bluuebunny/crossref_metadata_2025 huggingface dataset:
An Analytical Model for One-Dimensional, Three-Component Condensing and Vaporizing Gas Drives
Authors: Dumoré J. M. , Hagoort J. , Risseeuw A. S.
Published: December 2007

An analytical model based on the method of characteristics is presented for the calculation of onedimensional (1D), three-component condensing and vaporizing gas drives. The model describes (1) mass transfer between oil and gas, (2) swelling and shrinkage, (3) viscosity and density changes, (4) gravity stabilization, and (5) rock/fluid interaction. The main assumptions of the model are local thermodynamic equilibrium and the absence of dispersion, diffusion, and capillarity.

Example calculations are presented that bring out the main features of both condensing and vaporizing gas drives and also indicate the importance of mass transfer between the phases. In the special case of "developed miscibility," the model predicts a piston-like displacement having a complete recovery at gas breakthrough.

The main applications of the model are in (1) conceptual studies of gas drives in which mass transfer plays an important role and (2) the calibration and checking of numerical reservoir simulators for multicomponent, multiphase flow.
Petrophysical Parameters Estimated From Visual Descriptions of Carbonate Rocks: A Field Classification of Carbonate Pore Space
Authors: Lucia F.J.
Published: December 2007

The permeability, capillary properties. and m values of carbonate rocks are related to the particle size, amount of interparticle porosity, amount of separate vug porosity, and the presence or absence of touching vugs. Particle size. percent separate vug porosity, and the presence or absence of touching vugs usually can be determined visually. The amount of interparticle porosity is more difficult to determine visually and is done best by subtracting the visual estimate of separate vug porosity from the measure of total porosity obtained from wireline porosity logs or laboratory measurements. In the absence of touching vugs, the permeability, in values, and capillary properties can be estimated if the particle size, percent separate vug porosity, and total porosity are known. No acceptable method has been developed to estimate visually the permeability of touching vugs. A classification of carbonate porosity is proposed based on the data presented. This classification is intended to be used in the field or for routine laboratory description. Interparticle porosity is classified according to particle size and the dense or porous appearance of the interparticle area. Vuggy porosity is classified according to type of interconnection. Separate vugs are connected through the interparticle pore space and classified by percent porosity. Touching vugs are connected to each other and classified by presence or absence.

Introduction

The role played by the visual description of pore space in carbonate rocks in the field evaluation of a well has changed dramatically over the past 25 to 30 years. The change has been brought about by the development of new and improved logging techniques. The Archie classification, developed in 1952, was the only method at that time to estimate the amount of porosity in uncored wells. The development of porosity wireline tools (neutron, sonic, and density) has provided us with effective ways to measure wellbore porosity. The permeability of a carbonate rock, however, can not be measured directly by wireline tools and it is not directly related to total porosity. Visual descriptions of the pore geometry, therefore, still are needed to estimate permeability. While the Archie classification provides some insight into permeability relationships, new data presented here allow more accurate estimates. In addition, the relationship between pore types and Archie's m value and capillarity can be described. The role that the visual description of pore space can play in the evaluation is to describe factors that cannot be obtained from logging techniques but that are needed together with the logs to calculate saturations and productive capacities of the reservoir rock. This paper describes the basic geologic parameters that control the petrophysical parameters and shows how they are related.

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P. 629^
Type-Curve Matching Techniques With Error Sensitivity Numbers
Authors: Morita Nobuo , Gray K. E.
Published: December 2007

This paper presents several error sensitivity numbers suitable to general type-matching curves given as log-log graphs with dimensionless parameters. Also, the utility and application of type curves with tables of error sensitivity numbers are illustrated with an example type curve proposed by Wattenbarger and Ramey.1,2 The reliability of each parameter obtained by this type curve is discussed, as well as its appropriate use in terms of proper number of cycles to be used and proper data points.
A Simple Approach to Pressure Distributions in Geometric Shapes
Authors: Larsen Leif
Published: December 2007

General and simple algorithms are presented to determine the coordinates of sufficient numbers of image wells to compute pressure distributions and Matthews-Brons-Hazebroek (MBH) functions for rectangles of any shape, triangles with internal angles (30,60,90), (45,45,90), (60,60,60), and (30,30,120)°, rhombi with acute angle 60°, and hexagons. A simple extension to compute their slopes also is included. The well must be located at the center of the hexagon, on the short diagonal of the rhombus, and on the corresponding height of the last triangle. For the other shapes there are no restrictions on well location. Any combination of no-flow and constant-pressure outer boundaries can be handled for pressure distributions in rectangles and (45,45,90)° triangles, but only special cases are possible for the other shapes.
A Study of Plane, Radial Miscible Displacement in a Consolidated Porous Medium
Authors: Bentsen R.G. , Nielsen R.F.
Published: December 2007

This paper reports an experimental study of the transition zone in plane, radial, miscible, liquid displacement in a homogeneous porous medium. The viscosity of the displacing liquid is greater than that of the displaced liquid in most of the runs, to avoid viscous fingers. A consolidated natural medium was chosen so dispersion would be high enough for measurement. Porosity was 19.5 per cent and permeability was 310 md. The material was Berea sandstone in a circular sector 1.9 cm thick and 91.4 cm in radius. Compositions of produced fluids were determined with a chemical oscillometer in a manner similar to that described by Peffer. Fluid distribution in the plane, radial miscible displacements agreed with the mathematical theory of Raimondi, et al for favorable mobility ratios.

Introduction

Numerous papers have been published on theory and experiments relating to miscible fluid displacement in porous media. Some excellent reviews have appeared in the petroleum production literature, and it is not necessary to repeat the references listed in these reviews. Most previous experimental work has involved unidirectional flow, although the theory has been extended to radial and multi-directional flow. The experimental work involving multi-directional flow generally has been related to problems other than the extent of the transition zone and the fluid distribution therein, except for some cases where viscous fingering or heterogeneity of the porous media were predominant factors. This paper reports an experimental study of the transition zone in plane, radial, miscible, liquid displacement in a homogeneous porous medium. The viscosity of the displacing liquid is greater than that of the displaced liquid in most of the runs, to avoid viscous fingers. A consolidated natural medium was chosen so that the dispersion would be high enough for measurement.

THEORY

A solution of the plane, radial dispersion equation for the injection of a finite slug of a second fluid is

(1)

If injection of the second fluid is continued indefinitely (infinite slug) the second error function becomes unity, and the equation can be written

(2)

In the experiments to be described, the molecular diffusion constant D can be neglected in the theory. Then differentiation of Eq. 2 gives, for C= 0.5,

(3)

If it is assumed that, in a finite slug, the maximum concentration of slug material occurs at a time half way between the times at which the head and tail pass a given point, then Eq. l gives

(4)

where R is the radius of the undiluted slug just after injection.

EXPERIMENTAL

All runs were carried out on a slab of Berea sandstone in the shape of a circular sector, 1.9 cm thick and 91.4 cm in radius.

SPEJ

P. 1ˆ
Water Sensitivity of Sandstones
Authors: Khilar Kartic C. , Fogler H. Scott
Published: December 2007

Experimental and theoretical studies have been carried out to elucidate the mechanism of water sensitivity of Berea sandstone and to quantify a number of important parameters. Based on the results of a number of novel experiments, a physical model has been developed. In this model, clay particles are released only when the salt concentration falls below a critical salt concentration. These colloidal clay particles remain dispersed in fresh water and are carried with the flowing fluid until they are captured at a local pore constriction, thereby decreasing the permeability. A mathematical model based on this mechanism has been developed. This model contains two parameters stemming from the rate equations of the release and capture of clay particles. Correlations of these parameters with flow rate and temperature are presented.
Correlation of Capillary Number Relationships for Sandstone
Authors: Chatzis Ioannis , Morrow Norman R.
Published: December 2007

Capillary number relationships are presented for displacement of both residual and initially continuous oil from water-wet consolidated sandstones having permeabilities that varied over about two orders of magnitude. It was found that the critical displacement ratio, (ΔP/Lσ)cr, for the onset of mobilization could be correlated with sample permeability. Relationships between normalized reduced residual oil saturation and capillary number (taken as kwΔP/Lσ) also were correlated satisfactorily. For sandstones, capillary numbers for displacement of continuous oil were lower than values for mobilization of discontinuous oil for down to 50% of normal waterflood residual. Thereafter, capillary number relationships for the two types of displacement were indistinguishable. Conditions for complete recovery of residual oil correspond to values of (kwΔP/Lσ) of about 1.5 × 10−3 as compared with about 2 × 10−5 for onset of mobilization.
Mathematical Model of the Diamond-Bit Drilling Process and Its Practical Application
Authors: Ziaja Malgorzata B. , Miska Stefan
Published: December 2007

With several limiting assumptions, a mathematical model of the diamond-bit drilling process has been developed. The model represented by an instantaneous rate-of-penetration equation takes into account the reduction in penetration rate during drilling resulting from bit wear. The model has been tested both under laboratory and under field conditions. The comparison of the theoretical and experimental results has shown reasonable agreement. A method for estimating rock properties also has been established. Using this method, we can find the so-called index of rock strength and the index of rock abrasiveness.
Shale Oil Nears Competitive Level with Domestic Petroleum
Authors: Miller Ernest P. , Cameron Russell J.
Published: December 2007

Introduction

Advancements in oil shale technology, coupled with the sharply rising expense of finding and producing petroleum in the United States, have closed the economic gap between the two fuels. A realistic comparison of shale oil and petroleum costs presents certain problems, for the real meaning of posted crude prices is difficult to ascertain. Marginal crude-producing areas, discovered before the steep rise in exploration and producing costs of the past dozen years, are now being exploited. This report briefly reviews technical activities in oil shale and presents discussion and comparisons of shale oil production economics with crude petroleum prices.

Review of Technical Activities

Production of oil from shale has been an art and science in various parts of the world for more than a century. In the United States, prophecies of acute domestic petroleum shortages have been made periodically throughout this century. Previous flurries of activity in shale have soon diminished because of economic facts of life. Present efforts in shale development are the most significant to date and may finally indicate serious entry into the field - again because of economic facts.

Foremost among current and recent publicized oil-shale activity have been the multimillion-dollar project of the Union Oil Co. of California at Grand Valley, Colo.; the U. S. Bureau of Mines installation at Rifle, Colo., from 1944 to termination of that program in 1955; and the pilot plant retorting work being carried out by the Denver Research Institute (DRI) for the past several years. Most major oil companies hold oil shale land and represent varying degrees of interest and effort within their own organizations. Brazil has vast shale deposits and produces only 30 to 40,000 B/D of petroleum within her own borders - about 20 per cent of present controlled requirements.

Most current development work is directed toward the retorting phase of oil shale processing. USBM's mining work at Rifle is generally accepted as having adequately demonstrated that step to furnish basic information. Modern refining technology is such that shale oil can be processed to desired end products using processes with results and costs that are reasonably predictable.
The Propagation of Oil-Moving and Solubilizing Components of Broad Equivalent-Weight Sulfonate Systems in Micellar Floods
Authors: Chan Albert F. , Gupta Surendra P.
Published: December 2007

This paper presents a novel method of characterizing the broad equivalent-weight (BEW) sulfonates composed of two pseudosulfonate fractions that behave as the oilmoving and the sulfonate-solubilizing components. The terms quasi-monosulfonate and quasi-disulfonate are used to characterize these oil-moving and solubilizing components, respectively. Such a description of BEW sulfonates allows determination of sulfonate concentration in the flowing phases as well as the quantity adsorbed on the porous medium, and permits modeling of the sulfonate retention and transport behavior. Furthermore, the paper shows that the performance of a BEW sulfonate system in which a lower-phase microemulsion environment is predominant can be predicted by using independently measured input data, which include interfacial tension (IFT), fluid viscosity, and sulfonate retention isotherm.
A Numerical Study of Chemical Flooding—Comparison With Experiments
Authors: Van Quy N. , Labrid J.
Published: December 2007

This paper describes an enhanced oil recovery (EOR) model involving use of chemical additives. The model is as general as possible in light of present phenomenological knowledge. It takes into consideration diffusion, exchanges between fluid phases, exchanges between fluids and solids, and convection (including gravity, relative permeabilities, viscosities, interfacial tensions (IFT's), and mobility reduction by polymers).

Its main properties are (1) three-phase flow (aqueous, oleic, and microemulsion); (2) that each phase can be represented by a mixture of seven components; (3) overall flow is one dimensional (1D), but the sections of space considered may be constant or variable; and the porous medium may be heterogeneous.

In addition to its compositional nature, which is required for describing changes in phase properties, the model must also account for ionic environment, loss of chemicals, and capillary number distribution. For these reasons, it differs from conventional multicomponent models.

It is designed for simulating any EOR problem involving the addition of suitable chemicals to fluids to be injected continuously or in successive slugs. The model has been tested successfully by two-phase flow, four components (water, oil, polymer, and surfactant plus alcohol), and Winsor Type I environment experiments. It can be adapted to more and more complex phenomenological situations, depending on availability of data.
In-Situ Leaching of Crownpoint, New Mexico, Uranium Ore: Part 2—Laboratory Study of a Mild Leaching System
Authors: Vogt T. C. , Strom E. T. , Dixon S. A. , Johnson W. F. , Venuto P. B.
Published: December 2007

This paper describes laboratory leaching studies involving Crownpoint uranium ore samples and a mild leaching system. Batch leach tests with sodium bicarbonate solution and either high-pressure oxygen or low-pressure hydrogen peroxide gave qualitative data used to estimate leach rate and potential recovery. Using pseudo-first-order rate constants derived from the batch test data, ore leachability was characterized as fast, intermediate, or slow. It was observed that leach rates varied by a factor of 50 for samples taken from different areas at Crownpoint; samples from the same ore trend often varied by a factor of 10. Packed-column and core-leach tests with oxygen at pressures up to 800 psig (5520 kPa) provided more quantitative estimates of leach rate and uranium recovery. Batch test results were correlatable with leach rates and uranium recoveries in packed-column or core tests. In ore samples where uraninite was the predominant uranium mineral, leach rates and recoveries were high. In samples containing coffinite, leach rates were generally lower than those with uraninite. Very low leach rates and recoveries were encountered where coffinite was intimately associated with carbonaceous material. However, the slow leaching rates are not caused by differences in reactivity of coffinite and uraninite. Mineralogical studies before and after leaching using electron microprobe analyses indicated that exposed coffinite crystals are dissolved easily, but finely disseminated coffinite crystallites persist after leaching if they are encapsulated in the carbonaceous matrix. Slow-leaching ores that did not respond to the mild oxidant system are called "refractory."
An Improved Method for Measuring Fluid Loss at Simulated Fracture Conditions
Authors: McDaniel Robert Ray , Deysarkar Asoke Kumar , Callanan Michael Joseph , Kohlhaas Charles A.
Published: December 2007

A test apparatus is designed to carry out dynamic and static fluid-loss tests of fracturing fluids. This test apparatus simulates the pressure difference, temperature, rate of shear, duration of shear, and fluid-flow pattern expected under fracture conditions.

For a typical crosslinked fracturing fluid, experimental results indicate that fluid loss values can be a function of temperature, pressure differential, rate of shear, and degree of non-Newtonian behavior of the fracturing fluid.

A mathematical development demonstrates that the fracturing-fluid coefficient and filter-cake coefficient can be obtained only if the individual pressure drops can be measured during a typical fluid-loss test.
Well Test Analysis for Wells Producing Layered Reservoirs With Crossflow
Authors: Prijambodo R. , Raghavan R. , Reynolds A. C.
Published: December 2007

The pressure response of a well producing a two-layer reservoir with crossflow is examined. Virtually all studies on the response of a well in multilayered systems with crossflow claim that after a few hours of production these systems behave as if they are single-layer systems.

A careful examination of the early-time performance of a well in a reservoir with crossflow indicates that its behavior is remarkably different from that of an equivalent single-layer system and is influenced significantly by the degree of communication. It is important to understand short-time behavior, since the time span of virtually all pressure buildup tests encompasses the duration in which a layered reservoir with crossflow may not behave as if it were a single-layer system. Thus, interpretations of pressure buildup data based on single-layer theory can be erroneous.

In this study, we show that the flowing pressure response of a well at early times can be divided into three flow periods. The first period is one in which the reservoir behaves as if it were a stratified (no-crossflow) system. This period is followed by a transitional period. The response of the well during this period depends on the contrast in horizontal permeabilities and on the degree of communication between the layers. During the third period, the reservoir can be described by an equivalent single-layer system.

An examination of the time ranges of the various flow periods indicates that, unless tests are designed properly, most of the interpretable pressure buildup data would be measured during the time the well response is influenced by the transitional period.

The influence of the skin regions on the well response is examined. The significance of the estimate of the skin factor obtained from a pressure test is discussed. We show that the nature and the magnitude of the skin regions and the size of the reservoir determine the applicability of conventional semilog procedures to systems with interlayer communication.
Thermodynamic Modeling of Phase and Tension Behavior of CO2/Hydrocarbon Systems
Authors: Sahimi Muhammad , Davis H. Ted , Scriven L. E.
Published: December 2007

The gradient theory of inhomogeneous fluid is used to predict phase splits and compositions, interfacial composition profiles, and interfacial tension (IFT) of liquid-liquid, liquid-vapor, and liquid-liquid-vapor equilibria in binary and ternary mixtures of CO2 with propane and decane. The theory's input are the equation of state (EOS) of homogeneous fluid and the influence parameters of inhomogeneous fluid. An efficient computational algorithm is presented for simultaneously generating phase behavior, critical points, interfacial composition profiles, and tension between the phases. Most calculations are made with the Peng-Robinson EOS and the geometric mixing rule for the influence parameters. Use of other EOS and alternative schemes for choosing the influence parameters is explored.
Preliminary Experimental Results of High-Pressure Nitrogen Injection for EOR Systems
Authors: Ahmed T. , Menzie D. , Crichlow H.
Published: December 2007

Miscible-displacement processes have generally been recognized by the petroleum industry as an important enhanced oil recovery (EOR) method. Nitrogen flooding has become an attractive method for economical EOR.1–3 Since no previous studies have been undertaken to observe miscibility conditions directly during their development in an oil reservoir, a research program was initiated to investigate experimentally the mechanism by which miscibility could be achieved in a reservoir model undergoing high-pressure nitrogen injection. Several experiments were conducted in a low-permeability, consolidated sandpacked stainless-steel tube 125 ft long and 0.435 in. in diameter. The apparatus was designed to allow sampling at selected locations along the core tube enabling researchers to investigate fluid behavior during the process.

A more-detailed representation of the nitrogen displacement process is formulated and the graphical chromatographic results are presented to illustrate the nitrogen miscibility in consolidated cores.
Scanning Electron Microscopy and Core Analysis for "Mini" CO2 Flooding Operations in the Hospah Formation of the Miguel Creek Field, McKinley County, New Mexico
Authors: Kupperman Glenn Stuart , Ward Brenda Marie , Blanks Gary L.
Published: December 2007

A combined laboratory evaluation that included scanning electron microscopy (SEM), energy dispersive spectrometry (EDS), X-ray diffraction, petrography, and core flow/permeability damage analysis was performed on core samples from the Hospah formation of the Miguel Creek field, McKinley County, NM. The objective of this study was to determine what type of recovery method would be the most beneficial and economical for a pilot five-spot, 8-acre plot.

The geologic evaluation of the core samples indicated tremendous lithologie differences in this formation. The rock types contained appreciable amounts of migrating clays (kaolinite and illite). Various degrees of pyrite, total clay content, and residual hydrocarbon saturation also were observed.

According to the operator, a conventional waterflood operation attempted during 1974–76 proved unsuccessful. This study indicates that the most likely reason was migratory fines. A foam fracturing technique also was attempted in June 1980 in the Miguel Creek field, with similar negative results. The conclusions from this study suggested that the use of a clay-stabilizing surfactant preflush in a "mini" CO2 waterflood could be an advantageous method of controlling migrating fines and swellable clays.
The Niobrara Gas Play: Exploration and Development of a Low-Pressure, Low-Permeability Gas Reservoir
Authors: Brown C.A. , Crafton J.W. , Golson J.G.
Published: December 2007

The Niobrara gas play in eastern Colorado, northwestern Kansas, and western Nebraska is a successful economic development involving an integrated, interdisciplinary exploration and exploitation strategy. This comprehensive study of the Niobrara formation gives a concise description of methods for exploration, development, production and evaluation of the Niobrara reservoirs.

Introduction

In 1912, the Osborne and Dunn Co. encountered a strong flow of gas in the Niobrara formation while drilling the Goodland No. 1 well (Sec. 24-T8S-R40W) near the town of Goodland, KS. The well subsequently was plugged and abandoned. In the 1930's and 1940's, several small Niobrara gas wells were drilled in the Goodland field area by Industrial Gas Co. and others for local use only.

The Beecher Island field discovery well was Midfields No. 1 well (Sec. 14-T2S-R43W) in Yuma County, CO, drilled in 1919 by the Midfields Oil Co. It had estimated flow rates of up to 2 MMcf/D (57×10-3 m3/d) of gas. In the 1920's, four additional Niobrara wells were drilled in Beecher Island; however, connection to a pipeline could not be justified. By 1970, two of the four dry holes drilled to deeper formations had gas shows while penetrating the Niobrara formation.

Following a study in 1972 of the known gas shows in the Beecher Island field, Midlands Gas Corp. and Mountain Petroleum Corp. air-drilled six wells in Beecher Island. Five were completed without stimulation as producers and then were connected to a pipeline. The wells averaged 20 Mcf/D (565 m /d) each, which at $0.35/Mcf ($0.35/30 m) was uneconomical. However, they proved the existence of significant gas reserves.

Further investigation revealed many resistivity log anomalies and reported gas shows in the Niobrara of eastern Colorado and western Kansas. However, the play began when, in early 1974, the new high-quality foam fracture stimulation process was used for the completion of the Beecher Island field State 1-29 well (Sec. 29-T2S-R42W). The well had a prestimulation drillstem test rate of only 5.6 Mcf/D (160 m3/d). After the treatment, it had an initial potential of 721 Mcf/D (20×10 M /d), with a sustained rate of more than 150 Mcf/D (4250 m3/d).

The play now extends from Chadron, NE, and south to Kit Carson County, CO (Fig. 1). The major concentration of drilling remains in the original producing area in Yuma County, CO, and in Cheyenne and Sherman counties, KS. Since 1974, 919 Niobrara wells have been drilled, of which 454 are producers in more than 60 fields; 465 wells are dry holes. At this time, very few fields are developed fully.

Geology and Gas Origin

The Niobrara formation chalks were deposited during the last major transgression of the western interior Cretaceous sea, which extended from the Gulf of Mexico to the Arctic Ocean. The lower member of the Niobrara is the Fort Hays, which is 40 to 85 ft (12 to 25 m) thick. The upper member is the Smoky Hill, which averages 600 ft (180 m) (Fig. 2).

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P. 2863^
Stimulation Design for Short, Precise Hydraulic Fractures
Authors: Smith Michael B.
Published: December 2007

This report discusses the philosophy, design, and implementation of small, precise, hydraulic fracture stimulations as applied in a micellar pilot in Salt Creek field, located in central Wyoming.

Wellbore damage and relatively low permeability were resulting in low injection/withdrawal rates in the 1-acre [4046-m2] pilot in this field. Unchanged, these low rates would extend the pilot life by an unacceptable amount and also result in oil production rates too small for meaningful analysis. Accordingly, the decision was made to fracture-stimulate the pilot wells on the basis of reservoir stimulation, which snowed that the creation of very short (90 ft [29.5 m] tip-to-tip) fractures would not "harm" evaluation of the pilot's performance.

Normal stimulation practices in this area would not give the control desired for this pilot situation to create a 90-ft-[29.5-m-] long fractures in a formation with a thickness of 100 ft [32.8 m]. The procedure that was developed consisted of measuring bottomhole treating pressure (BHTP) while pumping the pad, using these data to calculate the required sand-laden fluid volume, and then switching directly from pad to heavy sand concentration.

A postappraisal of the treatments showed that BHTP measurement was necessary since the pressure varied from theoretical behavior for each well. After initial pressure increases that were predictable, a critical pressure was reached for each case and the value of this pressure (which governed slurry requirements) varied by 25% from well to well. The effects of the treatments also were evaluated with postfracture pressure falloff tests (PFOT). The stimulations performed generally were successful (fracture design/PFOT lengths of 156/146, 90/100, 134/150, and 55/20), confirming that it is possible to create short, controlled hydraulic fractures by using the procedure outlined in this paper.
Management's Use of Petroleum Engineering Evaluations
Authors: Houchin John M.
Published: December 2007

Management is normally confronted with more profitable investments than it has funds available. It is only through accurate engineering evaluations that management can determine which proposed investments will result in the greatest company profit.

Why Engineering Evaluations Are Important

Engineering evaluations required and used by management must contain reserve estimates along with predicted rates of recovery and the economics of the proposal.

Several types of data are needed. The engineer needs knowledge of formation characteristics including types of rock, net pay thickness, porosity, permeability and unusual characteristics such as fractures. He must know about proration and allowables. Formation fluid characteristics such as initial gas in solution, reservoir volume factors, and relative permeability are important. Gas-oil ratios, pressure, and production performance history are important factors in the later life of a reservoir.

Profit Making Aspects

Management's interest in reserve estimates goes beyond the number of barrels of oil and rates at which it is produced. This interest includes evaluating the profit making aspects of a proposal. The most convenient and reliable yardstick for evaluating investments is the annual rate of return calculated by the discounted cash flow method. This method takes into account fluctuations in income over the life of an investment, the effect of federal income taxes, amortization and all other taxes and costs.

The rate-of-return concept calculated using predicted recoveries, and reserves from prospective properties and in the drilling of wildcats should be used to a greater extent, especially in these days of high lease costs in active areas of operations. A wiser selection of wildcat acreage will be made if consideration is given to rate-of-return studies from actual production experience in pools which have similar geologic formations and drilling and operating practices. The risk in leasehold and wildcat investments is being reduced appreciably by those managements who are looking at their engineering evaluations using comparative reservoir experience as well as the geological and geophysical justifications.
An Ultrasonic Global Inspection Technique for an Offshore K-Joint
Authors: Rose J. L. , Fuller M. C. , Nestleroth J. B. , Jeong Y. H.
Published: December 2007

The catastrophic collapse of several offshore platforms has spurred the development of nondestructive inspection techniques for offshore structures. Presented here are the concepts of an ultrasonic global inspection technique. Also presented are the results of feasibility studies conducted on 119−, 110−, and ⅓-scale model K-joint models using this technique for early detection of damage. The technique takes advantage of the geometry of tubular joints to give global ultrasonic coverage of a joint while employing a similarity-coefficient-based algorithm for actual damage detection. The data from the scaled models indicate a correlation between the value of the similarity coefficient and the extent of induced damage. The results are encouraging for further development of the technique for field use.
Miscible Drive - Its Theory and Application
Authors: Clark Norman J. , Shearin H.M. , Schultz W.P. , Garms Kenneth , Moore J.L.
Published: December 2007

Petroleum industry research organizations have for a number of years placed considerable emphasis on investigations regarding various techniques of recovering more oil from reservoirs. Out of this effort has emerged the miscible-drive process which to date shows great promise for future oil recovery operations. The process can actually be subdivided into several kinds of operations; however, the basic principle of all is that hydrocarbon materials such as propane, LPG, or gas are injected into a reservoir under such conditions that fluid capillary forces are reduced to zero and resultant displacement of oil is essentially complete in those pore spaces through which injected materials move. Consideration is given in this technique to subsequent recovery of valuable injected materials and to leaving the reservoir essentially filled with dry gas at abandonment. Success in application of these techniques will depend almost entirely on proper engineering and geological evaluation. The engineer must not only understand the basic principles involved in miscible-drive techniques, but also must recognize where various techniques are applicable and be able to cope with the many factors that require careful consideration to assure proper design and conduct of complicated operations such as these. This paper discusses the various miscible-drive techniques, their place in present day oil and gas operations, factors that require detailed consideration in determining their applicability and feasibility with regard to given reservoirs, and the approach to the application of these techniques to production operations.

Introduction

It has been recognized for a number of years that oil does not produce itself, but instead requires energy from some other source to cause the movement of oil to the wellbore where it is produced. The type and availability of energy will to a great degree determine the general magnitude of the percentage of the initial oil that can be produced through means inherent in the reservoir producing mechanism itself. Depending upon the source of energy, only a small or a large percentage of the oil may be produced. Average recovery expectancy of oil from all reservoirs in the U. S. by primary means has been placed in the order of about 35 per cent of initial oil in place. An enormous amount of oil is thus left in the reservoirs awaiting only the development of new methods of extraction before the petroleum industry can realize the recovery of a part of this residual oil left underground.
Miscible Drive Field Applications in the Seeligson Field
Authors: Wright H.T. , Die R.R.
Published: December 2007

Introduction

Substantial research has been devoted to the possibilities of greatly increasing oil recovery by injecting into reservoirs a gas known to be soluble in the crude. Various requirements, advantages, and disadvantages of such a displacement have been theorized or indicated by laboratory work. In the final analysis, however, extensive field data are required to evaluate satisfactorily the requirements and merits of a recovery mechanism. In this connection an experimental enriched gas-drive pilot project of full reservoir size was initiated in Zone 20-B of the Seeligson field during March, 1957.

The Zone 20-B reservoir was selected as an injection project for several reasons. A supply of propane for enriching the gas was available from two gasoline plants in the immediate area. Unitization was not required because the zone has only one operator and one royalty interest. The reservoir has a reasonable configuration, the sand is comparatively uniform, and development is adequate. Another major reason for selecting Zone 20-B is that the saturated crude from this reservoir is similar to substantial reserves in the immediate area so that the data obtained will be useful in the evaluation of other projects.

Geologic and Reservoir Data

The Seeligson field is located in Jim Wells and Kleberg counties of Southwest Texas. The field is on a large anticlinal structure and contains numerous productive sands varying from 4,500 to 7,500 ft in depth in the Frio and Vicksburg formations. Zone 20-B, the reservoir selected for enriched gas injection, is a sand development lying at a depth of 6,000 ft in the basal portion of the Frio formation. Fig. 1, a cross section through three wells in the field, illustrates Zone 20-B and other sand sections. The reservoir has an average sand thickness of 14 ft and a productive area of 585 acres.
Miscible Drive Field Applications in the Parks Field
Authors: Marrs Doyle G.
Published: December 2007

Introduction

A review of the field-wide miscible displacement program being utilized in the Parks field unit is presented to assist others in the oil industry in evaluating the application of the miscible displacement process.

Geological Description

The structure is a long, gently sloping, deep-seated anticline trending north and south. The anticline is traversed, in a northwest-southeast direction, by a major fault which has divided the structure into two segments. This discussion is confined to the larger east segment. No significant oil accumulation was found on the west side of the fault. The productive area on the east side of the fault has an average net pay thickness of 21 ft (see Fig. 1). The Bend section of the Pennsylvanian formation in the Parks area is composed of tan, finely crystalline limestone, interspersed throughout with shale stringers varying from mere shale partings to shale beds several feet in thickness. Porosity of the Bend limestone is described as fossiliferous, with voids having been created as the result of leaching of microfossil shells. Intercrystalline porosity is negligible.

Production History and Data

The primary producing mechanism was solution gas drive. Cumulative production to Jan. 1, 1958, was 3.5 million bbl of oil, 21,000 MMcf of gas, and 35,000 bbl of water. The bottom-hole pressure declined from an original 4,567 to 1,760 psig in July, 1957, and the produced gas-oil ratio increased from 1,800 to 16,000 cu ft/bbl. Primary production and shrinkage of the reservoir oil has created a present gas saturation of approximately 25 per cent.

The average porosity for the net pay is 6 to 8 per cent; the average interstitial water saturation is 30 to 35 per cent; and the average permeability is 3 md.

The reservoir oil was undersaturated at the original reservoir pressure, 4,567 psig. The bubble point pressure is 3,508 psig. The original dissolved gas-oil ratio was 1,817 cu ft/bbl, and the initial formation volume factor was 2.014 reservoir bbl/STB. The reservoir temperature is 174°F. The oil gravity is 45°API, and the initial reservoir oil viscosity was 0.22 cp.
Miscible Drive Field Applications in the Panhandle Field
Authors: Relph J.L.
Published: December 2007

Introduction

The Hughey B lease, the north one-half Section 129, Block 3, T&GN RR Survey, Gray County, Tex., is the location of a pilot project of slug LPG injection to improve the existing gas drive. The Hughey B lease is one of the leases in the West Pampa Repressuring Assn. that has been returning produced gas to the Brown Dolomite reservoir since 1946.

The pilot project consists of two input wells that were gas injection wells and the 12 producing wells that are direct or diagonal offsets to the input wells. Table 1 contains information on the pilot area.

The LPG slug was taken from the Cities Service gasoline plant approximately 1 mile west of the Hughey B lease. In the spring of 1957, it was apparent that there would be products produced at the plant in excess of market demand and storage facilities. Plans were made to utilize this otherwise wasted material to test the recovery possibilities of LPG injection in this type reservoir. Laboratory research on samples of LPG and Brown Dolomite crude found no adverse effects on mixing the two liquids. Displacement tests on a core are being run to aid in the operation of the pilot project.

LPG - Gas Injection

It was determined that slug LPG injection would be the most advantageous mechanism and in July, 1957, liquid butane injection started in Hughey B No. 10. LPG injection continued until a slug consisting of 76,076 bbl of butane and 53,074 bbl of propane had been injected.

On Nov. 13, LPG injection ceased in Hughey B No. 10 and gas injection resumed at approximately 500 Mcf/D. LPG injection in Hughey B–23 was started immediately and a volume of 50,412 bbl of butane and 50,433 bbl of propane was injected to Jan. 22, 1958. Gas injection was then resumed and the LPG injection in the pilot area was completed. To April 1, 1958, 230,625 bbl of LPG and 100 MMcf of gas have been injected into the pilot area since project initiation.

The daily production performance from the Hughey B lease has always been erratic and well tests vary considerably. The best method of detecting stimulation of the producing wells in the pilot area has been by fluid-level surveys. Static fluid-level surveys on two producing wells, Hughey B–4, the north offset, and Hughey B–11, the west offset to Hughey B–10, indicated approximately 800 ft more fluid than was present before the project started. Production tests on these wells gave Hughey B–4 82 BOPD, up 71 BOPD from the normal rate, and Hughey B–11, 96 BOPD, up 61 BOPD. Testing continues on the lease and at latest report, three more wells are producing some increased oil. Further testing will show how much these wells are stimulated. Increased oil production to April 1, 1958, is estimated at 8,930 bbl.

The stimulation of producing wells is believed to be justification for assuming that this project will recover oil that would not be produced by continuing the previous recovery mechanism. The volume of this oil cannot be estimated at this time and for this reason, no economic evaluation can be made.
Experience in Gravel Packing Long, Perforated Intervals in Deviated Holes (includes associated papers 12886 and 13309 )
Authors: van Ballegooyen J. , Giap Kiat Tan , Seng Kong Tan
Published: December 2007

This paper presents the philosophy, criteria, and technique used in arriving at the gravel-packing method for Sabah Shell Petroleum Co. Ltd. 's(SSPC's) operations. It also analyzes and discusses problems and efforts to resolve them with the aid of an evaluation tool.

Introduction

All the gravel-packing operations were done in the South Furious field completions. The field is located offshore northwest Borneo, some 120 miles northeast of Labuan Island. The completion intervals comprise a series of inter bedded sands and shales with porosities between 20 and30% and permeabilities of 100 to 500 md. Hydrocarbon occurrences vary from 1,100 to 7,600 ft subsea (ss). Local experiences pointed out the need to gravel-pack most of the proposed completions. Previous efforts at gravel-packing intervals, typically of less than 50 ft, had been satisfactory. However, premature screen outs were noted in intervals that were initially only some 100 ft long. The difficulties increased with increasing interval length(single gross interval of 653 ft being the longest) and deviation angle(maximum of 52deg.) and also with differences in the permeabilities of the different sand layers. To understand the nature of the problem, a neutron log was used to locate the position ofthe gravel and the presence of voids.

The placement technique was modified by trial and error until an acceptable technique was achieved. This paper discusses the evolution of this technique.

Completion Philosophy

The limited areal extent of the sands, which stacked to form very long hydrocarbon columns, resulted incompletions across large groups of sands having common pressure regimes. Two-phase vertical-flow calculations indicated optimal tubing size to be 3 1/2 in. We set 9 5/8-in. casing across completion intervals with 4 1/2- and 6 1/8-in. wire-wrapped screens(WWS) across bottom and subsequent intervals. The coupling of the 3 1/2-in. tubing restrictedthe use of the 4 1/2-in. screen to the bottom interval. The internal gravel-pack technique was preferred over under reamed gravel pack because of greater flexibility, satisfactory in flow performance (local experience), and shorter installation time. To alleviate the need for future recompletions and high work over costs. all possible oil sands were included in the initial completion. To ensure seal integrity and minimize complexity, there was a maximum of only four zones per well.

Sand Failure Criteria

Experience in northwest Borneo indicated that sand control is required for zones with sonic transit times At >90usec/ft. In South Furious field, this was placed at+5,000 ft ss.

JPT

P. 2079^
Drainage of Aqueous Foams: Generation-Pressure and Cell-Size Effects
Authors: Rand Peter B. , Kraynik Andrew M.
Published: December 2007

The physical characteristics of aqueous foams make them excellent candidates for drilling fluids in geothermal formations.1,2 A major concern in this application is the foam-forming ability of a surfactant system in the harsh geothermal environment. While investigating the stability of various foams in an autoclave, we observed a dramatic increase in drainage times with increasing generation pressure, even though the liquid volume fraction of the foam was held constant. This effect appears to result from a decrease in cell size with increasing autoclave pressure and therefore is an artifact of the foam generation technique in which the pressure path of the foam changes with autoclave pressure. A theoretical model of drainage predicts that drainage times should increase with decreasing cell size, as observed. These results emphasize that proper control of cell size can have a substantial effect on the apparent stability of a foam.
Geothermal Reservoir Simulation Using Nonequilibrium Thermodynamics
Authors: Nguyen V. V. , Pinder G. F.
Published: December 2007

A phenomenological interpretation of the evolution of a steam/water system is proposed from a nonequilibrium mixture perspective. This type of thermodynamic behavior is structurally stable on the basis of catastrophe theory and therefore offers an unorthodox alternative approach to the simulation of geothermal reservoirs. Use of this approach in a one-dimensional (ID) finite-difference simulator yields results that can be compared with a traditional numerical scheme.
The Rheological Properties of Prudhoe Bay Oil and the Effects of a Prolonged Flow Interruption on its Flow Behavior
Authors: Economides Michael J. , Chaney George T.
Published: December 2007

The rheological properties of Prudhoe Bay oil, as with any other mixture of hydrocarbons, are markedly affected by the lowering of temperature. The Trans Alaska pipeline traversing the state in a north-south direction is subjected to severe ambient temperatures during the winter months. A prolonged flow interruption would result in inevitable heat losses from the trapped crude oil. The temperature decline would cause a significant alteration of the flow behavior. A fundamental heat-transfer study and laboratory measurements were combined to forecast the rheological response and subsequent start-up requirements of Prudhoe Bay oil in gathering lines and in the Trans Alaska pipeline.