bluuebunny/crossref_metadata_2025_split huggingface dataset:
Relationship Between Horizontal Stress and Depth in Sedimentary Basins
Authors: Breckels I.M. , van Eekelen H.A.M. 
Published: December 2007

Summary
Previous work on establishing a relationship between in-situ stress and depth is reviewed. On the basis of data from literature, supplemented by available field data, equations are proposed to describe the trend of horizontal stress with depth for normally pressured formations in the U.S. gulf coast region. A separate correlation between horizontal stress and pore pressure allows this trend to be extended to formations containing abnormal pore pressures.
Having achieved a good correlation for data from this well-documented region, we repeat the process for other parts of the world, using data from hydraulic fracture treatments and formation integrity (leakoff) tests. Similar relationships between horizontal stress and depth are found to hold for normally pressured areas that are geologically and tectonically similar to the U.S. gulf coast. Coupled with regional correlations between horizontal stress and pore pressure, these relationships enable horizontal stress levels to be estimated for a given depth, provided the pore pressure also is known.

Introduction
The instantaneous shut-in pressure (ISIP) recorded during or after a fracturing job or during a minifracture test provides a good approximation to the minimum principal in-situ total stress components sHmin. The vertical total stress or overburden stress sV (normally the maximum principal in-situ stress) can be derived by integration of the formation density, compensated (FDC) log. In tectonically inactive areas, the intermediate principal stress, sHmax, can be assumed approximately equal to the minimum principal stress: sHminsHmax&lt;sV. In the more general case, when sHmax&gt;sHmin, the value of sHmax in principle can be derived from the formation breakdown pressure pb as measured at the start of a fracturing job. For a fully plastering fluid, for instance, pb 3sHmin-sHmax-Pc where Pc is the pore pressure.
In practice, however, sHmax cannot be determined accurately because the breakdown value will be influenced by hole geometry, hole integrity, mud-cake properties, and the extent to which the fluid penetrates into and pressurizes the pore space around the borehole. Also, hydraulic fracturing data are often lacking in many areas of the world. The only remaining way, then, to obtain information relation to in-situ stresses is to analyze the results of formation integrity tests (leakoff tests and casing-seat tests). In these tests, the pressure at which the formation starts taking fluid may range from sHmin to 2sHmin-Pc. Therefore, it is the lower end of the range of values from formation-integrity tests that is of interest for in-situ stress determination.

Review of Previous Work
The majority of hydraulic fracturing/formation-integrity test data quoted in literature are from the U.S. gulf coast and Santa Barbara Channel (CA). From these data, a number of authors have derived fracture gradient correlations to be used in planning drilling programs.
Sulfonate Retention and Residual Oil Saturation
Authors: Presley C. Travis 
Published: December 2007

Abstract
This paper describes an empirical relationship between sulfonate retention and final residual oil saturation achieved by a micellar/polymer oil-recovery process. Using this relationship and certain assumptions, one can derive expressions for predicting oil recovery performance in coreflood experiments. The equations contain two experimental constants: (1) sulfonate retention and (2) a factor related to the oil-recovery efficiency of the sulfonate slug in cores, specific to both the slug and core material. This same relationship applies to both linear and radial cores.
The equations derived predict nonlinear scaling effects. These effects have been demonstrated in laboratory corefloods.
Laboratory Experiments in Fracture Propagation
Authors: Medlin W. L. , Massé L. 
Published: December 2007

Abstract
This paper describes fracturing experiments in dry blocks of various rock materials. The results have application to evaluation of hydraulic fracturing theories. The block dimensions were 3 in.×4 in.×12 in. [7.6 cm × 10.2 cm × 30.5 cm] with metal plates epoxied to the 3-in. × 12-in. [7.6-cm×30.5-cm] faces. Remaining faces were coated with soft epoxy to provide an impermeable jacket. The blocks were loaded in a pressure cell with an upper movable piston bearing on the 3-in.×4-in. [7.6-cm× 10.2-cm] faces. A servocontrolled press applied constant stress to these faces higher than a lateral confining stress applied by oil pressure. Fractures were initiated by injection of various fluids into a small notch located on a center plane parallel to the 4-in. × 12-in. [10.2-cm ×30.5-cm] faces. Fracture growth along the same plane was assured by the stress conditions. Use of these experiments to test theories of fracture propagation required measurement of three variables, fracture width bi, and propagation pressure pi at the notch entrance, and fracture length, L. bi was determined by a capacitance method, and pi, was measured directly by a pressure transducer. L was measured by two methods—either ultrasonic signals or pressure pulses generated in miniature cavities. The ultrasonic method confirmed the existence of a Barenblatt liquid-free crack ahead of the liquid front whose relative length decreased with confining stress. The metal plates bonded to the 3-in.×4-in. [7.6-cm× 10.2-cm] faces prevented slip at the top and bottom of the fracture, giving a three-dimensional (3D) crack of constant height. However, the bi, pi, and L data followed trends predicted by two-dimensional (2D) (plane strain) elastic theory reasonably well. Fracture closure measurements after shut-in showed an initial period of leakoff-controlled closure and a final period of creep-controlled closure. A pi, slope change at the transition is identified with the instantaneous shut-in pressure (ISIP) in field records and is higher than the true confining stress.
A Thermoelectric Device for Measuring Thermal Conductivity of Rock
Authors: Khan A.M. , Fatt Irving 
Published: December 2007

Abstract
A new type of steady-state thermal conductivity apparatus is presented and described. Results of measurements on Berea sandstone, Solehofen limestone, Banders sandstone and Bakelite are presented. The measurements were made in a two-hour period at temperatures up to 80C and axial stress to 125 bars. Results show that the thermoelectric beat pump and thermistor-controlled electric heater can be used in a steady-state apparatus for measuring thermal conductivity of rock. Steady-state is reached within two hours. With Urethane foam insulation, not more than 3 per cent of heat is lost by radial flow. The apparatus can be used as a comparator or for absolute thermal conductivity determinations.
Introduction
Calculations of heat flow through the earth, both for scientific purposes and engineering design, require thermal-conductivity data on rock. However, the high variability of rock often makes handbook thermal-conductivity data of little value. For engineering purposes in particular, it is desirable to have measured data on samples of the rock mass under study. Laboratory methods for measuring thermal conductivity of rock use either time-dependent or steady - state temperatures. The time-dependent (transient) techniques give thermal diffusivity from which thermal conductivity can be calculated if the specific heat and density of the sample is known. Most transient techniques require lengthy and involved sample preparation. Also, the accuracy tends to be low. Steady-state techniques are more exact and are the most commonly used. The steady-state methods, however, also have their difficulties. A long time is often required to reach steady state, troubles have been encountered in establishing good thermal contact between the heating and cooling elements and the rock sample, and unaccounted-for heat losses are difficult to prevent. In this paper we present a description of a new type of steady-state thermal conductivity apparatus. With it, measurements have been made in two hours at temperatures up to 80C and axial stress to 125 bars. Sample preparation is simple and no thermal conductivity standard is needed.
APPARATUS
Our steady-state apparatus is an improvement over the conduction pile used by Zierfuss and van der Vliet and Somerton. A linear heat flux is established through a conduction pile consisting of the rock sample and a standard material of known thermal conductivity in series.
SPEJ
P. 113ˆ
Experience With Piston and Piston-Rod Seals for High-Pressure Reciprocating Compressors Injecting Natural Gas on North Sea Production Platforms
Authors: Wilson R.S. 
Published: December 2007

Summary
The need to restrict flaring of associated natural gas has emphasized the importance of reliability of high-pressure reinjection compressors installed on certain North Sea platforms. This paper reviews the contribution made by the development of piston and rod seals used on injection compressors, with reference to three important fields: Beryl, Statfjord, and Thistle.

Early North Sea Reinjection Experience
During 1977 the first associated natural gas was reinjected in the U.K. oil sector. This operation is performed by two-stage reciprocating compressors. Early experience with these compressors revealed that the piston and rod seals. which are subjected to pressures approaching 400 bar [40 MPa], were a major source of machine failures. These failures consisted of severe scuffing and wear between the bronze sealing elements (piston and packing rings) and the countersurface (liners and piston rods), causing erratic seal life, sometimes of only a few hours' duration, together with badly damaged liners and piston rods. The typical condition of used bronze piston rings is illustrated in Fig. 1, and the operating lives achieved with bronze seals are summarized in Table 1. The most serious consequence of this unreliability was its effect on continuity of oil production, and an immediate development program to eliminate such failures was begun by the platform operator in collaboration with the appointed seal manufacturer. Details of this development are presented, including an analysis of the causes of seal failures and measures taken to remedy them, with particular attention to seal material and design and to lubrication requirements. Field experience gained in the application of the modified seals is summarized in three case histories. details of which arc given in Tables 2 through 4, with comparative results listed in Table 5.

Selection of Seal Material
At the outset of this development program, a change to nonmetallic seal materials for both the piston rings and the rod packings was considered on the basis of a proprietary grade of filled polytetrafluoroethylene (PTFE), which had already been used successfully for packings and piston rings in various lubricated compressor installations, includingethylene primary compression to 350 bar [35 MPa],ammonia synthesis gas compression to 350 bar [35 MPa], andhydrogen compression in refinery service to 200 bar [20 MPa].
JPT
P. 2294^
Modeling Infinite-Conductivity Vertical Fractures With Source and Sink Terms
Authors: Nghiem Long X. 
Published: December 2007

Abstract
This paper describes a method for handling infinite-conductivity vertical fractures in reservoir simulation by using source and sink terms. It begins with a review of the concept of source/sink in reservoir simulation, and uses that concept to develop a method for computing the flow into or out of the fracture by assuming elliptical flow and by using the pressures of the blocks surrounding those containing the fracture. The assumption that the flow into the fracture is everywhere perpendicular to the fracture plane (i.e., linear flow) and the effect of the skin factor are also investigated.
Test runs showed excellent agreement between computed results and those obtained by analytical and variational methods for single-phase systems. The formulation was extended to multiphase systems, and simulation of a waterflood yielded physically reasonable results.
A Practical Method for Modeling Fluid and Heat Flow in Fractured Porous Media
Authors: Pruess Karsten , Narasimhan T. N. 
Published: December 2007

AbstractA multiple interacting continua (MINC) method is presented, which is applicable for numerical simulation of heat and multiphase fluid flow in multidimensional, fractured porous media. This method is a generalization of the double-porosity concept. The partitioning of the flow domain into computational volume elements is based on. the criterion of approximate thermodynamic equilibrium at all times within each element. The thermodynamic conditions in the rock matrix are assumed to be controlled primarily by the distance from the fractures, which leads to the use of nested gridblocks. The MINC concept is implemented through the integral finite difference (IFD) method. No analytical approximations are made for the coupling between the fracture and matrix continua. Instead, the transient flow of fluid and heat between matrix and fractures is treated by a numerical method. The geometric parameters needed in a simulation are preprocessed from a specification of fracture spacings and apertures and the geometry of the matrix blocks.The numerical implementation of the MINC method is verified by comparison with the analytical solution of Warren and Root. Illustrative applications are given for several geothermal reservoir engineering problems.
Interpretation of Well-Block Pressures in Numerical Reservoir Simulation With Nonsquare Grid Blocks and Anisotropic Permeability
Authors: Peaceman Donald W. 
Published: December 2007

Abstract
Previous work on the interpretation of well-block pressure (WBP) for a single isolated well is extended to the case of nonsquare grid blocks (∆x ≠ ∆y). Numerical solutions for the single-phase five-spot problem, involving various grid sizes, show that the effective well-block radius (where the actual flowing pressure equals the numerically calculated WBP) is given by ro=0.14 (Δx2+Δy2)½.
This relationship is verified by a mathematical derivation for a single well in an infinite grid. The exact value of the constant is shown to be eγ/4, where γ is Euler's constant.
Finally, the analysis is extended to include anisotropic permeability, and an expression for the effective well-block radius in terms of Δx, Δy, kx, and ky is derived.
Kinematics of the Cone Bit
Authors: Ma D. K. , Yang S. L. 
Published: December 2007

Abstract
The bits' and bit cones' angular velocities are variable with time. All published papers on cone bit kinematics, however, are based on the supposition that the motions of cones are uniform. This supposition, therefore, has been the main obstacle to determining the objective law of the working cone bit.
The apparatus, methods, and tests results for measuring the bit and cone instantaneous angular velocities are described. A new theoretical analysis of cone bit motion is proposed and some interesting new conclusions are obtained that will help designers and users of cone bits.
Numerical Simulation of Coning Behavior of a Single Well in a Naturally Fractured Reservoir
Authors: Huan-zhang Chen 
Published: December 2007

Abstract
The history matching and predicting of an actual well in a reservoir with double porosity is performed with a new coning simulation model that gives satisfactory results. A discussion of the parameters used for matching provides some insight into the structure and parameters of the reservoir. Other points discussed include (1) bottom-water rising characteristics, (2) a comparison between the dual porosity and the single porosity (assuming that the mass transfer between the fracture and matrix is equal to zero), and (3) the imbibition characteristics of matrix.
Comparative Energy Requirements of Oilfield Pumping Units--Conventional vs Front-Mounted
Authors: Patton L. Douglas 
Published: December 2007

Abstract
Conventional front-mounted, rotary crank-balanced pumping units were compared with front-mounted pumps to determine the comparative electric energy requirements. The wells studied were divided into groups of identical make, API ratings, strokes per minute and stroke length. Monthly production and power consumption were averaged for a six-month period and kilowatt- hours per barrel of fluid per 1,000 ft of depth were calculated and plotted against fluid production per day. The front-mounted units consumed an average of 36.8 per cent less electric power than did the conventional units when the strokes per minute were scaled evenly. Design modifications of the front-mounted units are discussed and dynagraph cards are used to illustrate the work loads.
Introduction
A number of major oil companies have made comparative field tests of the front-mounted, rotary crank- balanced pumping unit (Fig. 1) and various conventional beam-type pumping units (Fig. 2). These tests were generally made using one type of unit on a given well for several days then replacing it with the other type unit for the same length of time. The daily production, electric energy used and inch-pounds of torque required were all noted during these exacting tests. Obviously a study of this type requires more time and money than are generally available to most companies. Another method of comparing the conventional beam- type pumping unit with the front-mounted, rotary crank- balanced pumping unit, based on electric energy consumed per barrel of fluid pumped, is discussed in this paper. The wells under study were divided into groups of identical make, API ratings, strokes per minute and stroke length:
conventional 160D units operating at 16.5 X 64 in. strokes/min; conventional 160D units operating at 16.3 X 64 in. strokes/min; and front- mounted 114D units operating at 16.7 X 64 in. strokes/ min.
JPT
P. 26ˆ
Fluid-Loss Control Through the Use of a Liquid-Thickened Completion and Workover Brine
Authors: Hudson T.E. , Coffey M.D. , Sauer C.W. , Teot A.S. 
Published: December 2007

Summary
A new liquid thickening agent has been developed for controlling fluid loss of clear brines. This control is of critical concern during the completion or workover of an oil, gas, or service well.
Many clear brines are expensive (up to $800/bbl for some concentrations). The loss of these fluids to the formation can become a significant completion/workover expense. From a safety standpoint, the loss of clear brines to a formation may create a reduction in hydrostatic pressure, which would increase the potential of a well kick or blowout.
The newly developed agents function in brines with densities from 9.1 to 19.2 lbm/gal. They are superior to the traditionally used polymer because they start to build viscosity instantly, without the formation of "fish eye"s. The viscosity developed in the clear brines through the addition of these materials can be broken easily at the surface by the addition of small amounts of commonly available breakers. Brines containing this polymer show little or no permanent return permeability damage. The properties of the materials as fluid-loss-control additives in clear brines, their nondamaging characteristics, and rheological properties of the thickened brines are described. Case histories support the advantages of these properties.

Introduction
Fluid-loss control of clear brines is of primary concern during the completion or workover stage of an oil, gas, or injection well. The clear brines used in completions and workovers typically contain KCl, NaCl, CaCl2, CaBr2, and ZnBr2, or combinations of these salts, and range in density from 8.4 to 19.2 lbm/gal. These brines cost from a few dollars for the least-dense brine to about $800 for a 19.2-lbm/gal brine. The loss of these relatively high-cost, clear brines to the formation can be of significant importance when attempts are made to minimize completion and workover expenses. Loss of fluid level, resulting in a decrease of hydrostatic pressure on the formation, which exposes the rig and personnel to the danger of a well kick or blowout. Fluid-loss-control mechanisms when clear brines are in use have traditionally included (1) reducing the density of the completion or workover fluid, thereby imposing less hydrostatic pressure on the formation, (2) adding solids such as graded CaCO3 particles, FeCO3 particles, or sized rock salt, and (3) increasing the viscosity of the clear brines by adding dry polymers such as guar gum, hydroxylpropyl guar, xanthan gum, and (most commonly) hydroxyethylcellulose (HEC). These methods have been used independently and in combination with one another.1–4
Experimental Study of Drilled Cuttings Transport Using Common Drilling Muds
Authors: Hussaini Syed M. , Azar Jamal J. 
Published: December 2007

Abstract
Experiments are conducted with actual drilling muds to study the behavior of drilled cuttings in a vertical annulus. The effect of parameters such as particle size, flow rate, apparent viscosity, and yield point to plastic viscosity ratio on mud-carrying capacity are studied. The applicability of a semiempirical transport model developed by Zeidler also is investigated.
It has been shown that in vertical annuluses, the fluid annular velocity has a major effect on the carrying capacity of muds, while the other parameters have an effect only at low to medium fluid annular velocities. We also conclude that Zeidler's semiempirical formulations for the prediction of drilled cuttings behavior are valid with certain limitations.
The Phase Behavior of Simple Salt-Tolerant Sulfonates
Authors: Barakat Y. , Fortney L. N. , LaLanne-Cassou C. , Schechter R. S. , Wade W. H. , Weerasooriya U. , Yiv S. 
Published: December 2007

Abstract
Alkane and α-olefin sulfonates can be used to produce optimal microemulsion formulations having very high salinity tolerance (including divalent ion) while maintaining large solubilization parameters and low inter-facial tensions (IFT's). Such molecules require elevated temperatures or higher alcohol concentrations to suppress liquid crystal formation. As in other species, solubilization is inversely related to width of the three-phase regime, and IFT and solubilization are strongly coupled.
Effect of Rates on Performance in Browning Unit Water Flood
Authors: Wright F.F. 
Published: December 2007

Abstract
A brief history of the Browning Unit waterflood project in Greenwood County, Kans., is presented in which both slow and high injection rates have been used. The pilot area which was subjected to six years of slow injection rates followed by high injection rates is analyzed. It is concluded that performance has been more satisfactory at the higher rates of injection.

Introduction
The Browning Unit is a pattern-type flood operated by Sinclair Oil & Gas Co. Other members of the unit include Tidewater Oil Co., Sunray Mid-Continent Oil Co., Dover Corp., C. A. Steele, Irma Rosenthal and David M. Rhodes Estate. Because of the variance in waterflooding rates applied during the past eight years, much interest in the performance has developed.

Geology
The Bartlesville sand of Pennsylvanian age is found at approximately 2,300 ft in a lens-shaped body apparently deposited as an offshore bar. The unit lies in a definite trend of shoestring development of the Bartlesville sand. Figs. 1 and 2 show core graphs of the Bartlesville sand on the Browning Unit. Table 1 gives other information concerning this reservoir.

Primary Production
Fig. 3 gives the oil production history of the unit since its development in 1924. In addition, Fig. 4 shows a pre-unit history on a typical part of the Browning Unit. At the start of the water flood the primary oil was essentially depleted.

Gas Repressuring
In 1928 a program of gas repressuring was started which recovered an estimated 3 million bbl of oil.