bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Correlation of the Electrical Properties of Drilling Fluids with Solids Content
Authors: Overton Harold L. , Lipson Leonard B. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 333–336.

Abstract
An approach to the study of the electrical properties of drilling muds, their cakes and their filtrates was made by treating the drilling fluid as a porous medium. During this study it was found that the weight parameter was omitted from previous investigations on electrical properties. Patnode in 1949 made a similar approach to this investigation. His work showed that there was a variation of resistivity relationships with per cent fluid present in a given suspension. This present study extends Patnode's investigation to one in terms of the solids fraction of the drilling fluids. Previous investigations were made on low weight muds where the effect of the solids fraction was obscured. The following equations were fitted to data taken from 94 field muds and 47 laboratory muds (see Tables 1 and 2).

Introduction
It is generally recognized that the materials present in drilling muds affect the relationship between mud filtrate and mud resistivities. However, most electric log interpretations proceed with the assumption that the mud resistivity and temperature are the only important parameters needed to obtain a filtrate resistivity or a mud cake resistivity.
Lamont suggests that only average relationships exist between mud cake, mud filtrate and mud resistivities. He indicates that there is limited accuracy when these intercorrelated factors are used since no other measurable variable is apparent. A previous paper by Patnode indicates that drilling fluids may be considered to be a system of fluids in solid particles which may be correlated electrically in a manner similar to rock solids.

Experimental
The measurements of mud weight, fluid and solids resistivity, alkalinity, and chloride content of mud samples were made in this research. Mud samples representing drilling fluids from 94 Louisiana and Texas wells (Table 1) and 47 laboratory-constructed systems (Table 2) were used in the experimentation. The measurements of the mud properties were made both in the field and in the laboratory.
The tests on the properties of weight, alkalinity and chloride ion were standard tests as described by API specifications. The resistivity measuring devices were constructed in the laboratory for this study. For details on the resistivity equipment see Fig. 1.
Field Results of South Belridge Thermal Recovery Experiment
Authors: Gates C.F. , Ramey H.J. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 236–244.

Abstract
Results of a field research project on the thermal recovery of oil by movement of a combustion front are presented. This field test was conducted in the South Belridge field, Calif. The test pattern was a single 2.5-acre five-spot pattern in the 700-ft deep Tulare sand.
Results of this project indicate the technical feasibility of producing high viscosity, low-gravity crude oils by thermal means. It was demonstrated that heavy oils could be moved rapidly over considerable distances by thermal drive, and that high percentage recoveries of oil could be effected. The bulk of the oil recovery came after arrival of the burning front at a production well. However, rapid corrosion and high-temperature failure of conventional pipe and equipment both below and above surface occurred. Stainless steels gave more satisfactory performance under these conditions than did conventional steels.
Oxygen was seldom observed in gas from wells ahead of the burning front, and it appears that the front was continuous throughout the life of the experiment.

Introduction
During late 1953 and early 1954, industry-wide attention was focused on the thermal recovery of oil by movement of a combustion front through an oil zone. Two separate Oklahoma field tests were described in publications by. Kuhn and Koch, and Grant and Szasz. To obtain basic information needed for making engineering and economic appraisals of commercial recovery of heavy oil by this thermal recovery method, a new field research project was started May 31, 1955. Twelve oil companies contributed to this project with General Petroleum Corp. as operator.
Since combustion recovery experiments with heavy oils in other areas had been conducted In small patterns, an important purpose of this test was to determine whether the process could be operated in a pattern of near-commercial well spacing. The South Belridge field, located 30 miles north of Taft, Calif., was chosen because its oil sands are similar to many heavy oil sands which typically have low primary recovery and leave a large amount of oil in place. Such fields are not particularly suited for common secondary recovery methods.
Effect of a Partial Monolayer of Propping Agent on Fracture Flow Capacity
Authors: Darin S.R. , Huitt J.L. 
Published: February 2020

Published in Petroleum Transactions, AIME, 1960, Vol. 219, pages 31–37. Paper presented at 34th Annual Fall Meeting of SPE, Oct. 4–7, 1959 in Dallas.

Abstract
The use of a partial monolayer of propping agent to obtain a high flow capacity for a hydraulically induced fracture is discussed. From the results of laboratory work it was shown that a modified form of the Kozeny-Carman relation could be used to describe the flow in the partial monolayer propped fracture. With equations presented in the paper, the density pattern of the propping agent (number of particles per unit of fracture surface) that results in the maximum flow capacity for the fracture can be determined. The maximum flow capacity obtained with a partial monolayer is often an order of magnitude greater than the flow capacity obtained in greater width fractures containing multilayers of the propping agent.

Introduction
One of the predominant factors controlling the success of a hydraulic fracturing operation is the propping of the fracture. The trend in hydraulic fracturing recently has been an increase in the ratio of propping agent-to-fluid. The primary purpose of this increased ratio is to sustain a propped fracture of greater width. It was shown in a recent study that for some formations low concentrations Of propping agent would result in "closing" or "healing" of the fracture. In some cases, in an effort to insure sufficient propping agent concentration, the fracturing operation is designed to obtain a pack of the propping agent in the fracture. The placing of a pack of propping agent in the fracture provides a fracture of maximum width; however, the width alone does not control the flow capacity of the fracture. The flow capacity is dependent on the permeability of the fracture, as well as the fracture width. Thus, increasing the permeability to obtain larger flow capacities is as important as obtaining a greater width fracture.
Production Behavior of a Water-Blocked Oil Well
Authors: Ribe K.H. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 1–6.

Abstract
Water often enters an oil reservoir during completion of workover operations on a well and forms a partial "water block" to oil production. A mathematical study of radial two-phase flow, neglecting capillary effects, has been employed to study the formation of such a water block and subsequent removal by production from the well. The effects of reduced oil permeability about the well on the well productivity were studied. The fluid saturation distributions about the well during formation and removal of the water block have also been computed. Several relative permeability relations and viscosity ratios were employed.
If water has invaded the formation, its influence through relative permeability effects alone can cause the following.Oil productivity will be depressed for extended periods after production is resumed and will build up only gradually as the water is removed.Oil injected for treatment of water blocking will delay rather than promote restoration of full well productivity by enlarging the region invaded by water.
Thus, unless the specific action of chemicals contained in the oil is needed, oil injection appears undesirable.

Introduction
During oilwell workover operations, water may enter the oil-bearing formation from the wellbore. When production is resumed, oil must flow through the region invaded by this water. The presence of this region can cause both well productivity and oil production rate to be low and oil to be produced with high water-oil ratio for some time after production is initiated. This situation is sometimes described as a water block.
The introduction of water into the formation may result in other actions which also lead to reduction in well productivity and which are also usually included in the connotation of the broad term, water block.
Estimation of Primary Oil Reserves for Lansing-Kansas City Reservoirs
Authors: Volosin J.H. 
Published: February 2020

Kansas Waterflood Symposium of the Society of Petroleum Engineers of AIME,19 November, Great Bend, Kansas

Abstract
The purpose of this paper is to present a method of making initial primary reserve estimates for Lansing-Kansas City reservoirs occurring within the confines of the Central Kansas Uplift. Hypothetical charts presenting reservoir fluid characteristics were prepared, based upon the comparison of a reservoir fluid sample and previously published fluid correlations. The method of predicting primary reserves is based upon the past performance of a number of Lansing-Kansas City wells. Also presented are formulae which permit the calculation of reservoir saturation conditions during, or at the end of the reservoirs primary life, which are necessary before reliable secondary estimates can be made.

Introduction
The initial estimation of primary oil reserves for a Lansing-Kansas City reservoir is in most instances a difficult problem for the petroleum engineer to solve. This difficulty arises not from a difference in production or reservoir energy concepts, but from the fact that the reserves discovered do not justify the collection of sufficient engineering data such as core analysis, relative permeability ratios, reservoir fluid samples, pressure histories, etc., to permit a reserve evaluation of these predominately undersaturated solution gas drive reservoirs, by normal material balance methods.
Therefore the purpose of this paper is to present correlations of the various reservoir fluid properties of the Lansing-Kansas City crude in conjunction with a method of making initial primary reserve estimates that is based on the past performance of a number of Lansing-Kansas City reservoirs.

Reservoir Fluid Correlations
Prior to making reservoir calculations a knowledge of the physical properties of the reservoir fluid is required. This data is best obtained from the PVT analysis of a sample of the reservoir fluid, which in the case of Lansing-Kansas City reservoirs is a rarity. We are therefore forced to rely upon a correlation of some easily obtainable surface parameters with these reservoir fluid properties to permit reliable reserve calculations.
Various authors have presented correlations concerned with the prediction of oil viscosity, solubility and shrinkage of numerous crude samples with various reservoir properties. In order to obtain a relationship between this published data and an available Lansing-Kansas City reservoir fluid sample, the original data presented by Katz and Beal was plotted in conjunction with this data and the published correlation curves were shifted to match the sample, as stated in the following discussion.
Some Aspects of Unitized or Cooperative Waterflood Development
Authors: Hockaday D.E. 
Published: February 2020

Kansas Waterflood Symposium of the Society of Petroleum Engineers of AIME,19 November, Great Bend, Kansas

Abstract
This paper examines the use of voluntary Unitization Agreements and Cooperative Agreements in forming waterflood projects in the Lansing-Kansas City formation. General characteristics and probable types of floods are discussed in relation to the two basic types of agreements.
It is concluded that both types of agreements will find a place in Lansing, Kansas City water flood operation but that the fully unitized operation is usually the superior method.
A compulsory unitization law in Kansas would greatly expedite the formation of unitized projects.

Introduction
During the past decade, the oil industry has made great technical strides in the fields of drilling, geology, geophysics, equipment development and reservoir engineering. These advances coupled with wise regulatory body regulations have enabled the industry to operate profitably and still provide the public with unlimited supplies of petroleum products at reasonable prices. This goal has been achieved even though the cost of replacing reserves has constantly increased due to deeper drilling, increased labor and material costs and a decline in the exploratory discovery ratio. One of the major factors involved in this accomplishment has been the increased use of secondary recovery by waterflooding. It is apparent that in the more mature producing provinces, current primary oil discoveries are relatively unimportant and the secondary recovery mechanisms are contributing an increasingly great portion of the domestic production. As previous papers presented here today have pointed out, the water flood possibilities of reservoirs in the Lansing-Kansas City group appear to be very attractive. The purpose of this paper is to discuss the use of unitized and cooperative agreements in developing these waterfloods.
While this is necessarily a broad subject, I have attempted to restrict my comments to areas which will specifically apply to Lansing and Kansas City problems.
Natural and Accidental Waterflooding of the Lansing-Kansas City Limestone in the Hall-Gurney Field, Russell County, Kansas
Authors: Huff Ray V. 
Published: February 2020

Kansas Waterflood Symposium of the Society of Petroleum Engineers of AIME,19 November, Great Bend, Kansas

Abstract
The Lansing-Kansas City formation, most prolific of several oil producing formations in the Hall-Gurney field, lies at a depth of about 2,900 feet and structurally is a relatively flat anticline.
Originally only wells in structural troughs along the edges of the field produced water with the oil, but by 1959 more than half of the wells produced appreciable quantities of water. Studies of the oil and water production histories of these wells, together with studies of analyses of produced water, indicate several natural and accidental floods. Waters entering through leaky casings and from improperly plugged wells have greatly complicated a correct interpretation. On many leases oil recoveries were increased as a result of these accidental floods.
Future water-flood development should consider the past oil and water production histories of the property as it relates to probable oil and water saturation of the several oil productive zones.

Introduction
The geology and production history of the Hall-Gurney field in Russell County, Kans., have been studied by Bureau of Mines engineers with a view toward suggesting methods to increase oil recovery. Waterflooding is one of the more successful methods commonly used for increasing oil recoveries and should have wide application in this field. In the consideration of properties for flooding, a knowledge of the oil and water contents of the oil productive zones is important. If the oil content is too low or the water saturation is too high, the flood will be unprofitable. Usually oil and water-production histories are valuable guides to the probable oil and water saturations of a property. However, in an old field, an increase in water production does not necessarily mean natural encroachment of edge or bottom formation waters. Leaky casings or faulty bottom-hole plugs may allow extraneous waters to enter the well or wells.
The chemical and physical characteristics of each extraneous water differ somewhat from those of water from the oil-productive zone. These differences can be determined and emphasized by a careful study of analyses of samples of produced waters.
This paper describes the use of water analyses and water-production data in determining the nature and extent of natural and accidental flooding of the Lansing-Kansas City limestone in the Hall-Gurney field. Six such flooded areas are described where oil and water production rates have been increased. Although some additional oil has been recovered by these floods, accompanying changes in the oil and water saturations of the oil producing zones seriously limit the potentialities of the areas for further planned development.
Macro-Rheology and Micro-Rheological Study of Composite Polymer Gel at High Salinity and Acidic Conditions for CO2 Shut Off Treatment in Harsh Reservoirs for Improving Oil Recovery
Authors: Lashari Zeeshan Ali , Kang Wanli , Yang Hongbin , Zhang Hongwen , Sarsenbekuly Bauyrzhan 
Published: February 2020

Abstract
In Enhanced oil recovery methods, CO2 is an excellent injecting fluid than water because of its prominent properties which includes non-flammability, non-polarity and non-toxicity. The reservoir pressure is over minimum miscibility pressure (MMP), it also provides for miscible displacement process of multi-contact. The CO2 injection process has been widely practiced in oil industry in the last decades. In the fractured or heterogeneous reservoirs, the injected gas will mostly passage through the fractures or high permeability layers which present the minimum flow resistance, leaving much of crude oil unrecovered in the low permeability rock-matrix.
In this research, a composite polymer gel was proposed for harsh reservoir conditions, such as high salinity (NaCl 15.0 wt%, Ca2+ 0.8wt% and Mg2+ 0.8wt %), acid conditions (pH 3.25) and analyzed systematically at laboratory scale, consisting of polymer, cross linker and nanoparticles (silica dioxide). The gel system was characterized by different parameters like viscosity (μ), loss modulus (G″) and elastic modulus (G′) by varying polymer concentration, cross-linker concentration, silica dioxide (SiO2) concentration by using macro-rheology. The micro-rheology was used to calculate mean square displacement (MSD) and elasticity index (EI) of composite gel system. The bottle testing method was used for characterizing the gelation time of composite, gelation code and synergistic mechanism.
The macro-rheological results of composite polymer gel proved that elastic modulus (G′) and loss modulus (G″) of composite gel system tends to increase with increment in silica dioxide (SiO2), polymer, cross linker and salinity concentrations. The results of G′ and G″ showed that composite gel have good elasticity at high salinity and acidic conditions. The gelation time observed was 6 days, which is sufficient to pump the gel into targeted zone. The gel code obtained was G at the temperature of 60°C. The elasticity index (EI) in micro-rheological results showed that gel has good elasticity, and MSD curve showed gelling fluid is elastic fluid and bears good stability. The composite polymer gel bears very low syneresis in acid conditions for 60 days at the temperature of 60°C, and having good thermal stability.
The laboratory scale research indicates that newly formulated composite polymer gel can be efficiently applied to heterogeneous reservoirs for harsh reservoir conditions and CO2 shut-off problems, and can decrease the water or gas breakthrough problems by plugging the highly permeable channels and increasing the sweep efficiency from low permeable reservoir to produce the residual oil and ultimately increase the production of oil.
Wellbore Stability Analysis in Anisotropic Shale Formations
Authors: Parkash Dayal , Deangeli Chiara 
Published: February 2020

Abstract
Serious stability problems in boreholes drilled in transversely isotropic rocks have led to several studies related to the combined effect of wellbore trajectory and weakness plane inclination. The stability analyses of wellbores drilled in fields that were affected by slip along the weakness planes were carried out with software based on the weakness plane model. However, this model is discontinuous and cannot capture features of some transversely isotropic rocks. The Hoek & Brown criterion, adapted to anisotropic rocks, is a continuous criterion that can predict mud pressures in a complete range of inclination of the weakness planes. However, this criterion requires a consistent number of triaxial tests, for the determination of the controlling parameters at various inclinations of the weakness planes. Here we propose a novel procedure for the prediction of wellbore pressures in transversely isotropic rocks (typically shales) with the Hoek & Brown criterion coupled with the weakness plane model. The procedure requires a set of uniaxial compression tests performed on rock specimens at different inclinations of the weakness planes and one triaxial test carried out at an inclination of the weakness planes in the range 50°-60°. For our purposes we used the results of lab tests carried out on Opalinus clay.
The Effect of Fluid-Flow Rate and Viscosity on Laboratory Determinations of Oil-Water Relative Permeabilities
Authors: Sandberg C.R. , Gournay L.S. , Sippel R.F. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 36–43.

Abstract
The effect of fluid-flow rate and fluid viscosity on oil-water relative permeability determinations was studied using the "dynamic flow technique." In this work relative permeability curves were obtained for homogeneous small core samples from several sandstone outcrop formations. Radio-tracers were used for the determination of fluid saturation and for the detection of saturation gradients. Cobalt–60 in the form of cobaltous chloride was used as a water-phase tracer in some of the experiments. Iodine–131 in the form of iodobenzene and Mercury–203 in the form of mercury diphenyl were used as oil-phase tracers in other experiments. Flow rates for each phase were varied within a range of 2.5 to 140.6 ml/hr. Oil-phase viscosities under flowing conditions were varied from 0.398 to 1.683 cp.
The relative permeabilities obtained were found to be solely a function of saturation and independent of flow rate, provided there was no saturation gradient induced in the core sample by "boundary effect." Even though equilibrium with respect to flowing conditions was obtained at the lower flow rates, where a saturation gradient exists, this equilibrium is of a "contingent" -type rather than the "steady-state" equilibrium implicit in the relative permeability concept. The only effect of increasing the oil or non-wetting phase viscosity was to decrease the flow rate required for the elimination of the boundary effect.
Fairly good agreement between experimentally determined and calculated values of the boundary effect was obtained when the non-wetting oil phase was the only flowing phase.

Introduction
In the characterization of reservoir rock, as well as in the solution of reservoir production problems, it is most desirable to have reliable relative permeability measurements for the rock and fluids of interest. Many techniques have been developed for the laboratory determination of the relative permeability of both large and small core samples. In varying degree, difficulties attend the use of all of the methods. Each of the methods requires the metered flow of fluids of known viscosity through the core sample under conditions wherein the pressure drop in the individual flowing phases can be measured or closely approximated. Since the relative permeability is a function of the saturation and distribution of the flowing fluids, some means of obtaining such information is also required.