bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improvements in Simulation of Naturally Fractured Reservoirs
Authors: Gilman James R. , Kazemi Hossein 
Published: December 2007

AbstractSimulation of multiphase flow in heterogeneous two-porosity reservoirs such as naturally fractured systems is a difficult problem. In the last several years much progress has been made in this area. This paper focuses on the practical aspects of that technology. It describes a stable, flexible, fully implicit, finite-difference simulator in heterogeneous, two-porosity reservoirs. Flow rates and wellbore pressures are solved simultaneously along with fracture and matrix fluid saturations and pressures at all grid points. Hydrodynamic pressure gradient is maintained at formation perforations in the wellbore. The simulator is accurate enough to match analytical solutions to single-phase problems. The equations have been extended to include polymer flooding and tracer transport with nine-point connection for determining severe local channeling and directional tendencies. It is shown that the two-porosity model presented in this paper will produce essentially the same answers as the common single-porosity model of a highly heterogeneous system but with a substantial reduction of computing time. In addition, this paper describes in detail several two-porosity parameters not fully discussed in previous publications.
Shear Failure of Rock Under Compression
Authors: Maurer William C. 
Published: December 2007

Introduction
It is difficult to produce tensile stresses under the high compressive stresses present in the earth; therefore, in deep drilling and geological faulting, shear failure predominates. This shear failure mechanism is complicated because rock is a heterogeneous material containing pore spaces, microfractures, elastic discontinuities and other imperfections. A study of shear failure of rock under pressure has been made to obtain a better understanding of this complex mechanism. A machine has been developed and used to measure the shear strength of rock and friction along sheared surfaces. This machine has certain advantages over the compression test-shear properties can be measured under low normal stresses and shear stress and normal stress can be varied independently. The first part of this paper is a description of shear failure of rock under pressure. The role of shear strength and friction along fracture surfaces in the shear failure mechanism will be discussed. The second part consists of a description of the shear machine and a discussion of the shear strength and friction data obtained using this machine. It will be shown that shear strength depends upon the size of the stressed zone, and that friction does not increase linearly with contact pressure as usually assumed. Attempts are made to relate some of the new concepts to tectonic failure and to drilling.

SHEAR FAILURE IN ROCK TRIAXIAL TESTS
The shear failure mechanism is illustrated by the triaxial test shown in Fig. 1. In this test, a cylindrical rock specimen is subjected to a confining pressure, pc, and an axial pressure, pa. These external pressures produce normal o and shear r stresses on inclined planes within the specimen equal to
(1)
(2)
where theta is the angle between the specimen axis and a normal to the inclined plane. Fig. 2 shows how triaxial specimens deform as the axial pressure is increased.
SPEJ
P. 167ˆ
A Thermodynamic Model of Redissolution of Calcium Sulfonate Precipitates in NaCl Solutions
Authors: Somasundaran Ponisseril , Ananthapadmanabhan Kavssery P. , Celik Mehmet S. , Manev Emil D. 
Published: December 2007

Abstract
Precipitation phenomenon in the sodium dodecylsulfonate system has been investigated in this study at various levels of CaCl2 in a wide range of NaCl concentrations. While precipitation is found to be caused by the formation of calcium disulfonate, redissolution of the precipitate at high sulfonate levels is found to occur only when micelles are formed. Correlation of the effect of ionic strength on the redissolution with that of it on micellization supports the proposed mechanism of micellar redissolution. A thermodynamic model capable of predicting the nature and concentrations of various species in solutions has been developed. The model was tested against different sets of experimental data and was found to predict the system behavior satisfactorily.
Laboratory Investigations of the Dynamic Stability of Polymer Slugs
Authors: Dietzel Hans Joachim , Pusch Günter 
Published: December 2007

Abstract
To assess the dynamic stability of polymer slugs, flooding experiments have been performed in sandpacks and consolidated sandstone cores. The investigations have been carried out with a hydroxyethylcellulose (HEC) and a biopolysaccharide (BPS) (scleroglucane). Highly saline water (100 g/dm3 [0.2 lbm/L]) was used for the displacement tests, as well as for the preparation of the polymer solutions.
From the eluate sampled during each flooding test, a concentration profile and a viscosity profile were recorded. A comparison between the two profiles gives an indication of the fraction of the polymer substance in the injected solution that does not contribute to the viscosity. From the recorded profiles, the influences of dispersion, adsorption/retention, and viscous fingering were established separately and quantitatively determined by means of material balances.
A High-Pyruvate Xanthan for EOR
Authors: Philips J. C. , Miller J. W. , Wernau W. C. , Tate B. E. , Auerbach M. H. 
Published: December 2007

Abstract
High-pyruvate xanthan (HP xanthan) is produced by a proprietary strain of the Xanthomonas campestris organism and is available in the form of a 3 to 5 % broth or a 12 to 15% concentrate. The liquid product is supplied commercially (FLOCON 4800 or 4800C™ from Pfizer Inc.) for use as a mobility control and permeability reduction agent for micellar, water-thickened, and waterflood diversion projects. This paper deals with use of the product for mobility control. The biopolymer is similar in structure to other commercial xanthans but contains a significantly higher level of ketal-bound pyruvic acid. Assay methods, including those applicable to field waters, are discussed.
While dilute HP xanthan exhibits viscosity/concentration profiles and pH sensitivities that are similar to other xanthans, it has superior tolerance to high levels of salinity and hardness. Injectivity, as measured by Millipore™ filtration, is not adversely affected by high levels of monovalent cations and magnesium ion. The presence of ferric ion produces severe filterability deterioration, while problems with calcium and ferrous ions are less serious. Good filterability in the presence of iron or hardness cations is restored by use of certain chelating agents and surfactants. Sequential filtrations of HP xanthan and other xanthans have been carried out with various-size Millipore membranes. On this basis, the effective size of the HP-xanthan molecule was shown to be no larger than 0.2 µm.
Compatibilities of HP xanthan with biocides, oxygen scavengers, and surfactants are discussed, as is information demonstrating control of microbiological problems and field propagation of the biopolymer.
Development of the In-Situ Combustion Process on an Industrial Scale at Videle Field, Rumania
Authors: Turta Alexandra T. , Pantazi Ion G. 
Published: December 2007

Summary
The Sarmatian 3 Videle field is among the largest heavy-oil reservoirs currently known in the world. The oil viscosity under reservoir conditions ranges from 30 to 120 cp [30 to 120 mPa·s]. There are three producing horizons: Sarmatian 3a and 3b, partially overlying Sarmatian 3c.
The field was discovered in 1959. During 1964-76, a water-injection project was gradually expanded to the whole reservoir area. The average oil recovery at the present time is about 13%, and the producing wells are approaching the economic limit—the producing oil/water ratio is higher than 25. For this reason, it was decided to study the feasibility of producing the field by in-situ combustion to recover additional tertiary oil.
To obtain the necessary data, three field combustion pilots located upstructure in various areas of the reservoir are being operated. The performance of the three tests is presented and discussed. The favorable results obtained so far justify the full-scale application of the in-situ combustion process. A linedrive scheme has been selected so that a more or less continuous combustion front will move downdip. To supply the necessary air for a combustion front of more than 11.2 miles [18 km] in length, a giant compression capacity of about 247.2 × 106 scf/D [7 × 106 std m3/d] will be required.
Flooding of Gas Cap in Norfolk Garr Sand Unit
Authors: Nelson H.A. 
Published: December 2007

Abstract
The West Norfolk Garr Sand Unit, which contains a large gas cap, is being successfully flooded using a conventional five-spot pattern and filling the gas cap with water to prevent loss of oil by migration into the gas cap.
Pilot water injection was commenced in July, 1953, utilizing two 10-acre, five-spot patterns. Increased oil production was first obtained in Oct., 1954, and gas-cap injection began in Feb., 1955. Over 4.5 million bbl of water have been injected into the gas cap to achieve fill-up. It is concluded that the gas cap of reservoirs with shallow dips may be filled with water to prevent loss of oil into the cap by migration with no adverse effects on the oil-bearing portion of the reservoir.

Introduction
Water flooding the Pennsylvanian sands in Oklahoma is becoming increasingly important. Numerous fields drilled during the late 1940's and early 1950's are now reaching their economic limit, and the successful water flooding of some of these fields is stimulating considerable interest. Gas caps have created difficult problems in many of these fields. The successful flood of the West Norfolk field has led to the development of additional similar projects.
Ten years ago water flooding of the shaly sands, such as the Peru, was believed to be impracticable. However, more accurate engineering and geological techniques, combined with improved operating techniques, have led to the successful flooding of fields similar to the West Norfolk field.

Primary Development and Production History
Primary reserves in the West Norfolk field have been developed during two periods:from 1927 to 1930 andfrom mid–1949 to 1952.
In Oct., 1927, gas was discovered in the Peru sand (now known as the Garr sand) on the east side of the field and 10 gas wells were soon drilled along this eastern edge. Continued production from these wells resulted in some going to oil, and after turning to oil the wells produced from 5 to 10 BOPD. In mid–1949 the discovery well was completed in the oil sand. This well, now Unit Well 16, produced 60 BOPD after a 60-qt shot. Further development resulted in the drilling of 60 oil wells.
Primary production from 870 acres totaled 870,000 bbl from mid–1949 to July 1, 1953, when the field was unitized for water flooding. It is estimated that of this 870 acres the oil column encompassed 645 acres, while the gas cap encompassed 225 acres. Total primary recovery was estimated at 1,097,000 bbl.
Successful Strawn Sand Water Flood
Authors: Riley E.A. 
Published: December 2007

Abstract
The field performance of waterflood operations in the Cherrykirk field, located in North Texas, is proving highly responsive to water flooding. High injection rates, in the order of 0.95 to 1.00 B/D/acre-ft, are being utilized to make the project successful and economically feasible. Prior to any attempts at water flooding, a detailed reservoir study aided materially towards successful operations. Pilot injection was initiated Oct. 18, 1955, using a 20-acre double five-spot. The pilot flood indicated efficient water flooding could be conducted so the injection pattern was expanded on a five-spot plan to encompass full field operations. Oil recovery by primary methods to Sept. 1, 1955, was 804,545 bbl. Reservoir pressure was depleted rapidly within 21/2 years from an initial pressure of 558 psig.
A total of 2,901,575 bbl of water had been injected to Dec. 1, 1957, resulting in the recovery of 612,147 bbl of oil or 4.7 bbl of water injected per barrel of oil produced. The revenue to Oct. 1, 1957, from the T. H. Cherryhomes and the Newmont Oil Co. leases amounted to $953,336 from an investment of $164,722 development and equipment costs and $206,277 operating costs. This is $582,387 profit to the full working interest. Since the pilot development cost was $43,131 this is a risk to gain ratio of 13.5 to 1 or an expenditure to return ratio of 1 to 3.88. A high rate of income is still being realized.

Introduction
The Cherrykirk (Strawn) field is located approximately 10 miles east of Jacksboro in Jack County, Tex. (Fig. 1).The discovery well, T.H. Cherryhomes No.1, drilled in Dec., 1951, potentialed 90 BOPD pumping. All wells in the field were drilled by mid-year 1952. The highest initial potential, 112 BOPD pumping, was obtained from the Cherryhomes No. 12. Forty-eight other wells were completed in the field by 1952 (see Fig. 2). Some wells required frac jobs for completion as producers. Rotary drilling tools were used to drill the wells to the top of the pay. Casing was then run, cemented, and the wells "tailed in" with the cable tools. The program on the wells consisted of 90 to 100 ft of 10.75-in. OD surface casing and either 5.5- or 7-in. OD casing as a production string cemented with 100 to 125 sacks of cement.
Effect of Preheating on Kern River Field Steam Drive
Authors: Restine Joe L. 
Published: December 2007

Summary
The productive formation in the Kern River field is a sequence of sands designated as the Kern River series. These fine to very coarse sands, each averaging 60 ft (18.3 m) in thickness, are separated by silt and clay interbeds. They are steam-displaced sequentially from the bottom up, one zone at a time.
Since steam drive became a viable recovery technique in the early 1960's, all Kern River field steamdrive design and planning was based on the use of a reservoir temperature of 85 to 90°F (29 to 32°C). It was recognized that zones immediately above a previously displaced interval eventually will become heated by the zone below through heat conduction. To a lesser degree, this also occurs in zones below the active drive.
With sufficient preheating, very thin sands, previously calculated to be uneconomical and scheduled to be deferred in favor of thicker sands, have proved very productive. The preheating of thicker sands also has resulted in significantly higher production rates than the non heated equivalent sands.
This paper discusses the numerical modeling work completed to evaluate the effects of preheating. Field results, including temperature surveys and production data, also are presented to substantiate the theoretical work and prove that preheating effects are an important consideration in a steamdrive operation.

Introduction
The Kern River field is a large, shallow, heavy-oil deposit located 5 miles (8 km) northeast of Bakersfield, CA. The reservoir is a sequence of up to seven sands designated as the Kern River series. These sands are separated by silt and clay interbeds. Both reservoir and fluid characteristics are very favorable for steamflood methods. The unconsolidated sands have high permeabilities of 1 to 5 darcies and porosities of 28 to 33 %. The average oil viscosity and reservoir temperature are 4,000 cp (4 Pa · s) and 85°F (29°C).
Three-Dimensional Hydraulic Fracture Propagation in the Presence of Stress Variations
Authors: Palmer Ian D. , Carroll H. B. 
Published: December 2007

Abstract
Models of three-dimensional (3D) fracture propagation are being developed to study the effect of variations of stress and rock properties on fracture height and bottomhole pressure (BHP). Initially a blanket sand bounded by zones of higher minimum in-situ stress is considered, with stresses symmetrical about both the pay-zone axis and the wellbore. An elliptical fracture perimeter is assumed. Fluid flows are one-dimensional (ID) Newtonian in the direction of the pay zone. Two models, FL1 and FL2, are developed. In FL1, a discontinuous stress variation is approximated by ar variation in the vertical coordinate, and the fracture criterion, Ki =Ke, is satisfied at both major and minor axes. The net pressure at the tip, Lf, of the long axis required by the boundary condition Ki =Kc does not seem crucial in determining fracture height or BHP (compare with one group of published models8,9 that assumes p = 0 at Lf). Model FL2 properly represents the discontinuous stresses, and satisfies Ki=Ke. at the wellbore but not at the tip of the long axis. A parametric study is made, with both models, of the comparative effects of stress contrast, σ2-σ1, Ke, pay-zone height, h, and Young's modulus, E, on fracture height and BHP. Results indicate that Kc does not have as much effect as either for σ2- σ1, at least for large stress contrasts. Model FL2 suggests the possibility of a rapid growth in fracture height as σ2−σ1 is reduced. Such modeling may be able to give an upper or "safe" limit on the pumping parameters (q and μ) to ensure good containment. When the stress contrast is high, σ2−σ1, ≥700 psi [4826 kPa], an analytic derivation of BHP appears to be a good approximation for the parameters we use, if everywhere the fracture height is assumed equal to the pay zone height. Although leakoff is neglected here, subsequent modeling results show that, for leakoff coefficients C≲0.001 ft-min−½ [3.9×10−5 m·s−½], the results herein are a good approximation to the case when leakoff is included.
Principles for Fracture Design Based on Pressure Analysis
Authors: Nolte K. G. 
Published: December 2007

SummaryThis paper reviews the procedures for interpreting, modeling, and predicting fracturing pressure. This review shows that excessive pressure resulting from fluid flow in the fracture can cause such problems as excessive height growth and screenouts, which reduce the potential fracture penetration. As a result, an important design consideration is to limit the pressure by controlling the fluid viscosity.
Optimization of Stiffening Rings' Position in Welded Tubular X-Joint
Authors: Salama Mamdouh M. 
Published: December 2007

Summary
Experimental results are presented to show that the position of the stiffening rings in welded tubular X-joints has a great impact on the value of the stress concentration factor (SCF) at the hot spot as well as its location. Preliminary guidelines for an optimal ring position are proposed. proposed. Introduction
In offshore structures, such as semisubmersible drilling vessels and fixed platforms, tubular members comprise the main load-carrying components. The platforms, tubular members comprise the main load-carrying components. The design of joints between these tubular members is complicated because the radial flexibility of the tube walls leads to significant stress concentrations. Since many of these structures are subjected to alternating loads, the presence of stress concentrations can lead to an early fatigue failure. Ring stiffeners often are used as a means of reducing the SCF and thus increasing the fatigue life. This has been confirmed by the results of Maeda et al. and Matoba et al. The effect of the position of ring stiffeners on the maximum SCF value and, hence, the fatigue life is, to my knowledge, not available in the open literature. This paper represents a preliminary study of the effect of positioning of both internal and external ring stiffeners on the value and positioning of both internal and external ring stiffeners on the value and the location of the maximum SCF. It should be recognized that this paper is not intended to give a generalized recommendation for the optimal ring position but rather to alert designers and fabricators to the danger of position but rather to alert designers and fabricators to the danger of unoptimized position. Poor positioning of the rings can result in very little improvement in the state of stress as well as the expense and drawbacks associated with welding.

Experimental Details
The experiments were conducted on welded tubular X-joints with an angle of intersection equal to 900 (this joint also is classified as double-T joint).
JPT
p. 328
Evaluation of Fracturing Fluid Stability by Using a Heated, Pressurized Flow Loop
Authors: Lescarboura Jaime A. , Sifferman Thomas R. , Wahl Harry A. 
Published: December 2007

Abstract
A flow loop was used to evaluate the stability of fracturing fluids at high temperatures. The design provides enough pressure to prevent vaporization of water-base systems up to 350°F [177°C]. Crosslinked polymer systems from four service companies were evaluated at 180 and 245°F [82 and 118°C]. The tests showed that crosslinked fracturing fluids degrade with temperature and shear, losing much of their viscosity and proppant-carrying capacity in a few hours. Thermal stability is a major factor in selecting gels for fracturing deep, high-temperature reservoirs.
A New Approach to Shale Management in Field-Scale Models
Authors: Haldorsen Helge H. , Lake Larry W. 
Published: December 2007

Abstract
Virtually every sandstone reservoir contains significant amounts of shale. Although the sand/shale sequence in the wells may be known, a reliable reservoir description must define quantitatively the lateral continuity of the shale, the shale distribution in unsampled areas, and the effects of the shales on transport properties.
This paper presents statistical techniques by which the lateral continuity and spatial disposition of shales can be estimated. These techniques rely on shale statistics from the wells and outcrop statistics from appropriate depositional environments. The resulting shale description can be conditioned to conform with the observations of the wells.
The subsequent discretizing of the reservoir into gridblocks for numerical simulation yields large elemental units that usually contain both sand and shale. The paper concludes by showing how the permeability and porosity may be estimated from the disposition of shales within each block.