bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fracturing at High Injection Rates, Spraberry Trend Area Field
Authors: Brooks Thomas P. , O&apos;Quinn Percy C. , Life Warner E. 
Published: December 2007

Abstract
The application of relatively large volume fracture treatments using anoil-sand mixture at high injection rates in wells completed in the Spraberryformation has indicated improved drainage from the matrix rock. This isconsidered to result from enlargement of existing open fractures, possibly fromopening of fractures not previously effective, and breaking down existingblockage in the vicinity of the well bore. The results of this type oftreatment as applied to a group of wells in the Spraberry Trend Area field arediscussed with reference to well performance and economics.

Introduction
Extremely small return on investment in a group of wells drilled in theSpraberry Trend Area field called for concerted effort toward stimulation ofproduction. Production history indicated that original recoverable reservefigures were inordinately above ultimate recoveries which could then beforeseen. Many wells were facing abandonment with subsequent writeoff ofreserves if means of restoring them to production were not forthcoming. Otheroperators were experimenting with means of increasing recovery, such as waterimbibition, but results would not be known for some time. Satisfactory resultsachieved from formation fracturing by injecting oil-sand mixture at high ratesin other areas indicated possible results from such treatment in the Spraberryformation. Particular similarity was noted between the Spraberry formation anda reservoir in Wyoming-both having low permeability, vertical fracturing, andinterbedding with shales. Fracturing of the formation in Wyoming using highinjection rates had been and was then being practiced with satisfactoryresults. The decision to apply this fracturing technique experimentally to onewell and the results of this initial treatment have led to numerous wells beingfractured in this manner.
Electrical Conductivities in Shaly Sands-I. The Relation Between Hydrocarbon Saturation and Resistivity Index; II. The Temperature Coefficient Of Electrical Conductivity
Authors: Waxman Monroe H. , Thomas E.C. 
Published: December 2007

The Waxman-Smits physical model for describing conductivity in shaly sand has been extended to allow for oil-bearing sand, and the required assumptions have been confirmed by laboratory measurements. A conclusion from the tests is that the effective concentration of clay-exchange cations increases in proportion to the decrease in water saturation. The temperature coefficients of electrical conductivity for a group of shaly sands were measured and these data were treated by the same model.

Introduction
Waxman and Smits have recently advanced a simple physical model describing shaly sand conductivities. physical model describing shaly sand conductivities. The model assumes:a parallel conductance mechanism for free electrolyte and clay-exchange cation components,an exchange cation mobility that increases to a maximum and constant value with increasing equilibrating electrolyte concentration, andidentical geometric conductivity constantsapplicable for the contributions of both the free electrolyte and the clay-exchange cation conductance to the sand conductivity.
The general equation for water-saturated sands is then obtained:(1)
with(2)
Co and Cw are the specific conductances of the sand and equilibrating brine, respectively (mho cm). F* is the shaly sand formation resistivity factor, related to porosity (0) according to an Archie-type relation:(3)
where m* is the porosity exponent. 1/F* is the slope of the straight-line portion of the Co vs Cw, curve. Qv is the effective concentration of clay-exchange cations (equiv/liter or meq/mi) and can be determined independently from the ratio of cation exchange capacity (meq per 100 gm of rock) per unit pore volume of rock (ml per 100 gm of rock). B represents the equivalent conductance of the clay counterions as a function of Cw with units of mho cm2 meq -1. lambda Na (or B max) is the maximum equivalent ionic conductance of the (sodium) exchange ions, and a and lambda are empirical constants. Waxman and Smits report values (Group 1 samples) of a = 0.83, = 0.02, and lambda Na = 38.3 cm2 equiv- 1 ohm-1 at 25 degrees C. Somewhat different values of the a, y, and lambda Na were reported by Waxman and Smits for another and considerably smaller set of shaly sand samples (Group 2). These were a = 0.6, lambda = 0.013, and lambda Na = 46.0 CM2 equiv-1 ohm-1 at 25 degrees C. Further work reported here (Table 2) supports the values obtained for the Group 1 samples. The Qv values calculated from conductivity data and a value of lambda Na = 38.3 cm2 equiv-1 ohm-1 agree within experimental error with Qv values determined by independent laboratory procedures for the new group of shaly sands used for this study.
JPT
P. 213
Offshore Fracture Gradients
Authors: Christman Stan A. 
Published: December 2007

The analysis described here, based on Santa Barbara Channel field experience, shows that increasing water depth reduces the overburden stress gradient, substantially influencing the apparent fracture gradient, particularly at shallow penetrations. Two methods of correlating fracture particularly at shallow penetrations. Two methods of correlating fracture gradient are presented in the analysis.

Introduction
The consideration of formation fracture gradients in selecting casing setting depths is fundamental to the preparation of an acceptable drilling program. When preparation of an acceptable drilling program. When Exxon Co. U.S.A. undertook the deepwater challenges of the Santa Barbara Channel, a project was initiated to develop a fracture-gradient prediction technique that would assess the impact of water depth.

Development of the Technique Onshore Fracture Gradients
As frequently referenced, Hubbert and Willis, established a theoretical basis for subsequent work in the development of actual fracture-gradient prediction techniques. Later theoretical studies of porous bodies have concluded that the most important factors affecting fracture initiation pressure are the overburden stress, the formation fluid pressure, and the horizontal-to-vertical stress ratio, whereas rock compressibilities and Poisson's ratio have relatively little influence. Matthews and Kelly, in a technique presented in 1967, correctly indicated that the stress ratio, F sigma, was the most significant and yet elusive variable. The following relation was presented for the fracture gradient:
..........................................(1)
By assuming a total overburden gradient of 1.0 psi/ ft, we can estimate the effective vertical stress as follows:
..........................................(2)
For normally pressured formations, the stress ratio, F sigma, is empirically correlated, on the basis of field data, for a given area as a function of depth. The onshore aspect of the technique that was developed for the Santa Barbara Channel area incorporates these stress-ratio concepts with a method to estimate the actual overburden gradient rather than using the assumed value of 1.0 psi/ft. Since the overburden stress at any depth should be the cumulative weight of the formations above that depth, well data that are indicative of formation density can be used to estimate overburden. Techniques have been published that are based on velocity data from seismic published that are based on velocity data from seismic surveys and sonic logs or that utilize formation bulk density logs directly. We selected the latter method and estimated overburden with Eq. 3:
..........................................(3)
where 0.4335 is the constant used to convert units of gm/cc to psi/ft. In practice, of course, a simple arithmetic average of the bulk densities of the overlaying formations, pb, will suffice:
..........................................(4)
The final form of the fracture-gradient prediction formula used in the Channel is given as Eq. 5:
..........................................(5)
JPT
P. 910
Experimental and Calculated Behavior of Dissolved-Gas-Drive Systems
Authors: Ridings R.L. , Dalton R.L. , Greene H.W. , Kyte J.R. , Naumann V.O. 
Published: December 2007

Abstract
This paper presents a one-dimensional numerical method for calculating dissolved-gas-drive behavior for a single well or a linear reservoir. Pressure and saturation distributions can be calculated, including the effects of capillary and gravity forces. The analysis has been programmed for solution on the IBM 7090 digital computer. A comparison of experimental and calculated behavior for two linear models demonstrates that the method is suitable for calculating dissolved-gas-drive behavior under reservoir conditions of flown Dissolved-gas-drive tests were run, at different production rates and with oils of different viscosities, on short (6-ft) and long (173-ft) flow models. For tests approximating reservoir pressure gradients and flow rates, there was excellent agreement between experimental and calculated results. A series of calculations of well behavior for thin, horizontal, homogeneous, dissolved-gas-drive reservoirs shows that ultimate recovery is independent of production rate or well spacing in such cases. These calculations also show that Muskat's method and similar material-balance analyses are not applicable under some conditionsparticularly for high pressure drawdowns.

Introduction
The problem of calculating dissolved-gas-drive reservoir performance has received a great deal of attention throughout the oil-producing industry for many years. Really significant advances, however, have been made only in recent years. The rapid evolution of high-speed computing equipment and techniques has opened up new approaches to the problem and led to realistic, quantitative analyses free of many of the assumptions and limitations of earlier methods. The one-dimensional numerical method described in this paper includes the effects of both gravity and capillary forces. A number of test calculations, based on different rates, spacings, and rock and fluid properties, have shown that the method is adequate for systems that can be reasonably represented by a one-dimensional model (linear or radial) and in which fluid segregation perpendicular to the direction of flow is not important. Along with the development of mathematical methods, an experimental program was conducted and the data were used to test the validity of the theoretical basis of the mathematical method. Linear models were used and all experiments were run using 1,000-psig bubble-point oils. The use of long, high-pressure models enabled us to more closely approach reservoir gradients and flow rates.

MATHEMATICAL FORMULATION DIFFERENTIAL EQUATIONS
The differential equations describing dissolved-gas-drive behavior in one dimension dare summarized here. They include Darcy's law for flow of oil and gas (Eqs. 1 and 2) and the equations for conservation of mass for oil and gas (Eqs. 3 and 4). The oil and gas pressures are related by capillary pressure (Eq. 5).
vo = - ..........(1)
vg = Rsvo - ......(2)
-qo + ......(3)
-qg + ............................................(4)
SPEJ
P. 41^
The Dye-Photo Tool: Its Operation and Applications
Authors: Bryant C.M. 
Published: December 2007

Description of Tool
The need for an economical, practical method for accurately locating zones of water entry in a wellbore has long been recognized by production men. The development of waterflooding made necessary a means of determining which horizons were being flooded, and the rate of flooding of each zone during actual operations. Research resulted in the Dye-Photo tool shown in Fig. 1.
The tool is designed to measure the translucency of any liquid in which it may be suspended. As fluid passes between a light source and a photo-electric cell. its light transmissive properties are measured. This data is transmitted to the surface where it is recorded (Fig. 2). By conditioning the fluid in the wellbore with an opaque dye, any fluid migration or dilution can be detected readily.
The Dye-Photo tool has three major components:a bailer for containing and releasing the dye,a photo-electric cell which accurately measures any change in light intensity in the conditioned section, anda sonic collar locator for coordinating depth measurements.
The tool is operated by electrical impulses transmitted from the surface through the standard 5/16-in. diameter single-conductor electrical armored cable.
The consolidation of these three components into single tool has greatly reduced the time, and resulting expense, required for conducting a survey. Simplicity of operations and easily interpreted results are characteristics of surveying with the Dye-Photo tool. Accuracy of results has been attested by the success of subsequent remedial operations.

Preparing for Survey
Certain fundamental preparations should be made for conducting a water location survey using the Dye-Photo tool:Water must be standing in the wellbore, at lease throughout the section to be surveyed.If water has been injected into the formation recently, the well should be produced in sufficient quantity to eliminate the possibility of injected water being produced during the survey from a normally non-producing zone.The well should be cleaned out to total depth. All cavings should be bailed or sand-pumped.For a pumping well with tubing and rods pulled, some method of producing the well (usually either a bailer or swab) must be available.If the well is to be surveyed down the annulus, a special wellhead should be installed to minimize the hazards of running a line down the annulus. The clearance between tubing couplings and casing must be sufficient to allow the free passage of the tool.Flowing wells should be equipped with open-ended tubing, suspended above the zone to be surveyed. (The Dye-Photo tool will pass through a standard 1-25/32-in. seating nipple).If a well containing a packer is to be surveyed down tubing, the opening through the packer must be sufficiently large to allow passage of the tool.A mast of some description must be available to handle the "derrick" sheave.
The Effect of Slant Hole, Drainhole, and Lateral Hole Drilling on Well Productivity
Authors: Roemershauser Alvin E. , Hawkins Murray F. 
Published: December 2007

Introduction
Methods have been developed for drilling (a) slant holes and (b) one or more curved holes from a common central hole in producing formations. These wells will have productivities exceeding that of a single hole drilled normal to and fully penetrating the producing stratum. other factors being equal. This increase is due to the decrease in resistance to flow in the vicinity of the wellbore by an increase in the cross section exposed to flow with increasing footage drilled in the formation and due to the geometrical arrangement of the holes with respect to the drainage radius or boundary. Where other factors are not equal, for example, where zonal damage exists in the single, fully penetrating hole but not in the slant or curved holes, additional increases in productivity will accrue.
Many of these wells have been drilled in the past and are currently being drilled with various results reported. While the authors are aware of some of the practical aspects of drilling and completing these multiple. curved holes, it is their hope to provide some basic data on the improvement in productivity to be anticipated in these wells for a number of hole arrangements or patterns.

Model Studies
Electric analogue or model studies have been used for solving some reservoir fluid flow problems in which the mathematical solutions are unknown, too approximate or too complex. For example, recent studies have used this method to determine the effect of shot density, diameter, and depth of penetration of gun perforations on well productivity. The success of these studies depends upon the analogy between Ohm's Law for electrical flow and Darcy's Law for incompressible fluid flow in homogeneous rock. Where a geometrical scale reduction is desired, a single scale factor is applied to all dimensions.
A Correlating Device for Predicting Reservoir Performance
Authors: Heuer George J. , Power Harry H. 
Published: December 2007

Abstract
The paper develops a means for predicting the relative permeability of gas to oil for a reservoir on the basis of early production data. The method is based on the observation that a log-log plot of the cumulative gas versus the cumulative oil production frequently results in a straight line, particularly in the case of solution-gas drive reservoirs, or reservoirs with a partial or delayed water drive.
The method of calculating the relative permeability of gas to oil from this relationship is discussed, together with the specific application to the actual behavior of the Schuler Jones sand pool, Union County, Ark.

Introduction
Ultimately, the determination of accurate relative permeability values may be solved, partially or completely, in the laboratory. At present the difficulty in obtaining representative core samples, the proper weighting of relative permeability values and the inadequacies existing in reservoir equations make it desirable to find some way for the determination of the ratio kg/ko which, when substituted in existing equations, will permit the prediction of future reservoir performance.
The experimental values of relative permeability as determined in the laboratory do not coincide closely with values calculated from field production data. This difference, probably, is a reflection of the original fluid distribution as well as that resulting from dynamic conditions of flow, which result in non-uniform saturation-permeability relationships from one portion of the reservoir to another. The calculated relative permeability for the field is a weighted average value, representing all the instantaneous variations in permeability alone flow lines into the well-bore due to differences in absolute permeability, saturation, pressure and pressure gradient.
At present, it is virtually impossible to simulate these conditions in the laboratory. This paper was written in an attempt to determine the relative permeability of the gas to oil phases from the relationship between oil and gas cumulative production. A prior method for determining field relative permeability by means of the "conformance factor" has been described by Patton.
Inertial and Slip Effects in Steady-State Radial Gas Flow Through Porous Media
Authors: Dranchuk P.M. , Piplapure A.R. 
Published: December 2007

Steady horizontal radial gas flow through porous media may be described by means of the equation(1)
provided there is no slip at the gas/solid interface and provided there is no slip at the gas/solid interface and q is taken to be positive in the r direction. If one assumes that the modified gas law holds and that viscosity, compressibility, and temperature remain constant, this equation may be integrated to yield(2)
which is similar in form to that proposed by Tek et al. This equation may of course be reduced to the well known form employed for Darcy flow by deleting the second term on the right-hand side. However, it has been shown that neither slip nor inertial effects should be neglected when linear laboratory gas flow tests are used to evaluate rock properties. It has been observed that the same is true for laboratory data when taken in radial tests. Although Eq. 1, modified to allow for slip, may be integrated for linear flow, radial flow yields a nonlinear ordinary differential equation with no known solution. However, an approximate solution may be developed in the following manner: To allow for slip, Eq. 1 may be modified and written as(3)
where(4)
If the modified gas law applies and viscosity, compressibility, and temperature are assumed to remain constant at their average values, Eq. 2 may be converted to the form(5)
Substitution of Eq. 4 into Eq. 5 yields(6)
If one defines(7)
and(8)
Eq. 6 may be written as(9)
or(10)
As was stated earlier there is no known solution to this nonlinear ordinary differential equation. Although this equation may be attacked with numerical techniques to estimate rock properties using flow data, the procedure is involved and difficult. However, if the ratio b/p is sufficiently small, Eq. 9 may be approximated by deleting the term (1 + b/p) in the numerator, in which case(11)
or(12)
This equation may be integrated between the limits
; and;
to yield
(13) or(14)
P. 1155
The Shale-Compensated Chlorine Log
Authors: McKinlay P.F. , Tanner H.L. 
Published: December 2007

Although many chlorine logging systems have been used by the petroleum industry, they never attained widespread popularity. The use of many of these systems was limited by their sensitivity to increasing shale content. A shale-compensated chlorine logging system (SCC) has been developed and evaluated. The SCC log interpretation has proven to be correct in predicting the type of fluid behind the casing more than 80 percent of the time.

Introduction
The chlorine log was introduced to the petroleum industry in the late 1950's. The primary purpose of this log was to determine the amount of salt water in the formations immediately behind the production casing and to relate this salinity measurement to hydrocarbon content. Although many chlorine logging systems were used by industry,1–4 they never attained widespread popularity. The use of many of these systems was limited by their sensitivity to increasing shale content.
A shale-compensated chlorine logging system (SCC)5 has been developed and extensively evaluated. The recorded log supplies a continuous salinity profile of the formations behind the casing. A specific advantage of this log over other similar logs is that the system compensates for the effect of shale on the salinity measurement. Also, the porosity, lithologic, and borehole fluid effects on the salinity measurement are minimized.
The log has been run in several hundred cased wells. The majority of the runs have been made in wells subject to workover and/or abandonment. New hydrocarbon-bearing intervals have been identified and oil-water contacts in producing reservoirs have been located. The SCC log interpretation has proven to be correct in predicting the type of fluid behind the casing more than 80 percent of the time. Oil production has been obtained in many wells that, before logging, were considered to have little, if any, economic potential.
The SCC log will give reliable results at logging speeds of 20 to 30 ft/min in formations containing high porosity and salinities above 45,000 ppm NaCl. Slower logging speeds are recommended for areas where porosities are low and/or salinities are less than 45,000 ppm NaCl. The possibility of successful completions based on the log interpretation decreases rapidly when porosities are less than 20 percent and formation salinities are below 30,000 ppm NaCl.

Tool Design
The SCC system was specifically designed to minimize the effects of shaliness, porosity, and lithology on formation salinity measurements and water saturation (Sw) determinations.
The system measures thermal neutron-capture gamma radiation in two gamma ray energy ranges: 1.3 to 2.92 MeV, recorded as the NG (Hydrogen) curve, and all gamma ray energies above 3.43 MeV, recorded as the NG (Chlorine) curve. The detector is a 2-in. by 4-in. long NaI(Tl) scintillation detector that is spaced 15¾in. (center to center) from a 2.3 × 107 neutron / americium - beryllium neutron source. Lead is used as shielding material between neutron source and detector.