bluuebunny/crossref_metadata_2025 huggingface dataset:
Improving Polymer Injectivity at West Coyote Field, California
Authors: Shuler P. J. , Kuehne D. L. , Uhl J. T. , Walkup G. W.
Published: December 2007

This paper presents a case history where laboratory and simulation results were used to model a single-well polymer injectivity field test in the West Coyote field and to improve injectivity in a subsequent field test. The polyacrylamide used in the first test exhibited low injectivity. Laboratory studies were performed to identify the causes of low injectivity and to model the field test physically. Laboratory core data and reservoir properties were used in a mathematical model to calculate the polymer injectivity, which closely matched that observed in the field.

The low polymer injectivity at West Coyote was a result of formation damage caused by the polymer and low-salinity polymer makeup water and the high resistance factor developed by the polymer. These problems were overcome by using a lower-molecular-weight polyacrylamide, preshearing the polymer solution before injection, and increasing the salinity of the polymer makeup water. These improvements resulted in a 50% increase in injectivity during the second polymer injectivity field test at West Coyote.
Water-Influx Modeling of the Svartsengi Geothermal Field, Iceland
Authors: Gudmundsson J. S. , Olsen G.
Published: December 2007

In this paper, lumped-parameter models are presented for confined and unconfined liquid-dominated geothermal reservoirs without recharge and compared to production data from the Svartsengi geothermal field in Iceland. They show that recharge or water influx is likely to affect the field's drawdown with time. Three petroleum reservoir water-influx methods.are then presented for steady-state, pseudosteady-state, and unsteady-state aquifers encroaching into the geothermal reservoir. History matching shows that the reservoir/aquifer system is best described as unsteady state and radial, with the aquifer boundary taken at infinite distance.
Improved Treatment of Dispersion in Numerical Calculation of Multidimensional Miscible Displacement
Authors: Peaceman D.W.
Published: December 2007

In previous papers by this author on numerical calculations of multidimensional miscible displacement, some simplifying assumptions were made in writing the dispersion term of the differential equation. It was assumed that the flow vector were essentially parallel to the x-axis. However, in most multidimensional miscible displacements, the flow vectors are not so simply oriented with respect to the coordinate axes. This paper derives the correct dispersion term for the more general case; gives a difference approximation for the dispersion term; and derives the stability criterion for the corresponding explicit difference equation.

Introduction

The differential equation for solvent concentration in miscible displacement is:

.........(1)

where v is the bulk flow velocity, C is concentration and D is the dispersion coefficient. For simple isotropic dispersion, D is a scalar quantity. however, dispersion in porous media is not generally isotropic since it is usually greater in the direction parallel to flow than in the direction transverse to flow. Hence, D must be treated as a tensor. Scheidegger has shown for an isotropic porous medium that, for the dispersion tensor to be invariant under coordinate transformations, there can be no more than two independent dispersivity factors; these are the longitudinal dispersivity D1, which acts in the direction of flow, and the transverse dispersivity Dt, which acts in the direction perpendicular to flow, In general, both D1 and Dt are functions of the magnitude of the flow velocity. In previous papers, the author made some simplifying assumptions in writing the dispersion term of the differential equation. It was assumed that the flow vectors were essentially parallel to the x-axis and, therefore, that the dispersion term. D C could be replaced by the sum:

...... (2)

However, in most multidimensional miscible displacements, the flow vectors are not so simply oriented with respect to the coordinate axes. The purpose of this paper is to derive, without using tensor notation, the correct dispersion term for the more general case, to give a difference approximation for the dispersion term, and to derive the stability criterion for the corresponding explicit difference equation.

DERIVATION OF DISPERSION TERM

Let x, y be a fixed coordinate system and at any point let v be the velocity vector with magnitude v and angle, measured counter-clockwise from the x-axis. Let q be the vector which describes the rate and direction of flow of solvent due to dispersion. Consider a rotated coordinate system r, s where r is in the direction parallel to v, and s is in the perpendicular direction. Then, for an isotropic medium:

SPEJ

P. 213ˆ
Pressure-Transient Analysis for Fractured Wells Producing at Constant Pressure
Authors: Guppy K. H. , Kumar S. , Kagawan V. D.
Published: December 2007

Past solutions to many well-test problems considered the wells to be produced at a constant rate. It has become apparent that there are many cases in which constant-pressure production is more common. Gas wells, geothermal wells, and even oil wells are operated at constant pressure during most of their producing life.

Constant-pressure well-test data for fractured wells are commonly analyzed using type-curve-matching techniques that may result in nonunique solutions. By the use of a semianalytic model, a set of correlations has been developed that reduces the nonuniqueness problem, as well as accounts for well-test data in which the well is produced at high rates.

When applied to high-flow-rate wells, this technique uses the bilinear flow period to determine an apparent fracture conductivity for constant-pressure drawdown or buildup tests. These apparent values can be corrected to true conductivities by the use of correlations presented in this study. These relationships were derived through computer simulation of a wide range of possible situations.

In summary, this paper presents for the first time a technique that analyzes buildup and drawdown data from wells produced at constant pressure with turbulent flow in the fracture. Two example applications, one for buildup and one for drawdown, are included to demonstrate the use of these techniques.
Summary of The Alcohol Slug Process for Increasing Oil Recovery
Authors: Gatlin Carl , Slobod R.L.
Published: December 2007

The primary purpose of this investigation was to define the basic mechanism of the miscible displacement of oil and water from porous media by various water-driven alcohol slugs. The first portion of this investigation deaIt with use of a single alcohol (isopropyl) as the slug material. In later studies two distinct process variations were developed, wherein the total alcohol slug consisted of two or more slugs of different alcohols. The first of these utilized methyl alcohol and isopropyl alcohol, while the second variation used normal butyl alcohol and methyl alcohol as the composite slug. These techniques were shown to have distinct advantages over the simple, onealcohol process and represent an important extension of the original process.

The porous medium used in this study was I-in. diameter, 100-ft long, unconsolidated core. The porosity of this system was 35 per cent, and the permeability was approximately 4 darcies. Total pore volume of the core was 5,700 cc. All displacements were conducted at an injection rate of 5 to 6 cc/min, which corresponded to a frontal advance of 5 to 6 ft/hr. Most of the alcohol slug runs were initiated in a previously waterflooded system; however, several were conducted at irreducible water saturation. The oils used were naphtha, SoItrol-C and Kendex 0837, having viscosities of 0.52, 1.5 and 16 cp at 20°C, respectively. Kendex 0837 was used in only one run. Individual displacements were conducted by injecting the desired size and type of alcohol slug, which was then driven or displaced in turn by water. The basic data obtained from each run were the composition-time histories of the effluents. From these data it was possible to study the displacement mechanism and to determine the oil recovery. Data from 30 such runs were obtained.

In the first series of runs, isopropyl alcohol (IP A) was used as the alcohol slug. This alcohol is completely miscible with either oil or water; however, miscibility of the three-component system (oil-water- IP A) requires a relatively high concentration of IP A. Hence, the displacement is not of the miscible type unless the IP A content is maintained above some critical value. Slug volumes ranging from 8 to 16 per cent of total core pore volume were used in several runs in both the naphtha and Soltrol-C systems. Complete (100 per cent) naphtha recovery from a previously waterflooded core required a 13.5 per cent IP A slug. Complete SoItrol recovery required a 17 per cent slug under the same conditions.
Simulation of Gas/Liquid Flow in Slug Catchers
Authors: Bos A. , du Chatinier J. G.
Published: December 2007

For the optimization of existing multiple-pipe-type slug catchers and the development of novel configurations, small-scale model tests are used that use a two-liquid system with a density ratio representative of that of the gas/liquid phases in practice. The technique has been validated by field tests with an existing slug catcher.
Solutions of Heat- and Fluid-Flow Problems in Naturally Fractured Reservoirs: Part 1 – Heat-Flow Problems
Authors: Satman A.
Published: December 2007

This is the first of two papers concerning the solution of heat- and fluid-flow problems in naturally fractured reservoirs. It deals with the temperature behavior of a naturally fractured reservoir. The naturally fractured reservoir model used assumes unsteady-state heat transfer between the matrix and fracture systems. The model consists of a production (or injection) well fully penetrating a reservoir containing equally spaced horizontal fractures.

The problem of hot- or cold-water injection into a naturally fractured reservoir is considered, and a solution describing the temperature distribution in such a reservoir is given that can be used to locate the thermal front and to estimate the reservoir volume affected by the injection process. It also has application in estimating the amount of heat that can be extracted from a geothermal reservoir as the result of a reinjection process. The results of a field test support the validity of the model.
The Nonlognormality of the OCS Lease Bidding Data
Authors: Keating Jerome P.
Published: December 2007

A simple nonparametric technique is given that can detect deviations from normality in the right tail by combining studentized maxima over samples of the same size. The technique is successfully applied to the ten bid oil and gas lease data on the outer continental shelf of the United States.
Formation Damage Tests of High-Density Brine Completion Fluids
Authors: Morgenthaler L. N.
Published: December 2007

Laboratory core flow tests were conducted to assess the formation damage potential of brines with densities between 13.4 and 19.2 lbm/gal [1606 and 2301 kg/m3]. Unfavorable fluid/rock interactions are not evident. Recovery of oil permeability is slow but complete, in agreement with established displacement theories. Observed damage effects are the result of the instability of the brine or incompatibility with water in the cores. The effectiveness of ZnBr2 in preventing impairment suggests acid-soluble impairing materials.
Multiple-Rate Analysis for Pressure-Buildup Tests in Reservoirs With Tectonic, Regional, and Contractional Natural Fractures
Authors: Aguilera Roberto
Published: December 2007

Approximate solutions of radial flow theory are presented for pressure-buildup analysis in naturally fractured reservoirs with tectonic, regional, and contractional fractures. The solutions allow handling of variable rates before shut-in, as well as unsteady-state interporosity flow. Although approximations, these solutions are apparently satisfactory for most cases of practical interest.
Effects of Acids on Gravels and Proppants
Authors: Cheung S. K.
Published: December 2007

The effects of acids on the integrity of gravels and proppants should be considered in acid treatments. This paper reports on the influence of acid type, acid concentration, and contact duration on the acid solubility of five sands and bauxitic materials. The effects of the acids on the mechanical strength and the size distribution of the solids are determined. We found that intermediate-density and low-density bauxites (IDB and LDB) are very soluble in HF acid and that sintered bauxite is weakened by HF acid.
Engineer's Oil, A Challenge and An Opportunity
Authors: Bell John S.
Published: December 2007

Introduction

In recent years, especially with the advent of the space age, attention has been focused on man's accelerating technological progress. The great majority of this progress has come in the last 100 years, and each generation has seen more progress than the last, Because the petroleum industry has played a vital part in providing the stimulus for this pattern and has continued to keep pace with man's ever increasing demand for energy, we have good reason to be proud of our industry.

However, in providing for America's future progress, which is largely dependent on an abundance of low cost energy, technological advances in the domestic oil industry far greater than in the past will be required. Our engineers have the challenge-the opportunity-to provide these advances.

Present Status of the Industry

As the domestic oil industry enters its second century, it is beset by problems of great magnitude. The threat to our continued growth and prosperity is probably greater today than at any other time in our colorful history. The total result of all our problems is demonstrated by the decline in rate of return on investments from 27.9 per cent in 1948 to 10.2 per cent in 1958. Investors in our industry today are receiving only about one-third the yearly income per dollar invested that they did just 10 years ago. Both the ability and willingness of investors to furnish the risk capital for continued expansion and growth is threatened, This decreased rate of return results from a combination of low production rates, rising costs and lagging prices.

Investments and Production

The domestic industry made capital expenditures of more than $40 billion to expand resources between 1948 and 1958 exclusive of refining and marketing expenditures. Close to 500,000 wells were drilled, reserves of 30 billion bbl were added, and producing capacity was increased by more than 4 1/2 million B/D. The oil industry had produced at near capacity during 1948, and the outlook was for a continued increase in demand.
Proration and Well Spacing in Texas
Authors: Decker Harold
Published: December 2007

Introduction

In determining proper well spacing today we must consider the effect worldwide overproduction of crude oil will have on the oil producer in Texas both today and in the future. No longer can a producer here expect to enjoy high allowables, nor have any assurance that the price of his oil will be stabilized. We have seen both low allowables and an erosion of the price level.

With this overproduction of crude oil seeking a market, most of the foreign crude is far cheaper to produce than the oil found in Texas. In fact, oil is cheaper to produce in many states in the United States than it is in Texas because of higher allowables or no proration laws. In effect, Texas is holding an umbrella over the heads of our neighbors.

In addition, we find that we are competing with ourselves in that our gas production is taking away our oil markets. As you are all aware, the demand for gas is expanding at a much greater rate than the demand for oil-in some instances because gas is cheaper on a Btu basis and in other instances because consumers are willing to pay a premium price.

Foreign Production - World Oil Market

The Chase Manhattan Bank in its "Monthly Review of the Petroleum Situation" for July, 1959, made the following observation regarding gas:

As the expansion of gas shrinks the market for fuel oils, requirements for crude oil are lessened. And that reduces the incentive to search for new reserves. As the process continues, producers may increasingly shift their operations to foreign areas where the combination of economic factors may look relatively better. Exploratory dollars spent abroad won't find reserves in this country - neither crude oil nor natural gas. This trend, already in evidence, if carried to the extreme, could lead to a deficiency in the United States of both oil and gas reserves. Once that happens, it is doubtful that petroleum would continue to be available at bargain prices.

For Texas production to compete with oil from the Near East, where wells produce 5,000 B/D, we must work toward reducing our individual well costs and producing new wells at higher daily rates.
Capillary Pressures and Gas Relative Permeabilities of Low-Permeability Sandstone
Authors: Ward Jill S. , Morrow Norman R.
Published: December 2007

Use of a high-speed centrifuge for capillary pressure measurements on low-permeability sandstones has been investigated. Curvatures for air/brine and air/decane displacements are compared. Capillary pressures of up to about 800 psi [5516 kPa] for gas displacing brine were extended over an order of magnitude by measurement of isotherms for desorption of water, Capillary pressures measured by high-speed centrifuge merged satisfactorily with results derived from the desorption isotherms. No distinct irreducible water saturation was observed. Permeabilities to gas at various levels of water saturation were also measured and found to be generally consistent with previous relative-permeability measurements.
A Comprehensive Fracture Diagnostics Experiment: Part 1—An Overview
Authors: Fitz-Patrick R. P. , Karr G. K. , O'shea P. A.
Published: December 2007

A comprehensive field fracture mapping experiment was performed in 1983-84 in Mounds, OK, south of Tulsa. The target zone was the Skinner sandstone, a deltaic formation roughly 80 ft [24 m] thick found at a depth of 1,020 ft [311 m]. The first two phases of testing—extensive prefracture testing—included in-situ stress tests and minifracture treatments designed to extract the maximum amount of information about the possible orientation and azimuth of the hydraulic fracture to determine the optimum experimental procedure for the final stage of the tests, in which a fracturing treatment with a magnetized proppant would be performed. The primary goal of the experiment was to measure the transport characteristics and final distribution of the magnetic proppant with surface and borehole magnetometers. Secondary goals included extensive data acquisition to determine fracture geometry by different methods, including various types of seismic monitoring and tiltmeters. This paper, an overview for the entire experiment, focuses on the role the first two phases of the test played in the experimental design for the final phase, explains the nature of the fracture diagnostic procedures used, and summarizes the operations performed and the results obtained during the three phases of the testing. Where appropriate, conclusions regarding the degree of success of the different diagnostic methods and their potential applicability at more commercial depths are discussed.
A Comprehensive Fracture Diagnostics Experiment: Part 2— Comparison of Fracture Azimuth Measuring Procedures
Authors: Smith M. B. , Ren N.-K. , Sorrells G. G. , Teufel L. W.
Published: December 2007

A great deal of effort has been devoted to finding geophysical techniques for measuring the hydraulic fracture azimuth. This paper discusses a comparison of seven different measurements to determine the azimuth in a sandstone formation at a depth of 1,050 ft [320 m]. The azimuth was determined as N95E, but significant differences existed between some of the results. This is of fundamental importance because in developing new measurements, the limits of these must be found and honored.

Of particular interest are the results from microseismic monitoring. The lack of results suggests that remote (e.g., surface) monitoring for seismic events may be impractical for normal, sedimentary, hydrocarbon-bearing formations.
Effect on Gas Proration of Recent Special Orders
Authors: Cameron John S.
Published: December 2007

Introduction

Natural gas is no longer the undesirable, troublesome by-product of oil production that it was just a few years ago. Table 1, a summary of Texas gas production from 1936 to 1958, highlights the tremendous increase in Texas gas production since World War II. Texas produced 6.05 trillion cu ft of gas in 1958, and this gas production is paying the way for many operators during the current low oil flow days. Gas proration is becoming more important as Texas gas production increases and should be generally understood by all producers and purchasers of gas of Texas. New special orders, issued since 1955, are explained in the paper.

Texas Railroad Commission's Duties

The Texas Railroad Commission's basic duty in gas proration is to determine the market demand for gas from a field, then to grant that demand as the field allowable in such manner as to allow each well its ratable share. The Commission is required by statute (Article 6008, Section 1 of the Revised Civil Statutes of Texas) to prorate and regulate gas production in such manner thatboth public and private interests will be protected from waste,correlative rights will be protected, andratable take will be obtained from all wells producing from a common reservoir.

The present basic method used to determine the market demand in Texas gas fields is the monthly nominations from all producers in a field. Each gas reservoir is prorated separately in Texas, and nominations are required from each producer in the reservoir. However, past experience has clearly shown that these nominations do not always accurately indicate the true market demand in a field. Adjustments are necessary to keep the nominations and the actual reported production of each field in balance.

The Commission adds the nominations from each producer to determine the market demand for that month; then this demand is adjusted by the difference between the total nominations and the actual production from that reservoir for the third previous month. The nomination and production for the third previous month must be used because monthly gas reports (Form 3–266-A) are not required until the last day of the month following the month for which the report is made. For example, in preparation of the gas schedules for October, the difference between the July nominations and July production is applied against the October nominations to obtain the October allowable for a field. A monthly gas schedule is issued for each prorated gas reservoir in Texas on the first day of each month showing the monthly allowable in thousands of cubic feet of every gas well in that reservoir.
History Matching by Spline Approximation and Regularization in Single-Phase Areal Reservoirs
Authors: Lee Tai-yong , Kravaris Costas , Seinfeld John H.
Published: December 2007

An automatic history-matching algorithm is developed from bicubic spline approximations of permeability and porosity distributions and from the theory of regularization to estimate permeability or porosity in a single-phase, two-dimensional (2D) areal reservoir from well pressure data. The regularization feature of the algorithm, the theoretical details of which are described by Kravaris and Seinfeld, is used to convert the ill-posed history-matching problem into a well-posed problem. The algorithm uses Nazareth's3 conjugate gradient method as its core minimization method. A number of numerical experiments are carried out to evaluate the performance of the algorithm. Comparisons with conventional (nonregularized) automatic history-matching algorithms indicate the superiority of the new algorithm with respect to the parameter estimates obtained. A quasioptimal regularization parameter is determined without requiring a priori information on the statistical properties of the observations.
Oil Show Detection by C5+ Hydrocarbon Mud Logging
Authors: Dembicki Harry
Published: December 2007

Hydrocarbons between C5 and C30 in drilling mud can be detected and analyzed by a combination of thermal extraction and gas chromatography. This information about the heavier hydrocarbons can be used to locate or to confirm the presence of liquid-hydrocarbon-filled reservoirs and to give a preliminary assessment of the types of hydrocarbons present. The technique is intended to supplement existing mud-gas logging and electrophysical logs for formation evaluation.
Deepwater Drilling and Production Articulated Column: Water Depths of 1,150 ft
Authors: Baduel F. A. , Figenschou A.
Published: December 2007

An articulated tower for drilling and production in the Norwegian Sea in water depths of 1,150 ft [350 m] is presented. The main features are production trees at the deck level; a 19,000-ton [17 000-Mg] deck payload; limited motions; a steel structure, including main float and lattice; low-stressed mechanical articulation with antitorque device; and controlled bending risers.

This extensive study has considered in detail the behavior in extreme conditions, the fatigue of main structural parts and risers, operating procedures, fabrication, and installation. General results are given concerning behavior, structural design, articulation, bending riser, fabrication, and installation. A fabrication and installation schedule is also given.
Adaptive Implicit Methods Applied to Thermal Simulation
Authors: Behie G. A. , Forsyth P. A. , Sammon P. H.
Published: December 2007

The application of adaptive implicit methods to a dead-oil steam simulator is discussed. Various test results are presented. The adaptive implicit method works well on thermal problems, demonstrating a 30 to 50% computing time reduction compared with a fully implicit solution technique, while giving essentially the same results.
Measuring Oil Flow Rates Using Standard Oil-Gas Separators
Authors: De Wit H.P.
Published: December 2007

Methods are described of measuring flow rates and total liquid produced from oil wells using standard oil-gas separators. These methods are now used for normal production controls in several fields by Compania Shell de Venezuela.

The development of the weight-type metering separator used for well gauging of foamy crude during the past four years is described.

The object of this type of metering is to increase both frequency and accuracy of well gauging in the field and, at the same time, to reduce labor costs and capital investment on new installations.

Introduction

For continuous optimum production in an oil field, frequent and reliable individual well gauges, in addition to accurate bulk production measurements, are essential.

In those fields which have a large number of wells, however, because of restricted manpower it is not always possible to realize either the accuracy or the frequency of well gauging necessary for the most efficient running of the field.

All metering systems on the market based on the volume principle are not very suitable for our types of heavy viscous crudes because too much gas stays trapped in the oil and results in inaccurate readings.

In an attempt to improve the accuracy of well gauging operations, while at the same time reducing manpower and installation costs, experiments were initiated during 1954 to ascertain whether this could be achieved satisfactorily by counting and registering automatically on a chart the number of filling stages over a certain period of time of a standard vertical separator of known dimensions. A method was finally developed whereby it is possible to record the time to fill a vertical separator between predetermined levels and, at the same time, to record the weight of crude in each filling stage on a differential pressure chart, thus allowing the average throughput of crude through the separator to be calculated.

To date, this method has proved satisfactory and is used with success for both well gauging and bulk measurement of crude in block stations.
Installation of the Central Production Facilities Deck for the Mokoko-Abana Field, Cameroon
Authors: Gatto A. W.
Published: December 2007

Summary. To reduce development costs at the Mokoko-Abana field, all production equipment was installed in deck units during fabrication and the equipment was precommissioned in,the contractors’ yards before loadout. The 5,000-ton [4500-Mg] central production facilities deck, however, exceeded lifting capabilities of available marine equipment, so a unique installation technique was developed that uses tidal changes and rapid barge ballasting to lower the completed deck onto a specially designed jacket.
High-Temperature Sand Consolidation
Authors: Friedman R. H. , Surles B. W. , Kieke D. E.
Published: December 2007

A sand consolidation system has been developed that is stable to wellbore temperatures of 700°F [371°C]. Two improvements in technique have contributed to this development. First, a controlled quantity of catalyst is adsorbed on the sand. Consequently, consolidation occurs only on or very near the sand grains, resulting in a high-permeability consolidation. Second, the reaction is driven to completion by avoiding, insofar as possible, the adverse effect of water. The resin used for the consolidation is a very viscous derivative of furfuryl alcohol that requires a diluent to make it injectable. The diluent used to reduce viscosity is a hydrolyzable ester. The diluted fluid, which is still more viscous than water, displaces much of the water present in the pore space. During the catalyzed consolidation, water produced by the polymerization is removed by reaction with the diluent (hydrolysis of the ester). The high-molecular-weight polymeric consolidation is better able to resist the high temperatures encountered in steam-displacement producing wells. Adaptation of the technology has been made so that the process can also be used in low-temperature wells. Because of the catalysis method, long shelf life is guaranteed for the consolidating formulation.
Simulations of Naturally Fractured Reservoirs
Authors: Dean R. H. , Lo L. L.
Published: December 2007

This paper describes a three-dimensional (3D), three-phase, black-oil model being used to simulate naturally fractured reservoirs. The program is fully implicit and can perform single-porosity, dual-porosity, or dual-permeability computations. Sample simulations are presented to illustrate the differences between the three computational techniques. Single-porosity recoveries are much larger than the recoveries predicted by the dual techniques. The dual-permeability, primary-depletion recoveries are very similar to the dual-porosity, primary-depletion recoveries, while the dual-permeability waterflood recoveries are significantly larger than the dual-porosity waterflood recoveries.

Pseudocapillary pressures are generated from fine-grid, single-matrix block studies. The pseudocapillary pressures are then used in the dual-porosity simulations to account for fluid distributions in the matrix and fracture systems.
Chemical Equilibrium Models: Their Use in Simulating the Injection of Incompatible Waters
Authors: Bertero L. , Chierici G. L. , Gottardi G. , Mesini E. , Mormino G.
Published: December 2007

One of the problems encountered in waterflooding projects is scale formation caused by chemical incompatibility between potential injection waters and reservoir brine. Chemical compatibility evaluation through laboratory experiments on cores at reservoir conditions is of limited value because only first-contact phenomena are reproduced. A numerical model is presented that couples a reservoir-fluid-flow/thermal-equilibrium simulator with a chemical-equilibrium computer code. This model, AGIPS, enables us to calculate the evolution in time of the amount of scale formed at any point in the reservoir and inside the wells when changes occur in the temperature of the injected water and when the injection water mixes with reservoir brine. Moreover, the model calculates temperature and pressure profiles in the reservoir, together with their evolution in time, taking into account the permeability reduction caused by scale formation. Results are presented for the chemical-equilibrium code validation by matching experimental data on scale formation in mixtures of incompatible waters. An example is also given of the use of AGIPS in simulating a five-spot waterflood where incompatible water is injected.
Effect of Oil Composition on Minimum Miscibility Pressure—Part 2: Correlation
Authors: Orr F. M. , Silva M. K.
Published: December 2007

A new correlation for CO2 minimum miscibility pressure (MMP) is proposed and tested. The correlation is based on experimental evidence that extraction of hydrocarbons from a crude oil depends most strongly on the size of the hydrocarbon molecules. Thus, an oil rich in hydrocarbons that are efficiently extracted should show a lower MMP than a heavier oil. The only crude-oil data needed for use of the correlation are a carbon-number distribution, which can be obtained easily by chromatography. The density of CO2 at the MMP is correlated against a weighted-composition parameter. The MMP of any oil at a given temperature is estimated as the pressure required to yield that CO2 density. The effects of contaminants in CO2 can be estimated easily by calculating the pressure required to give a mixture density equal to that required for pure CO2.

Correlation accuracy was tested by comparing predicted and measured MMP's for 35 oils. The proposed correlation produces MMP estimates accurate to within about 10% for most oils. Comparison of correlation predictions with those of other commonly used correlations indicates that the proposed correlation is significantly more accurate, particularly for recombined oils.
Laboratory Evaluations and Field Testing of Silica-CMHEC-Cement Mixtures
Authors: Rust C.F. , Wood W.D.
Published: December 2007

Introduction

The discussion which follows represents a report on laboratory evaluations and field testing of silica-carboxymethyl hydroxyethyl cellulose (CMHEC)-cement mixtures. While the major part of the laboratory work reported, and all of the field tests, were carried out in Mobil Oil Co.'s operations in Venezuela, the work received its impetus at the Magnolia Petroleum Co. Field Research Laboratory (now Socony Mobil) in Dallas, a Mobil affiliate. Laboratories of other companies have been active in this area of cementation methods, although very little data are available in the literature.

Extensive laboratory tests, involving the use of a high-temperature consistometer in conjunction with high-temperature curing baths, have indicated that at temperatures exceeding 250°F oilwell cements of all types develop undesirable properties. These tests show that at elevated temperatures compressive strengths retrogress and become dangerously low near a temperature of 300°F. This fact is illustrated in the upper part of Fig. 1, which represents a plot of compressive strength vs time for an oilwell Class E cement at various temperatures. This figure shows that at 180°F compressive strengths build up and remain essentially constant with time. At 260°F, high strengths are realized early but pass through a maximum and then decline. At 320°F, the maximum compressive strength is reached in less than 24 hours and is much lower than at the lower temperatures.

This is not the only detrimental factor which affects the properties of a cement cured at high temperatures. Fig. 2 illustrates that corresponding increases in permeability accompany the strength retrogression. At 320°F, the permeability of this sample increased from 4 X 10(–6) to 2,780 X 10(–6) darcies.

Fortunately, these deficiencies can be corrected by the use of proper amounts of silica. The lower part of Fig. 1 shows the effect on compressive strength when 35 parts of silica are added to 100 parts of Class E cement. For a curing temperature of 180°F, maximum compressive strength is obtained more slowly but reaches the same order of magnitude as in the case of neat cement. For a temperature of 260°F, an increase in compressive strength is realized, with no evidence of subsequent retrogression apparent. At 320°F, an initial strength is observed which is not only satisfactory but which, for all practical purposes, remains constant. The effects on the water permeability of adding 22.5 parts of silica to 100 parts of Class E cement are shown in the lower right-hand portion of Fig. 2. The water permeability decreased with curing time and is much lower than in the case where no silica was used.
A New Test for Determination of Individual Layer Properties in a Multilayered Reservoir
Authors: Ehlig-Economides Christine A. , Joseph Jeffrey
Published: December 2007

Many wells penetrate several layers, and flow from each layer is often commingled during production or injection. The behavior of pressure transients for layered systems has been studied in detail for two types of systems: (1) layers that are separated by impermeable barriers (no formation crossflow) and (2) layers that communicate in the reservoir. In this work, the general problem of n homogeneous layers, in which any two adjacent flowing layers may or may not be crossflowing in the formation, is solved analytically. Properties, including permeability, porosity, layer thickness, the wellbore skin factor, and the vertical permeability between crossflowing layers, are distinct for each flowing layer. Wellbore storage effects are also included, and solutions are provided for both infinite-acting and bounded systems.

The key to finding the individual layer properties in a given reservoir lies in the interpretation of the transient flow rates from each layer following a change of the total flow rate for the well. Pressure transients are also used in the analysis. The limiting forms of the analytic solution are used to identify certain characteristic patterns in the flow-rate transients that provide the means for determining the individual layer properties.

The methods used in this analysis are entirely new. An example of the interpretation method is provided.
Distribution and Permeability of Stylolite-Bearing Horizons Within a Lower Cretaceous Carbonate Reservoir in the Middle East
Authors: Koepnick R. B.
Published: December 2007

Stylolites and related pressure-solution features occur in many carbonate reservoirs. They are seams of insoluble residue that record the removal of rock by pressure dissolution. Stylolites may limit reservoir continuity by forming barriers or impedances to fluid flow. This core-based study documents both the distribution of stylolites and the variable impact of stylolite-bearing horizons on reservoir continuity for a Lower Cretaceous carbonate reservoir in the Middle East.
The Effects of Mud Rheology on Annular Hole Cleaning in Directional Wells
Authors: Okrajni Slavomir S. , Azar J. J.
Published: December 2007

The effects of field-measured mud rheological properties on cuttings transport in directional well drilling were studied experimentally. Water and bentonite/polymer muds were used, and angles of annulus inclination ranging from 0 to 90° from vertical. Experimental data were processed to express the cuttings transport quantitatively through annular cuttings concentration (vol%) at steady state.

Three separate regions of hole inclination can be identified regarding cuttings transport: 0 to 45°, 45 to 55°, and 55 to 90°. The effect of laminar flow dominates cuttings transport in low-angle wells (0 to 45°). In high-angle wells (55 to 90°), the effect of turbulent flow predominates. In the range of intermediate inclination (45 to 55°), turbulent and laminar flow generally have similar effects.

In laminar flow, higher mud yield values and yield-point/plastic-viscosity (YP/PV) ratio provide better cuttings transport. The effect of mud yield value is significant in the range of 0 to 45° hole inclination and becomes small or even negligible in the range of 55 to 90°. The effects of mud yield value and YP/PV ratio are more significant for lower annular fluid velocities. In turbulent flow, the cuttings transport was generally not affected by the mud rheological properties.
Postanalysis of Abnormal Cementing Jobs With a Cementing Simulator
Authors: Smith R. C. , Beirute R. M. , Holman G. B.
Published: December 2007

Postanalysis often cannot be applied because of lack of prediction and real-time performance data. Proper postevaluation includes collection of actual job performance data and comparison with predicted cementing performance. A comprehensive cementing simulator is required that accounts for fluid properties, well geometry, changing displacement and mud return rates, and the free-fall effect. Such a simulator has been used successfully in the design of many cementing operations and quite frequently in actual jobs to monitor the progress of the operation. In this paper, case histories are presented to show how this model and on-site measurements can be used for postevaluation of cementing jobs that did not perform as predicted. Two examples illustrate job problems caused by a restriction either in the annulus or in the casing; a third case points out problems associated with use of improperly calibrated pressure gauges during a cementing job.
Steady-State Tar/Water Relative Permeabilities in Peace River Cores at Elevated Temperature
Authors: Closmann P. J. , Waxman M. H. , Deeds C. T.
Published: December 2007

On the basis of Peace River bitumen/brine flow experiments at elevated temperatures, tar relative permeability/saturation relations vary depending on the previous thermal history of the tar. The relative permeability curve for thermally unaltered tar is shifted toward the region of low water saturation, while that for thermally altered tar is closer to the Leverett oil permeability curve for water-wet unconsolidated sands. Oil permeability values for deasphaltcd tar lie at saturations intermediate between those of the thermally altered and unaltered tar.
Gas Reservoir Decline-Curve Analysis Using type Curves With Real Gas Pseudopressure and Normalized Time
Authors: Fraim M. L. , Wattenbarger R. A.
Published: December 2007

A normalized time has been developed that linearizes the rate decline vs. normalized time for a gas reservoir producing against constant wellbore pressure during (external) boundary-dominated flow. This allows type-curve matching of the exponential decline curve for a reservoir with any shape. Values of G, kgh, and kg/ϕ can be determined from this type-curve match. It was determined that gas reservoir depletion plotted vs. actual time does not match exponential, harmonic, or hyperbolic decline curves, and future performance can lead to overestimates of reserves and future rate.
A New Technique for the Evaluation of Shale Stability in the Presence of Polymeric Drilling Fluid
Authors: Lu Cheng-Fa
Published: December 2007

A quantitative evaluation technique for shale stability in a polymeric medium has been developed with a rheological method. The storage modulus of a shale pellet immersed in a drilling fluid is used to predict the shale-inhibitive properties of the fluid. Polymer concentration, molecular weight, carboxyl sUbstitution, and KCI concentration are important parameters affecting shale stability.
Acoustic Determination of Producing Bottomhole Pressure
Authors: McCoy James N. , Podio Augusto L. , Huddleston Ken L.
Published: December 2007

This paper discusses the acoustic determination of producing bottornhole pressure (BHP). Two different techniques are presented for wells that have liquid above the formation and gas flowing upward through the gaseous liquid column. One technique involves the acoustic measurement of the liquid level and the casing-pressure buildup rate when the casinghead valve is closed. When these data are used along with an empirically derived correlation given here, the gradient of the gaseous liquid column in the annulus can be obtained. This technique offers a reasonably accurate procedure for determining the producing BHP of a well by acoustic means. The second method involves two acoustic measurements. A backpressure valve is used in the casing head to depress and to stabilize the liquid level at two positions while the well is produced at a constant rate. The gradient of the gaseous liquid column is then calculated and extrapolated to the formation depth.

This paper discusses results from the field testing of numerous wells where the actual gradients of gaseous liquid columns were measured in a variety of casing/tubing sizes, oil gravities, gas flow rates, and pressures.
Influence of Shear History at Bottomhole Temperature on Fracturing-Fluid Efficiency
Authors: Harris P. C. , Penny G. S.
Published: December 2007

The effects of downhole environmental conditions on fracturing-fluid rheology and leakoff were evaluated in a flow loop at simulated fracture conditions. Linear and crosslinked gel fluids were subjected to shear rates of 50 to 100 seconds−1 past core for 4 hours at temperatures of 75 to 250°F [24 to 121°C].

Nonlinear effects commonly observed with crosslinked gel fluids diminished as the fluid was sheared. Shearing for 30 minutes to 4 hours at 100 seconds−1 before a fluid-loss test was run resulted in leakoff following square-root-of-time behavior. Spurt loss increased for crosslinked gel fluids as the fluid degraded, whether by enzyme or oxidative mechanism. The leakoff coefficient decreased slightly with time under shearing conditions. Although the polymer was breaking, the absolute amount of polymer available for deposition did not change.

The apparent viscosity of fluid remaining within the fracture was also investigated. During initial fluid leakoff, polymer was concentrated as a gel filter cake at the fracture face. Once an equilibrium filter-cake thickness was achieved, however, fluid loss to the formation resulted in an increase in the polymer concentration in the remaining fluid and hence an increase in apparent viscosity.
Inverse Lumping: Estimating Compositional Data From Lumped Information
Authors: Schlijper A. G. , Drohm J. K.
Published: December 2007

Many methods of characterizing reservoir fluids thermodynamically yield equation-of-state (EOS) models with a large number of components. For simulation studies, this detailed compositional model is subsequently replaced by a simplified model in which compositions are described with a limited number of groups or pseudocomponents. This paper discusses methods of translating group (pseudocomponent) compositions into detailed component compositions, a procedure that will be referred to as "inverse lumping." Inverse lumping can be used to calculate phase properties in the group (pseudocomponent) model. This eliminates the need to construct ad-hoc property correlations. Another application would be to inverse lump the well streams as predicted by the simulator so that the results can be used in a fully compositional separator-system simulator.