the double-porosity parameters calculated from tests in naturally fractured reservoirs. The state of the art of testing and measurement tools, acquisition systems, and interpretation methods affects the type of information obtained from well tests and should be considered by the petroleum engineer before results are used. The paper presents information to help the engineer use transient tests properly and to their fullest extent. Field examples are used when appropriate.

Introduction
The main difference between petroleum engineering and most other engineering disciplines is that the systems that petroleum engineers work with are given to them, whereas in other engineering disciplines the engineers design their systems. For example, the car engine is designed by a mechanical engineer and the structure of a building is designed by a civil engineer. Oil and gas fields are not designed or developed by petroleum engineers. They are given to them. As a matter of fact, the biggest challenge petroleum engineers face is to characterize these systems. In this regard, petroleum engineers have the same problem as mining and meteorological engineers and groundwater hydrologists. However, petroleum engineers have the added complexity, which mining and meteorological engineers do not have, of being unable to see the in-situ properties of our systems physically and measure them directly. Therefore, to obtain the physical properties of hydrocarbon-bearing formations, petroleum engineers rely on indirect measurements, such as inferring formation permeability from production data, calculating porosity from a sonic log, or determining the distance to a fault from a buildup test.
Viscometric Determination of the Onset of Asphaltene Flocculation: A Novel Method
Authors: Escobedo Joel , Mansoori G. Ali 
Published: December 2007

Abstract
A new technique for the determination of the onset of asphaltene flocculation has been developed through accurate viscosity measurements of a crude oil being diluted with a precipitating agent (n-pentane, n-heptane, n-nonane). This detection method is based on experimental observations of an increase in the viscosity of a crude oil-asphaltene-precipitating agent suspension in which asphaltene particle aggregation occurs. The key point in this development is the phenomenon of asphaltene flocculation induced by the addition of a n-paraffin hydrocarbon (i.e. n-heptane, n-pentane, n-nonane) to crude oil. The onset of asphaltene flocculation is detected graphically, and its location is enhanced by comparison of the analyte curve with a reference system. The reference system was developed using polar and non-precipitating solvents (i.e. toluene, benzene, THF).
PIERS Timings on Various Parallel Supercomputers
Authors: Keenan Philip T. , Flower Jon 
Published: December 2007

Summary
A parallel implicit research reservoir simulator (PIERS), designed for experimentation rather than production yet with many of the features of realistic petroleum reservoir models, was made available to us as a test program. This article reports results of timing PIERS on five parallel supercomputers. Graphs illustrate performance as a function of the number of processors for several problem sizes. Results indicate that parallel computation provides substantial speed improvement in reservoir simulator codes. Also, the raw timings provide an interesting comparison of machine performance, though one should remember that they apply directly only to PIERS and may vary with different simulators, compilers, operating systems, and hardware configurations.
Casing-Cost Optimization for Complex Loading Situations
Authors: Roque J. L. , Maidla E. E. , Wagner R. R. 
Published: December 2007

Summary
Casing can be the single most expensive item of an oil well and, in many cases, can be designed in a cheaper way. We present the optimization procedure, method, and algorithm to minimize cost of a combination casing string. The algorithm is general and can be used with any commercial program, provided a few modifications are made for it to be used as a subroutine. To demonstrate its use, a commercial package (that can handle complex load calculations) is tested and the results confirm the effectiveness of the optimization procedure. We present two complete examples that include cost predictions for multiple combination casing strings by use of an extensive database of price and casing properties for the 9⅝-in. (with 27 different casing types) and the 7-in. casing (with 64 different types). With such a great casing database from which to select, it would be very hard to obtain the cheapest string by trial and error.
Shocks and Bifurcations in Black-Oil Models
Authors: Herrera Ismael 
Published: December 2007

Abstract
Here, it is shown that the ‘traditional’ approach to variable bubble-point problems is not consistent, because it does not incorporate important kinds of shocks that occur in black-oil models. This paper contains an exhaustive analysis of shocks that black-oil models may develop and it is shown that a considerable variety of them may indeed occur; a bifurcation mechanism is also exhibited. Except for the class of shocks described by Buckley-Leverett theory, all other kinds may be developed even if capillary forces are present. Modelers must be aware of these pathologies in order to handle them properly. This paper also supplies a basis for the developement of consistent black-oil models, applicable to variable bubble-point reservoirs. The analysis and results here presented, also contribute to a better understanding of limitations imposed by the simplifying assumptions of black-oil models.
Automatic Lease Operations - Weeks Island Field, La.
Authors: Northern Turner P. 
Published: December 2007

Introduction
The upward trend of oil production, which usually amplifies producing problems, combined with a search for improved economic and efficient methods have revealed the possibilities of automatic producing facilities along the Gulf Coast. In 1952 the Gulf Coast District of the Gulf Refining Company's Houston Production Division initiated a plan for testing and appraising various types of automatic lease equipment for use in bay fields and offshore operations. Under this plan a small lease was selected, where operating and flowing conditions are similar to coastal and offshore wells. By such a method the performance of all equipment could be observed and evaluated prior to more complex situations. Gulf's Provost Cyr Unit lease was selected for the installation. It consists of 158.70 acres and is located on the east flank of the Weeks Island field, in Iberia Parish, La. The first well was completed in March, 1950. When the drilling program terminated in January, 1953, production had been established from five wells. The calendar daily allowable for the ninth of June, 1953 was 1,254 bbls. All wells are produced by natural flow through positive chokes at the well-head. Flowing tubing pressures range from 800 psi to 1,800 psi. Two of the wells are producing salt water. API gravity of the crude ranges from 30.9 degrees to 35.0 degrees. Producing equipment on this lease consists of four 1,000 bbl stock tanks, one 500 psi oil and gas separator, two 125 psi oil and gas separators, one emulsion-type heater-treater, and one horizontal precipitator. All are connected with adequate manifolds and piping to serve their specific purpose in production of oil and gas. Electricity is available at the lease from a utility company.

Requirements of Equipment
Basic requirements must be met in order to completely produce a lease automatically. First, some type of tank switcher is necessary which will transfer flow from one tank to another when a predetermined fluid level (full) is reached. The set-up must insure that flow cannot be transferred to tanks either full or on pipeline run. Control must be maintained over the opening and closing of the wells. Wells must be closed in when:no tank space is available,a well is produced on a pre-determined schedule, ora failure occurs in the producing equipment.
This should be an automatic operation, accomplished by closing in the well preferably near the well-head. In the event of a pumping well, the prime mover must be stopped.
Production-Based Effective Vertical Permeability for a Horizontal Well
Authors: Yamada Tomimo , Hewett T. A. 
Published: December 2007

Summary
The presence of a stochastic distribution of impermeable shale sheets strongly affects the production performance of a horizontal well. Oil recovery is drastically reduced, and its uncertainty is dramatically increased for a reservoir with high shale density and long correlation range. Construction of a probability distribution of the oil recovery based on many stochastic images requires extensive work and computation time. However, that probability distribution can be approximated easily if a single ranking parameter is assigned to each realization. Conventional effective vertical permeability, keV, which is based on vertical single-phase flow, was tested first because it governs horizontal-well productivity. This attempt was unsuccessful because of the inappropriate representation of inner and outer boundary conditions applied to the domain. Production-based effective vertical permeability, keV,p, which honors both inner and outer boundary conditions, was tried next. It successfully ranked each realization in terms of oil recovery after 10 years with excellent accuracy. The correlation between keV,p and recovery is independent of the shale density or correlation range. This study shows that honoring the appropriate boundary conditions to obtain a representative permeability is extremely important. The conventional permeability renormalization technique, in which either no-flow or constant-pressure boundaries are applied to coarse grids, fails for this reason.
Fluid Flow in Vertical Fractures From a Point Source
Authors: Clark P.E. , Zhu Qinsheng 
Published: December 2007

Summary
Flow into a fracture from a point source recently has been the focus of attention in the petroleum industry. The suggestion has been made that, in this flow configuration, convection (gravity-driven flow) would dominate Stokes' -type settling for determining final proppant distribution. The theory is that when a dense fluid flows into a fracture filled with a less dense fluid from a point source, the density of the fluid will force it to the bottom of the fracture. This clearly happens when the two fluids have low viscosity. However, viscosity of both the fluid in the fracture and the displacing fluid and nonuniformities in the fracture influence displacement process significantly. Results presented in this study clearly show the effects of viscosity and fracture nonuniformity on the convective settling mechanism.

Introduction
While this paper deals with the convection mechanism for proppant transport in a vertical fracture, a review the history of proppant transport and placement is appropriate to help understand the experimental modeling of fracture flow better. Kern et al. reported the first model study. Their model was small, and their study dealt primarily with equilibrium velocities (the velocity where the height of the settled bed ceases to change). The authors used no crosslinked fluids and presented only limited data on thickened fluids. This paper laid the groundwork for the concepts of bank buildup and equilibrium velocity, concepts that dominated early thinking on proppant transport.
Babcock et al. made the next contribution to laboratory fracture-flow modeling. Their model was longer than that used by Kern et al., and they used several concentrations of guar and different sizes and types of proppant, fracture widths, and flow rates for their study. Their results were reported in terms of equilibrium bed heights, settling velocities, and equilibrium velocities. Schols and Visser reported data from a model that was ˜ 10 ft long and 1 ft high. Their work focused on equilibrium velocity and bank buildup and resulted in a set of equations that could be used to predict bed height and length.
Most of the early work with fracture models involved determining equilibrium velocities and equilibrium bed heights for "bankbuilding" fluids. Models constructed after 1975 were used to study particle settling. Clark et al. constructed a 12-ft-long by 4-ft-high model. This model was used to determine settling velocities in guar and hydroxypropyl guar (HPG) solutions. This paper includes what appears to be the first report of particle clustering during settling after shutdown. Sievert et al. report further data from the use of Clark et al.'s model. They observed that pack-growth rate as a function of proppant concentration in non-Newtonian fluids was nonlinear and that doubling of the viscosity of non-Newtonian fracturing fluids would result in a several-fold decrease in particle-settling velocity.
The Mechanical Stability of Propped Hydraulic Fractures: A Numerical Study
Authors: Asgian M.I. , Cundall P.A. , Brady B.H.G. 
Published: December 2007

Summary
Proppant is sometimes produced along with hydrocarbons in hydraulically fractured petroleum wells. Sometimes 10% to 20% of the proppant is backproduced, which can lead to damaged equipment and downtime. Furthermore, proppant flowback can lead to a substantial loss of fracture conductivity. A numerical study was conducted to help understand what conditions are likely to lead to proppant flowback. In the simulations, the mechanical interaction of a large number (several thousand) individual proppant grains was modeled with a distinct-element-type code. The numerical simulations show that hydraulic fractures propped with cohesionless, unbonded proppant fail under closure stress at a critical ratio of mean grain diameter to fracture width. This is consistent with published laboratory studies. The simulations identify the mechanism (arch failure) that triggers the mechanical instability and also show that the primary way that drawdowns (less than ˜75 psi/ft) affect proppant flowback is to transport loose proppant grains in front of the stable arch to the wellbore. Drawdowns &gt;75 psi/ft are sufficient to destabilize the arch and to cause progressive failure of the propped fractures.

Introduction
Proppant back production can significantly affect well economics because of (1) loss of fracture conductivity [unpropped sections of fractures tend to close under stress (Figs.1 and 2)], (2) the damage it inflicts on equipment (i.e., abrasion of pumps, casing, and wellhead), and (3) downtime and expense required to clean up the wellbore.
Refs. 1 through 3 address technical issues involved in the flowback of proppant. Ref. 1 presents experimental data that show how various properties and conditions (e.g., closure stress, fracture width, proppant embedment in the fracture walls, grain-size distribution, relative inclination of the fracture walls, and drawdown) affect the mechanical stability of cohesionless, unbonded proppant packs. It also raises fundamental questions regarding the process of proppant production (e.g., why does the transition from stability to instability occur over a narrow range of fracture widths and why do proppant packs in the laboratory fail at much smaller fracture widths than are known to exist in the field).
A numerical study presented in this paper addresses some of these fundamental questions. The objectives of the study are to help understand the mechanical process of proppant back production and to show how various field conditions and proppant properties affect the propensity for proppant flowback. This is accomplished by means of numerical simulations of proppant on a grain-size scale.
WELCOM: Evolution of Chemical Monitoring of Drilling Fluids and Industrial Perspectives
Authors: Aquilina Luc , Brach Michel 
Published: December 2007

Summary
During the last ten years, the Bureau de Recherches Géologiques et Minières (BRGM) has carried out five experiments to monitor drilling fluids chemically. BRGM has developed a methodology adapted specifically to this type of work and has acquired considerable experience in interpreting the results. The results of these scientific investigations could have industrial applications. The purpose of this paper is to describe the evolution of the techniques BRGM used and the principal results acquired.
Evolution of Wetting Alteration by Adsorption From Crude Oil
Authors: Liu Yu , Buckley J. S. 
Published: December 2007

Summary
Crude oils are complex mixtures of organic molecules, some of which can adsorb onto high-energy surfaces, altering mineral surface wettability. In cores, the extent of wetting alteration varies with oil and brine compositions and saturations as well as with aging time and temperature. Previous studies on flat surfaces have demonstrated rapid interaction between oil components and solid surfaces that can vary with the composition of the intervening brine phase. This study is designed to investigate interactions that occur after initial oil/solid contact. Wettability alteration is assessed by measurement of contact angles between pure fluids after removal of bulk crude oil. The influences of aging time, temperature, and fluid compositions have been considered.
Adsorption appears to proceed in two stages. Initial exposure of wet surfaces to oil produces weakly water-wet conditions. Longer aging may produce oil-wet surfaces or, in some cases, a return to more water-wet conditions. This second stage of the adsorption process may continue for days or even weeks and is influenced by temperature and fluid compositions. Desorption of crude oil components can occur when a treated surface is re-exposed to brine.
Drilling Mud Control in the Southwest Louisiana Coastal Area
Authors: Claus C.R. , Standish G.A. 
Published: December 2007

Abstract
Since March 1945, the Magnolia Petroleum Co. has drilled 39 wells in Southwest Coastal Louisiana. All wells were drilled within a comparatively small radius, but the area provides a large variety of problems. The deepest well drilled was 13,518 ft, and the total depth averaged 10,977 ft. Throughout this period drilling mud control and types of mud handled were:phosphate,red lime (late conversion),red lime starch (early conversion),red lime starch oil emulsion,precision controlled low alkalinity-low lime content, andgel muds for completion purposes.
Improvement has been obtained in effecting some or all of the following:more rapid penetration,reduction in drilling hazards,better evaluation of cores and logs, andbetter completions.
The geological sequence of zones penetrated range from recent sediments at the grass roots through the Frio section. Anticipation of high-pressure zones and incompetent formations entails precision control of drilling mud weights, and the unconsolidated nature of the various zones requires constant attention to the filtrate, viscosity, and gel strength values. In the Chalkley field, particularly, this combination of problems exists, where the formation pressures and overburden weight density values are in very close proximity. Design of casing and drilling mud programs must be modified to fit each well.

Introduction
Field and research work on drilling fluids has made constant progress, enabling operators to prospect progressively deeper horizons. Numerous papers have been written on the theoretical aspects of drilling fluid development, but in the field engineers have found it difficult to evaluate the role of specific mud constitutents when dealing in terms of thousand barrel mud systems. For that reason field data is somewhat lagging in technical report writing. However, applications of new techniques in the field have usually paralleled, and in numerous instances preceded, research work.
On the Subject of Reserve Estimates in Water-Drive Gas Reservoirs
Authors: Chierici G.L. , Cuieci G.M. 
Published: December 2007

In his article in the JPT Forum, William Hurst resumes his discussion of our paper on reserve estimates in water-drive gas reservoirs. We can only make reference to our previous reply and add the following comments.1. The aims of our paper were:to show that the simultaneous determination of gas reserves and aquifer characteristics from the past history of waterdrive gas reservoirs can result in more than one set of solutions; andto evaluate the actual indetermination range of gas reserve estimates for some reservoirs that have a well known past history, where a water-drive had been ascertained, as they had been partially invaded by the water encroaching from edge partially invaded by the water encroaching from edge or bottom aquifers.
2. The detailed geological description of the gas reservoirs of the Po Valley, Italy, was presented in 1957 at the "Symposium on Gas Fields of Western Europe". A feature that is common to almost all of these reservoirs is their being in contact with aquifers of good permeability. 3. Contrary to William Hurst's statement that "the authors claim that they have water-drive reservoirs, but with their computer programs, they are unable to establish this effect", the presence of a water encroachment (calculated according to the van Everdingen-Hurst method) is clearly shown (Ref. 2, Table 3) in all sets of solutions presented for the reservoirs considered. The actual occurrence of a water encroachment into the reservoirs in question 2 has been proved by the following facts:a. In three of the reservoirs (BM-A, R-A, S-F)new wells have been drilled in the last few years. It has been ascertained that the water/gascontacts, at the moment the wells have been drilled, were 220 ft, 65 ft and 1 10 ft, respectively, abovetheir initial position in the three reservoirs inquestion.b. In BM-A field, 3 years after shut-down thereservoir pressure increased by 361 psi from 1,252to 1,613 psia, the initial reservoir pressure being1,927 psia.c. Some time after the production period consideredin our paper a marked deviation from linearityeventually occurred in the p/z vs Gp curve of allthe reservoirs considered. 4. Hurst's discussion seems to imply that linearity in the initial part of the p/z vs Gp curve is enough to prove a depletion-type of performance. That this does not prove a depletion-type of performance. That this does not apply has already been shown by others. There is no ground to support William Hurst's interpretation that the reservoirs in question are depletion-type and, as an unlucky consequence, to validate his "indication that considerable gas reserves may still exist" in those gas reservoirs of the Po Valley which have been abandoned. Of course, we are confident we are able to distinguish between a well needing only a work-over and a well that has been completely invaded by the encroached water (incidentally, we never wrote "logged up").
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