bluuebunny/crossref_metadata_2025_split huggingface dataset:
Preliminary Studies on Using Artificial Neural Networks to Predict Sedimentary Facies of the Permo-Carboniferous Glacigenic Al Khlata Formation, Oman
Authors: Schoenicke Olaf , Al-Alawi Saleh M. , Al-Bemani Ali S. , Kalam Mohammed Z. , Le Varlet Xavier 
Published: December 2007

Abstract
Artificial Neural Network (ANN) models have become increasingly significant in predicting various reservoir-engineering parameters. Their ability to generalize and infer subtle, unknown relationships from the input data makes them predestined for geological facies determinations from wireline log data.
Initiated by the need for a robust and automated facies identification tool in the very heterogeneous Permo-Carboniferous glacigenic Al Khlata Formation of south Oman, the present study is directed towards an improved definition of sedimentary facies and facies associations from wireline logs, which can be used as direct input to 3D modeling.
A total of eleven (11) sedimentary facies were described from conventional and borehole image log data in the Rima field of south Oman. The core- and partially outcrop-calibrated sedimentary facies form the basis of a facies interpretation technique using two ANN models: The first model uses quantitative analysis of conventional wireline log data (density, neutron, gamma ray and photoelectric effect). The second model uses a combination of qualitative information of the internal organization of the formations (‘image morphology’ - provided by high-resolution electrical borehole image data) and the quantitative data of model 1.
Preliminary results show that the first model can predict a set of six ‘wireline facies’ with an accuracy of 93%. The second model, which is presently being trained with ‘image morphology’ information derived from FMI*/FMS* data, will allow for the prediction of all pre-defined 11 sedimentary facies and facies associations.
Once fully trained this interpretation technique requires a minimum of interactive intervention by the analyst. The highly robust output can directly be used as input for 3D modeling of reservoir architecture and ultimately in 4D dynamic simulations, which will lead to optimized field development strategies for the Al Khlata Formation, one of the most prolific fields in south Oman.
Performance and Operations Review of the Major Multi-Reservoir, Bell Creek Field, Montana
Authors: Burt R.A. , Haddenhorst F.A. , Hartford J.C. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the Rocky Mountain Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Denver, Colo., April 7–9, 1975. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. 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 Bell Creek Field consists of six Muddy Sand reservoirs unitized as six units. A line drive water flood from the west edge of each reservoir has been in operation since 1970. oil production in November 1974 was 26,000 BPD. Cumulative production to December 1974 was 66.9 million barrels of oil. Tertiary recovery by a micellar process is under active consideration.

Introduction
The Bell Creek Field is located sixty miles north of Gillette, Wyoming, in Townships 8 and 9 South, Range 53, 54 and 55 East, Powder River and Carter Counties, Montana, as shown on Figure 1. The field is fifteen miles long and three and one-half miles wide, and consists of six secondary recovery units encompassing 17,000 productive acres, containing 305 active producing and injection wells. The current 26,000 BOPD rate accounts for nearly one-third of the oil production in the State of Montana.

HISTORY
The field was discovered June 4, 1967, by Exeter Drilling on a farm-out from Samuel Gary. The discovery well, 33-1 Federal-McCarrel, located in the NE1/4NE1/4 of Section 33, Township 8 south, Range 54 East, was completed for an initial pumping potential of 230 BOPD from perforations at 4524 to 4537 feet.
The Montana oil and Gas Commission designated forty-acre spacing for Bell Creek which resulted in drilling and completion of 405 oil wells and 10 gas wells. The average depth of a Bell Creek well is 4500 feet.
Difficulties of Relating IR T1 Maps to Pore Size Distributions
Authors: Al-Mugheiry Mohammed Adil , Issa Bashar , Mansfield P. 
Published: December 2007

Abstract
The measurement of longitudinal relaxation time (T1) by inversion recovery (IR) method or in short IR T1 mapping is a relatively simple and straight forward method for obtaining information related to the void space of saturated porous materials like sandstones. The way in which this information is to be interpreted, however, requires a more careful judgment.
The T1 distribution of water phantom reveals that there is a spread in T1 values due to intrinsic NMR noise caused by the imaging system. A similar effect will also cause T1 distributions of porous materials to be broadened in addition to the expected broadening due to void size variation or localized domains of different microscopic structures. Thus, the spread due to noise complicates the interpretation of T1 maps of these materials.
The spin-lattice data presented in the form of population distributions are believed to be an indirect reflection of the distributions of average pore sizes. For 3.0 mm and 1.0 mm glass bead packs, the relative distribution peak value of 2.6:1 was found to be broadly in line with the expected ratio of 3:1 assuming spherical pores and constant surface relaxation strength.
In the case of rocks, however, the lack of information about expected pore sizes and surface relaxivity pose a real difficulty as to how to interpret the data. The calculated values are believed to be broadly overestimated though may still indicate a genuine distinction in relative peak average values related to void spaces in these materials.
Design, Execution and Evaluation of a Novel Coiled Tubing Acid Stimulation Operation - A Case History
Authors: van der List E. J. F. , Quintero L. F. 
Published: December 2007

Abstract
A novel coiled tubing acid stimulation technique was successfully implemented in a horizontal well in Oman. Prior to stimulation the well was producing approximately 850 bopd with 2% watercut, from the Natih limestone reservoir. The open hole section had not been previously stimulated and it was fair to assume that there was near borehole formation damage due to overbalanced drilling and/or mud cake buildup. System analysis of the well suggested that the producing tunnel length was being severely affected by this skin and that removing such damage would increment the effective tunnel length almost twofold. As a consequence, the potential productivity index would increase by 78%. The objective of the stimulation job was to remove the drilling damage and allow the horizontal wellbore to flow to its full capacity The recommend acid system was a combination of a silt removal formulation (MSR) and Temporary Crosslinked Diverter (TCD). The treatment was done in 15 stages, covering 250 ft. per stage. A four month continuous production analysis shows an increase in PI from 1.6 to 3.2 and an oil rate of 1585 bopd (a 82% increase).
This paper should serve as a guideline into what tools and techniques can be used for complete design and execution of a stimulation operation. Also shown is an evaluation tool, which is vital to both service and operating Companies. To the former it shows where success is achieved enabling the company to focus attention and increase activity. To the latter it provides a quick economic view that should always be a part of the operator's decision making.
Following the well A coiled tubing acid stimulation, the challenge of performing a similar operation in a dual lateral was undertaken. This resulted in the application of the described techniques and use of a novel technique, using tracer material and a temporary chemical plug that proved to be successful.
A Review of Different Methods in Initializing and History Matching a Reservoir Model with Tilted Oil-Water-Contact
Authors: Hsueh P. T. , Pham T. R. , Bu-Hulaigah E. H. 
Published: December 2007

Abstract
Initializing a reservoir simulation model with a tilted oil-water-contact requires a special consideration in terms of capillary pressure curves selection and an understanding of reservoir fluid distribution. The paper discusses four different methods used, and presents the advantages and disadvantages of each method. Some of these methods will reveal that it is not enough to initialize a reservoir model, check for original oil-in-place then proceed with the history matching process. Inappropriate use of capillary pressure curves may cause errors in pressure and saturation calculations. The errors are often masked by changes made to reservoir parameters towards achieving a history match. A simple, quick procedure is outlined to identify these errors and to correct them before history matching efforts begin.
The Effect of Hyrolysis of Polyacrylamide on Solution viscosity, Polymer Retention and Flow Resistance Properties
Authors: Martin F.D. 
Published: December 2007

Abstract
Many excellent articles have reported various aspects of the nature of hydrolyzed polyacrylamide flow in porous media. The polyacrylamide flow in porous media. The degree of mobility reduction is proportional to:the viscosity of the polymer solution which is greatly affected by the presence of dissolved ions in the water, andthe reduction in reservoir permeability to water caused by flow of the polymer solution.
Penetration of a low mobility polymer slug Penetration of a low mobility polymer slug into a reservoir is limited in part by the adsorption of the polymer onto the rock surfaces or entrapment of the polymer in restricted flow channels. However, the behavior of "partially hydrolyzed" polyacrylamide can depend on both the nature polyacrylamide can depend on both the nature and extent of hydrolysis of the polymer molecule.
Reported in this paper are laboratory investigations of the viscosity and adsorption characteristics of polyacrylamide hydrolyzed to varying degrees with potassium hydroxide. Hydrolysis of polyacrylamide will increase both the measured and relative viscosity in both fresh water and NaCl brines. However, these polymers are sensitive to divalent ions. The higher the percent hydrolysis, the more polyacrylamides are affected by the divalent ions and at the 35% hydrolysis level may begin to precipitate. With fresh injection waters, the higher hydrolyzed polyacrylamides (25–35%) produce the most viscous polyacrylamides (25–35%) produce the most viscous solutions. In high calcium brines, a 15% or lower percent hydrolyzed polyacrylamide can produce greater solution viscosity. produce greater solution viscosity. Sandpack flow tests indicate that the adsorption of polyacrylamide in porous media decreases with increasing hydrolysis. Resistance factor curves display the effects of viscosity and polymer retention on mobility reduction properties. Information outlined in this paper is helpful in showing specific differences in hydrolyzed polyacrylamides that are a function of the degree of hydrolysis and are important in selecting the right polymer for a particular field application. polymer for a particular field application

Introduction
The energy crisis has stimulated additional activity in all aspects of oilfield operations.
Kick Detection and Well Control Training
Authors: Letbetter S.C. 
Published: December 2007

Abstract
As we are all aware, drilling activity is on the upswing, with a current average of over 1,600 rigs in operation in the United States, compared with 975 in 1971. A National Petroleum Council study projects 33,000 well completions and the drilling of 172 million ft of hole in 1975, despite shortages of tubular goods, pumps and other equipment. As a result of the continued increase in drilling activity, especially in foreign operations, the drilling industry is experiencing acute shortages of experienced, qualified personnel and is having to face the resultant problem of training new personnel.

INTRODUCTION
Traditionally, technical instruction, such as that needed in well control training, has been conducted by several methods: study of printed material, classroom activities, and actual on-the-job training. Even in situations where on-the-job training is feasible, as on a drilling rig, the trainee receives only limited instruction, since making hole and reaching contract depth quickly is the ultimate goal of drillers. The trainee learns normal, routine operations and seldom, if ever, experiences the abnormal condition of a kicking well and the control problems associate with it.
Even with the best of planning, the drilling of wells will always carry a potential blowout hazard, and some will probably occur. However, a carefully planned, continuing program to make crew members aware of the potential hazards of blowouts and exactly what is expected of them in an emergency situation should prevent most blowouts.
Recognizing this fact, Shell management began searching for a way to reduce the length of on-the-job training through simulations of control problems without waiting for training during actual control situations. The result of the search for an experience accelerator is training on an actual test well and an electrical well control simulator.
Geothermal Projects and Estimates Through 1985 and the Year 2000
Authors: Glass W.A. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the Oklahoma City SPE Regional Meeting, to be held in Oklahoma City, Okla., March 24–25, 1975. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. 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
Production of geothermal energy in the U.S.A. to date is 410 MWe. On an "accelerated program", this is to increase to 20,000 MWe by the year 2000. The geothermal projects that will contribute to this growth include dry steam fields, hot brines, moderate temperature/low salinity fluids, geopressured reservoirs, hot dry rock, and magmatic deposits.

Introduction
The contribution of geothermal energy to the total current U.S. energy needs is 410 MWe. This is approximately equivalent to a daily oil production of 16,400 bbls. per day. This amount of energy is less than .1% of the U.S. daily oil consumption.
The Federal Energy Administration (FEA) was asked to compile a report on what can be done in all energy fields for the U.S. to become energy self-sufficient by the year 1985 with projections to the year 2000. The FEA asked the National Science Foundation (NSF) to compile a portion of this Project Independence Report concerning Geothermal Energy.
Geothermal energy production is very small at present and will not progress at sufficient speed without being accelerated on a large scale to be a significant part of "Project Independence" by 1985 and 2000.
The nest projections were made on business-as-usual condition. This would mean that private industry would continue its current pace using present guidelines, procedures, and practices. The projections were finally procedures, and practices. The projections were finally estimated on an accelerated program. This means that a Federal research program would assist private industry in solving the problems that currently inhibit or restrict their current exploration efforts.
Hydrocarbon Location by Cased-Hole Methods in Mid-Continent Wells
Authors: Ermey B.R. , Alger R.P. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the Oklahoma City SPE Regional Meeting, to be held in Oklahoma City, Okla., March 24–25, 1975. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. 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
When production from a well falls below the profitable level, usually due to declining profitable level, usually due to declining reservoir pressure, the producer must decide whether to abandon, recomplete, or begin secondary-recovery operations. Until recently, the choice was made very difficult by the scarcity of reservoir-rock information obtainable from the existing logs.
The development of new took and techniques for logging in cased holes has greatly improved this situation. A modern logging program for these old wells might consist of a Dual-Spacing Neutron Decay Time tog, a Compensated Neutron log, and, where applicable, a cased hole Formation Density log. These, in conjunction with the original open-hole logs (usually a vintage Electrical Survey or a Gamma Ray-Neutron log) permit much better accuracy and reliability in the determination of porosity, fluid saturation and in some cases the type of hydrocarbon behind the pipe.
This paper presents several examples of Mid-Continent wells which were logged by such modern techniques. In each, the cased-hole logs allowed the producer to select with confidence the most appropriate action for his well.

Introduction
Developments in technique and equipment have brought a new order of reliability to log evaluation in cased holes. The key to these advances is the Dual-Spacing Thermal Decay Time device (TDT*-K). Also useful are the Compensated Neutron and Formation Density logs, which can be run in combination, and which under favorable conditions will provide good porosity determination and gas detection in cased holes.
Recipe for Heating and Recovering an 800 Foot Column of Heavy Oil, Potter Sands, Midway-Sunset Field, California
Authors: Lolley C. S. , Fram J. H. , Fortier J. D. , Deemer A. R. , Robinson K. L. 
Published: December 2007

Abstract
This is the first in a series of papers detailing the development of an 800-foot thick Potter sand oil column on the northwestern boundary of the Midway-Sunset oilfield in west-central section 21N, T31S, R22E. Tools used to develop the depletion strategy for this property include analogy and thermal numerical simulation. This viscous 11° API crude is currently producing 1500 bopd under cyclic steam support. This area will be re-developed as a steam flood over the entire 81 acres. Besides the viscous nature of the crude and the massive volume of reservoir that must be heated, another technical challenge is the presence of low pressure vadose or air sands immediately above the oil column. These air sands will act as a thief zone to the injected steam and will make heating this massive oil column more difficult. These challenges posed the following question: How does one effectively heat an 800-foot thick oil column without having the steam preferentially rise to the top of the column and into the low pressure air sands?
To adequately develop guidelines for steam injection rates and placement, a numerical simulation model with sufficient gridblock and compositional resolution was used to accurately simulate the countercurrent flow of steam and oil as the steam rises to the top of the reservoir. A two dimensional mechanistic model with very fine gridblocks was used to isolate this mechanism. Gridblock dimensions were calculated using a characteristic length, and the steam assisted gravity drainage (SAGD) process was used to estimate the rate of rise of the vertical steam chest. The oil was characterized by a 5-component system that was fully compositional and could simulate the complex phase behavior associated with the oil and steam rising into the air sands. The techniques used in the study resulted in a numerical model with sufficient resolution to provide guidelines for steam injection rates and for steam placement within the 800-foot thick oil column.
This project is under active development with over 130 wells drilled and completed in 1998. Future papers will detail the producer/injection well completion strategies and the steps used to optimize the recovery process.
CO2 and Miscible Gas Injection for Enhanced Recovery of Schrader Bluff Heavy Oil
Authors: Khataniar S. , Kamath V. A. , Patil S. L. , Chandra S. , Inaganti M. S. 
Published: December 2007

Abstract
The Schrader Bluff Pool in the Milne Point Unit, Alaska, is estimated to contain 1.5 billion bbl of heavy oil. Due to the lack of any significant primary recovery mechanism, enhanced oil recovery methods are considered for early stage application. Availability of hydrocarbon gases and CO2 on the Alaskan North Slope makes a miscible solvent injection process attractive. Therefore, the objective of this study was to experimentally investigate the performance of CO2 injection and miscible WAG processes for enhanced recovery of Schrader Bluff heavy oil. From slim tube experiments, CO2 was found to be immiscible with Schrader Bluff oil at reservoir conditions. Prudhoe Bay gas (PBG) enriched with at least 50% natural gas liquids (NGL) achieved dynamic miscibility with the crude oil. Coreflood experiments in 4 ft long sandpacks were conducted using CO2, and a mixture of 50% PBG and 50% NGL as the solvents to study the effects of slug size and WAG ratio on displacement of Schrader Bluff oil at reservoir conditions. These experiments showed that there was no significant improvement in the incremental oil recovery (IOR) for PBG/NGL slug sizes larger than an optimum value, however, the highest IOR per unit slug size occurred for a much smaller slug size. On the other hand, a single, small CO2 slug resulted in almost same IOR as a large PBG/NGL slug. Thus, CO2 had the highest IOR per unit slug size although it was immiscible with the oil. The IOR from PBG/NGL multiple slug WAG decreased asymptotically with increasing WAG ratio and a single slug WAG resulted in highest IOR per unit slug size. Thus, in coreflood experiments, a small single slug of 50% PBG and 50% NGL mixture, or of CO2 appears to be most efficient in improving oil recovery.