bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of Dispersion Factors on Slug Size for Miscible Displacement in Stratified Oil Reservoirs
Authors: Iqbal G. M. , Tiab D. 
Published: December 2007

ABSTRACT
This study investigates the performance of a miscible slug material injected in a heterogeneous reservoir of multiple layers of different characteristics. Considering the large number of stratified or fractured formations subjected to miscible flooding, the study focuses on the estimation of slug volume that would be required to efficiently recover oil from those type of media.
The study extends one dimensional dispersion equation (describing dissolution characteristics of a concentrated fluid in the reservoir) to a two-dimensional model by incorporating the phenomenon of transverse dispersion which causes fluid transfer normal to flow so far not considered in the existing methods.
The results are derived in terms of slug size, attainable oil recovery and slug concentration profile, based on varying characteristics of different layers in a stratified reservoir.
The study has demonstrated that miscible flooding conditions in a heterogeneous formation can be reasonably predicted by a set of equations representing different regional properties as well as the nature of inter-layer communication. Suitably applied, such models would effectively replace averaging techniques used to predict the performance of a slug in displacing oil from a reservoir having multiple regions of different porosity, permeability, and dispersion characteristics. Furthermore, inclusion of interlayer mass transfer terms like transverse dispersion coefficients in analyzing the effectiveness of a finite amount of slug material in stratified media is of prime importance, otherwise models considering longitudinal dispersion alone in such reservoirs tend to produce over-optimistic results. The reason is that the one-dimensional models do not consider degradation of slug transverse to flow direction, and introduce an error analogous to the assumption of negligible vertical permeability between communicating layers.
It was observed that flood performance would deviate significantly from what is expected in homogeneous formation if contrast in properties between two layers become large. Several correlation equations were developed for predicting: (1) percent sweep by any finite amount of solvent; (2) the sweep that can be achieved with varying degrees of critical concentration for a particular slug size; and (3) the slug size as a function of maximum recovery.
New Three-Phase Equilibrium Model (Oil/Gas/Brine) Used to Interpret Production of Liquid Hydrocarbons from a Geopressured Gas Well
Authors: Weres O. , Jun C. H. , Tsao L. 
Published: December 2007

ABSTRACT
Several of the design geopressured gas wells developed by the U.S. Department of Energy have produced small amounts of liquid hydrocarbons. At all wells, an unusual, aromatic gas condensate has been collected. This condensate differs dramatically from oil, containing predominantly light aromatic hydrocarbons, with subordinate cycloalkanes, branched alkanes, and normal alkanes. Two of the wells have also produced a paraffinic oil. We have analyzed hydrocarbon liquids produced from the Gladys McCall No. 1 well (Cameron Parish, Louisiana).
We have developed a computer program that models detailed phase relations in the system gas-oil-brine, and have used it to interpret the production of hydrocarbon liquids from Gladys McCall No. 1. We conclude that a single dispersed hydrocarbon phase was present within the producing formation, initially at some distance from the wellbore. The aromatic condensate represents the relatively water soluble hydrocarbons which dissolved in the brine. Prolonged production of brine from the well caused the hydrocarbon phase to move toward the well, ultimately leading to production of oil. Adsorption of of less volatile hydrocarbons on minerals and organic matter retarded their transport in the formation, producing some chromatographic separation of the hydrocarbons in the oil.
A Feasibility Study of Cyclic Steam Injection in a Deep Heavy Oil Reservoir in Western Venezuela
Authors: Colonomos P. 
Published: December 2007

ABSTRACT
A feasibility study of a cyclic-steam injection process on very deep wells based on numerical simulations, is presented. The Boscan field is located in the western part of Venezuela, it has been in production for over thirty years, has an average, depth of 8000 feet, an 00IP of over 20 MMMSTBN, an oil gravity of 10.5 °API, and the present pressure in the depleted area is about 800 psi.
In order to justify the process, which involves high costs mainly due to the price of the injection-string, numerical simulations of both the heat losses along the injection-well, and of the reservoir response to cyclic-steam injection were performed.
The feasibility of injecting a high-quality steam at the wellbore was performed with the use of a well simulator that includes the most relevant mechanisms of heat losses along the well. The heat losses along a 9000 feet well were lower than 10%, for the cases of practical interest. This makes the injection of a high quality steam with reasonable wellhead pressures, possible.
A single-well numerical simulation study, was carried out using a compositional thermal simulator. It involved a match of 28 years of production and pressure history under depletion-drive of a candidate well, followed by predictions of both cyclic-steam injection, and depletion. Results of these predictions show a good response of the field to cyclic-steam injection. The cycles tend to be very long (2-3 years), and the ratio of incremental oil – steam injected does not decay sharply with tile amount of steam injected. These two facts were considered important in this study, mainly because of the reduction of the operational costs per cycle.
Results of this study indicate the technical feasibility of the process in this very deep reservoir. Implementation of a pilot project, according to the recommendations of this study is under way.
A Unique Computer Simulation Model Well Drilling: Part II—The Drilling Model Evaluation
Authors: Reza M. R. , Alcocer C. F. 
Published: December 2007

ABSTRACT
A drilling model based on three dependent variables, the penetration rate, the bit dulling rate, and the bearing wear life; and twelve independent variables was developed. The model was evaluated by first deriving the unknown constants and exponents in the three equations through a linear regression analysis. The data for parametric evaluation was selected from published data on the Unit 2 Well #1 of the East Apache field. Reduction of the data over specific intervals provide the data base required to derive the three equation constants and the ten exponents. Further evaluation of the model involved sensitivity studies of the dependent variables with respect to each of ten independent variables. Each equation was partially differentiated with respect to one of the independent variables and evaluated over a range of values for the independent variables. The sensitivity for each dependent variable could then be compared to the independent variable being studied. Also, a comparison between the derived model and a widely used drilling model was done. It was concluded that the derived model yields more realistic results in terms of factors affecting the deep drilling process than the model compared in this study.
The Basic "K" Mud System: A Nontoxic Mud System Field Proven To Be Superior to Lignosulfonate Muds
Authors: Carney L. L. 
Published: December 2007

ABSTRACT
A new intermediate pH drilling fluid has been developed and field proven in over 400 wells. The results are amazing when compared to high pH drilling fluids containing such additives as lignosulfonates, starches, starch derivatives, oils, asphaltic materials, caustic soda, CMC, and hydrolyzed polyacrylamide polymers.
The new concept is based on knowledge generated under a D.O.E. contract for studying clay minerals and additives under conditions of high temperature and pressures. This new fluid does not use Wyoming bentonite as a primary viscosifier. It minimizes the use of sodium cations, while substituting the potassium cation (Basic "K") whenever possible, without. using hydroxides or chlorides of sodium or potassium while drilling potentially troublesome shales. Field data generated shows faster drilling rates, less shale problems, improved cement bonding, less permeability damage to reservoirs, reduction in hole washout, lower cement cost, and better logging interpretation.
The chemistry of the filtrate from the system is controlled by additions of formulated products, predesigned to eliminate harmful cations and anions being added. These predesigned products eliminate spot concentration of raw, harsh chemicals that would momentarily shock the pH of the borehole wall. The addition of these additives minimizes the costly shale problems during drilling and completion of oil and gas wells and eliminates formation damage from insitu precipitation of insolubles caused by co-mingling of fluids. The system is also temperature stable for use in drilling geothermal wells and deep, hot, gas wells.
The system has been formulated so that it is easy to run and maintain by the fluids engineer. By using his chemical titration of Pm, Pf, and Mf alkalinity values, which yield exact answers and are, therefore, better than relying on pH meters, pH papers, etc., the engineer's technical abilities are enhanced for maintaining the alkalinity of the system in a moderate range.
The products used to completely control the system do not contain heavy metals and are nontoxic. They can be used as soil conditioners and/or plant food. Fish kill tests in both salt and fresh water systems show that the systems have no toxicity. Therefore, not only is the ecology of the productive formations protected, but the effects on the surface can be classified as beneficial instead of detrimental.
Pressure Transient Response in Stress-Sensitive Formations
Authors: Pedrosa O. A. 
Published: December 2007

ABSTRACT
Pressure transient response in stress-sensitive formations is obtained by solving analytically the radial flow equation with pressure-dependent rock properties. In cracked rock systems and tight formations, hydraulic permeability is very sensitive to pore pressure change. The mathematical model presented in this paper takes into account the reduction in permeability caused by an increase in effective stress.
The dependence of permeability on pore pressure makes the flow equation strongly nonlinear. A perturbation technique is applied to determine approximate analytical solutions for transient flow in an infinite radial system with constant rate inner boundary. The model includes a new parameter, the permeability modulus, which measures the permeability dependency on pressure.
The solution of the model leads to the construction of type curves that can be applied to drawdown and buildup analysis of well test data from stress-sensitive reservoirs. Type curve matching provides a way to estimate initial permeability and permeability modulus. From buildup data, initial permeability may be obtained from the slope of the semi-log straight line on Horner plot, as shown in an example using field data from a low permeability gas reservoir.
Pressure Transient Analysis for Wells with Horizontal Drainholes
Authors: Clonts M. D. , Ramey H. J. 
Published: December 2007

Abstract
Drainholes have been drilled in several areas of the world and there is a need to understand these drainage systems for accurate well test analysis. This study presents an analytical solution for the transient pressure response of a uniform flux horizontal drainhole in an anisotropic reservoir of finite thickness. The solution also applies for a reservoir with multiple drainholes in a vertical array. The solution shows that there are two possible types of transient pressure behavior depending on the length of the drainhole relative to the height of the reservoir. If the drainhole is short, initial radial flow perpendicular to the drainhole axis is followed by a transition to a pseudo-radial flow period. If the drainhole length is long relative to the reservoir height, the initial radial flow period ends rapidly and transient pressure behavior becomes identical to that of a uniform flux vertical fracture.
The pressure transient response for multiple drainholes is identical to the single drainhole solution if dimensionless variables are defined relative to the number of drainholes. Consequently, the pressure response of a uniform flux vertical fracture can also be approximated by a vertical array of drainholes. The pressure response for infinite conductivity drainholes is also suggested by analogy to the infinite conductivity vertical fracture solution.
Log-log type curves are presented for various drainhole radii and can be used in the conventional manner to determine reservoir characteristics including directional permeability or drainhole half length. Short and long time approximations are presented along with appropriate time limits. Finally, conditions for greater productivity than with vertical wells or hydraulic fractures are presented.
Geostatistical Characterization and Comparison of Outcrop and Subsurface Facies: Shannon Shelf Sand Ridges
Authors: Tomutsa L. , Jackson S. R. , Szpakiewicz M. 
Published: December 2007

ABSTRACT
Permeability and porosity data from outcrop measurements and subsurface cores have been analyzed for geostatistical similarities and differences. The formation is the Shannon in the Powder River basin, and we compare an outcrop of the Salt Creek Anticline with Teapot Dome reservoir (5 mi away and at 300 ft depth) and with Hartzog Draw field (40 mi away and at 9000 ft depth). The emphasis is on quantitative geological comparisons, and how the results can improve reservoir characterization. The tools used here to characterize and compare two separate facies from three different occurences of shelf sand ridge deposits are: (1) distribution functions, (2) variograms (correlation length), and (3) log permeability versus porosity plots. Results include: first, a remarkable agreement in permeability distributions for the High Energy Ridge Margin (HERM) facies in the outcrop and Teapot Dome reservoir, even though the porosities are lower in the subsurface by 4 percentage points on average. The permeability agreement is remarkable because the outcrop and subsurface correspond to different depositional events (upper and lower Shannon, respectively). Second, the distribution functions for permeability and porosity in Hartzog Draw are shifted to substantially lower values than those in the outcrop. Third, correlation lengths which characterize the vertical variability are short (usually a few feet). In the lateral direction the correlation lengths could be longer, but are still probably less than 10 ft. Fourth, four separate zones are found to comprise the 9 foot thick HERM facies in the outcrop, and each has a characteristic permeability distribution. Furthermore, large lateral permeability fluctuations (factor of 100) in a 1-ft thick zone are attributed to the variability of glauconite-rich layers. The overall permeability distribution agreement between outcrop and Teapot Dome mentioned above suggests using permeability distributions obtained from outcrop measurements to improve the reservoir modeling in Teapot Dome.
Drilling on Forest Lands
Authors: Penn B. G. 
Published: December 2007

Abstract
The United States is comprised of approximately 2.3 billion acres. Of this, 737.7 million acres, nearly one-third (1/3), are controlled by the federal government. In the western states, there is a predominance of federal land; Wyoming is nearly 50%, Nevada is 85%, Montana is 29%, Colorado is 36%, and Idaho is 65%. The Forest Service is responsible for management of an estimated 151.8 million acres in the Rockies. of this remaining total, 43.7 million acres are withdrawn from mineral entry for leasable minerals. These areas are the designated wilderness areas and study areas set aside by the agencies and Congress through the 1964 Wilderness Act as well as State Wilderness Acts recently passed or proposed. The withdrawal of lands for wilderness designation proposed. The withdrawal of lands for wilderness designation amounts to 29% of the Forest land in the Rockies. The industry has taken a closer look at these areas for their oil and gas potential even though they are sometimes more environmentally sensitive and, therefore, more costly.
The exploration process, in my opinion, is driven by economics. Generally, the economics of dealing with the Forest Service and leaving established basin production didn't exist until the late 1970's, with exceptions. Higher prices and stiffer competition resulted in an expansion out of the basins.
I would like to talk about the additional requirements put on oil companies to drill in some of these Forest Lands where the potential for oil and gas exists. I would like to show several potential for oil and gas exists. I would like to show several examples of the permitting delays that have been encountered and some of the common stumbling blocks. Additionally, I have some examples of exploration in sensitive environments to illustrate the compatibility of oil and gas operations in sensitive environments.
Preliminary Studies Leading to Microbial Enhanced Oil Recovery
Authors: Anderson D. L. , Sarver A. Q. , Chin Y. H. , Honarpour M. M. 
Published: December 2007

ABSTRACT
Increased costs in exploring and developing frontier areas have resulted in greater emphasis in enhanced oil recovery methods. Since the location is known and most of the field equipment and the facilities are in place, microbes will enhance the recovery.
An average of seventy percent of reservoir oil is left after secondary and primary recovery. Therefore, developing effective oil recovery methods to produce the trapped oil enhances the project scope. All conventional chemical flooding methods are expensive. In contrast, microbial enhanced oil recovery (MEOR) involves injecting a small amount of microorganisms in solution to propagate through the reservoir and subsequently produce desirable chemicals. and gases that will enhance oil recovery and therefore profit.
Case History: Water Shutoff Treatment in the Phosphoria Formation, Hot Springs County, Wyoming
Authors: Olsen E. H. 
Published: December 2007

ABSTRACT
Polymer water shut-off treatments have been successful in the past for the purpose of increasing oil production and decreasing water production in problem wells. The results of applying a polymer water shutoff treatment to a well producing form the Phosphoria Formation in Hot Springs County, Wyoming, are presented in this paper. This water shut-off treatment represents an effective low-cost method for enhancing oil production in wells which have severe water production problems. The proper application of this technology can result in a significant amount of incremental oil production and a corresponding decrease in water production.
The specific well in this study was completed in the Phosphoria Formation with an initial producing rate of 216 barrels of oil per day. Within six months, the well was making 30 barrels of oil and 900 barrels of water daily. From this point, the oil production declined to 6 barrels per day after a period of two years and the water production remained nearly constant at 900 barrels per day.
A polymer water shut-off treatment, was performed on the well; after which, the oil production increased to 82 barrels per day and the water production decreased to 180 barrels per day. The expense of the treatment paid out in nearly two months, and after seven months the well was producing 13 barrels of oil and 200 barrels of water per day. The successful result of this treatment indicates the viability of polymer water shut-off treatments as low cost enhanced oil projects.
Cost-Effective Paraffin Inhibitor Squeezes Can Improve Production Economics
Authors: Haynes H. H. , Lenderman G. L. 
Published: December 2007

ABSTRACT
The formation of paraffin downhole or in surface equipment can significantly reduce or stop production. During winter months, when paraffin problems are at their worst, many paraffin chemicals are difficult to apply due to their high pour points. A method of squeezing paraffin inhibitor into the producing formation so that it will feed back over a long period of time may provide an effective solution to this problem.
Electric Submersible Pump Cable Designed for Rugged, High-Temperature Service in Wells with High Concentrations of H2S
Authors: Neuroth D. H. 
Published: December 2007

ABSTRACT
Artificial lift is becoming increasingly important to the economical production of deep, high water-cut production fluids. As manufacturers extend the operating life of pumps and motors, improved performance is required of ESP cables. This is particularly true in hot, sour wells with high concentrations of H2S gas.
This paper describes a new ESP cable specifically designed to operate in the severest hot, high pressure, high H2S environments. The mechanisms by which high concentrations of H2S attack pump cable are explored. How new cable technology can extend cable life in H2S environments is explained. Actual field results in a 20% H2S well are discussed and related to cable design theory.
Operators considering ESP artificial lift in severe-service H2S wells will benefit from the information in this paper. Supportive documentation of lab tests and field experience is included.
Travis Peak: An Integrated Approach to Formation Evaluation
Authors: Howard W. E. , Hunt E. R. 
Published: December 2007

ABSTRACT
The low porosity, low permeability sands of the Travis Peak (Hosston) of east Texas and north Louisiana are typical examples of tight gas sand reservoirs which may contain significant amounts of natural gas. Evaluation of such tight gas sands by traditional methods, including the interpretation of wireline logging measurements, has frequently proven inadequate in evaluating the parameters essential to the determination of the economic potential of such reservoirs.
A cooperative well program has been developed between the Gas Research Institute (Chicago, Illinois) and several operators in the east Texas, north Louisiana area. Each well is selected based on geologic, economic and engineering factors. Wells selected establish core points before drilling and take approximately two hundred feet of core. Core measurements include routine porosity, permeability, and grain density. Special core analysis includes restored state permeability, porosity, cementation exponent, saturation exponents, Dean Stark water saturations, elastic moduli, cation exchange capacity, and compressional and shear velocities. Routine analysis is performed over each foot of core. Special core analysis is performed on approximately fifty plugs.
Logging services include dual induction spherically focused, long spaced sonic, litho-density, compensated neutron, electromagnetic propagation, micro-log, natural gamma ray spectroscopy, induced gamma ray spectroscopy, and stratigraphic high resolution dipmeter.
Four wells to date have been included in this cooperative well program. Interpretation models based on the integration of petrographic thin section point count, routine and special core analysis, and wireline log data have been developed. An example of the methodology is presented for the evaluation the Clayton Williams, Sam Hughes, #1 well. These models are routinely used for the evaluation of tight gas sand wells in east Texas.
The models employ a simultaneous solution of linear equations based on porosity log response for lithology, a dual water method for water saturations, and a shale corrected crossplot technique for porosity computation. The Waxman-Smits saturation model is explored as well as a method to determine fluid density from the electromagnetic propagation tool. A method for reconstruction of invalid density data based on gamma ray and sonic log response provides necessary corrections to input data. Results are evaluated and compared to core analysis measurements.