bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of a Single-Phase Simulator to Study the Effects of Liquids on Pipeline Efficiencies in a Natural Gas Gathering Network
Authors: Knobloch M.H. , Brill J.P. , Crafton J.W. 
Published: December 2007

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

Abstract
It is possible to history-match an existing gas pipeline network to obtain flow efficiencies that account for abnormal pressure losses resulting from liquids entrained in the gaseous flow stream. An actual gas gathering network which was known to produce relatively large volumes of condensate was successfully history-matched. The network was studied with a simulator which uses the single-phase Panhandle Equations to calculate the pressure losses in the pipeline. The observed pressures were matched in the calculations by lowering the pipeline efficiencies to account for liquids in pipeline efficiencies to account for liquids in the flow stream. Data was gathered which supported the theory that the low pipeline efficiencies resulting from the calculations were in fact due to liquids in the pipeline. Summaries and graphs of the data and calculated results are presented.

Introduction
The capability exists to completely simulate a gas gathering network with the modern digital computer. The simulator which has been used in this study employs single-phase flow equations to calculate the pressure drops through the pipeline segments. Satisfactory results have been achieved for all dry gas systems which have been studied using the simulator.
One gathering system was known to produce relatively large amounts of natural gas liquids, i.e. condensate. The single-phase simulator yielded rather wide pressure discrepancies when applied to this particular network. The purpose of this study was to determine if it is possible to apply a single-phase simulator to an actual operational flow network having abnormal pressure losses caused by the inclusion of liquids pressure losses caused by the inclusion of liquids in the gaseous stream.
The simulator calculates the pressure loss in a pipeline segment with an equation which incorporates a flow efficiency term. Normal line efficiencies for dry gas systems range from 70% to 90%. The nature of work performed was to duplicate the observed pressure losses by adjusting the line efficiencies of each individual pipeline segment.
The study was accomplished by concentrating on two different time periods; one during the winter when liquid production was high, and one during the spring when liquid production was low. The result was that two efficiencies were derived for each pipeline segment.
Preliminary Evaluation of Rock Springs Site 9 In-Situ Oil Shale Retorting Experiment
Authors: Wise R.L. , Sudduth B.C. , Winter J.M. , Jackson L.M. , Long A. 
Published: December 2007

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

Abstract
Successful startup of an in situ retorting experiment in the Tipton Member of the Green River oil shale formation near Rock Springs, Wy. began on April 5, 1976, at Rock Springs site 9. The target shale was located in a 40-foot zone between 137 and 177 feet beneath the surface and averaged 21.3 gallons of oil per ton and 2.3 per cent water by Fischer assay. After fracturing the shale zone with a combination of hydraulic and explosive fracturing treatments, the oil shale was ignited at a central air injection well with an electric heater and a propane burner. The oil shale was retorted in advance of the combustion front which propagated radially toward eight surrounding production wells. About 700 gallons of oil and 165 MM Btu of low-Btu gas were recovered during the first 35 1/2 days of operation.
Preliminary evaluation indicates that only a fraction of the oil shale reserves were retorted in advance of the combustion front. A computer data acquisition system automatically monitored underground temperatures, pressures, gas flow rates, and gas compositions at hourly intervals. Based on integration of these measurements, energy and material balance calculations indicate that the maximum amount of shale retorted in specially designated test areas was probably less than 14 to 18 percent of the oil probably less than 14 to 18 percent of the oil shale reserves within the 40-foot zone.
Post-retorting core samples will be evaluated after the experiment is finished. At the time this paper was prepared, the experiment was still continuing and data from only the first 35 1/2 days of operation were available. When the experiment is completed, data from environmental monitoring of the experiment will also be evaluated to determine the impact of in situ oil shale processing on air, water, and land quality. processing on air, water, and land quality

Introduction
Development of the oil shale resources in Colorado, Utah, and Wyoming could contribute significantly to the goal of achieving national energy independence. So far, the primary efforts to develop these resources have emphasized a combination of mining and surface retorting. However, two-thirds of the "potentially recoverable" shale oil resource is in low-grade deposits that may never be recovered by conventional mining techniques.
Oil Yield and Quality from Simulated In-Situ Retorting of Green River Oil Shale
Authors: Needham R.B. , Judzis Arvids , Cornelius A.J. 
Published: December 2007

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

Abstract
The yield and quality of shale oil produced for in-situ retorting conditions was measured by laboratory experiments and related to shale particle size, retorting temperature, and particle size, retorting temperature, and heating rate. In-situ retorting with recycle shale gas at a temperature of 800 deg. F should result in an oil yield of 80 to 85 weight percent of Fischer assay. The in-situ retorted percent of Fischer assay. The in-situ retorted oil would contain 1.7 to 2.0 weight percent nitrogen and 0.5 to 0.7 weight percent sulfur; these values are typical of shale oil from the conventional gas combustion retort. The in-situ retorted oil will have a slightly higher API gravity and be more volatile than oil produced by the gas combustion retort because of additional thermal cracking during production from the larger particles. The oil yield and nitrogen content of the oil did not depend upon the shale particle size for retorting temperatures up to about 800 deg. F, but at higher retorting temperatures, the oil yield was markedly lower for the larger particles. Therefore, in-situ retorting temperatures should be less than about 800 deg. F.

Introduction
This laboratory investigation of the oil yield and quality obtained from Green River oil shale simulated the conditions for the indirect heating method of modified in-situ retorting. In this method an underground retort is created by fragmenting an oil-shale bed in-situ and thereafter the bed is heated by the injection of hot shale gases. Methods of creating in-situ retorts by fragmentation of shale beds have been considered and experimental fragmentations are being conducted. Most of the reported investigations on retorting methods to recover the shale oil from such fragmented shale beds have concentrated on the in-situ combustion method.
The information obtained in this work specifically applies to the modified in-situ retorting process where a fragmented shale bed is heated by injecting hot shale gases into the top of the fragmented zone. The cooled gases and oil are considered to be recovered at the bottom of the fragmented zone. The conditions anticipated for such a process requires that lower retorting temperatures, longer times, and larger shale particles be used in the simulation than is usual for conventional surface retorting processes. processes.
Test Of A Submerged Production System - Progress Report
Authors: Childers T.W. , Loth W.D. 
Published: December 2007

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

Abstract
Offshore installation of Exxon's prototype Submerged Production System is prototype Submerged Production System is nearing completion. This pilot test installation is being conducted in Exxon's West Delta 73 Field in the Gulf of Mexico. It includes the equipment necessary to develop and produce deep water oil reserves. This pilot test should provide the information necessary to verify provide the information necessary to verify equipment designs, as well as deep water installation, operating, and maintenance procedures. The program thus far has procedures. The program thus far has included the seafloor installation of two large pile-founded structures (a drilling and production template and a marine production riser base), installation of two production riser base), installation of two subsea booster pumps on the template, and drilling and completion of three directional wells which have been connected to the subsea manifold. All five pipelines and the two electric cables required have been laid and connected to establish necessary communications between the template, riser base, and surface production facilities located on a nearby platform. Finally, remote maintenance procedures and tools have been used to perform maintenance tasks on the subsea equipment. The system is currently being brought up to operational status.
While most of the equipment and procedures have proven satisfactory, numerous procedures have proven satisfactory, numerous unexpected problems have been encountered. These have been solved using techniques applicable to deep water operations. Improvements are needed in some areas to reduce installation costs and increase equipment performance. Our experience to date continues to generate confidence that deep water oil reserves are within reach of current technology and the problems attendant with the use of complex equipment in a remote environment can be satisfactorily overcome.

Introduction
This paper updates progress of the offshore activities of the SPS pilot installation. Previous papers described the system in detail and discussed the fabrication of a prototype system and its offshore installation in Exxon's West Delta Block 73 Field in the Gulf of Mexico.
To facilitate the review of this paper by readers who do not have access to the previous papers, elements of the SPS and previous papers, elements of the SPS and the pilot test installation are briefly described in the following paragraph.
Analysis of Pressure Buildup in an Infinite Two-Layered Oil Reservoir Without Crossflow
Authors: Otuomagie Robert , Menzie D.E. 
Published: December 2007

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

Abstract
The purpose of this study is to obtain a set of expressions and procedures that can be used to determine the reservoir parameters from pressure buildup curves for an infinite pressure buildup curves for an infinite two-layered oil reservoir. Equations were derived that define the pressure behavior at the wellbore. Pressure drop equations were derived for the upper and lower zones using Hartsock's method. From these pressure drop equations, other equations were derived that describe theoretical buildup for this system when the well is shut in.
From these equations it is possible to determine the initial pressure of one zone the other initial pressure or the difference between the two initial pressures of the respective zones are known. The effective permeabilities can also be computed under the permeabilities can also be computed under the above conditions; that is, if the initial pressure in either zone is known or if the pressure in either zone is known or if the difference in pressure between the two zones is known.
Hartsock used only the pressure drop of the upper zone for these derivations and determinations, but this study shows that from the pressure drop and shut-in pressure equations, equations can be derived to determine the skin factors for the upper and lower zones. This study also shows under what conditions an infinite two-layered oil reservoir is similar to a single-layered reservoir.
Hartsock and Lefkovits et al. methods have been used to show the effects of permeability and thickness ratios on pressure buildup permeability and thickness ratios on pressure buildup curves. Also studied were the effects of skin and wellbore storage using the equations derived for an infinite two-layered reservoir with boundary conditions at the wellbore outlined by Lefkovits et al.

Introduction
The pressure buildup analysis considered in this study is that of an infinite two-layered reservoir without crossflow. So far, equations have not been developed to obtain the pressures, permeabilities and skin factors for the permeabilities and skin factors for the individual zones of two- or more-layered reservoirs.
Lefkovits et al. studied the behavior of bounded reservoirs composed of stratified layers. Their work showed that the time necessary to reach pseudo-steady state is much longer for a two-layer reservoir than for a single-layer reservoir.
A Unified Treatment of the Effects of Wellbore Storage and Variable Sandface Flowrate on Gas Well Drawdown and Buildup Analysis
Authors: Breit V.S. , Bishop K.A. , Swift G.W. 
Published: December 2007

This Paper is Subject to Correction
American Institute of Mining, Metallurgical, and Petroleum Engineers Inc.

Abstract
A unified method for analyzing drawdown and buildup data for permeability, non-Darcy coefficient, and skin factor is presented. The method account for wellbore storage and variable sandface flow rate. Drawdown/buildup data for two rates from an experimental reservoir are analyzed with this method. The parameters obtained from that analysis were used in a mathematical reservoir simulator to generate a pressure-time history which matched the experimental history within 3 psi over the test period, thereby demonstrating the compliance of the experimental reservoir with accepted principles of compressible fluid flow in porous principles of compressible fluid flow in porous media.

Introduction
For several years we have been performing drawdown and buildup experiments using an apparatus which is a physical analog of a gas reservoir with a single, centrally located, production well. Although care has been taken to preserve dimensional similarity between our "model" reservoir and a actual reservoir wherever possible, the model necessarily has a larger well storage volume/surface flow rate ratio than its real counterpart because the equipment for measuring pressure and rate, and the valves used on the model apparatus cannot be built to dimensional scale. Also, attempts to control the model reservoir flow rate have been thwarted because of the storage volume associated with the apparatus. Thus, to analyze the model drawdown and buildup data we must take particular care to correct the data for wellbore particular care to correct the data for wellbore storage and variable sandface rate effects and have developed a procedure for doing this. This procedure has utility for reducing field test data procedure has utility for reducing field test data as well as our experimental model data.
A number of papers have treated these effects-those of Ramey and Odeh and Jones cite most of the other relevant papers and present a good theoretical basis for the method presented here. Our paper unifies previous theory—presenting detailed procedures for properly analyzing drawdown and buildup data taken under variable flow rate conditions with appreciable wellbore storage present. The procedures are demonstrated by present. The procedures are demonstrated by applying them to data for two rates acquired from our experimental model. The values obtained for permeability and skin factor from this analysis permeability and skin factor from this analysis are used in a mathematical reservoir simulator to generate pressure-time histories for the experimental sandface rate-time history. Comparison of these computed pressure-time histories with those measured experimentally demonstrate the degree of compliance of the experimental reservoir with accepted principles of compressible fluid flow in porous media. porous media.
Logging Services Used for Large Diameter Boreholes
Authors: Atkinson Asher , Pointer Ralph 
Published: December 2007

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

Abstract
Logging of large-diameter boreholes for formation evaluation and as an aid to construction has become a routine procedure at the United States Energy Research and Development Administration (ERDA) Nevada Test Site. Many of these logging services are being used in commercial applications such as mine shaft construction. Log interpretation has been altered to account for conditions of 121-cm (48 in.) to 304-cm (120 in.) diameter boreholes, generally above the water table, and penetrating volcanic rocks. The methods are described and log examples and photographs of the borehole instruments are shown. Application of the data is discussed.

Introduction
The logging of large-diameter boreholes began in 1962, in the early stages of the Unite States AEC 's Underground Nuclear Testing Program, but was limited to modified caliper and temperature instruments. Other than that, logging data were gathered from 32-cm (12 1/2-in.) diameter exploratory boreholes, drilled at the location of, but prior to the large emplacement borehole. Standard logging instruments requiring large correction factors and the costs associated with the drilling of 32-cm (12 1/2 in.) exploratory boreholes gave impetus to the development of logging equipment especially designed for the large borehole environment.
This equipment is now being used to insure the integrity of commercial mine shafts being constructed for haulage, access, and ventilation purposes. Boreholes as large as 304 cm (120 in. purposes. Boreholes as large as 304 cm (120 in. in diameter have been logged to depths of 1,830 M (6,000 ft).

LARGE BOREHOLE LOGGING SERVICES
The data acquired from logging can be divided into two categories:properties of the borehole andproperties of the formation.
Borehole properties include:hole diameter and volume,borehole temperature,level and density of material in the annulus between the casing and the borehole wall during and after cementing,level and density of the material used inside the casing around the control cables for stemming to contain the nuclear event, andvarious repair operations in the borehole prior to using it for its designed purpose.
An Investigation of Wind Induced Load on Guyline Anchors
Authors: Hoyt Phillip M. 
Published: December 2007

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

ABSTRACT:
Most producing oil wells in the United States include guyline anchors to provide structural support for wind loaded service derricks. Recent safety regulations have focused attention on the load transferred to these anchors during high wind, but no definitive data has been available to establish precise requirements for such loading. In order to provide accurate and broadly acceptable data, a full scale field study was conducted on an actual servicing unit subject to severe wind. Load measured on the guyline anchors during the test indicate that there is less load on the guylines than standard criteria would predict. This result seems to be a singular property of oil well servicing units and is probably associated with both the flowfield around the derrick and the vertical velocity profile of the wind.

INTRODUCTION:
Standards for the strength of guyline anchors used in conjunction with oil well servicing operations have been a matter of considerable discussion and frequent controversy. In 1970, the adoption of regulations by the Wyoming Occupational Health and Safety Commission affecting Wyoming oilfields sparked considerable interest. In 1974, proposed expanded rules (later adopted in 1975) increased this interest to new proportions as the required capacity logically was made a function of anchor location. Various calculations produced diverse results, and the Wyoming standard was ultimately adopted to incorporate the highest of these values. A safe standard was thus assured, but the result was deemed to be overly conservative by oil producers who supply the anchors. With other states apparently ready to adopt similar standards, the time seemed appropriate for a definitive field study to establish the true value of anchor load through field testing. A cooperative effort by the Wyoming Occupational Health and Safety Commission and the Rocky Mountain Oil and Gas Association, under financial sponsorship of the latter organization, produced such a test. Many interesting factors associated with well servicing were quantified during the test, but by far the most interesting were the anchor loads themselves. These loads are the focus of the study.

TEST SITE:
The site chosen was the top of a low knoll on a relatively flat plain at Cooper Cove, approximately 35 miles northwest of Laramie, Wyoming.
Comparative Assessment of Natural Gas Hydrate Production Models
Authors: Sawyer W. K. , Boyer II C. M. , Frantz J. H. , Yost II A. B. 
Published: December 2007

Abstract
Methane hydrates represent a potentially enormous supply of natural gas, assuming the technology can be developed for commercial gas production from this reservoir type. An important part of this required technology is the development of mathematical models for predicting methane production rates for various field operational strategies. This paper presents a review and analysis of ten types of predictive models for gas hydrates. These models vary from simple energy balance models, to single-phase analytical porous-flow models, to robust three dimensional, three-phase numerical simulators. The models can be broadly classified into depressurization models, and thermal injection models. Each of the ten models focused on specific characteristics of the dissociation, migration, and production of methane from gas hydrates. The models are compared based on what we believe are necessary features for a full-featured hydrate simulator.
Relevant Time Update of an Earth Model with Logging While Drilling Data
Authors: Marshall G. , Holt J. , Winters W. , Evans S. 
Published: December 2007

Abstract
The drive for greater efficiency combined with the ever-increasing complexity of today's wells requires operators to search for improved methods of working. This has led to the introduction of better tools to facilitate data integration. The high costs of drilling in deep-water operations require that communications between disciplines be optimized. One way of ensuring that the latest information is being used across disciplines is to combine down-hole data with seismic interpretations on a "relevant time" basis. A flexible system has been developed which integrates real-time data capture and management tools with geoscience interpretation and well design software.
This paper illustrates gains that are possible in the well construction process through improved utilization of the available data from the wellbore and the rigsite. Two recent case studies are presented from the Deepwater Gulf of Mexico and West of Shetland, UKCS. Logging While Drilling (LWD) data were transmitted from down-hole to onshore, then into a shared earth seismic model on a "relevant time" basis. This data integration allowed the well operations team to make a significant correction to the planned casing point during the drilling of the Gulf of Mexico well by having a detailed correlation of the logging data to the seismic model used to plan the well. It is believed that this technique and related ones will yield further examples of operational efficiency through "relevant time" data integration. This project also illustrates the benefits of close collaboration between an E&P operating company and its vendors.