bluuebunny/crossref_metadata_2025_split huggingface dataset:
Natural and Induced Systems and Their Application to Petroleum Production
Authors: Pasini J. , Overby W.K. 
Published: December 2007

Abstract
The Morgantown Petroleum Research Laboratory, U.S. Bureau of Mines, is investigating the orientation of hydraulically induced fractures in petroleum reservoirs to help guide producers in better location and spacing of producers in better location and spacing of wells for more efficient fluid injection and petroleum production. The results of analyses petroleum production. The results of analyses of surface and subsurface information show a definite correlation between surface lineations and azimuths of hydraulically induced fractures. Joint systems determined from remote sensing imagery and/or surface surveys have been correlated with subsurface fracture orientations to depths of 3,000 feet and used to predict the bearing of hydraulically induced fractures in the Appalachian basin. Possible applications of fracture orientation Possible applications of fracture orientation prediction to petroleum production are also prediction to petroleum production are also discussed.
Introduction
One of the most important problems facing the domestic petroleum industry is the declining reserves to production ratio. Although additions to reserves through increased secondary recovery operations have nearly offset the decline in reserves added by drilling in recent years, there is a limit to the volume of crude oil that can be recovered through economic secondary means. A large fraction of our oil reserves, both primary and secondary, are contained in low permeability formations from which they cannot be economically produced by present techniques. Although the development of hydraulic fracturing has enabled the industry to develop a portion of these reserves, little is really known about the system of fractures created or the effect of natural fractures on fluid flow. Planes of weakness, which could be opened Planes of weakness, which could be opened during secondary recovery operations or hydraulic fracturing, do exist and have a preferred compass orientation. The effect preferred compass orientation. The effect of induced fractures on fluid movement in the reservoir must be known to attain maximum production efficiency. production efficiency. The Morgantown Petroleum Research Laboratory of the U.S. Bureau of Mines initiated a study in 1967 to investigate hydraulically induced and natural fracture systems and their effect on crude oil recovery. Results of these investigations will be used to locate wells in secondary recovery projects to obtain the highest injection rates and breakthrough sweep efficiencies possible and, in areas under primary recovery, to make maximum use of the primary recovery, to make maximum use of the drainage capabilities of the hydraulically induced fractures.
Geologic Factors Which May Affect the Occurrence of Natural Gas in the Oklahoma Panhandle
Authors: Moore Carl A. 
Published: December 2007

Introduction
The Oklahoma Panhandle was once called "no man's land" because it was a narrow strip of land of doubtful value lying between Kansas and Texas.
Geologically, the Oklahoma Panhandle is situated along the northwest flank of the Anadarko Basin and separates the Dalhart Basin from the Hugoton Embayment of the Anadarko Basin. This is a geographic separation rather than a tectonic separation. As a result, the Panhandle has been subject to a basin-flank Panhandle has been subject to a basin-flank geological history as compared with the basin troughs on either side.
Initial production of natural gas in the Oklahoma Panhandle was from rocks of Permian age: the Herington, Krider and Winfield porous limestones and dolomites in the Hugoton field. Production came from above 3,000 ft [drilled Production came from above 3,000 ft [drilled depth] and many wells were rated as being major producers. producers. Prior to the early 1950's, there had been only limited, sporadic production from reservoirs older than the Permian. With the discovery of gas in Beaver County [eastern county in the panhandle] in upper Pennsylvanian limestones, major development and exploitation of other Pennsylvanian and Mississippian horizons quickly Pennsylvanian and Mississippian horizons quickly followed.
In addition to the Permian production in the Oklahoma Panhandle, variable production has been found in the Pennsylvanian rocks: Wabaunsee, Hoover, Tonkawa, Topeka, Kansas City lime, Toronto, Douglas, Council Grove, Hodges, Lovell, Des Moines, Oswego, Marmaton, Cherokee, Morrow, Purdy, Keyes, Collier, Atoka, basal Pennsylvanian; Mississippian: Chester, Meramec Pennsylvanian; Mississippian: Chester, Meramec and Devonian Hunton. Some of these beds are correlative, being local names of a given horizon. The Morrow is by far the most important of this list,, followed by the Chester, the Hoover, Tonkawa and Topeka in approximately equal proportions.

REGIONAL GEOLOGY
Fig. 1 illustrates the subsurface structure across the Oklahoma Panhandle as shown on the datum at the base of the Pennsylvanian system of rocks. Starting in the western part, in Cimarron County, depths to the pre-Pennsylvanian sequence of rocks average some 1,000 ft below sea level. Because of the lack of drilling, this part of the county is poorly known. One fault probably related to the faults in Texas County, is shown. Keyes Dome is situated within the closing contour in the northeast corner of Cimarron County.
Differences in subsurface elevations across Texas County range from 1,000 ft to 4,400 ft below sea level.
Lithology-Dependent J-Functions and Relative Permeabilities
Authors: Phelps R. E. 
Published: December 2007

ABSTRACT
This paper demonstrates a technique of using log data coupled with lithology dependent porosity-permeability transforms to calculate facies-dependent Leverett J-functions for the Hadriya reservoir. A comparison of initial water saturation profiles from formation analysis logs versus profiles from a single global J-function and facies-specific J-functions are presented.
These facies dependent J-functions were then used to compute facies specific imbibition and drainage relative permeabilities for both the wetting and non-wetting phase.
Interpretation of the Transient Pressure Recorded by a Multiprobe Wireline Formation Tester in a Layered Reservoir
Authors: Shah P. C. , Thambynayagam R. K. M. , Pop J. J. , Pelissier-Combescure Jacques , Heliot Denis 
Published: December 2007

Abstract
The deconvolution of the transient pressure response recorded by one monitor probe (the v or "vertical" probe) of a multiprobe formation tester with respect to that recorded by the other probe (the h or "hor-izontal" probe) yields the Pv/Ph transfer function. The transfer function response is independent of the flow rate variation and local effects in the vicinity of the sink probe and hence offers an attractive diag- nostic/interpretation technique. However, the complete theoretical transfer function response has not been calculated and systematically studied even for the simplest case of a wellbore located in a homogeneous infinite reservoir. This paper contains a limited catalog of responses, which account for the wellbore, for reservoirs that are homogeneous, infinite or finite, have one or two layers, and have a thin shale streak present between the h and v probes. A systematic study is made of the variation of this response with the formation, fluid and geometric parameters of the model.
This study has led to the conclusions that the existence and location of layer boundaries and shale streaks must be independently known from other measurements (openhole logs or borehole images) before inverting for the anisotropic permeabilities. A simultaneous inversion of the geometric parameters and the permeabilities will most likely result in nonuniqueness. For example, if the data from a formation with layering are interpreted using a homogeneous model, the resulting permeability anisotropy estimates may be in significant error. Moreover, very different physical situations often lead to very similar Pv/Ph transfer functions, and thus the risk is high that a diagnosis is incorrect when it is made solely from the transfer function obtained by deconvolving the measured pressure responses.
An example with field data is presented, and the transfer function derived from the measured pressure transients through deconvolution is compared with the theoretical response of models obtained by pressure history-matching.
Transient Testing of Limited-Entry Wells in Communicating Layered Reservoirs
Authors: Abbaszadeh M. D. , Tomita Nobuhiko , Tanaka Tatsuo 
Published: December 2007

ABSTRACT
This paper presents both theory and field application for well testing of single or dually completed limited-entry wells in layered reservoirs. A comprehensive analytical solution is developed which considers anisotropic layers with crossflow among layers in the formation. Features of the model are discussed and sensitivity studies are presented to illustrate effects of contrast in layer properties, dual completion, and geometry of limited-entry wells on transient responses. Some behavior of interference tests for different well completion geometries are also studied.
An interpretation method is presented which characterizes high and low permeability layers from pressure transient data. A field pressure buildup test from a layered reservoir, where a high permeability layer is between two low permeability layers and the well is partially completed in a low permeability zone, is analyzed by the interpretation method of this paper. Properties of high and low permeability layers are computed from this single buildup test
Transient Pressure Analysis for Wells in Multilayered Reservoir with Finite Conductivity Fractures
Authors: Osman M. E. 
Published: December 2007

ABSTRACT
In this study, a mathematical model was developed to present the pressure behaviour of a well located in a multilayered infinite acting reservoir and crossed by a finite conductivity vertical fracture. It was found that dimensionless pressure functions and it's derivative are strong functions of fracture conductivity and extension during early time. The effects of reservoir heterogeneity on pressure function are negligible compared to their affects on the pressure derivative. It was also found that fractional production rate from different layers is a good measure of reservoir and fracture characteristics. Flowmeter survey data can be used to eliminate uniqueness problems in using type curves presented in this study.
Successful Applications of the Multilayer Transient Testing Technique: Arab-C Members of the Umm Shaif Reservoir
Authors: Khalaf A. A. , El Emam M. , Mahmoud Y. , Saeedi Jawaid 
Published: December 2007

Abstract
The Multi-Layer Transient Testing technique (MLT) was implemented in deviated wells with relatively low potential in order to estimate the layer production capacity (Kh), skin and pressure in the commingled production of Arab-C different sub-layers. For each MLT, a pair of rate and pressure transient were acquired over each member when the surface flow rate was changed systematically.
This paper discusses the successful use of the MLT technique as a monitoring tool in Arab-C reservoir of the Umm Shaif field. The rate and pressure transients were used to identify the reservoir model using the rate normalized pressure derivatives. Whilst the parameter estimates were obtained using the Sandface Rate Convolution (SFRC) plots and pressure derivative matches to the convolution type curves. The layer estimated parameters were used with a single well numerical model to calculate the bottom hole pressure (BHP) response during the test. A match to the measured BHP response gave the final parameter estimates.
Logging Experience with the Pulsed Spectral Gamma Tool
Authors: Wyatt D. F. , Jacobson L. A. , Fam Maged 
Published: December 2007

Abstract
A newly introduced pulsed spectral gamma-ray (PSG*) logging tool utilizes a high-density bismuth germanate (BGO) scintillation detector to improve the log measurement. The traditional limitation of the carbon/oxygen (C/O) measurement is its poor statistical performance due to the small dynamic range of the measurement. This limitation is significantly reduced by the improved sensitivity of the bismuth germanate detector to high-energy gamma-rays.
Chaxts based on extensive laboratory measurements characterize the tool response to porosity, lithology, fluid type and borehole conditions. The C/O ratio shows a dynamic range of 22% at 35 pu in a 10-in borehole. It is relatively insensitive to variations in casing size and weight, and cement type and thickness. Field logging experience demonstrates that, compared to older C/O tools, the improved capabilities of the PSG tool enables either recording acceptable logs at higher logging speeds (5 ft/min) or better saturation precision at slower speeds (1 to 2 ft/min) than was previously possible. Logging speed can be at least tripled while obtaining precision Comparable to older tools. Capture spectral processing to obtain relative elemental yields is provided and aids in lithology interpretation.
Several logs from wells in both Nigeria and Alaska illustrate log presentation formats and the quality of the measurements under a variety of logging environments. Oil saturation calculations using only PSG data and using PSG data plus porosity from open-hole logs correlate well with open-hole oil saturation predictions. Complex lithology evaluation is available through ULTRA* and is compared to open-hole results. Merging multiple passes improves the quality of the oil saturation determination. Five-minute station measurements are compared to continuous logs and show satisfactory correlation. Generally, statistical uncertainties for logs run at an effective logging speed of 2 ft/min or less are dominated by systematic uncertainties from environmental effects. Several log quality indicators that monitor hardware spectral gain stabilization and offset and software functions (curve statistical precision) are available in real time.
In-Situ Determination of Oill/Water Relative Permeability Curves Using Well Performance Data
Authors: Al-Khalifa A-J . A. 
Published: December 2007

ABSTRACT
This paper describes a new method to estimate oil-water relative permeability in-situ, using well performance data. The historical production rates of an oil producer reflected in a time-lapse of successive flowmeters are used to estimate the oil-water relative permeabilities. The corresponding water saturations are obtained through saturation logs or computed using the cumulative production volumes in a Buckly-Leverett solution.
The proposed method is a major improvement over current historical performance methods. This method yields the individual oil and water relative permeability curves, rather than the ratio of oil to water permeability curve obtained using other techniques. Furthermore, this method results in different relative permeability curves for different facies as they are swept at different times.
The resulting relative permeability curves reflect the properties of the whole drainage area, rather than those of a small laboratory core. They also reflect true reservoir conditions, accounting for wettability, heterogeneities and fluid compositions. Therefore, they yield a better modelling result with minimal changes in the history matching process.
The proposed method is demonstrated using field data of a giant carbonate reservoir under a major water flooding project. Field results presented in this paper demonstrate the ease and the applicability of this method.
Estimation of Residual Oil Saturation (ROS) on a Field-Wide Basis Using Multiwell Data-Base Techniques
Authors: Reiss A. R. , Watfa Mohamed , Plomb J-P. 
Published: December 2007

ABSTRACT
The estimation of ROS is essential for a variety of applications in the oil industry. This application varies from the requirement of ROS input to the reservoir simulation, to the estimation of the recoverable hydrocarbon volume. A knowledge of the ROS is also essential for evaluating the sweep efficiency of the reservoir, and correspondingly for the evaluation of the unswept hydrocarbon volume. A variety of techniques were used in the past for the evaluation of ROS which included core analysis, Log-Inject-Log techniques, and saturation monitoring of zones which have been swept by the production process. Invariably, these techniques yielded results which at best are representative of single wells and over small intervals.
The technique presented in this paper looks at using multi-well data-base statistical techniques to estimate the ROS. The approach is to collect the known data on ROS from Thermal Decay Time Log (TDT*) data and open hole data over swept intervals which is not perforated or acidized.; such data is normally scattered over small intervals from different wells. The next step is to use this data in a multi-dimensional statistical data-bank to obtain ROS values over most of the logged intervals, and in wells where no ROS data is available. The Data-Bank statistical correlations are used to find correlations between the ROS and the various log and log-derived interpretations, and then to extrapolate this knowledge to estimate ROS data across the field. Such techniques have been applied successfully to estimate permeability variations across all the logged intervals in large reservoir.
This approach is definitely a big step forward in understanding the variations of ROS. In the limit. the results obtained can be used as a first order approximation of ROS. Accuracy of the results obtained can be tested by estimating ROS in wells where some ROS values are available and to estimate the errors by comparison with true data. The availability of a representative volume of estimated ROS data on a field wide basis can facilitate the drawing of ROS maps for the various layers and sub-layers in a producing reservoir.
Rigsite Ions Monitoring System for Drilling Fluids
Authors: Hughes T. L. , Jones T. G. J. , Geehan Thomas , Tomkins P. G. 
Published: December 2007

Abstract
Chemical composition is a critical factor determining the performance of water-based drilling fluids. During drilling, the circulating fluid undergoes chemical changes due to additions of mud products at surface, interactions with drilled formations and losses of fluid in discharges and on drilled cuttings. Chemical changes due to interactions with drilled formations may degrade the performance of the drilling fluid. Rigsite tools to monitor chemical composition as well as functional properties are required for optimum maintenance of a fluid specification during drilling.
A rigsite system to monitor and control the ionic composition of water-based drilling fluids is presented. The system consists of (i) a measurement component which provides frequent determinations of the ionic composition of the aqueous phase of the fluid during drilling and (ii) an interpretation component which includes software for calculation of filtrate density and water activity, an advisor tool for designing fluid treatments and a data storage and processing package for constructing chemical logs during drilling.
The Measurement component has two units; a cross-flow filtration unit for rapid preparation of filtrate from representative samples of the fluid entering and exiting the wellbore during drilling and an ion chromatography unit for rapid and accurate analysis of filtrate composition. The ionic compositions of filtrates prepared using the cross-flow filtration unit and a standard API static filtration apparatus are compared. Further laboratory and pilot-scale tests involving controlled additions of inorganic salts to simple water-based drilling fluids simulate chemical changes in fluid composition and provide data with which to assess measurement accuracy and precision. The use of the Interpretation component for calculating water activity and as an advisor tool in designing treatments to control fluid composition is described.
Results from field case studies emphasise the importance of chemical monitoring in an optimum drilling fluids engineering service. Correlations between the chemical composition and functional properties of water-based drilling fluids are discussed with particular reference to the effect of divalent cations on the efficiency of water-soluble polymers.
A New PDC Cutting Structure Improves Bit Stabilization and Extends Application into Harder Rock Types
Authors: Weaver G. E. , Clayton R. I. 
Published: December 2007

Abstract
The destructive effects of the dynamic forces typically induced by the cutter/rock interaction of PDC bits have been identified in previous works. The material presented in this paper deals with a new cutting structure developed for PDC bits which is self-stabilizing; forcing the center of rotation to remain at or near the bit's design center.
Positioning the PDC cutters in concentric rings with little or no overlap between cutters produces a bottom hole profile with deep grooves. These grooves act as guide tracks for the PDC cutters and provide a restoring force to resist off-center rotation.
This paper describes the design and testing of whirl resistant PDC bits based upon these design principles. Laboratory drilling experiments are discussed and conclusions developed which are validated with field performance in six case histories.
Estimating Secondary Reserves
Authors: Amyx J.W. , Bass D.M. 
Published: December 2007

1962 Economic and Valuation Symposium Dallas, March 15–16, 1962

Introduction
The estimation of secondary reserves unfortunately cannot be reduced to a simple, standard procedure wherein all factors or parts are automatically specified once a process has been selected. This paper will discuss the general procedure and factors which must be considered in estimating secondary reserves. Before any discussion pertaining to estimation of reserves, it is necessary to define the terminology.
Reserves, as used herein, is that quantity of oil which is yet to be reduced to possession by the production procedure in operation.
Ultimate or Total Reserves is that quantity of oil which can yet be reduced to possession by either the existing or augmented operational procedure.
Primary Reserves is that quantity of oil which is yet to be reduced to possession soley by means of the naturally occurring reservoir energies under the existing competitive and regulatory conditions.
Secondary Reserves is that quantity of oil in excess of primary reserves which is yet to be reduced to possession by supplementation of the naturally existing reservoir energy.
Ultimate Recovery is that quantity of oil which will be reduced to possession during the operational life of an oil reservoir.
Primary Recovery is that quantity of oil which will or could be reduced to possession in an oil reservoir's producing life utilizing only the naturally occurring reservoir energy.
Secondary Recovery is that quantity of oil in excess of the ultimate primary recovery which will be reduced to possession because of the supplementation of natural reservoir energy. It is the difference between ultimate and primary recovery.
For the foregoing definitions, general equations can be written to express the relationship between ultimate, primary and secondary recovery and primary and secondary reserves. The most general form of these equations are

Ultimate Recovery
(1) = ( EA EV Ed ) N= ( ER ) UN

Primary Recovery
(2) = ( ( Ed ) p ( EA ) p ( EV ) p ) N= ( ER ) p N
= (EA) ij (EV) ij (Ed) ij) (N-Np0 pj)
- (ER)p - (ER) pj) N
or
= (ER) ij (N - (Np) pj)
(3) − ( ER ) p N − ( Np ) pj )
Reserves at time k
(4) = ( ER ) UN − ( Np ) k
Primary Reserves at time k
(5) = ((ER)p − (ER) pk) N = ((ER0p N − (Np) pk)
Secondary Reserves at time k
(6) = ( ER ) ij ( N − ( Np ) pj ) − ( ( ER ) p N − ( Np ) pj ) − ( ( Np ) k − ( Np ) pk )
P. 36^