bluuebunny/crossref_metadata_2025 huggingface dataset:
An Engineering Challenge Development of South Louisiana's Giant Timbalier Bay Field
Authors: Lipari C.A.
Published: December 2007

LIPARI, C.A., JUNIOR MEMBER AIME, GULF OIL CORP., MORGAN CITY, LA.

The Timbalier Bay field, covering 9,500 productive acres of inshore and offshore area, containing 81 productive horizons and some 434 reservoirs ranging in depth from 2,000 to 17,500 ft, presents a challenge to engineers. Reservoir mechanisms of many combinations make it necessary that water flooding, gas injection, attic oil recovery and other recovery methods be examined for possible application in this filed. This paper presents the history and characteristics of the field and the approaches taken by Gulf Oil Corp. in arriving at a system of operation in the coastal waters of South Louisiana.

Introduction

The operation of an oil field in the coastal area of Louisiana is similar in many ways to operations elsewhere, but there is one significant difference. The operation takes place over a body of water. The logistics of an operation of this type require that all functions be coordinated carefully if the project is to be successful. Throughout 24 years of operating the Timbalier Bay field, Gulf Oil Corp. has employed more efficient equipment as it became available, and the most efficient operating practices known at the time. The purpose of this paper is to convey to the industry the history and the practices followed by Gulf Oil in developing this field in the coastal waters of South Louisiana.

Location and General Description

The Timbalier Bay oil and gas field is located in, and offshore from, Lafourche Parish, La. (Fig. 1). It is situated approximately 20 miles south of the town of Golden Meadow, 70 miles southeast of Morgan City (the area operational office) and 60 miles southwest of the city of New Orleans. The crest of the structure lies almost directly underneath East Timbalier Island. This low-lying island, averaging about 350-yd wide, is the site of the central Timbalier Bay field camp (Fig. 2) and separates the open waters of the Gulf of Mexico from the shallow Timbalier Bay waters. Access to the field is from the Leeville shore base, through Bayou Lafourche, into Timbalier Bay and the Gulf of Mexico, Presently, there are 410 completion intervals in 277 wells. Daily production is 33,826 STB of oil and 52 MMcf of gas. The productive portion of the field covers approximately 9,500 acres, The present lease arrangement (Fig. 3), within the present productive area of the field, consists of Gulf Oil Corp. as sole owner and operator of Louisiana State Lease "PP" 192, 1772 and 1773, and operator for the joint interest of the Louisiana State Leases 1423, 1483 and the Outer Continental Shelf Lease 0263, Block 21. Union Oil of California operates Louisiana State Leases 3088 and 3324, and Tenneco operates Louisiana State Lease 1369.Surrounding fields are (Fig. 1) Bay Marchand to the cast, Caillou Island to the west, Lake Raccourci to the north and South Timbalier Area Block 54 to the south.

JPT

P. 127^
The Role of Bubble Formation in Oil Recovery by Solution Gas Drives in Limestones
Authors: Stewart C.R. , Hunt E.B. , Schneider F.N. , Geffen T.M. , Berry V.J.
Published: December 2007

Laboratory data show that the gas-oil ratio perforce of non-uniform porosity limestones produced by solution gas drive is sensitive to producing rate and to fluid properties. Non-uniform porosity lime st ones are those for which laboratory solution and external gas drive tests yield considerably different relative permeability ratio characteristics.

The oil recovery performance by solution gas drive depends directly on the number of gas bubbles formed. Laboratory rates of pressure decline, which are 100 to 10,000 times greater than normal field rates, cause the formation of an unusually large number of gas bubbles. This results in abnormally high oil recovery efficiencies, Since it is impractical to reproduce the number of bubbles formed under field conditions, laboratory solution gas drive data on non-uniform porosity limestones are therefore not directly applicable to field operations. However, certain laboratory data can be used to make a conservative estimate of field performance.

The concepts presented in this paper indicate the possibility that increased field oil recoveries may be obtained from non-uniform porosity limestones by rapidly reducing reservoir pressure for a short interval of time. It has yet to be established that significant improvements in oil recovery from such reservoirs can be realized by varying the pressure decline rate within limits possible in the field. However, the possibility that recovery may be increased in this manner warrants further study.

Introduction

Limestone reservoir rocks can be divided into two general classes according to the nature of their pore space. One class has a comparatively uniform pore system composed mainly of voids between grains of the rock (intergranular type porosity). The other class, in addition to having intergranular porosity, has a secondary pore system composed of combinations of solution cavities, fractures, etc., and is considered to have non-uniform porosity.
Conveniences in Analyzing Two-Rate Flow Tests
Authors: Pinson A.E.
Published: December 2007

In 1963, Russell presented a method by which the now familiar two-rate flow test could be analyzed to provide the same information - permeability, skin provide the same information - permeability, skin factor, average reservoir pressure, and distance to a linear barrier to flow as that derived from conventional pressure buildup tests. The two-rate test method offers several practical advantages over conventional pressure buildup tests, but these will not be discussed here. The purpose of this note is to point out two simplifications that can often be used to make the analysis of two-rate flow tests more convenient.

General Russell showed that his Eq. 3,

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

indicates that a plot of pwf vs

will yield a straight line of slope m, given by

(2) m =

Calculation of is tedious

and can often be avoided if we note that a plot of pwf vs log t will also give a straight line if t »delta t. pwf vs log t will also give a straight line if t »delta t. When t >> delta t, log(t + delta t) log t and

log log t.

If we let log (t + delta t) = log t in Eq. 1 and rearrange, the following expression results.

........(3)

It is apparent from inspection of Eq. 3 that a plot of Pwf vs log delta t is a straight line of slope m', given by Pwf vs log delta t is a straight line of slope m', given by

.........(4)

P. 1139
Advantage of a Coordinated Formation Evaluation Program
Authors: Shearin H.M. , Latimer J.R.
Published: December 2007

The importance of obtaining sufficient reliable data on reservoirs has increased in recent years as wider use is made of reservoir engineering technology. These data can be obtained at minimum cost through a coordinated formation evaluation program during the development of a reservoir. Such a program and its benefits are outlined, and the results of the application of a program in a Strawn lime field is presented in this paper.

Introduction

The growth of reservoir engineering over the past 15 years has caused a fundamental shift in the approach to the production of oil. The oil operator in the 1920's and 1930's was primarily concerned with finding a porous zone which would give up oil. He drilled with tools which were constantly improved, and gradually he learned to employ the newly developed logging devices which helped to locate the oil pays. Relatively speaking (compared with today), there were large amounts of oil to be found fairly cheaply at shallow depths. Exactly how much oil he found or about how long it would take to recover it was of concern to the operator, but how to determine these factors was not known at that time.

Today's outlook is different. There has been a shift from thinking about individual well behavior to thinking about the entire reservoir. The basic reservoir concepts of Schilthuis, Buckley and Leverett, and others have been tried and proved and expanded. Much was learned about reservoir theories during World War II when many reservoirs were produced at high rates without apparent damage. Today, reservoir engineering has progressed so that the behavior of a reservoir can be predicted with reasonable accuracy.

The reliability of reservoir performance predictions depends upon the accuracy of the reservoir data. As new oil reservoirs are found at deeper depths and are more costly to develop, accurate recovery predictions grow more important so that a proper evaluation of risks can be made. Today also finds a new and growing need for reliable recovery predictions to establish the feasibility of unitized operations.
Water Flooding Down-Structure Displacement In the Presence of a Gas Cap
Authors: Wilson J.F.
Published: December 2007

Steady-state flow theory, previously applied to displacements with two mobile phases, is extended to cover down-structure flow involving three mobile phases; oil, gas and water. When used with normal reservoir fluid properties, the theory predicts the existence of four distinct flow regimes and the conditions under which each regime exists. The predicted behavior is verified by a parallel-plate model study.

Introduction

Special problems exist when a water flood is contemplated in a dipping reservoir having a substantial gas cap. Normally, the gas-cap region is one of very low oil saturation. If oil is moved into the gas cap during the flood, a loss in recovery results. Efficient recovery of the oil underlying the gas is therefore difficult. In two reported field water floods, injection into the gas cap has been used to solve these problems. At the West Norfolk Garr Sand Unit, injection into the up-structure region of the reservoir was made for the stated purpose of filling up the gas cap with water. The purpose in the Sholem Alechem Fault Block "A" Sims Sand Unit was to form a continuous water barrier between the gas cap and oil band. A laboratory model study preceded this flood and was described in the same publication. Both of these gas-cap water injections gave satisfactory results, but the published data are insufficient to allow generalizing to other field conditions. The present investigation was also undertaken to obtain results for a specific field problem. However, these results will be shown to be in agreement with an extension of the Dietz mathematical model to three-phase flowing systems. The agreement between the theory and the model studies indicates that the mathematical model can be used to describe completely the flowing system under some conditions, and to indicate the general type of flow to be expected under all conditions.

FLOW THEORY

The Dietz equations for two-phase flow are derived for the case of constant-velocity linear flow in a homogeneous porous medium. The transition zone between the fluids is assumed to be of negligible extent so that the displaced and displacing fluids are separated by a sharply defined interface, as illustrated in Fig. 1. The density and mobility of the displacing fluid are constant over the region behind the interface, and the same properties of the displaced fluid are constant over the region ahead of the interface.

In such a system, if

sin, .............(1)

a stable (nonfingering) flow will result in which the tilt of the interface will approach a steady-state value at which

tan - ....(2)

where subscripts 1 and 2 refer to the displaced and displacing phases, respectively. To extend the Dietz equations to three-phase systems, we postulate the flowing system shown in Fig. 2 and determine the conditions under which it can exist.

JPT

P. 1383^
Two-Phase Vertical Flow in Oil Wells - Prediction of Pressure Drop
Authors: Chierici G.L. , Ciucci G.M. , Sclocchi G.
Published: December 2007

A combination of mass-transfer flow regime methods is presented for predicting two-phase pressure gradients in oil wells with low to medium predicting two-phase pressure gradients in oil wells with low to medium GOR'S. New relationships are proposed for the slug-froth flow regime to improve the accuracy of the calculated local thermodynamic parameters.

Introduction

The polyphasic flow of Newtonian fluids in vertical pipes has been investigated both theoretically and pipes has been investigated both theoretically and experimentally by several authors. Poettmann and Carpenter, Ros, Duns and Ros, and Hagedorn and Brown dealt with the problem of predicting pressure gradients in oil wells, where the flowing fluid pressure gradients in oil wells, where the flowing fluid may be a gas-oil-water mixture with interphase mass transfer Several applications and improvements of the equations proposed by the above authors have been published; empirical relationships have also been published; empirical relationships have also been presented. presented. A method for predicting two-phase pressure drop in vertical pipes was proposed by Orkiszewski. This method, which has been widely accepted in the oil industry, is basically a combination of methods previously proposed by other authors, with some previously proposed by other authors, with some modifications as far as slug flow is concerned. The same basic approach as Orkiszewski's has been adopted in the present work. Theoretical studies as well as experimental results presented in the technical literature have been examined and a set of equations has been selected that has proved to be particularly efficient in predicting pressure gradients in two-phase vertical flow. A new relationship has been developed to deal with the slug-froth flow regime.

Pressure Gradient and Flow Regimes Pressure Gradient and Flow Regimes Starting from the macroscopic mechanical energy balance equation, the elementary pressure drop, dp, in a vertical pipe can be expressed as follows.(1)

By making some approximations in evaluating the acceleration gradient, p v dv, which is almost always negligible, we have(2)

Before integrating Eq. 2 numerically, the locally prevailing flow regime must be determined because prevailing flow regime must be determined because the way both p and Tf are to be evaluated depends on the flow regime. The various ways a gas-liquid mixture can flow in a vertical pipe are usually grouped into three main flow regimes; that is, bubble-plug flow, slug-froth flow, and mist flow. A transition zone exists between the last two regimes. By combining the experimental results by Griffith and Wallis with those by Duns and Ros, the following criteria have been proposed by Orkiszewski for determining the flow regime.

Bubble-Plug Flow(3)(qg/qt) less than Nv

Slug-Froth Flow(4a)(qg/qt) greater than Nv,

JPT

P. 927
Interfacial Tension of Normal Heptane
Authors: Warren H.G. , Bills R.V.
Published: December 2007

The interfacial tension values of pure normal heptane were obtained orthobarically by the pendent-drop method for temperatures ranging from 58 degrees to 338 degrees F. The values above 274 degrees F were questionable because of unreliable measurements on unstable drops at high temperatures. Excellent results were obtained at 274 degrees F and lower temperatures. Table 1 gives the experimental data and Fig. 1 compares these data with those of other experimentors. These data are almost identical with the values obtained in earlier experiments using the pendent-drop method. pendent-drop method. A log-log plot of / vs (1 - T/Tc) yields a straight line. The experimental pendent-drop data correlated between interfacial tension, density difference, and temperature for normal heptane are represented by the following equations:(1)= 46.96 (1 - T/Tc)1.10(2)= 83.00 ()3.74(3)= 54.80 (1 - T/Tc)0.80626

where

= interfacial tension, dynes/cm

= density difference, gm/cc

= temperature, degrees R

= critical temperature, degrees R = 972.6 degrees R

A parachor, which is a constant that is dependent on the constitution of a compound, is related to molecular volume. It is used to calculate the interfacial tension of a pure compound at any condition of temperature and pressure where the density difference of the liquid and vapor phases is known. The parachor of a pure component may be calculated with the following equation.(4)Parachor =,

where

MW = molecular mass

TABLE 1 - INTERFACIAL TENSION OF NORMAL HEPTANE

Interfacial Density Temperature Tension, Difference, (degrees F) (dynes/cm) (gm/cc) 1 - T/Tc 58 20.50 0.6870 0.4675 61 20.32 0.6865 0.4640 64 20.45 0.6850 0.4610 83 19.74 0.6760 0.4410 93 18.63 0.6710 0.4310 95 18.48 0.6700 0.4295 100 17.57 0.6675 0.4240 102 19.08 0.6665 0.4220 108 18.15 0.6635 0.4160 118 16.46 0.6585 0.4050 128 17.78 0.6540 0.3950 131 17.00 0.6520 0.3910 148 15.46 0.6440 0.3750 167 14.39 0.6335 0.3550 180 14.93 0.6260 0.3410 197 13.81 0.6165 0.3240 221 12.53 0.6030 0.2990 226 11.77 0.5995 0.2940 266 10.16 0.5745 0.2520 274 9.82 0.5690 0.2450

P. 543
Salinity Effects of Micellar Flooding
Authors: Paul G.W. , Froning H.R.
Published: December 2007

Extensive laboratory flood tests have been conducted to optimize oil recovery with micellar slugs. A study was made of the effects of variables such as temperature, crude oil type, rock type, and surfactant-cosurfactant type, and of the effects of concentration and salinity of connate water, micellar slug, and chase water. The tests demonstrated conclusively that a pronounced benefit in oil recovery can be achieved by using a particular sequence of injected water compositions. For example, it was found that optimum oil recoveries are obtained if the micellar slug contains sufficient salt to produce effective miscibility or very low interfacial tension between the micellar slug and the oil and if the water injected immediately ahead of the micellar slug has approximately the same salt content as the slug itself. It was also found that the polymer drive water behind the micellar slug should be fresh water if optimum oil recovery is to be achieved. The effect of the salinity sequence is illustrated by data obtained in floods of a Wyoming crude oil from 4-ft Berea cores at 110 degrees F. The cores were saturated with water, driven to connate water saturation, waterflooded, and subsequently flooded with 10 percent PV water-external micellar slugs (92 percent water). PV water-external micellar slugs (92 percent water). The micellar slugs were driven with a 750-ppm solution of biopolymer to achieve mobility control. The flood rate for the micellar and polymer slugs was 2 ft/D. All flooding fluids were prepared with a "fresh water" of about 2,800 ppm total solids. Sodium chloride was added in preparing the saline waters and micellar fluid. Repeat tests established that the reproducibility of the data was 3 percent in residual oil saturation after the micellar-polymer injection. Curve 1 of Fig. 1 shows the oil fraction produced during a tertiary micellar flood when a preflush (waterflood) of the same salinity (16,000 ppm) as the micellar slug is employed. Curve 2 shows the oil fraction when fresh water precedes the micellar slug. The total oil recovery, both secondary and tertiary, with the saline water preflush was 95.7 percent of the original oil in place, whereas without the saline preflush the oil recovery was 74 percent. preflush the oil recovery was 74 percent. JPT

P. 957
Mixing Equations in Various Geometries
Authors: Brigham W. E.
Published: December 2007

In flow through porous media, the mixing characteristics of the flowing fluids are often defined by the diffusivity equation. Solutions of this equation are available for linear flow, and close approximations are available for radial flow. In this paper, one of the radial flow approximation methods has been generalized to a variety of geometries. The solution is assumed to be in the form of an error function; and equations are derived for the standard deviation—i.e., the argument of the error function. By breaking the flow system into segments and by repeated use of these solutions, mixing can be calculated in a large variety of flow systems. For example, equations can be used to calculate tracer flow behavior in reservoirs and mixing in vertical miscible displacement.
Water Source and Requirements
Authors: Earlougher R.C. , Amstutz Ray W.
Published: December 2007

Introduction

Poor selection of a water source and a miscalculation of the water requirements can affect adversely the economics of a potentially successful flood. A methodical examination of the sources, selection of the best one available, and application of engineering principles to the development of that source mean cheaper production of each barrel of waterflood oil.

Following is the preferred order for approaching these basic problems which must be solved early in the launching of a waterflood program:determine the requirements as accurately as data permit;survey all possible water sources with special attention to the quantitative satisfaction of the requirements; anddevelop the selected source in the most economical manner permitted by good engineering practice.

WATERFLOOD REQUIREMENTS

Daily Water Injection Rate

The heaviest drain on the make-up water source is during the fill-up period when there is no return water and the desired unit daily injection rate is as much as twice that needed after fill-up. The maximum daily total injection rate usually is tempered somewhat by progressive development of the flood acreage.

Empirical relationships established during 18 years experience with injection projects throughout the country are the bases for the following general requirements. During the initial or fill-up period of injection into a depleted reservoir, a unit rate of between 1 and 2 B/D/acre-ft is desirable. This normally will result in increased oil production within six to nine months without adversely affecting the ultimate oil recovery. After fill-up has been achieved, the injection rate should be maintained at about 1 B/D/acre-ft and at not less than 1/2 B/D/acre-ft. Flood pattern, well spacing, and injection pressures should be designed to meet these requirements.

For depleted reservoirs in which there is gas sand in the top of the sand section, together with basal water sand, the water requirements normally will be several times that for an oil sand section alone. The gas sand must be filled with water in order to prevent, as much as possible, migration and loss of oil into such sand.
Well Completions for Waterflood Operations
Authors: Watson Marsh S. , Ward Ted G. , Buckles George L.
Published: December 2007

Reservoir conditions in Permian sand fields of West Texas present problems in waterflood operations unique to that area. These are caused by upper water-bearing formations; a series of sand lenses in the producing zone separated by shale, sandy shale and dolomite stringers and gas sands above the producing oil zones. In some fields bottom-hole water is present in the down dip area in the principal oil-producing oil zones. pointed out that the most satisfactory methods used to overcome these problems could apply to any area where an open hole completion would be possible.

The paper presents a discussion of current completion practices for injection and producing wells. The methods by which properly completed wells help to solve the problems of thief zones, injection rates, maintaining properly treated water, and isolation of the sands to be flooded are presented.

A method for completion of cable tool holes, where the operator may chip core and shoot the producing zone before running casing is discussed in detail.

Introduction

The essence of water flooding is to inject water continuously into the pore spaces of an oil reservoir at a rate that will result in the production of the maximum amount of commercially recoverable oil. Any mechanical, chemical, or biological processes that assist or detract from this endeavor are of vital importance.

In its simplest aspect the problem then resolves itself into injecting the most suitable water available into an oil bearing formation at the right pressure. This involves spacing, pattern, water treating and well completions. Pore spaces refer to any openings through which fluid could pass. The scope of this paper concerns itself with well completions.

Injection well completion is the most critical factor to waterflooding success. This for the simple reason that the injection well is the sole medium for directing the water to its function. In like manner producing wells must be completed so that all waterflood oil can be produced. It is an economic waste to continually attempt to work over a completed injection well, and it is a hazard to try to solve all problems by increasing injection pressures.
Linear Fluid-Barrier Detection by Well Pressure Measurements (includes associated discussion and reply)
Authors: Davis E. Grady , Hawkins M.F.
Published: December 2007

In recent years considerable attention has been given to the use of unsteady-state pressure measurements in wells as a means of investigating thenature of petroleum reservoirs both near to and away from wells. These methodsare based on sound theory; for, theoretically at least, pressure build-up anddrawdown curves reflect the nature of the reservoirs from which the data aretaken. One of the more common and prominent features of reservoirs which can bedetected in some instances by pressure measurements is the linearfluid-barrier, e.g., a linear sealing fault. There has been some misuse of thistechnique in engineering practice, and it was therefore thought worthwhile todiscuss the criteria for valid pressure tests which indicate the presence andlocation of linear fluid-barriers.

Introduction

The present discussion will be concerned with the detection of linear fluid-barriers in ideal reservoirs, thus establishing optimum conditions fortheir detection in real reservoirs. The ideal reservoir considered is ahomogeneous, isotropic, porous bed of uniform thickness saturated with aslightly compressible fluid. Bounded on one side by a reasonably extensivelinear fluid barrier, the reservoir is assumed to be of such extent thatdiscontinuities other than the linear barrier have no appreciable affect on themeasured well pressures within the duration of the test. it is further assumedthat there are no appreciable pressure transients at the test well as caused byflow rate changes in other wells tapping the reservoir. A skin effect, ifpresent in the test well, is assumed to be invariant with flow rate, pressureand time.

Discussion

The theory of linear barrier detection using well pressure measurements has been treated by Horner, Jones, Dolan, Einarsen and Hill and Davis. For thepressure drawdown case in an ideal reservoir with constant rate of fluid entryinto the wellbore, this theory predicts pressure decline curves such as shownin Fig. 1. Here the dimensionless pressure drop p, assuming no skin effect, isplotted vs the natural logarithm of dimensionless time t for several values ofdimensionless distance d between the test well and the linear fluid-pressurebarrier. These dimensionless groups are defined in the Nomenclature. The plotsof Fig. 1 show a curved section which covers approximately a 25-fold timerange, i.e., the ratio of the time at the end of the curved section to that atthe beginning. Stated otherwise, the curved section covers about three naturallog cycles on the time scale or about 1.4 common log cycles, beginning at 0.35and ending at 9.

JPT

P. 1077^
Decline Curve Analysis Using Type Curves
Authors: Fetkovich M.J.
Published: December 2007

This paper demonstrates that decline curve analysis not only has a solid fundamental base but also provides a tool with more diagnostic power than has been suspected previously. The type curve approach provides unique solutions on which engineers can agree or shows when a unique solution is not possible with a type curve only.

Introduction

Rate-time decline curve extrapolation is one of the oldest and most often used tools of the petroleum engineer. The various methods used always have been regarded as strictly empirical and generally not scientific. Results obtained for a well or lease are subject to a wide range of alternate interpretations, mostly as a function of the experience and objectives of the evaluator. Recent efforts in the area of decline curve analysis have been directed toward a purely computerieed statistical approach, its basic objective being to arrive at a unique "unbiased" interpretation. As pointed out in a comprehensive review of the literature by Ramsay,1 "In the period from 1964 to date (1968), several additional papers were published which contribute to the understanding of decline curves but add little new technology."

A new direction for decline curve analysis was given by Slider2 with his development of an overlay method to analyze rate-time data. Because his method was rapid and easily applied, it was used extensively by Ramsay in his evaluation of some 200 wells to determine the distribution of the decline curve exponent b. Gentry's3 Fig. 1 displaying the Arps4 exponential, hypbolic, and harmonic solutions all on one curve also could be used as an overlay to match all of a well's decline data. However, he did not illustrate this in his example application of the curve.

The overlay method of Slider is similar in principle to the log-log type curve matching procedure presently being employed to analyze constant-rate pressure buildup and drawdown data.5–9 The exponential decline, often used in decline curve analysis, readily can be shown to be a long-time solution of the constant-pressure.10–13 It followed then that a log-log type curve matching procedure could be developed to analyze decline curve data.
A Result of SP Log Interpretation
Authors: De Andrade Paulo Varjao
Published: December 2007

Introduction

Since 1949, attention has been directed in this laboratory to the interpretation of SP logs. It has been the aim of the work to get connate water resistivities to use in quantitative interpretation of the resistivity curves. Wyllie's theory was taken as the fundamental working hypothesis as it would provide a correct theoretical background to support the results. In order to have an idea of the precision of the method, it was decided to make a series of interpretations in wells which produced only water and to compare the calculated results with resistivities obtained from chemical analysis of water samples.

Several water analyses and electrical logs were available from wells in the Sergi sands in several fields of the Bahian Reconcavo. The Sergi sands are the highest member of the Brotas formation, presumably of Lower Cretaceous age, and were deposited all over the basin. They constitute a homogeneous body and can be correlated over distances of tens of miles with only minor changes in lithology. The upper part of the Sergi known as "C zone," is a medium to fine grained sandstone, medium consolidated to friable, with finely disseminated clay, 15 to 30 ft thick, good porosity and permeability. Fig. 1 shows a log of part of the upper Sergi with the shale section overlying it.

Water samples came from formation tests, being collected in the lower part of the column. In case of mud contamination, they were discarded. Analysis comprised routine determinations of chloride, sulfate, bicarbonate and carbonate, calcium and magnesium. Sodium was calculated by difference. Resistivities of water and mud were obtained using either the Schlumberger salinity-resistivity chart or a combination of the said chart with Dunlap's method (the low sulfate content of the brines made this method very simple and accurate). Bottom-hole temperatures were available either from log headings or from direct measurements made with a maximum thermometer. In order to avoid the influence of resistivity on the amplitude of the SP "peak," only water wells were used in this study. Corrections for bed thickness were unnecessary in the wells studied. All wells were rotary drilled.
Comparison of Liquid-Holdup and Friction-Factor Correlations for Gas-Liquid Flow
Authors: Vohra I.R. , Hernandez F. , Marcano N. , Brill J.P.
Published: December 2007

Predicting expected pressure drop during two-phase, gas-liquid flow in pipes is highly significant to the petroleum industry. The relative accuracies of four published correlations are determined in terms of the constitutent liquid holdup and friction-factor prediction schemes. Liquid-holdup values predicted from two other correlations and from no-slip considerations are included in the comparisons.

Introduction

The prediction of pressure drop during two-phase, gas-liquid flow in pipes is of great significance to the petroleum industry. Extensive theoretical and experimental research has been conducted on horizontal, vertical, and inclined two-phase flow, but few of the resulting correlations are valid over broad ranges of flow rates, fluid properties, and pipe sizes.

Most published pressure-loss prediction correlations require prediction of two parameters: the liquid holdup and a two phase friction factor. The reliability of any flowing pressure-drop correlation is, therefore, dependent on the relative accuracies of the constituent liquid-holdup and friction-factor predictions. The accuracy of these correlating schemes may be evaluated only for test cases for which simultaneous liquid-holdup and pressure-drop data are available.

Beggs'2 and Eaton's5 experimental data include accurately measured pressure-loss and liquid-holdup values. These data are restricted to 1-, 1.5-, 2.067-, and 4.02-in.-ID pipes. Additional data are available in the literature or from private sources, but the accuracy of measurement is unknown or questionable, so they were not considered here. Fifty-eight tests from Beggs' study and 238 tests from Eaton's study were combined in a data bank for this investigation.

Using this data bank, two separate comparison studies were pursued. The first study compared measured liquid holdup with that predicted from six commonly used correlations and a no-slip calculation for two-phase horizontal flow in pipes. The second study predicted two-phase friction factors from correlative functions of four authors and compared these factors with the friction factors calculated from their respective mechanical energy-balance equations. Some differences exist in the definition of terms used in the energy-balance equations. The four friction-factor correlations considered were developed by Beggs and Brill,3 Dukler,4 Eaton et al.,6 and Guzhov et al.7 Their liquid-holdup correlations were also compared with the correlations of Hughmark9 and Lockhart and Martinelli.10 To establish a lower bound on predicted liquid-holdup values, a no-slip holdup was also calculated.

The percent differences between measured and predicted liquid holdup and between measured and predicted friction factors were computed for each test in the data bank. The mean and standard deviation of these differences were determined to evaluate the reliability of selected correlations for predicting two phase pressure drops in horizontal pipes.
Canadian Oil at the Eighth Milestone (1947-1955)
Authors: Twaits W.O.
Published: December 2007

Introduction

Recently Canada celebrated the eighth anniversary of a discovery which to Canadian oil men ranks with that made by Columbus. The finding of crude oil at Leduc, Alta., eight years ago on Feb. 13 had some other similarities with the experiences of Christopher Columbus. As with the discovery of America, the significance of finding oil in Canada was not immediately recognized. Today, at the comparatively advanced age of eight, and with an unprecedented rate of growth, there are few who are not aware of the size or importance of the Canadian development. It seems appropriate at this time to examine some of the factors influencing the economic behavior of thin new supply source-not in detail, but rather in terms of future growth.

Canadian Oil Today

The stature of present Canadian oil can be measured with considerable ease and a minimum of statistics. Eight years of progress has brought the industry to the point where it supplies the needs of virtually all of Canada west of Toronto on Lake Ontario. This is in marked contrast with the 1947 situation in which an area near the Arctic Circle and another around Calgary were the only sections supplied with local crude. This widening of the area supplied reflects the growth of total reserves from 72 million bbl to some 2 3/4 billion and of daily average production from a declining position at 20,000 to a position with excess maximum efficient recovery at 260,000 bbl. Potential production has risen to around 420,000 bbl. There are a great many other measurements of progress which could be enumerated, but the one which is perhaps most striking from a Canadian viewpoint is that currant production with a 1954 gross value of $245 million effects a foreign exchange saving of considerably more than that amount. This saving of foreign currency is in U. S. dollars, and it is augmented by the inflow of additional cash for investment in oil development by companies and individuals.
Effect of Clays, Limestone, and Gypsum on Soluble Oil Flooding
Authors: Bernard George G.
Published: December 2007

Introduction

In our investigation of the soluble oil flooding process we observed that the process is less efficient in some porous rocks than in others. There are two basic porous rocks than in others. There are two basic factors that affect the oil displacing action of the soluble oil process:composition of interstitial fluids, andcomposition of reservoir rock.

The literature has much data showing that composition of interstitial water, particularly the presence of divalent ions, greatly affects the efficiency of a soluble oil flood. This study is not concerned with that aspect of the problem. problem. This study is concerned with the effect of rock minerals on soluble oil flooding. We evaluated the possibility that certain rock minerals can drastically possibility that certain rock minerals can drastically affect the efficiency of the soluble oil flood. One previous study has shown some of the possibilities in previous study has shown some of the possibilities in this regard.

Experimental Procedure

The flooding experiments were conducted in unconsolidated sandpacks (No. 16 sand) containing from 0 to 2 percent of either gypsum, montmorillonite clay, or calcium carbonate. The sand was packed in 3-ft long, 2-in. diameter plastic tubes to a porosity of about 40 percent and a permeability of about 4 darcies. In preparation for the flooding experiments, the systems were first saturated with brine or fresh water, permeability was determined, and then crude oil was permeability was determined, and then crude oil was injected to irreducible water. Next, the system was waterflooded to residual oil saturation, and, finally, a soluble oil flood was made. Oil saturations after waterflooding ranged from 28 to 32 percent PV. In each soluble oil flood, 0.03 PV of soluble oil was injected and followed by 1 PV of polyacrylamide solution that had a viscosity of about 32 cp.

Effect of Calcium Sulfate On the Soluble Oil Process

Gypsum (CASO4 2H2O) is a slightly water-soluble mineral present in some oil reservoirs. Its maximum solubility is about 2,000 ppm in fresh water, and about 7,000 ppm in NaCl brine. We ran several flood tests to determine whether this slightly soluble mineral would affect the soluble oil flooding process. The data in Fig. 1 show that 0.5 percent or more gypsum in the sand reduces oil recovery by the soluble oil-polymer flood. With no CASO4 present, oil recovery was 96 percent, while with 2 percent CASO4 in the sand, oil recovery was 55 percent. The most probable mechanism by which gypsum reduces the oil-displacing effectiveness of the soluble oil-polymer process is related to the dissolution of solid gypsum by flooding solutions and the consequent reaction of dissolved Ca++ with flooding chemicals. Dissolved Ca++ can affect the soluble oil flooding process in two ways:it can precipitate some process in two ways:it can precipitate some of the petroleum sulfonates, andit can reduce the viscosity of polyacrylamide solution.

JPT

P. 179
Engineers as Managers
Authors: Donnell J.C.
Published: December 2007

New Emphasis on Management Training

Hardly a week passes in which an invitation does not come from some university or management consultant firm to send some of our prospective management personnel for exposure to the newest concepts in the arts of administration. Seldom do we pick up a periodical, even of the popular variety, that does not contain an article about some company's program for management development. Your bookcases, like mine, surely have received more than their share of books on how to become a more effective administrator, a better manager, or an executive that gets the job done.

This unprecedented emphasis on managerial development has been prevalent since the close of World War II, and has long since passed the fad stage. Why is this? American industry has always managed to develop its leaders in the past; what is it that's different today?

Probably it stems from the increasing size and complexity of industry. Great technological developments, for which the engineers are partly responsible, have contributed to this complexity and growth. We have also inherited some factors from the past, the depression of the 30's and war in the 40's with their respective unemployment and shortage of workers played their part in disrupting the transition of American industry to its present status. The fact that in the past 25 years government has come to play an ever increasing role in American industry, exercising much greater regulation and control, has also had its effect. Now with the return to a highly competitive era, we are all concerned with the problem of getting more people to manage capably and to perpetuate our enterprises.

No Stereotype for Successful Managers

In all the discussion that bas developed over the past few years, it is obvious that many people think a manager or an executive has certain specific traits easily recognized which can be developed by education, training, and experience. This is not true, for there is no stereotype of successful managers. Managers vary just like other people do. Certainly there is no reason why all the characteristics of managers at different levels should be similar, and why shouldn't they vary from company to company and industry to industry and from time to time? American industry, and the oil industry in particular, must depend on all its professional and highly skilled employees as a reservoir of managers today and increasingly so in the future.

On this basis, undoubtedly the engineering profession will provide its share of these managers. In searching for managers, our criterion should not be any arbitrary traits or qualifications, but rather "what can a man accomplish."
The Application of Electrical Transients to Well Logging
Authors: Karplus Walter J. , Smith Otto J.M.
Published: December 2007

The transient response of earth formations may be determined by means of four electrodes mounted colinearly on a sonde. Exponentially decaying current pulses are applied to one pair of electrodes and the resulting voltage transient at the other pair is recorded. It is shown by theoretical analysis and verified by laboratory experiments that this arrangement readily yields the direct resistivity of the formation and provides valuable additional information as well.

Introduction

Although electrical transients have been employed with moderate success in geophysical prospecting, their application to well logging has received virtually no attention in technical literature. In the conventional direct resistivity logging methods only the zero frequency impedance of the formation under study is measured, and no information is obtained regarding its reactive characteristics. Since the use of certain transients appears to offer some advantages in this respect, experiments were performed on a laboratory scale to investigate this possibility. This investigation was limited to a study of a four-electrode array where both the receiving and transmitting electrode pairs are mounted on a logging sonde, and decaying exponential pulses are applied to the transmitting electrodes.
Velocities in Developed Five-Spot Patterns
Authors: Parsons R.W.
Published: December 2007

Laboratory experiments have shown that some oil recovery processes are rate sensitive, particularly Those employing surfactant-type materials. In this note, an ideal reservoir is analyzed to give a feel for proper rates in linear laboratory tests to best simulate proper rates in linear laboratory tests to best simulate a field pattern.We need to consider the distribution of frontal velocities* for field patterns. For the developed five-spot, velocities will range from very high in the well-bore vicinity to zero at the stagnation points halfway along each of the five-spot sides. Detailed frontal velocity distribution was determined from a computer streamline model for a homogeneous, isotropic, single mobility, confined five-spot octant. Each of the 12 equal volumetric rate stream channels in the octant had 40 cells with computer-generated values of volume and velocity.Fig. 1 shows the volumetric distribution of frontal velocities for the entire five-spot pattern (the same as for the octant). Velocities are on a normalized, but not dimensionless, basis, so the single curve applies for any pattern size, injection rate, and porosity. The median frontal velocity, 0.016, is that value at which half the five-spot volume has higher velocities and half lower. For example, a 10-acre five-spot with 20 percent porosity and an injection rate of 5 B/D-ft percent porosity and an injection rate of 5 B/D-ft would have a median frontal velocity of 0.016 X 5/(0.2 X the square root of 10) = 0.13 ft/D. Unless there is some other compelling consideration, this median value is probably a good single characterization of fluid velocity in a developed five-spot. Note that because of high near-wellbore velocities, the volumetric averaged velocity is somewhat higher than the median.A more detailed analysis would consider velocities at a displacement front in each of the stream channels as a function of total pattern injection. Fig. 2 shows the five-spot octant stream channels and location of a unit mobility ratio perfect piston front at various injection times. Velocities in Stream Channels 2, 4, 6, 8, 10, and 12 as a function of total pattern injection are shown in Fig. 3. Each curve is symmetrical about some vertical line. Consideration of Figs. 2 and 3 will give one a feet for just how realistic a particular linear laboratory experiment might be in simulating field five-spot rates.

P. 550
Estimating Flow Efficiency From Afterflow-Distorted Pressure Buildup Data
Authors: McKinley R.M.
Published: December 2007

Since publishing the type-curve analysis method given in Ref. 1 for afterflow-distorted pressure; buildup data, I have received numerous queries on estimating the flow efficiency of a damaged well directly from the type-curve match. This note describes a method that gives a rough estimate of flow efficiency for wells with localized damage.Fig. 1 shows pressure buildup data computed during the afterflow period for a well producing at 60kh percent flow efficiency. In this figure, T = percent flow efficiency. In this figure, T = md-ft denotes transmissibility in units of, and F is thecp wellbore storage capacity in cu ft/psi, as defined below Eq. 5 in Ref. 1. If one assumes that this storage factor remains reasonably constant during the afterflow period, then the breakaway character of the type-curve match in Fig. 1 denotes localized wellbore damage with at least a 5:1 permeability reduction around the well. The departure of the data points in Fig. 1 from the T/F = 5,000 curve after a buildup of 80 to 100 psi denotes a transition from a state in which flow into the wellbore is determined by damage-zone resistance to a state in which formation resistance controls the flow. Conversely, pressure buildup before the departure represents pressure recovery across the damage zone. This is obviously a true statement for the two limiting cases ofno wellbore damage at all, andinfinitely large formation permeability beyond the damaged zone.

Statement validity for intermediate cases can be shown from the unit response formulation given in Ref. 1.

P. 696