bluuebunny/crossref_metadata_2025_split 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.

Abstract
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

Abstract
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 &gt;&gt; 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

Abstract
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

Abstract
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

Summary
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.