bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gravity Drainage of Oil Into Large Horizontal Fractures
Authors: Morrisson T.E. , Henderson James H. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 7–15.

Abstract
An investigation has been made of the production of oil through horizontal fractures of high capacity and large radius placed at the base of producing formations. The specific aims of the study were todetermine by model studies the reservoir performance when gravity drainage is the only producing mechanism, anddevelop a method of predicting such performance from commonly measured reservoir properties.
Although the theoretical approach failed to develop a rigorous analytic solution to the transient problem, it did lead to a practical method of predicting performance. Predictions are in good agreement with rates and recoveries observed in scaled-model experiments. Capillary effects and the influence of relative permeability are taken into account.
The experimental program wad mainly concerned with the influence of fracture radius, fracture capacity and capillary hold-up on the total recovery and the rate of recovery. Much of the experimental work was done on a triangular model which represented one-eighth of a square well pattern, so constructed that horizontal fractures of varying radii and flow capacity could be studied. An electrolytic model was used to relate the initial production rates to fracture radius, formation thickness and the drainage radius of the well pattern.
The conclusions reached as a result of the work are as follows.The production of oil under gravity force alone into a well-propped horizontal fracture, whose radius is of the order of hundreds of feet, is a recovery method which combines high recoveries with very acceptable production rates.The mechanism is effective in "dead oil" reservoirs as well as in reservoirs which possess the energy of solution gas.A method of predicting performance has been developed which gives good agreement with experimental behavior in cases of practical interest.
Even for very thick beds and large fracture radii, where actual conditions do not conform to the assumptions made, the method gives order of magnitude predictions which would not otherwise be possible.
Approximation of Gas-Drive Recovery and Front Movement in the Abqaiq Field, Saudi Arabia
Authors: Stanley L.T. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 273–280.

Abstract
A method is described whereby the behavior of the front is approximated when gas is injected into a thick reservoir having reasonably homogeneous properties. The method is applied to the Abqaiq field of Saudi Arabia. The producing member is the Arab-D, a high-permeability calcarenite which has no continuous bedding planes. Field performance indicates the injected gas to be partially miscible with the reservoir oil because gas volume factors experienced are lower than those predicted by the gas law. Equilibrium calculations confirm this and also show that the volume factor may vary appreciably, depending on the relative quantities of oil and gas in contact in the reservoir; consequently, volumetric balances are made for the purpose of determining the behavior of the gas volume factor during injection history. The effect of gravity segregation on position and shape of the gas front is approximated by dividing the producing section into three zones vertically and tracing the movement of the average interface in each zone, with counterflow of oil and gas taking place between zones behind the front. This results in a gas front that advances more rapidly along the top of the formation than along the base, producing an "umbrella" effect in cross section that becomes more pronounced as the front progresses. The calculations cover the gas-injection period of Abqaiq field history through 1958, and the position of the gas front is plotted at one-year intervals. Finally, some comparisons between the calculated frontal position and the gas-oil contact as measured by neutron logs are made.

Introduction
Fig. 1 is a structure contour map of the Abqaiq field. For analytical purposes, the field has been divided into two areas designated A and B, as shown on the map. Gas injection into Area A was begun in early 1954 into two wells located near the crest of the structure on the north-south axis of the anticline. During the period covered by this paper, the average injection rate has been 122 MMscf/D with a maximum sustained rate of 160 MMscf/D. The reservoir pressure has been maintained at 2,450 psig since start of gas injection.
The Diffusional Behavior and Viscosity of Liquid Mixtures
Authors: Adamson Arthur W. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 158–165.

Abstract
A model for transport processes in liquid mixtures is discussed which supposes that the elementary act involves a position exchange between two species and that the exchange is so confined by the solvent cage as to occur nearly isosterically. The rate-determining step, thus, is likened to a bi-molecular reaction and is so treated, using absolute rate theory. The cage model has been applied to diffusion, thermal diffusion, sedimentation and viscosity, but only the first and last of these phenomena are emphasized in the present paper.
The model leads to semi-empirical relationships between the absolute value for a diffusion coefficient and the activation energy for diffusion, between mutual and self-diffusion coefficients and for the variation of the viscosity of a binary mixture with composition. These are discussed in relation to experimental data for various systems, including hydrocarbon mixtures.
It is shown that the proposed viscosity equation and seven other commonly iced ones all may be regarded as special cases of a single general relationship; a brief critical analysis is made of the basis of selection of one or the other for data fitting or interpolation.

Introduction and General Theory
The present paper covers a brief discussion of a cage model for transport processes in liquid mixtures and how this model may be useful in treating the diffusional behavior and the viscosity of such systems. Since diffusion requires the more detailed treatment, it will be taken up first, and the model then applied to viscosity.
There are two types of diffusion coefficients that may be measured experimentally, apart from thermal diffusion quantities. The first is the mutual or binary diffusion coefficient, D, which may be defined in terms of Fick's first law.
.....................(1)
This states that the permeation, or flux P, is proportional to the concentration gradient. In the usual experiment, P is measured relative to a frame of reference fixed with respect to the medium (e.g., the diaphragm in a diffusion cell); as a consequence, the same value of D12 is obtained regardless of whether P and C refer to Component 1 or to Component 2; i.e., there is only one independent mutual diffusion coefficient for a binary system.
Determination of Effective Capillary Pressures for Porous Media from Imbibition Data
Authors: Handy L.L. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 75–80.

Abstract
Two equations are compared for calculating imbibition rates of water into porous media. A linear relation was found to apply when the square of the volume of water imbibed was plotted against time for water imbibing in natural rock materials. The effect of absorbed organic materials on surface wettability was determined from measurements of rate of imbibition, water saturation and water permeability.

Introduction
An understanding of the mechanisms by which water displaces oil from porous media requires an understanding of the role of capillary forces in the displacement process. The capillary forces are determined by properties of the water-oil-solid surfaces. Consequently, some measure of the surface properties of reservoir rocks is necessary if displacement behavior in oil reservoirs is to be predicted from laboratory measurements.
Several experimental procedures have been proposed to assign quantitative wettability indexes to reservoir rock surfaces. The most recent of these proposals are those of Bobek, Mattox and Denekas and Amott. These indexes are designed to show a continuous variation from the preferential oil-wet to the preferential water-wet systems. They require measuring some property of the rock which is a function of surface wettability. The quantities are measured on unaltered core material and compared with values obtained for known oil-wet and water-wet extremes on the same material. These methods are useful but are semi-empirical in nature. they have the disadvantage that the measured quantities may be functions of other variables in addition to surface wettability.
Some understanding of the behavior of water-oil-rock systems may be obtained from studies of the simpler water-air-rock systems. Surfaces of a given wettability are more easily maintained for the latter. Also, certain approximations can be made for the flow of water and air which are not justified for water-oil flow. The theoretical and experimental work discussed in this paper is part of a study of the role of capillarity in the dynamic displacement of air by water. The expectation is that observations for the water-air system will lead to generalizations which are applicable to water-oil systems.
Automatic Well Testing
Authors: Foster George H. 
Published: February 2020

Regional Fall Meeting of the Los Angeles Basin Section of SPE, 22–23 October, Pasadena, California

Abstract
Honolulu Oil Corp., as operator for the Antelope Shale Zone Unit, Buena Vista Hills Field, has been testing 28 wells in a fully automatic system for the last three years.
The well gross volumes range from 25 to 500 BOPD. Cuts range from 0 to 95per cent; oil gravity is 30 API. Rapid oil-water separation makes the use of tank gauging practical. In conjunction with tank gauging, a simple device for the transmission and multiplication of the fluid data into daily rate has been found both reliable and accurate.
The well gas volumes range from 1 Mcf/D to 980 Mcf/D. Three positive displacement meters operate in parallel to measure the gas from dual stage gas-oil separation; a device for the transmission of the gas production flow and the multiplication of this flow into a daily gas production rate has been found satisfactory.
The operation of a satellite station in conjunction with the central station has been satisfactory; 10 wells are brought in sequence to the central station for test.
Short testing periods of 4, 6 or 12 hours are used; data on oil, water and gas is multiplied into daily rates and printed on a tape along with the direct four-digit well identification and the gauge period. Other test periods up to 24 hours can be incorporated; the multiplication system limits the selected test periods to multiples of 24 in order to print the final data as daily rate.
The present 28-well system control unit can be expanded to handle 22additional wells at minor additional cost.
The initial cost of the installation was $36,000; the operating cost averages $2.22 per day. The unit averages approximately four tests per 24hours.

Introduction
The system was designed to use the field facilities then in place. Standard telephone-type stepping switches and conventional open relays are used.
The control panel is constructed in one plane to permit maximum ease in checking the operation of the unit. This type construction also facilitates visual inspection and preventive maintenance.
The system is safe in the event of power failures. The well on test is returned to the production facilities. After the power supply is restored the well test is resumed and completed.
A Novel Correlation to Predict Gas Flow Rates Utilizing Artificial Intelligence: An Industrial 4.0 Approach
Authors: Kalam Shams , Khan Mohammad Rasheed , Tariq Zeeshan , Siddique Faisal Anwar , Abdulraheem Abdulazeez , Khan Rizwan Ahmed 
Published: February 2020

Abstract
Reservoir and production engineers rely heavily on well production rates to optimize well activities such as ensuring optimum reservoir monitoring. Individual gas well rates are not readily available, rather, they can be estimated thru multi-phase flow meter (MPFM) and well test analysis. These methods are associated with certain limitations such as high cost, high uncertainty, and technically elaborate calculations. Consequently, empirical and numerical calculations are employed with well test data to calculate daily rates. These practices lead to inaccurate gas rate estimations.
A model with an ability to provide accurate estimates of gas rates for a gas reservoir can serve as a handy tool for the subsurface engineers in addressing well and reservoir optimization strategies. This work presents artificial intelligence models to estimate gas rates in a gas field containing ten wells. The aim is to develop a correlation that is simple and easy to incorporate yet providing robust answers on a global scale. Multiple machine learning tools are employed. These include; Artificial Neural Network (ANN), Functional Network (FN), and Adaptive Neuro Fuzzy Inference System (ANFIS).
Production data from a dry gas field X was used for the model development. Data cleaning and data reduction steps were carried out to ensure the input parameters for the proposed model are physically relevant and accurate. Missing these steps would result in the development of an erroneous correlation, i.e., garbage -in garbage-out (GIGO). This led to finalization of certain basic well-head parameters which are available at any typical well and had direct impact on the output production rate. The target parameter for model training is the gas rate. A rigorous comparison between the investigated artificial intelligence models was conducted by calculating average absolute percentage error (AAPE) and coefficient of determination. The comparative analysis shows that the intelligent model is able to predict the gas rate in condensate wells with accuracy in excess of 90%. Examples of such large accuracy has not been reported previously.
ANN performs a step ahead as compared to the various intelligent algorithms used in this study. This paper sheds light on the potential of the Industrial Revolution 4.0 for the Pakistani Oil and Gas Sector. Data-driven artificial intelligent models are capable of validating the well test and multiphase flow meter results. In addition, it can prove to be a vital tool in an engineer's tool-kit to reduce uncertainties in gas rate measurements.
Impact of Geo-Mechanical Effects in Reserves Evaluation of Naturally Fractured Carbonate Reservoir Using Rate Transient Analysis – A Case Study of Potwar Region
Authors: Muhammad Danish , Hussain Sadam , Hassan Mohsin , Zakir Mufaddal Murtaza , Qazi Shoukat Elahi , Ali Shahzad , Haleemuddin H. M 
Published: February 2020

Abstract
In Potwar Basin, Tight Naturally Fractured carbonate reservoirs usually have matrix porosity of the 2-3% and permeability less than 1 mD. It is very challenging to evaluate Gas initial in-place (GIIP) and reserves accurately in these type of reservoirs. The objective of this study is to evaluate Gas in-place and to characterize the reservoir energy mechanism using rate transient analysis (RTA). A comparison has also been made for Gas in-place from conventional material balance analysis and from rate transient analysis.
In this study, rate transient analysis has been performed in a well, located in Potwar with thirteen years of production history. The well is completed in Chorgali and Sakesar formations. Different scenarios of initial reservoir pressure, geo-mechanical effects during initial production of the well and aquifer volume were sensitized to evaluate the Gas initial in-place (GIIP) and reserves. Different type curves such as Agarwal Gardner, Blasingame and flowing material balance and analytical aquifer modelling with / without geo-mechanical effects were applied and matched with the production history. Production logging data was also incorporated in the study. During history matching (gas-rate and bottom-hole flowing pressure), different sensitivities were run to quantify the uncertain parameters and level of uncertainty in the simulator.
While history matching and evaluating GIIP/reserves, it was observed that 8,060 psi reservoir pressure measured in the well was not stabilized and the reservoir was dominated initially by geo-mechanical effects. The best match was achieved with 10,935 psi initial reservoir pressure which was measured in the first well of the field. Without considering this pressure and geo-mechanical effects, the best match could not be obtained. It was also confirmed by different type curves that reservoir was geo-mechanically pressured during the early life of the well and also, it has a weak aquifer support during the late life of the well. The GIIP evaluated from these type curves are in the range of 75-90 BSCF whereas conventional material balance showed 60-70 BSCF indicative volume associated with the well. This study exhibited a significant difference in GIIP/reserves evaluated from conventional material balance and rate transient analysis, indicating remaining hydrocarbon potential in the region i.e. approximately 10-13 BSCF.
If the static reservoir pressure is taking too long to stabilize, the conventional material balance approach always depicts lower hydrocarbon volume associated with the well due to the tight and heterogeneous nature of the reservoirs. Therefore, conventional material balance cannot be applied in these reservoirs and unconventional approach such as rate transient analysis should be applied to evaluate GIIP / reserves and reservoir energy mechanism.
An Analytical Method for Solving Dipmeter Data
Authors: Rowland David A. 
Published: February 2020

Annual Meeting of the American Institute of Mining, Metallurgical, and Petroleum Engineers, 24–28 February, New Orleans

Abstract
This paper presents a new method for determining dip and strike of bedding planes observed in dipmeter survey data. A mathematical procedure has been developed for reducing these data to the dip and strike of formation penetrated by the drilling well. Computations are simplified and shortened with a Calculation Form which may be retained in the well files. The method is more accurate, faster, and easier to follow than any other method known to the author. The only requirements are a slide rule and a knowledge of elementary trigonometric functions.

Introduction
Of great importance to the engineer and geologist is a knowledge of the dip and strike of formations penetrated by the drilling bit. The solution of this problem may be dependent on a dipmeter survey, particularly in wildcat wells and in wells being drilled in areas of extreme diastrophism where surface methods are inaccurate. A difficult problem arises in the calculation of true dip and strike from dipmeter survey data.
Various methods of interpreting dipmeter data have been presented in the literature. They include usage of a mechanical reader, and application of numerous graphical techniques requiring stereographic nets and charts. The limitations of these methods become apparent when they are put into practice. This paper presents an analytical method of treating dipmeter data which is believed simpler, faster and more accurate than any of the methods now in general use.

Theory of the Dipmeter
The dipmeter device employs three electrode arms equally spaced along the circumference of the borehole. The electrodes are pressed against the wall of the well to insure adequate electrical contact with the rock formations being studied. Either SP, resistivity or microlog electrode arrangements are used to make continuous measurements of properties of the stratigraphic column at each of the three are position. the various factors involved in obtaining these data are well-covered in existing literature, and will not be elaborated upon in this paper.
Special Measurements of Core Properties - Effects of Pore Geometry on Oil Recovery
Authors: Aufricht W.R. , Koepf E.H. 
Published: February 2020

Joint Annual Technical Meeting of the Petroleum Branch of AIME Student Chapters of the University of Texas and A. and M. College, 14–15 February, Austin, Texas

Abstract
Conventional core data for defining reservoir fluid contacts, total pore storage space, permeability distribution and permeability to a single phase fluid have been In general use for many years. The development of reservoir analysis as a science required specific information on the properties of the reservoir fluids and the reservoir rock. Experience has shown that the rock properties affect productive characteristics and recovery more than the fluid properties.
Additional tests, frequently referred to as special core analyses tests, have been developed to provide the information required for reservoir analysis. Capillary pressure-saturation relationships, when used with conventional data, permit determination of the interstitial water content and the original distribution of fluids. Gas-oil relative permeability tests provide data to study the simultaneous flow of gas and oil. Various types of water flood tests are made to evaluate the displacement of oil by water.
The results of studies on many reservoirs show that the pore size and the pore size distribution affect markedly both the oil-in-place and the oil recovery. Information is presented to illustrate variations in oil-in-place, as determined from capillary pressure-saturation relationships, for three types of reservoirs where pore geometry is the only major variable. Ranges in recovery to be expected by solution gas expansion and by water flooding are also presented. The wide ranges in recovery estimates illustrate the marked effect of pore geometry and demonstrate the necessity of obtaining specific data on each reservoir being studied for accurate engineering evaluation.