bluuebunny/crossref_metadata_2025_split huggingface dataset:
Opportunities for Petroleum Engineers in Overseas Work
Authors: McCobb H.W. 
Published: December 2007

"Wanted, for overseas operations-switchers-with-their-brains-knocked-out." That's roustabout talk for petroleum engineers. While tinged with sarcasm, the men who work around drilling rigs pack a world of respect into the description.
Today, with more and more U. S. oil companies staking their future on foreign operations, there is an increasing demand for top petroleum engineers. The dynamic growth of foreign markets in recent years is the basic reason for increasing overseas participation. This sets off a chain reaction of competition in the already highly competitive oil industry. In the scramble for a share of the "market", companies compete for the best petroleum engineers while the engineers compete with each other for the desirable posts.
While this may sound like the promised land to both newly graduated as well as experienced petroleum engineers, it is not entirely a land of milk and honey.

The Overseas Outlook
Just what is the present outlook for petroleum engineers in overseas operations? Latest available figures show that some 150 oil companies are engaged in about 400 separate operations in 73 of the countries spread around the world. This is about double what it was some five years ago and would indicate a heavy demand for petroleum engineers. The demand ratio shrinks rapidly, however, because more of the opportunities are with relatively small companies just entering the foreign field than with the majors having long-established operations.
The demand is further whittled by restrictions, and understandable ones, placed on operations by the governments of the host countries. Just as we are desirous of opportunities for our nationals in the U. S., the governments of other countries want to assure technical development of their people. Consequently, the ratio of U. S. expatriates to foreign nationals is relatively small. The ratio will continue to shrink each year as more people of other nations are trained in such a technical field.
The world-wide business recession which plagued us for a year and a half also cut into the demand for petroleum engineers overseas. Happily, this now appears to be on the wane.
State-of-the-Art Summary for Underground Coal Gasification
Authors: Davis B.E. , Jennings J.W. 
Published: December 2007

Distinguished Author Seriesarticles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleum engineering.

Introduction

Process Chemistry
Underground coal gasification Process Chemistry. Underground coal gasification (UCG) process chemistry has been studied extensively through physical and mathematical simulations. The basic chemistryis the same as for surface gasifiers although the reaction sequences arc lesswell defined. The primary reactions include:
Oxidation: C + O2 = CO2 + 94.05 kcal/mol 2C+01=2CO + 26.42 kcal/mol
Gasification:
C+H2O=CO+H,-31.4 kcal/mol C+Co2 =2CO - 41.2 kcal/mol
Pyrolysis: Pyrolysis: coal+heat=char+tar+water+gases
Secondary reactions involving, gasification products include:
Water gas shift:
CO + H2O=CO,+H,+9.8 kcal/mol
Methanation:
C + 2H2 = CH4 + 17.9 kcal/mol CO + 3H2 =CH4 + H4O + 49.3 kcal/mol 2CO + 2H2 =CH4 + C + CO2 + 59.0 kcal/mol
During the process all of these reactions can contribute to the finalproduct composition. Both thermodynamic and kinetic effects are significant. Residence times and temperature gradients in the reactor determine the degreeto which these effects are significant for a given coal seam.

Process Mechanics
Three distinctively different Process Mechanics. Three distinctively different activities must be completed to ensure a successful UCGoperation.Preparation of the process reactor. This includes selection anddetailed characterization of the geologic domain that will be affected by theprocess, as well as installation of process wells and preparation of the seamfor gasification.Gasification of the coal. This entails in-situ conversionof the coal to a gaseous mixture of CO, CO2, H2, CH4, and higher-molecular-weight compounds. The operation should be maintained so thatinflux of boundary strata and water and loss of product gas are minimal. product gas are minimal.Site restoration. Before a site can be abandoned, restoration of the facility to its original-use value must be demonstrated. After an acceptable site is chosen the process reactor is installed by drilling two wells into process reactor is installed by drilling two wells into the coatseam and establishing a highly permeable zone or link between the well pair. Wells should be completed into the lower third of the coal seam.
JPT
P. 15
Development and Field Use of a High-Frequency Gas-Operated Rotary-Percussion Drilling Tool
Authors: Howard G.C. , Vincent R.P. , Wilder L.B. 
Published: December 2007

Abstract
A successful air or gas-operated percussion tool has been developed and used in drilling nine wells - one each in New Mexico, Utah and Montana; five in Wyoming; and one in Alberta, Canada. Penetration rates with the percussion tool in these wells have averaged 2.5 times faster than those obtained with rotary gas drilling and approximately 5 times greater than rotary mud drilling. Laboratory and field tests indicate that bit footages with rotary-percussion drilling have averaged 1.3 to 4 times those observed with conventional air rotary. Evaluation of laboratory drilling tests and field results shows that, where air drilling is economical, the percussion tool should be used to further decrease well costs. The additional savings should increase the number of wells in which it is profitable to drill with air instead of with liquid-base drilling fluids.

Introduction
Holes have been drilled in the earth for centuries by variations in the cable tool or churn drilling method. With this percussive method, a heavy steel bit suspended on a cable is dropped a few feet onto the bottom of the well where the bit's kinetic energy is used to chip and crush the formations. The rotary drilling system, introduced to the oil industry around 1900, drilled faster and cheaper than cable tool drilling for most wells. With the development of roller rock bits, rotary drilling gained widespread use in all areas.
In an effort to further speed rotary drilling, air was substituted for liquid as the drilling fluid on an experimental basis on several wells in the early 1950's. Air drilling resulted in faster penetration, greater footage per bit, alleviation of lost circulation problems and lower drilling costs. As a result, at the present time air or gas drilling is a routine procedure in parts of Arkansas, Pennsylvania, West Texas and the San Juan basin. The biggest deterrent to widespread use of air drilling has been the water control problem, but, as solutions to this problem are perfected, the scope of rotary air drilling will undoubtedly grow.
Permeability of Idealized Fractured Rock
Authors: Parsons R.W. 
Published: December 2007

Abstract
The over-all apparent single-phase permeability of fracture-rock systems was studied using two different two-dimensional models. In a strict sense the results are applicable only to these models, yet may give some insight into real reservoir behavior.
The regular fracture-matrix model can have any number of regular fracture sets. All fractures within each set have the same orientation, width and spacing. The gross behavior is analytically equivalent to that of an anisotropic permeable medium.
In the heterogeneous fracture systems, individual fracture conductivities vary within a two-dimensional network pattern. A computer program calculates the overall permeability after the conductivities are randomly placed in the network. The calculated permeability depends upon the distribution of these conductivities and the particular fracture pattern into which they are placed.
Although detailed information on actual reservoir fracture systems is not available, this study shows bow some of the possible variables may affect observed gross reservoir characteristics.

INTRODUCTION
Characteristics of reservoir rocks are determined by direct (core analysis) or indirect (logging and production tests) examination. Both methods, singly and together, are widely used in reservoir evaluations. For fractured reservoirs a problem exists in relating characteristics of cores to the in situ reservoir properties. Knowing fracture characteristics can be of value in determining production mechanisms. Because of the limitations of observation, the intimate details of a fractured rock system will never be known. One approach in analyzing fractures is to study the behavior of some conceptually simple models.
The two models analyzed contain features which may be realistic, yet are mathematically tractable. Flow is considered in two dimensions only, with the plane of interest at right angles with the fractures. This concept represents the horizontal flow in a reservoir system with the fractures oriented vertically. Only single-phase, laminar flow is considered. The regular fracture-rock system permeability is calculable from a simple analytical expression. The heterogeneous system requires a computer program for calculating overall permeability.

FLOW IN A SINGLE FRACTURE
Fluid flow in a single fracture is assumed equal to laminar flow between two infinite parallel smooth plates. This is expressed as:1Equations 1 and 2
Turbulent flow in fractured reservoirs is quite unlikely. As with flow in circular pipes, a Reynolds number can be defined to characterize the flow regime (2Wv?/µ). Values of this dimensionless group at the- onset of the transition to turbulent flow vary from 1,800 to 4,000, depending on the reference.1-3 Surface roughness on the fracture faces lowers this number.2-4
Polymer Retention and Adsorption in the Flow of Polymer Solutions Through Porous Media
Authors: Cohen Yoram , Christ F. R. 
Published: December 2007

Summary
A new experimental technique based on a surface treatment process was developed for determining mobility reduction as a result of polymer adsorption in flow of polymer solutions through porous media. The experimental method also allowed the direct determination of adsorptive and nonadsorptive polymer retention from flow experiments.
The adsorptive mobility reduction for the flow of polyacrylamide (J333™) mobility control polymer through silica sand was found to be as high as 14% at the lowest experimental stress level of 3.75 dynes/cm2 [0.375 Pa]. This corresponded to an effective hydrodynamic thickness (EHT) of the adsorbed polymer layer of 0.57 μm. Both the mobility reduction and the EHT decreased with an increase in shear stress. The amount of adsorptive polymer retention accounted for about 35.2% of the total retained polymer.
Laboratory Investigation of High-Temperature Surfactant Flooding
Authors: Ziegler V. M. 
Published: December 2007

SummaryExperiments were conducted to evaluate the use of surfactants for improving heavy-oil recovery from the hot-water zone in a steamflood. Criteria used to screen surfactants for this high-temperature application included thermal stability, interfacial activity, and surfactant flood performance.The thermal stabilities of several classes of sulfonate surfactants were measured. Surfactants exhibiting no thermal decomposition at elevated temperature (500°F [260°C]) were identified.The phase behavior between heavy crude oil (14.5°API [0.969 g/cm3]) and surfactant solution was determined over a temperature range from 150 to 350°F [65 to 177°C]. Regions of high interfacial activity were generated by the addition of salt to the brine phase. Interfacial tension (IFT) measurements confirmed the high salinity requirement of the selected surfactant/brine/oil system at elevated temperature.High-temperature (200 to 350°F [93 to 177°C]) surfactant floods were performed to study the effect of several variables on tertiary oil recovery. Variables studied included preflush slug size, surfactant slug size, surfactant concentration, flood temperature, core material, and mobility control. Improved oil recovery was obtained when a salinity-gradient flood design was used. For the most favorable systems, incremental oil recoveries up to 14% PV were achieved.Estimates of field performance indicate an 8 to 32% increase in oil recovery when surfactant is used with steam.
Further Investigation of High-Temperature Alkaline Floods
Authors: Medizade Mason M. , Handy L. L. 
Published: December 2007

Summary
Effectiveness of alkalies, such as NaOH, Na2SiO3, and Na2CO3, to recover residual oil during hot waterfloods (356°F [180°C]) was investigated and compared. These alkalies, with or without surfactants, may be added to steam to enhance oil recovery from that portion of the reservoir subjected to a hot waterflood during steam injection. Tertiary flood rate and concentration of the injected alkalies were changed and their corresponding effects on recovery efficiency, WOR, recovery mechanism, and alkali consumption were studied. Some lower-temperature floods were also performed with caustic. Dynamic interfacial tensions (IFT's) between the acidic crude oil and the alkaline solutions at different pH's were measured at elevated temperatures up to 356°F [180°C] with a drop-weight technique. For some alkalies (e.g., NaOH), the effects of salt and surfactant addition were also investigated.
The results show that dynamic IFT's between the acidic crude oil and the alkaline solutions increase with increase in temperature. At high temperatures, IFT values at low pH approach values obtained for distilled water. This is more pronounced for caustic than for sodium metasilicate and sodium carbonate. The same IFT values obtained for caustic at elevated temperatures can be obtained with sodium carbonate and sodium metasilicate at a lower solution pH. Although IFT and alkali consumption increase with an increase in temperature, recovery efficiencies obtained at high temperatures were comparable with those obtained at lower temperatures. This could result from ease in flow of emulsions at high temperature. Recovery efficiencies obtained with sodium metasilicate at 356°F [180°C] were higher than those for sodium carbonate and sodium hydroxide. These recoveries took place at IFT values as high as 1 dyne/cm [1 mN/m]. Oil was always recovered with the injected chemicals, and no significant oil bank was formed.
New Kinetic Models for Thermal Cracking of Crude Oils in In-Situ Combustion Processes
Authors: Lin C. Y. , Chen W. H. , Culham W. E. 
Published: December 2007

Summary
This paper presents two kinetic models for representing the thermal cracking of crude oils, which incorporate the cracking rate parameters and stoichiometric coefficients to correlate experimental data. The models presented show that the first-order kinetics generally accepted for pure components are unsatisfactory for multicomponent systems characterized by pseudocomponents. We conclude that three corrections to the existing first-order model are needed for modeling thermal cracking of mixtures. First, the apparent reaction order is always greater than one. Second, the reaction order is a decreasing function of temperature. Third, coke may also be formed from intermediate products. These corrections are incorporated into the models.
In the first model, crude oil is split into two pseudocomponents, while in the second model, crude oil is represented by three pseudocomponents. The models can be easily extended to any number of pseudocomponents.
The models successfully correlated experimental data of four systems available in the literature. Furthermore, it was confirmed that coke is not always the sole source of the fuel burned in an in-situ combustion process.
Well Testing and Analysis Techniques for Layered Reservoirs
Authors: Kucuk F. , Karakas M. , Ayestaran L. 
Published: December 2007

Summary
This paper presents new testing and analysis techniques to obtain individual-layer permeabilities and skin factors for layered reservoirs. The new multilayer testing technique consists of a number of sequential flow tests with a production logging tool that simultaneously measures the wellbore pressure and flow rate at the top of each layer.
Two different analysis techniques are presented to estimate layer parameters. The first technique, which is the logarithmic convolution method, estimates the approximate values of parameters. The second technique, which is the nonlinear least-squares estimation method, improves the first estimates.
It is shown that layer permeabilities and skin factors can be estimated uniquely from simultaneously measured wellbore pressure and flow-rate data that are acquired from all layers sequentially. It is also shown that these individual-layer parameters cannot be estimated from the conventional drawdown- or buildup-test wellbore pressure data. Several synthetic examples are presented to illustrate the application of multilayer testing and analysis techniques.
Effect of Fluid, Confining Pressure, and Temperature on Absolute Permeabilities of Low- Permeability Sandstones
Authors: Wei K. K. , Morrow N. R. , Brower K. R. 
Published: December 2007

Summary
The combined effect of temperature, confining pressure, and test fluid on absolute permeabilities of low-permeability sandstones has been investigated. Absolute permeabilities to liquids were dependent on polarity but were always significantly less than Klinkenberg permeabilities for gases. Differences are ascribed to swelling and dispersion of fine particles. Changes in state of dispersion caused by ultrasonication were investigated by measurement of resulting changes in permeabilities. Nitrogen, brine, and distilled water were used as test fluids in a main series of tests for which temperatures ranged from 0 to 93°C [32 to 199°F] and confining pressures from 3.45 to 34.47 MPa [500 to 5,000 psi]. Absolute permeabilities of five formation samples of various origins differed by up to three orders of magnitude, with the highest permeability being a few millidarcies. All specimens showed marked reduction in permeability with increase in confining pressure. For all cores, however, absolute permeabilities to gas were essentially independent of temperature at all levels of confining pressure. Comparable measurements of brine permeability were made for two core samples and, as with gas flow results, no significant temperature effect was found. Klinkenberg slip factors, B, were found to vary linearly with absolute temperature, but gave positive intercepts on the temperature axis of B vs. T plots. The intercepts were larger for gases of higher boiling point. This deviation is shown to be mainly a result of the nonideal effect of temperature on gas viscosities.
Geology Drilling Log—A Computer Database System for Drilling Simulation
Authors: Onyia E. C. 
Published: December 2007

SummaryDramatic developments have occurred during this decade in the applications of computer simulation in drilling. Our high-fidelity Engineering Simulator for Drilling (ESD) has the distinctive capability to permit an operator to simulate drilling in different geographic locations using actual drilling and geologic data for that environment. The Geology Drilling Log (GDL) is a data base used by the ESD that not only gives the ESD the flexibility described, but also allows us to describe in sufficient details the properties of the rocks through which we drill. Engineering models and other simulation activities pool information from a GDL during simulation. This paper discusses the technique used to build a GDL and illustrates the steps necessary to build a similar data base for other drilling simulators.
Reservoir Sizing Using Inert and Chemically Reacting Tracers
Authors: Robinson Bruce A. , Tester Jefferson W. , Brown Lee F. 
Published: December 2007

Summary
Nonreactive tracer tests in prototype hot, dry rock (HDR) geothermal reservoirs indicate multiple fracture flow paths that show increases in volume as a result of energy extraction. Tracer modal volumes can be correlated with estimated reservoir heat-transfer capacity. Chemically reactive tracers are proposed that will map the rate of advance of the cooled region of an HDR reservoir, providing advanced warning of thermal drawdown. Critical parameters are examined with a simplified reservoir model for screening purposes. Hydrolysis reactions are a promising class of reactions for reservoir temperatures ranging from 80 to 2OO°C [176 to 392°F]
The Effects of Salt, Gas, Temperature, and Pressure on the Compressibility of Water
Authors: Osif Terry L. 
Published: December 2007

Summary
Laboratory measurements of compressibilities are presented that show that plots of the reciprocal of compressibility vs. pressure are linear for water and brines. The slopes of these plots are all the same, but the intercepts are linearly dependent on the temperature and salinity over the range of conditions studied (1,000 to 20,000 psi [6.9 to 138 MPa], 200 to 270°F [93.3 to 132°C], and 0 to 200 g/L). Dissolved gas has no effect on these compressibilities at gas/water ratios (GWR’s) of 13 scf/bbl [2.3 std m3/m3]. Even at GWR’s of 35 scf/bbl [6.3 std m3/m3], dissolved gas probably has no effect, but certainly causes no more than a 5% increase in the compressibility of brine.
Characteristics of a Retrograde Condensate Reservoir Containing a Large Quantity of Carbon Dioxide
Authors: Bauman W.E. , Miles F.V. 
Published: December 2007

Introduction
The literature possesses limited data on reservoirs containing an appreciable quantity of carbon dioxide. The primary purpose of this paper is to present the fluid characteristics of a retrograde condensate system containing approximately 92 per cent carbon dioxide. The text includes the basic PVT studies as well as a discussion of surface separation equipment and problems associated with testing and producing the reservoir. Included also are geological and engineering characteristics of the reservoir and a review of corrosion problems.

General Description of Area
About eight miles northeast of Walden, Colo., in the North Park basin, there are at present four commercial oil fields producing from the Muddy, Dakota, Lakota and Morrison sands of Cretaceous age. These fields are not very significant in size, but each field is on a separate anticlinal structure, and the apparent variation in the nature of their reservoir fluids is quite unusual. Fig. 1 is a map of the area showing the four producing fields. The average elevation of this general area is 8,200 ft. This discussion will deal with the most recently discovered area situated in the South McCallum field, which produces condensate with a large quantity of carbon dioxide from the Muddy, Dakota and Lakota sands. The reservoir fluid is 92 per cent CO2, 3 per cent nitrogen and 5 per cent hydrocarbons.
This area, more specifically referred to as the Ballinger-Federal, was discovered in Oct., 1958 with the completion of Gulf Oil Corp.'s Ballinger-Federal No. 1, C-SW-SE Section 8–9N–78W, Jackson County, Colo., for a calculated absolute potential of 39,400 Mcf of CO2 and 542 B/D of 480 gravity condensate. The condensate is an almost clear liquid with a light golden color. A second well was completed in Dec., 1958 for a calculated absolute potential of 101 MMcf of CO2 and 1,390 B/D condensate. The produced GOR initially was approximately 72, - 600 cu ft/bbl. Both wells tested water in the Morrison sand at the approximate depth of 5,400 ft and are completed in the Muddy, Dakota and Lakota sands between 4,980 and 5,345 ft. Production from the three sands is commingled in the wellbore. The two wells are presently being produced at the rate of 200 B/D each.