bluuebunny/crossref_metadata_2025_split huggingface dataset:
Clastic Formation Evaluation Program In Cased Holes For Both Fresh And Saline Formation Waters To Determine Hydrocarbon Content
Authors: Vercellino W.C. , Skaggs L.L. , Bishop W.D. , DeVries M.R. , McWhirter V.C. , Wichmann P.A. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
Formation evaluation of clastic formations in Cased Hole uses the principals and logics of Sandstone II and Complex Reservoir Formation Analysis. Included in the Program are analysis from Open Hole Surveys, when available, along with analysis of the Carbon Oxygen Ratios, Silicon Calcium Ratios, Gamma Ray, Silicon, Calcium, Compensated Neutron, Neutron Lifetime Sigmas, near detector curve from the Lifetime Log, and for detector curve from the Lifetime Log measurements. The Cased Hole Clastic Evaluation will allow analysis of possible hydrocarbon bearing zones regardless of water salinities through casing.
Matrix constants, formation salinities, clay volumes, formation fluid parameters, i.e., water, gas, and oil, are determined from comparison of a series of checks and balances of the survey responses and their material balance equations. The analysis is presented in analog form along with a printed report and commentary. Examples are shown from the Gulf Coast, California, Red Desert, and East Texas of the analysis along with tested results.

Introduction
Evaluation of clastic formations in cased holes uses pattern recognition in (addition to the principals and logic of Dresser Atlas' evaluation programs for Sandstone and Complex Reservoir formations. The evaluation technique allows analysis through casing on possible hydrocarbon bearing zones regardless possible hydrocarbon bearing zones regardless of water salinities. Data are utilized from Gamma Ray Logs, Silicon/Calicum (Si/Ca) ratios, Silicon/Calcium (Si/Ca) continuous curves, Carbon/Oxygen (C/O) ratios, Inelastic Neutron Logs, Compensated Neutron Logs, Dual Detector Neutron Lifetime Logs and open hole surveys.
Matrix constants and formation salinities are determined from crossplots. Shale volume parameters are calculated. Then the data is parameters are calculated. Then the data is compared in a series of checks and balances using crossplots of porosities that are shale volume corrected.
Data output is in analog and tabulated form. The analog plot is the Cased Hole Exploration Service Epilog, (Figure 8C). Displayed on a four track grid, the curves are recorded as follows:
Track I Lithologic characteristics - Shale% of Bulk Volume, Permeability Index, and C/O Ratio measurements.
A Quantitative Technique for Determining Injectivity Profiles Using Radioactive Tracers
Authors: Wiley Ralph , Cocanower R.D. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
A new technique is presented that will quantify the losses to the formations in the well bore utilizing tracer profiles. The method is supported analytically and provides a sound basis for tracer profiles not available with other surveys in the field today.
This quantitative technique utilizes the intensity of the radioactive tracer material as a function of depth. As the material is lost through the casing performations and open hole sections into the formation, the intensity of the tracer material remaining in the borehole is related to the intensity before any losses occur. The gamma ray count rate is related to the intensity by correcting the observed count rate for system resolving time and integrating the corrected count rate as the tool moves through the radioactive material. The integral of the corrected count rate of each drag run through the material is normalized to the intensity before any losses to the formation take place. place. The accuracy of this system over an existing manual geometric approximation technique is demonstrated by several field examples.

Introduction
Current methods to determine the vertical water injection distribution include radioactive velocity measurements and radioactive tracer logging. Velocity determination is performed by measuring the time elapsed for a slug of radioactive material to travel a known distance between two detectors. The velocity measurement and the well bore diameter are then used to obtain quantitative injection distribution. The tracer profile technique utilizes a single detector to determine the injection profile by determining the intensity of the radioactive material in the well bore as a function of depth.
A geometrical measurement is made of the recorded response in the surface unit and is related to the response of the tool as it passes through the radioactive slug as moving in the well bore. Comparison of the geometrical plots provide a profile of losses in the well bore. provide a profile of losses in the well bore. On occasions the velocity profile and the tracer profile have presented a difference in loss profile have presented a difference in loss percentage plots. percentage plots.
Reduction Of Grid Orientation Effects In Reservoir Simulation
Authors: Holloway Carl C. , Thomas L. Kent , Pierson Ray G. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
This paper presents a method for reducing the effect of grid orientation on computed numerical results in finite difference reservoir simulation. The method involves modification to the interblock phase transmissibilities normally calculated and the use of a two-point weighting scheme in calculating mobilities. These are minor changes to an IMPES type simulator.
Example problems of unit mobility ratio and high mobility ratio with both long and short transition zones are included. The results indicate that neither the transmissibility modification nor the two-point weighting scheme are sufficient by themselves to correct the error although the two-point. weighting of mobility has the greatest effect.

Introduction
Many reservoir simulation problems involve the study of displacement patterns of injected fluids. Results of such studies using finite difference models are affected by grid orientation errors in which fluid tends to flow in the direction of the grid axes rather than diagonal to them. This paper presents a method for reducing grid orientation effects, inherent in finite difference simulators, by modification of the interblock phase transmissibilities to account for diagonal flow. Incorporation of the modified transmissibility is a minor change to an IMPES type simulator and when used with two-point upstream mobility weighting gives excellent results.
The grid orientation problem is illustrated by a quarter of a five spot overlain by two different finite difference grids. A diagonal grid has its coordinate axes parallel to the sides of the quadrant of the five spot, with the injection and production wells on diagonally opposite corners of the grid.
Results of Waterflooding Some High Watercut Reservoirs in South Louisiana
Authors: Poston S.W. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The effects of waterflooding four high watercut, partially pressure-depleting South Louisiana reservoirs are discussed. In all cases, the secondary reserves estimates had to be increased after response to water injection had been established. Subsequent to response, an engineering re-evaluation indicated the primary production mechanism had been primary production mechanism had been misinterpreted and the original secondary reserves estimates had been unnecessarily conservative.
The installation and operation of a waterflood project in a South Louisiana salt dome associated field is subject to several variables. The fault patterns are quite complex and the deltaic-type deposits produce sands with erratic continuity. Intrawell sand correlation is oftentimes difficult. The areal extent of these Miocene reservoirs are usually never more than 500 acres. Also, wellbore availability is a constant problem. Due to the multiplicity of pay zones, neighboring wells may be dually pay zones, neighboring wells may be dually completed in different reservoirs. Water injection projects must often be initiated with a minimum number of wellbores and then gradually be expanded as other wells become available for recompletion.

Introduction
A study of the productive fields operated by Gulf Energy and Minerals Co. - U.S. in South Louisiana indicates few examples of pressure-depleting, nonwater producing reservoirs. pressure-depleting, nonwater producing reservoirs. In fact, reservoirs experiencing very efficient water drives with little pressure decline may display less associated water production than a structurally comparable partial water-drive reservoir. Significant pressure declines occur in many of these partial water-drive reservoirs when the water influx is incapable of offsetting the fluid offtake rate. Economic considerations often require the optimization of the rate of reservoir oil recovery.
The increased emphasis on maximizing oil recovery has resulted in a re-examination of the reservoir mechanics associated with oil production from the South Louisiana fields. production from the South Louisiana fields. The investigation revealed that the areal sweep efficiency may be quite low in some low relief, partial water-drive reservoirs. partial water-drive reservoirs. The-following study discusses four waterfloods operated by Gulf Energy and Minerals Co. - U.S. in South Louisiana. The reservoirs did not fit the classic picture for potential waterflood candidates.
Petrophysical Study of the Cardium Sand in the Pembina Field
Authors: MacKenzie Wm. T. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
An evaluation technique to help define net pay and refine reserve estimates, and to aid in pay and refine reserve estimates, and to aid in optimizing productivity, was developed for the Cardium sand in the Pembina Field, Alberta, Canada. This technique is based on rock type as determined from mercury injection data. An empirical correlation between effective pore throat or aperture radius and the ratio of permeability to porosity (k/phi) was applied to permeability to porosity (k/phi) was applied to all core analyses on the Pembina "G" lease to generate suites of reservoir parameters such as net pay, pore volume, and flow capacity. When correlated with lease well productivity, they revealed wells with potential for improved productivity. Additional data from other leases productivity. Additional data from other leases in the field support the k/phi correlation validating its application to Cardium sand areas in the Pembina field. The technique is ideally suited to computer application.

Introduction
This petrophysical study of the Pembina "G" lease in the Pembina Field, Alberta, Canada, is part of a more extensive study of the Cardium part of a more extensive study of the Cardium sand reservoir. It was undertaken to obtain a better understanding of the reservoir characteristics and their relationship to the field performance. In areal extent, the Pembina performance. In areal extent, the Pembina field is the world's largest waterflood project. Thirty-four operators are active in 155 projects in the field. With some 921 million bbl of remaining recoverable oil reserves in the Cardium pool as of Jan. 1, 1975, there is incentive to obtain a better understanding of reservoir performance.
While some projects in the Pembina field are generally responding well to waterflooding, there are areas like the "G" lease where productivity is relatively low with a wide productivity is relatively low with a wide variation in well capability not explained by reservoir permeability, porosity or net par. Specifically, this study, in application to the problem at hand on the "G" lease, investigates problem at hand on the "G" lease, investigates the reason for the difference in well capability and defines wells with potential for improved production. A more fundamental purpose of the study is to provide an evaluation technique applicable to reservoir sand areas throughout the Pembina field which would aid in increasing productivity and refine oil-in-place and reserve estimates.
The approach utilizes mercury injection data and scanning electron microscope (SEM) studies of core samples to classify the Cardium sand into three basic rock types based on effective pore throat or aperture radii.
Influence of Cold Water Injection on Residual Oil Saturation of Multilayered Oil Reservoir
Authors: Rubinstein L. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
The paper contains information on the results of some calculations describing the influence of cold water injection on oil output from a multilayered oil reservoir. It is shown that there exists a real possibility of a complete or almost complete loss in productivity of a low-permeable sublayer adjacent to a highly permeable one, due to the filtration resistances permeable one, due to the filtration resistances redistribution under the influence of thermal interference of different sublayers.

Introduction
All large oil fields are exploited with the application of water injection in order to maintain the interlayer pressure. Usually each oil reservoir consists of a number of productive layers separated by relatively thin impermeable layers. Different neighboring productive layers are exploited simultaneously, being open by a well of unique face.
If the temperature of the injected water is lower than the initial temperature of the reservoir, the water injection can lead to the essential cooling of a relatively small permeable sublayer in front of an oil-water contact permeable sublayer in front of an oil-water contact moving inside it, but behind that in the most permeable layer. This is a consequence of permeable layer. This is a consequence of thermal interference of different productive layers.
If the volume of water injected into different productive layers can be maintained on a prescribed level, proportional to their physical permeability, such a cooling does not physical permeability, such a cooling does not lead to any sufficiently essential effects as well as heating of the stratum by injection of hot water. Unfortunately, in practice, the prescribed value is the pressure of injection on prescribed value is the pressure of injection on but not the distribution of water between different productive layers of the oil reservoir. By such a real system of speration the cooling (as well as heating) leads to a redistribution of resistances of oil and water to filtration. This redistribution may lead in some real cases to complete loss of productivity of low permeable sublayers or, in any case, to its almost permeable sublayers or, in any case, to its almost complete loss. Such a catastrophic consequence of cold water injection into multilayered oil reservoirs can be prevented by heating the injected water approximately to the initial temperature of the oil reservoir, and this action is economically admissible. Naturally such treatment must be applied from the beginning of the oil reservoir's exploitation.
Our aim consists of the demonstration of results of a number of calculations that were fulfilled some years ago on the base of the spatial developed methods. All these results were published in the author's book.
Case Histories of Design and Implementation of Underbalanced Wells
Authors: Giffin David R. , Lyons William C. 
Published: December 2007

Abstract
As operators strive to increase production from existing reservoirs with depleted reservoir pressure, the use of under-balanced drilling and underbalanced horizontal drilling is becoming more widely used. One of the primary problems to be overcome in drilling under-balanced is designing a circulating "fluid" that has an equivalent circulating density below the reservoir pressure. This paper discusses the mathematical equations used to design air drilled "under-balanced" wells. It will also show how these equations were used to design four separate wells. The presentation of actual field data will validate these equations and computer modeling used. The four wells will include 1) 17,000 TVD well drilled into the Ellenberger formation with reservoir pressure at 1200 psig, 2) horizontal well drilled into the Petit formation at 5900 ft. TVD with reservoir pressure at 210 psig, 3) horizontal wells drilled into the upper Penn Formation at TVD 7800 ft. and reservoir pressure of 1000 psig., and 4) deviated wells drilled into the Ellenberger formation below 13,000 feet TVD and reservoir pressure of 600 psig.
The mathematical equations used were developed by Dr. William C. Lyons of New Mexico Institute of Mining and Technology in Socorro, NM. Computer simulations for these wells were run by David Giffin on software developed by Boyum Guo and Dr. Lyons. Each of these wells was drilled using air drilling techniques. By measuring the pressure at both surface and bottom hole conditions, the validity of the mathematical models used has been established. Air or other compressed gas can be used to reduce equivalent circulating densities to accommodate almost any reservoir pressure.
Using 3D Seismic to Identify Spatially Variant Fracture Orientation in the Manderson Field
Authors: Gray David , Head Kim , Chamberlain Kent , Olson Gordon , Sinclair John , Besler Chris 
Published: December 2007

Abstract
Oil is produced from the Manderson Field, in Big Horn County, Wyoming, from a fracture system with possible significant lateral connectivity. So characterizing the fractures in this field is of great importance. Amplitude Versus Offset (AVO) analysis of azimuthally restricted seismic data is used to determine the orientation and density of fractures at selected locations corresponding to well locations in the Manderson field. The result of this analysis is compared to fracture strike analysis from oriented cores for three wells.
A Laboratory Study on Steam Distillation in Porous Media
Authors: Wu Ching H. , Brown Alfred 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Steam distillation investigations were made on crude oils in porous media to measure steam distillation yields and to determine the effect of process parameters on the distillation mechanism. parameters on the distillation mechanism. Experiments were performed in a vertically-oriented, 3-foot long, 3-inch diameter cell, designed to avoid steam displacement and entrainment of oil during steam distillation. Both saturated and superheated steam distillations were made on crude oils ranging in gravity from 9 to 36 deg. API. These tests were performed at pressures ranging from 200 performed at pressures ranging from 200 to 500 psig and steam temperatures ranging from 387 to 600 deg. F.
Experimental results show that the equilibrium saturated steam distillation yields are mainly dependent on the oil composition and may not correlate with crude API gravity. The yields are basically independent of the porous media and steam injection rates investigated. Changes in steam saturation pressure and temperature have insignificant effect on the yields; however, superheated steam significantly increases the yields for some crude oils.

Introduction
Steam distillation has been used chemical and other process industries for years. It is used as an alternate to processes requiring vacuum distillation to treat a feed stock at a temperature below the components' normal boiling point. These industrial steam distillations usually take place in cells not packed with porous materials.
Steam distillation of crude oil in porous media has been recognized as one porous media has been recognized as one of the major mechanisms responsible for high oil recovery by steam flooding. Willman et al estimated the oil recovery due to the steam distillation mechanism to range from 5 to 19% OOIP for various crude oils at steam temperatures up to 520 deg. F. Farouq Ali estimated that 5 to 10% of the heavy oil recovery by a steam flood may be attributed to steam distillation; and that as much as 60% of the oil recovery for some light oils may be attributed to the same mechanism. Volek and Pryor reported that in a field steam distillation drive test, the residual oil saturation in the steam swept region was less than 8%.
The Unified Analysis of Well Tests
Authors: Ridley Trevor P. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
A technique has been developed for the unified analysis of pressure data, using information from all drawdown and buildup periods of virtually any test schedule. Best periods of virtually any test schedule. Best statistical estimates are obtained for values of initial reservoir pressure, permeability, skin factor and, if applicable, the nondarcy flow constant.
The fundamental reliability of the method is demonstrated by the precision with which it analyzes artificial test data. Analysis of field data from both oil and gas wells provides further strong support for the dependability of the technique.
The method is easily programmed on a computer for a regression analysis on many observations to give fast, reliable and inexpensive analysis of well-test data.

Introduction
The design of a well test is generally bound by constraints such as the need for constant flow rates, isochronal flow periods or stabilized pressures. These are required so that the test data can be reliably analyzed by an appropriate method.
The execution of a well test is often influenced by factors beyond the control of the testing crew. For example, it may be impossible to maintain a constant flow rate because of a varying backpressure on the well; a test may be disrupted by equipment failure; flowing pressures might not stabilize for weeks or pressures might not stabilize for weeks or months. Thus, test data may fail to meet precisely the specifications required by the precisely the specifications required by the particular analytical method. The choice is to particular analytical method. The choice is to retest the well in the hope of obtaining more suitable data, or to use the existing data recognizing that the results may not be entirely reliable.
Many analytical techniques ignore a significant amount of the data collected during the test. Horner's buildup analysis, for example, ignores all but the final flowing pressure of the drawdown period before shut-in. pressure of the drawdown period before shut-in. An isochronal test ignores the pressure data preceding the endpoints of each flow and shut-in preceding the endpoints of each flow and shut-in period. The multiple flow-rate analysis period. The multiple flow-rate analysis proposed by Odeh and Jones ignores all shut-in proposed by Odeh and Jones ignores all shut-in periods. periods.