bluuebunny/crossref_metadata_2025 huggingface dataset:
Postbuildup Drawdown Analysis of Tight Gas Wells in the Rocky Mountains
Authors: Hale B. W. , Firth C. H. , Hansen R. C. , Murphy M. J. , Woodcox S. C.
Published: December 2007

Through the use of recently available daily volume data on Northwest Pipeline Corp.'s gathering systems, drawdowns following pressure buildups can be analyzed to predict flush production behavior of tight gas wells that have been shut in, perhaps owing to market restrictions. The "flush" rate as a percentage of the final flowing rate is a function of flowing time after the buildup. The magnitude of the initial flush rate is related to the length of time the well is shut in, to the final flow rate before shut-in, and to the age of the well. The amount of flush production increases as the well downtime increases.

Daily production histories of the wells on the Douglas Creek Arch and the Green River, San Juan, Piceance, and Uinta basins were studied. Wells within each area were grouped by geologic formation, by flow rate, and by similar periods of shut-in time. When plotted on a log-log scale, the ratio of the postbuildup rate to the stable rate shows a straight-line relationship to the drawdown time. Theoretical curves to predict flow rates after a buildup are presented that are based on the superposition of constant-pressure solutions to the flow of a real gas in a porous medium and that show a nearly straight-line rate/time relationship.

In light of the current gas surplus and the evolving spot market, the prediction of accurate short-term performance is useful in scheduling gas sales and gas transportation.
New Applications of the Pressure Derivative in Well-Test Analysis
Authors: Onur M. , Yeh N. , Reynolds A. C.
Published: December 2007

This work presents and illustrates a new general procedure for constructing type curves on the basis of a new pressure-derivative group that involves the dimensionless pressure change divided by its logarithmic derivative. When type curves based on this group are constructed, the vertical scale of the dimensionless derivative group is automatically aligned with the vertical scale of the field-data derivative group. This automatic alignment of the vertical scales simplifies type-curve matching and is advantageous for determining whether field data actually represent the solution assumed by a given type curve. It is also shown that the basic idea used in constructing the type curves can be used to ensure that proper semilog straight lines are chosen when well-test pressure data are analyzed by semilog methods.
The Laminar-Turbulent Transition in Suspension Of Rigid Spheres
Authors: Krieger Irvin M. , Dodge James S.
Published: December 2007

The laminar-turbulent transition was studied for monodisperse rigid polymer latices as functions of particle diameter and concentration at several tube diameters. Breaks in the graph of friction factor vs Reynolds number were used to characterize the transition; rates of shear were sufficiently high so that Newtonian behavior at the high shear limiting viscosity could be assumed. No abnormal behavior was noted at concentrations below 30 volume percent. At higher concentrations, suppress ion of turbulence was observed with critical Reynolds numbers rising to as high as 5,500 at 50 volume percent. No definite effect on the transition was noted due to variation of particle size or tube diameter. The type of surfactant used to stabilize the latex was found to have an important influence on the critical Reynolds number.

INTRODUCTION

For some polymer solutions and solid-in-liquid suspensions, the transition from laminar behavior to turbulence in pipeline flow has been reported to take place at unusually low1-5 and in some cases at higher than normal6,7 critical Reynolds numbers. Extreme values of critical Reynolds numbers (NRe*) have been found to range from 1 to 6,000, as opposed to the values of 2,000 to 3,500 which are obtained for ordinary liquids. Observations have also been reported of drag reduction in fully developed turbulent flow, i.e., a decreased value of the friction factor in the Reynolds number-friction factor plot6,10-14 in colloidal and polymeric fluids. In some cases, turbulence suppression (unusually large values of NRe*) was noted to occur preceding the drag reduction,6 while a normal transition was noted in other cases of drag reduction.14

To relate the occurrence of turbulence suppression and drag reduction to the molecular or particulate structure of the fluid, it is desirable to characterize the structural variables with some precision. For most colloidal dispersions and polymeric fluids, this is very difficult; particle sizes, shapes and stiffnesses may vary over wide ranges in the same sample. Recently, however, a colloidal fluid has become available which consists of rigid spherical particles of highly uniform diameter dispersed in a simple Newtonian liquid. These are monodisperse polymer latices, prepared by carefully controlled emulsion polymerization reactions. The purpose of this research was to study the transition to turbulence in these well-characterized colloidal fluids a s a function of concentration, particle diameter and tube diameter.
Hydrate Dissociation in Sediment
Authors: Sellm M. S. , Sloan E. D.
Published: December 2007

An analytical model that describes hydrate dissociation under thermal stimulation in porous media is presented. The model views the dissociation as a process in which gas and water are produced at a moving dissociation boundary. The boundary separates the dissociated zone containing gas and water from the undissociated zone containing the hydrate. A similarity solution to the conservation equations is derived, and results are presented in graphical forms that are useful in numerical computations. In particular, heat fluxes, temperature profiles, and gas pressure distributions are presented for two cases that simulate saturated-steam and hot-water thermal stimulation. A parametric study showed that the dissociation rate is a strong function of the thermal properties of the system and the porosity of the porous medium. The energy efficiency of the dissociation process, defined as the ratio of the heating value of the gas produced relative to the heat input, was also computed. For hydrate thermal stimulation, an energy efficiency value of about nine was found, which appears encouraging for natural gas production from hydrate.
Carbonate Acidizing: Toward a Quantitative Model of the Wormholing Phenomenon
Authors: Daccord G. , Touboul E. , Lenormand R.
Published: December 2007

We present the first quantitative study and complete model of the wormholing phenomenon, leading to a means of predicting and optimizing carbonate acidizing treatments. Laboratory experiments on a gypsum model system and computer simulations show that for a given geometry, wormholes can be quantified by a unique parameter, their equivalent hydraulic length. The behavior of this quantifying parameter vs. all the system parameters is studied and allows the quantitative prediction of the efficiency of an acidizing treatment. This study highlights the fractal nature of the phenomenon, which is accounted for in the equations, and the strong effect of the sample geometry. Three types of etching can be obtained: compact, wormhole type, or homogeneous. The optimum conditions for achieving die best skin decrease correspond to the creation of wormholes and can then be defined in terms of fluid reactivity and injection rate.
A Systematic and Consistent Approach to Determine Binary Interaction Coefficients for the Peng-Robinson Equation of State
Authors: Slot-Petersen Carsten
Published: December 2007

A new technique to determine binary interaction coefficients for a cubic equation of state (EOS) is introduced. The technique is physically consistent and easy to apply when an EOS is tuned to laboratory-measured PVT data. The method's simplicity provides a rational way of evaluating the sensitivity of binary interaction coefficients to fluid composition and temperature. Laboratory-measured expansion data are demonstrated to be crucial for proper determination of binary interaction coefficients for near-critical fluids.

The ability of the technique has been demonstrated by matching laboratory-measured constant-composition-expansion curves for six fluid compositions, including black-oil, volatile-oil, rich-gas-condensate, and lean-gas-condensate systems. In addition, the near-critical fluid behavior has been evaluated by matching constant-composition-expansion data for a fluid at four temperatures in the near-critical range, two on either side of the critical temperature. The literature reports that the Peng-Robinson EOS (PR-EOS) cannot predict the retrograde phase behavior of the rich-gas-condensate fluids applied in this study. This paper shows that this is because insufficient and/or improper binary interaction coefficients were used in the fluid characterization.

The method enables tuning of near-critical fluid behavior in addition to normal bubblepoint and dewpoint system behavior. Use of the proposed procedure to assign binary interaction coefficients may allow matching of renascent condensation for a near-critical bubble-point system.
Practical Model for Predicting Pressure in Gas-Storage Reservoirs
Authors: Molinard Jean-Eric , Bitoux Philippe Le , Pelcé Veronique , Tek M. R.
Published: December 2007

Optimal planning, design, and operation of gas fields in production or storage critically depends on reliable models for predicting pressures that are often based on sophisticated numerical and mathematical concepts. The pressure that prevails at a given time is a direct function of production/injection schedules, past history, and surface equipment as related to reserves and reservoir characteristics. Maintaining the pressure within prescribed limits is particularly important in underground storage to avoid pressures above a maximum for reasons of safety and migration and below a minimum for surface-equipment and contracted-deliverability considerations.

This paper presents a new way to calculate the convolution integral on which the pressure variations depend. The classic methods were long and costly to run and seldom used. Our method, which identifies this convolution integral with a finite sum of exponential terms, is much quicker and has been implemented in a program called PREPRE, usable on microcomputers. Based on a production/pressure schedule, the model is capable of forecasting the evolution of pressures in main zones of interest, such as wellbores, gathering systems, and surface equipment. The data required for the model—past production/pressure history—are matched by a special algorithm that automatically calculates the main reservoir parameters used as bases for future projections. The quick and easy-to-run program is now in use at all engineering levels at Gaz de France.
Automatic History Matching With Variable-Metric Methods
Authors: Yang P. -H. , Watson A. T.
Published: December 2007

Variable-metric minimization methods are introduced for use with optimal-control theory for automatic reservoir history matching. Variable-metric methods are more efficient and robust than the previously used minimization methods, such as steepest-descent and conjugate-gradient methods. in addition, variable-metric methods can be used effectively with parameter-inequality constraints.

Two variable-metric methods — the Broyden/Fletcher/Goldfarb/Shanno (BFGS) method and a self-scaling variable-metric (SSVM) method — are tested with hypothetical two-phase reservoir history-matching problems. Estimated rock/fluid properties include permeability, porosity, and relative permeabilities. The SSVM method is more efficient than the BFGS method when the number of unknown parameters is large. Both methods perform better than the steepest-descent and Nazareth’s conjugate-gradient methods except when the performance index is nearly quadratic, where the conjugate-gradient methods may be more efficient than the BFGS method. A constrained BFGS algorithm is tested to be successful in problems where the unconstrained algorithms have failed
History Matching With Cumulative Production Data
Authors: Watson Ted A. , Lane Scott H. , Gatens J. Michael
Published: December 2007

A measurement-error model is formulated and an appropriate weighted-least-squares (WLS) performance index is developed for history matching with cumulative production data. This performance index provides more accurate estimates of the unknown reservoir properties than the usual ordinary-least-squares (OLS) performance index.

Introduction

The use of numerical reservoir simulators to predict well performance is an important acid well-established process in reservoir engineering. The reliability of these predictions is limited by the accuracy with which the input reservoir properties are determined. The reservoir properties can be estimated by history matching measured pressure or production data, whereby parameters in a numerical reservoir simulator are adjusted so that the resulting calculated quantities m some sense match the measured data. These adjustments can be made with automatic history-matching algorithms.

Most automatic history-matching algorithms determine parameter estimates that minimize an OLS performance index given by the sum of squared differences between the measured data and the corresponding values calculated with the reservoir simulator. Knowledge of the data-measurement process, however, can be used to develop a WLS performance index that may provide more accurate estimates of the reservoir properties.

In this paper, we formulate a measurement-error model and develop a WLS performance index appropriate for history matching with cumulative production data. Residual analysis is introduced as a means for checking the validity of the measurement-error model, and two useful tests are presented for analyzing history-matching residuals.

Background

Two key steps are involved in obtaining accurate estimates of reservoir properties from history matching measured pressure or production data. The first step is to select an appropriate reservoir model for describing the physical process. The reservoir model need not describe the process exactly, but it is desirable that the differences between measured and calculated quantities (for an appropriate set of reservoir parameters) be reasonably described as random error. (The problem of model selection is considered elsewhere I and is not discussed in detail here.) The second step is to estimate unknown parameters (i.e., reservoir rock properties) within the reservoir model by minimizing an appropriate performance index so that the resulting parameter estimates are, statistically, the best estimates for the unknown reservoir properties.
Effect of Nonuniform Core Saturation on Laboratory Determination of the Archie Saturation Exponent
Authors: Lyle W. D. , Mills W. R.
Published: December 2007

A simple numerical example is presented to demonstrate that the laboratory-derived Archie saturation exponent, n, will be in error unless the data are taken with the core uniformly saturated. The numerical example is shown by a more rigorous mathematical analysis to be a special case of the general result of this study: even in an ideal case, measurements performed on nonuniformly saturated cores yield erroneous n values. The overall conclusion is that accurate determination of n requires that laboratory procedures be established to ensure that the core is uniformly saturated whenever measurements are made.
Steam Zone Growth During Multiple-Layer Stream Injection
Authors: Closmann P.J.
Published: December 2007

The development of multiple parallel steam zones of equal thickness and uniform separation is described mathematically. At small times, the growth of one of the steam zones is independent of the presence of the orders. At long times, simple relationships are obtained which describe the growth of the steam zones. Generally, it is found desirable to allow steam to penetrate the underground reservoir at a number of vertical positions if sufficient steam-generating capacity is available to maintain comparable injection rates in all the layers. If a limited steam-generating capacity is available, the larger steam zone volume is created in the single-layer system.

Introduction

The use of hot fluid injection as a means of lowering oil viscosity in petroleum reservoirs is becoming increasingly common. Prominent among the thermal techniques being used is steam injection. The basic mechanisms involved when steam flows through oil-containing porous rock have been reported by Willman et al. The growth of the steam zone when steam enters a single layer at constant injection rate has been developed by Marx and Langenheim. Frequently, an underground formation is stratified and presents a number of horizontal paths for the injected fluid to follow. This paper considers the steam zone development when a large number of highly permeable paths of equal thickness, separated by arbitrary but equal distances, are available for flow of injected steam.

THEORY

Consider the system shown in Fig. 1. A number of horizontal zones of equal thickness, hs are separated from each other at distances 1. It is assumed that there are infinitely many layers in the vertical direction. Further, important assumptions of the mathematical model to be employed are as follows.

- Steam enters all the layers at constant and equal rates.

- Steam zone temperature remains constant throughout the steam zone at the value of the input steam temperature.

- The heat capacity of the steam zone may be represented by some average value.

- Heat loss occurs normal to the horizontal boundaries of the steam zones.

- No heat is transported by conduction or convection ahead of the steam front. The formation immediately ahead of the steam zone remains at original reservoir temperature. The shape of the temperature distribution will then be that of a step which moves outward.
The Dispersive Effect of Variable Layer Lengths on Miscible Displacements in Layered Heterogeneous Porous Media
Authors: Kossack Charles A.
Published: December 2007

The effect of small- and intermediate-scale heterogeneities on miscible displacements is investigated by Monte Carlo simulations in a two-dimensional (2D) flow field containing random permeabilities and random layering. The effect of the variable layer lengths on the level of dispersion is calculated for various well-to-well distances. It was determined that the variable layer lengths add a significant amount of dispersion compared with constant layer lengths for well-to-well distances on the order of 1,000 ft [305 m] or less.
Mining at Athabasca - A New Approach to Oil Production
Authors: Spragins F.K.
Published: December 2007

The first large-scale commercial extraction plant in the Athabasca tar sands region of Canada begins operating in late 1967. The start of this plant hails the beginning of the use of mining technology in the production of crude oil on this continent. This article reports on two basically different mining approaches that could be used in a commercial tar sands, plant, and details economics and types of equipment to be used.

Introduction

Geological studies, including results from approximately 2,000 test holes, outlined the deposit and established the reserves in the Athabasca region.' The total in-place reserve of bitumen is calculated to be approximately 625 billion bbl. Of this amount, it is estimated that about 45 percent can be recovered by known techniques and transformed into a marketable synthetic crude oil. Hence, proved reserves in the tar sands total about 285 billion bbl of recoverable synthetic crude oil. Compare these reserves with two other major sources of oil in North America: conventional oil and potentially producible Colorado oil shales. Proved reserves of conventional oil are currently placed at 49 billion bbl. Total in-place reserves of shale oil are estimated at over 2 trillion bbl; but, on the basis of current technology, only 80 billion reserves of tar sand oil are more than twice the combined total of conventional oil and shale oil proved reserves.

Description of Ore Body

Though extremely variable in nature, good quality ore body in the Athabasca tar sands covers about 10,000 sq miles. The average thickness is 150 ft and the ore body reaches a maximum thickness of about 400 ft. The deposit is covered by overburden that varies in depth from a few feet to as much as 2,000 ft. Oil saturation varies from trace amounts to as much as 18 percent by weight. In a so-called good, average, potentially commercial area, the average saturation ranges from 10 to 15 weight percent. On this basis, at an average thickness of 150 ft, 1 sq mile of tar sand contains over 100 million bbl of bitumen in place - the equivalent of a major oil field. The extent of the overburden thickness determines how the bitumen might be recovered from the ore body. As a result, the main Athabasca oil deposit (Fig. 1) is generally divided into two principal areas: one where oil is recoverable by mining methods and the other where oil is considered recoverable only by in situ methods. Proved reserves of recoverable synthetic crude oil in these two areas are estimated at approximately 85 billion and 200 billion bbl, respectively. Division of the two areas has been roughly determined by the amount of overburden as related to the thickness of corresponding tar sand beds. However, this relationship is continually changing to allow for greater recoveries in the mineable area as operational techniques are improved.

JPT

P. 1337ˆ
Simulation of Big Muddy Surfactant Pilot
Authors: Saad Naji , Pope Gary A. , Sepehrnoori Kamy
Published: December 2007

An improved compositional chemical-flood simulator has been used for the study of the low-tension pilot project at the Big Muddy field near Casper, WY. Both the tracer injection conducted before injection of the chemical slug and the chemical-flooding stages of the pilot project were analyzed. Using a compositional simulator, we successfully matched not only the oil recovery but also the tracers, polymer, alcohol, and chloride histories.

Simulation results indicate that for this freshwater reservoir, the salinity gradient during preflush and the resulting calcium pickup by the surfactant slug played a major role in project success. In addition, the analysis of the effects of crossflow on the performance of the pilot project indicate that for the well spacing of the pilot, crossflow does not play as important a role as it might for a large-scale project.
Professional Contemporizing: A Personal Challenge
Authors: Stockman F.D. , Dempsey J.R. , Preston F.W.
Published: December 2007

This article outlines one major company's method of insuring that its engineers keep up with the increased expansion of technical knowledge. The continuing education program developed for personnel of one division is presented and evaluated as to methods of presentation and impact upon participants. Stressed in the article is the unique industry-university cooperation exhibited in the program.

Introduction

The problem of technological obsolescence has been recognized for many years. Practically every journal devoted to engineering or technology and many outside this area have published editorials calling attention to the accelerating rate at which knowledge is increasing. These editorials also point out the serious problem facing scientists, engineers and even managers because of their own decreasing familiarity with principles once learned and because of the growing store of human knowledge.

The Knowledge Gap

Fig. 1 dramatically illustrates the growing gap between knowledge that is available to the technical world and the individual's knowledge that is eroded through infrequent use and a fallible memory. The number of publications in the technical literature is a measure of the increase in human knowledge. In 1963 Kriegel estimated that the total volume of technical literature would double in the period from 1960 through 1967. This prediction is already a fact and corresponds to a rate of increase of about 10 percent per year compounded annually. In a like manner, Thomas Stelson, head of the Civil Engineering Dept. of the Carnegie Institute of Technology, estimated that the decay of an engineer's knowledge without renewal is approximately 10 percent per year compounded annually. The difference between these two effects, called the knowledge gap (KG), can be reduced to the following generalized equation, KG = (1 + i)n - 1/(1 + d)n, where i = fraction increase per year in man's knowledge, d = fractional decrease per year in an engineer's remembered knowledge if no subsequent training is undertaken and n = number of years since graduation.

This equation is not the most plausible or best mathematical model of obsolescence. However, it does have gross qualitative significance. If, using the criteria cited above, i = d = 0.10, then within 5 years after graduation, a person's KG can be as large as his original store of knowledge.

A much more disturbing aspect of this obsolescence is that the changes in technology within the past decade have been so extensive that the entire mission of engineering has changed.
Gravel Packing in an Abnormally Pressured Chalk Reservoirs A Valhall Field Case Study
Authors: Attard Marcel , Mathes Robert A. , Mower Lawrence N.
Published: December 2007

Gravel-packing operations in the Valhall field, offshore Norway, are performed under pressure with diesel as the work fluid and with a snubbing unit, because of the sensitivity of the reservoir rock to aqueous completion fluids. The methods used for wellbore preparation, wellbore cleanout, and gravel packing are described. These completion techniques have allowed wellhead pressures to be drawn down to much lower levels than before, resulting in significantly increased production rates.
Semianalytical Productivity Models for Perforated Completions
Authors: Karakas Metin , Tarlq S. M.
Published: December 2007

This paper discusses the effects of various perforation and reservoir parameters on the productivity (or injectivity) of perforated completions. Because of the complex, 3D flow into a spiral system of perforations, productivity analysis of perforated completions is not easily amenable to analytical treatment. This paper presents a semianalytical solution for the estimation of skin in perforated completions. Results are presented for two separate cases: the 2D-plane-flow problem, which is essentially valid at small dimensionless perforation spacings (large perforation penetrations or high perforation shot densities) and the general 3D problem, where the vertical convergent flow into perforations is significant. In these analyses, the wellbore and vertical-flow effects are quantified in terms of pseu-doskins obtained by accurate finite-element simulations. The effects of perforation damage and formation anisotropy are also included. The results provide a better understanding of the relative role of various perforation parameters in affecting well productivity. Because they are based on theoretical considerations, the correlations allow reliable estimates of the skin in perforated completions.

New relations are provided for estimating productivity of perforated completions with formation permeability damage. Results indicate the importance of angular phasing, in addition to perforation penetration, in overcoming the effects of formation damage on well productivity.
Case Study of a Stimulation Experiment in a Fluvial, Tight-Sandstone Gas Reservoir
Authors: Warpinski Norman R. , Branagan Paul T. , Sattler Allan R. , Cipolla Craig L. , Lorenz John C. , Thorne B. J.
Published: December 2007

A successful stimulation experiment was conducted in a fluvial sandstone of the Mesaverde formation at the U.S. DOE's Multiwell Experiment (MWX) Site in the Piceance basin of Colorado. The stimulation experiment consisted of stress tests, a three-well prefracture interference test, step-rate/flowback tests, a minifracture, a full stimulation treatment, borehole geophone diagnostics during fracturing, and a postfracture interference test.
Boundary-Dominated Flow in Solutions-Gas-Drive Reservoirs
Authors: Camacho-V. Rodolfo G. , Raghavan Rajagopal
Published: December 2007

The performance of wells in solution-gas-drive reservoirs during the boundary-dominated flow period is examined. Both constant-wellbore-pressure and constant-oil-rate production modes in closed systems are considered. For the constant-wellbore-pressure production mode, Arps' performance-prediction equations are examined, and predictions of future performance are shown to be strong functions of well spacing, well condition, and fluid properties. The parameters b (the decline exponent) and di (the initial decline rate) in the Arps equations are expressed in terms of physical properties. The conditions under which these equations can be used are specified. An empirical procedure to predict production rates is also presented. In the case of constant-oil-rate production, an expression to correlate the pressure distribution in the reservoir is presented. The correlating function permits us to extend the definition of pseudosteady-state flow to solution-gas-drive systems. Its use also allows the simultaneous computation of average properties (pressure and saturation) during boundary-dominated flow from wellbore information.
Planning Engineering Careers Staff and Line
Authors: Matthews C.S.
Published: December 2007

The basic aim of engineering career planning should be to provide the optimum opportunity for self-development. Planning for the early years should encourage development of technical proficiency. Later planning can then be directed either toward development of a highly qualified specialist or toward development of an administrator.

Introduction

During the last decade two factors have tended to emphasize the importance of career planning for engineers. The first of these is the growing dependence of companies upon engineering and research for economic success. The second is the shortage of engineering talent. These two factors make it imperative that the talent of each engineer be developed and used in an optimum manner optimum from the standpoint of both the individual and the company. The aims and goals of both the individual and the company must be compatible. Successful career planning strives to satisfy the need and desires of both.

To develop and use staff in an optimum manner, career planning is necessary. Career planning may be thought of as the providing of an environment conducive to the growth of an individual, and with his growth, the growth of the company. Provision of this environment the challenges, training, responsibilities, recognition and reward is the duty of the career planners. Other than to provide this environment and to provide motivation through recognition and reward, there is little the career planners can do to aid the development of an individual. The responsibility for this development rests solely on that individual. He alone can provide the necessary motivation and effort for his own growth. These two aspects then, career planning and self development, go hand in hand, and each is equally important in development of a successful career.

Helpful advice in planning the career of the young engineer has been given by Sands and Brown. Danielson has given insight into how engineers view themselves and their careers in his "Characteristics of Engineers and Scientists". This insight was gained through interviews with scientists and engineers and thus is of considerable value to the career planner. Much has been written about preparing the engineer to manage. Miller has discussed the training of engineers for management and Wilson has discussed the selection of candidates for management from the engineering ranks. From the viewpoint of aiding self-development of an engineer Douma points out what management expects of an engineer and suggests methods for achieving these expectations.

Many of the thoughts given in the sections to follow can be found in these cited references. In addition, I have drawn heavily on the thoughts of colleagues in my own and in other companies. To them must go the credit for most of the ideas that will be discussed. These ideas are directed specifically toward career planning in an exploration and production organization of large to medium size. However, many of the ideas will apply to career planning in any organization.
Scaled Physical Modeling of Steam-Injection Experiments
Authors: Klmber K. D. , Farouq All S. M.
Published: December 2007

Scaled model experiments are valuable aids to steamflood design and numerical simulation. Current scaling techniques, however, have limitations. Because the techniques require porous media and pressure conditions different from those in the field studied, pressure-dependent properties and porous media characteristics are not scaled accurately. This paper discusses scaling techniques that allow field porous media and pressure conditions to be used. The ability of scaling approaches to predict such parameters as oil production rate, temperature distribution, and pressure conditions is considered. The new approaches provide scaling options for steam processes that use additives (PVT properties must be scaled), that use pressure cycles (fluid compressibilities must be scaled), and that require use of the same porous medium as found in the field.
Some Practical Considerations in the Numerical Solution of Two-Dimensional Reservoir Problems
Authors: Briggs J.E. , Dixon T.N.
Published: December 2007

A study was made of numerical techniques for solving the large sets of simultaneous equations that arise in the mathematical modeling of oil reservoir behavior. It was found that noniterative techniques, such as the Alternating Direction Implicit (ADI) method, as well as some other finite difference approximations, produce oscillatory or unsmooth results for large time steps. Estimates of time step sizes sufficient to avoid such behavior are given.

A comparison was made of the Point Successive Over-Relaxation (PSOR), Two-Line Cyclic Chebyshev Semi-Iterative SOR (2LCC), and iterative ADI methods, with respect to speed of solution of a test problem. It was found that, when applicable, iterative ADI is fastest for problems involving many points, while 2LCC is preferable for smaller problems.

Introduction

With the advent of high speed, large memory, digital computers, there has been an increasing emphasis on the development of improved methods for simulating and predicting reservoir performance. Two-dimensional, three-phase reservoir models with various combinations of PVT effects, as well as gravity and capillary forces, are common throughout the industry. Such models are also available through consulting firms, to anyone desiring to use them. Three-dimensional models will probably be practical in only a few years.
Enhanced In-Situ Stress Profiling With Microfracture, Core, and Sonic-Logging Data
Authors: Ahmed Usman , Markley M. E. , Crary S. F.
Published: December 2007

Knowledge of in-situ stress distribution, especially in the vertical direction, is vital to hydraulic-fracture geometry calculations. The microfracturing technique is recognized as the best method to measure in-situ stress directly. The technique, however, is typically limited to very few measurements and, at times, it is impractical to break down and measure in-situ stress in bounding nonproducing layers. Also, in layers with significant stress variation, microfracture measurements can be reflective of an average value of the variations and thus can be misleading. Alternative techniques like core measurements can suffer from depth discrepancies and lack of measurements at in-situ conditions. Sonic-logging methods can provide continuous in-situ measurements of rock mechanical properties; however, modeling stresses from mechanical properties have certain limitations. In this paper, we present a method that can compensate for the disadvantages of the individual techniques with the advantages of the others and thereby create relationships that can facilitate obtaining representative and continuous in-situ stress data. Data from two wells are presented to illustrate the method's application.
Shared-Time Net Oil Measurement for Commingling Operations
Authors: McDuffie John C.
Published: December 2007

Electrical control over the discharge sequence for emulsion dumps from several separator allows one meter. probe and computer to measure separately, under pressure. the net oil from diverse ownership sources. Volumes from a lease-shared test separator may be included. Regulatory approval was granted and field use has commenced.

Introduction

Commingling untreated crude from diverse ownership sources for central treating and custody transfer commonly involves proportional allocation of central deliveries on the basis of lease net oil measurements. Equity maintenance obligation are met by using lease net oil measurement methods of equal quality, accuracy and reliability for all properties connected to the system. The difference between actual deliveries adjusted for central stock change and the sum of the lease net oil volumes for the month provides a continuing evaluation of commingling system performance.

A lease net oil measurement unit (Fig. 1) costs about $2,500 and has a capacity exceeding 2,000 B/D. Many leases produce less than 200 B/D, and many multiwell leases need facilities for well testing that involve a net oil measurement separated from the remaining lease production being handled simultaneously. High initial investments can result from inefficient applications of equipment that occur when fieldwide modernization programs are attempted with separate measuring assemblies for production and well test functions needed on all properties.

The shared-time net oil measurement method was developed to reduce both initial costs and future operating expenses required for lease measurements in commingling operations. It comprises electrical control of the sequence of discharge cycles from several emulsion source vessels that are connected to a single metering and measuring assembly. In effect, the multilease automatic custody transfer (ACT) control method is applied to the small-volume dumps under separator pressure from lease separators through a capacitance probe and meter assembly to achieve separate registration of measured net volumes by leases. The shared-time method has most of the merits and liabilities associated with its predecessor components.
A Unique Method for Perforating, Fracturing, and Completing Horizontal Wells
Authors: Damgaard A. P. , Bangert D. S. , Murray D. J. , Rubbo R. P. , Stout G. W.
Published: December 2007

This paper describes the evolution, laboratory testing, and field installation of a completion system developed to perforate, fracture stimulate, and isolate multiple zones in North Sea horizontal wells. This system is designed to reduce overall completion time and well control problems significantly and to allow selective zone control in production and restimulation phases. The field performance of this system is compared with that of previously used methods.
Combating Gas Migration in the Michigan Basin
Authors: Bour D. L. , Wilkinson J. G.
Published: December 2007

Gas migration has been a significant problem in cementing wells drilled in the Praire du Chien formation. Several types of gas-migration cementing systems have been used successfully during the past several years, but only recently has an analytical method been developed to help quantify the nature of gas-migration potential on an individual well basis. Once the probable limits of the gas flow have been established, it is possible to match an appropriate gas-migration-control cementing system for a specific set of well parameters. An important aspect of this process is computer analysis that establishes the probability of gas migration for a given set of well conditions and then selects an effective strategy for designing the cementing program for that particular set of conditions. This paper presents case histories illustrating applications of gas-migration-control cement systems with particular emphasis on the job design process.
Whole-Core Analysis by 13C NMR
Authors: Vinegar H. J. , Tutunjian P. N. , Edelstein W. A. , Roemer P. B.
Published: December 2007

A whole-core nuclear magnetic resonance (NMR) system was used to obtain natural abundance 13C spectra. The system enables rapid, nondestructive measurements of bulk volume of movable oil, aliphatic/aromatic ratio, oil viscosity, and organic vs. car bonate carbon. 13C NMR can be used in cores where the ‘HNMR spectrum is too broad to resolve oil and water resonances separately.

A 51/4-in. 13C/1H NMR coil was installed on a General Electric (GE) CSI-2T NMR imager/spectrometer. With a 4-in.-OD whole core, good 13C signal/noise ratio (SNR) is obtained within minutes, while 1H spectra are obtained in seconds. NMR measurements have been made of the 13C and 1H density of crude oils with a wide range of API gravities. For light- and medium-gravity oils, the 13C and 1H signal per unit volume is constant within about 3.5%. For heavy crudes, the 13C and 1H density measured by NMR is reduced by the shortening of spin-spin relaxation times. 13 C and 1H NMR spin-lattice relaxation times were measured on a suite of Cannon viscosity standards, crude oils (4 to 60°API), and alkanes (C5 through C16) with viscosities at 77°F ranging from 0.5 cp to 2.5 × 107 cp. The 13C and 1H relaxation times show a similar correlation with viscosity from which oil viscosity can be estimated accurately for viscosities up to 100 cp. The 13 C surface relaxation rate for oils on water-wet rocks is very low.

Nonproton decoupled 13C NMR is shown to be insensitive to kerogen; thus, 13 C NMR measures only the movable hydrocarbon content of the cores. In carbonates, the 13C spectrum also contains a carbonate powder pattern useful in quantifying inorganic carbon and distinguishing organic from carbonate carbon.
Scaling Procedures for Capillary Pressure Data at Low Wetting-Phase Saturations
Authors: Melrose J. C.
Published: December 2007

New capillary pressure data, applicable to the saturation range below 5%, are reported. The method used to obtain these data involved the determination of low-temperature nitrogen adsorption/desorption isotherms. Three types of samples were studied: Berea sandstone, a producing-reservoir sandstone, and microporous chert extracted from the producing-reservoir sandstone. The data for Berea sandstone, when scaled according to the usual Leverett J-function procedure, did not agree with previously reported data for the air/brine system. Because saturation resulting from wetting films is not expected to scale according to the J-function procedure, one cause of the disagreement could be a significant contribution of wetting films to the total saturation in the low-saturation region. Other contributing causes appear to be a 20% difference in surface area between the two sample sets used in the scaling test and a difference in the clay mineral fabric (pore structure) established under two different test conditions.
Application of Time-Series Analysis to Induced Gamma Ray Spectroscopy Logs From Two Cold Lake Heavy-Oil Observation Wells
Authors: Georgi Daniel T.
Published: December 2007

Induced gamma ray spectroscopy (IGRS) logs from two cyclic-steam-stimulation observation wells in Cold Lake were analyzed to determine the vertical resolution and repeatability of data derived from gamma rays of inelastic and capture neutron reac tions. Time-series analysis, a technique that uses the Fourier representation of the log data, was used to quantify the vertical resolution and the signal/noise characteristics of various IGRS log curves and to compute the coherence vs. spatial frequency of data collected on multiple IGRS passes. The coherence function ranges from 1.0 for perfect repeatability to 0.0 for incoherent noise. Because no real variations in the measured data were expected for the 12- to 24-hour data-collection period, any deviation of the coherence function from 1.0 is attributed to incoherent noise. Generally, coherence is high at low frequencies (large vertical scales) and low at high fre quencies (small vertical scales). By noting the frequency at which the coherence level decreases to the expected value of random noise, we can quantify the vertical resolution of a log curve.

Data analysis from these wells indicates that both the vertical resolution and repeatability of individual capture and inelastic curves differ. We found that the H-yield and capture curves have the highest vertical resolution (≈0.3 m) and the best signal/noise ratios (FSN≈30:1). In contrast, the capture Ca and Si yields are of significantly lower quality (FSN≈2:1). Only a small difference exists between the vertical resolution of the inelastic C (1.0 m) and O (1.3 m) yields, but the FSN the O yield is only one-half that of the C yield. Fortunately, the vertical resolution and the repeatability of the C/O ratio, FCO, are determined primarily by the quality of the inelastic C data. Specific to our application of monitoring heavy-oil saturations during cyclic-steam stimulation in a relatively uniform, high-porosity unconsolidated sand, we developed a simplified FCO interpretation that does not rely on the elemental yields from capture data. This linear model permits us to assess the uncertainties in computed saturations from the statistical noise in the inelastic FCO data.
Determination of Reservoir Permeabiiity From Repeated induction Logging
Authors: Tobola D. P. , Holditch S. A.
Published: December 2007

When fresh-water mud filtrate invades a gas reservoir containing a saline connate water, a low-resistivity annulus will form and propagate into the formation. Analysis of how readings from an induction log change with time can yield reasonable estimates of formation permeability. This paper describes a method and presents field data that can be used to estimate permeability from time-lapse logging data.
Simulation of Thermal-Well Sucker-Rod Pumping
Authors: Wong Arthur , Sudol Tad A.
Published: December 2007

A major problem experienced in pumping thermal wells is low volumetric efficiencies resulting from steam and noncondensable gas interference. This paper examines the results of physical simulations performed on a full-scale sucker-rod pump test facility and numerical simulations that used an equation of state (EOS) to predict theoretical volumetric pump efficiencies.
Experimental Study of Brine Injection and Depressurization Methods for Dissociation of Gas Hydrates
Authors: Kamath V. A. , Mutallk P. N. , Sira J. H. , Patil S. L.
Published: December 2007

The two most promising techniques for producing natural gas from hydrate reservoirs are depressurization and brine injection. This paper examines the dissociation characteristics of methane hydrates during these processes. A correlation for the rate of hydrate dissociation during brine injection as a function of salinity, brine temperature, brine injection rate, pressure, and hydrate/brine surface area is presented. Depressurization experiments show that hydrate dissociation results in a decrease in the rate of pressure decline and contributes significantly (15% to 70%) to the cumulative gas production.