bluuebunny/crossref_metadata_2025 huggingface dataset:
Effect of Ultrasonic Irradiation on Coalescense and Separation of Crude Oil-Water Emulsions
Authors: Schoeppel R.J. , Howard A.W.
Published: December 2007

This paper was prepared for the 41st Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Dallas, Tex., Oct. 2–5, 1966. 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 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.

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.

The coalescing and separating tendencies of untreated and treated crude oil-water emulsions when exposed to ultrasonic treatment are experimentally investigated. Combined ultrasonic and chemical treatment greatly increased separation efficiency over chemical treatment exposed only to low-frequency mechanical agitation. Both short- and long-duration ultrasonic irradiations were effective in producing coagulation: the rate of separation increased as much as 700-fold over natural settling rates.

The ultrasonic treatment technique offers a potentially practical method of improving natural oil-water coalescence and separation while simultaneously decreasing chemical requirements.

Introduction

One of the recurring problems which has bontinually plagued the oil industry is separation of water produced with oil. The significance of this problem is shown by an estimated 15 to 20 million dollars expended for chemicals each year to treat the world's oil production. This expense does not include costs for handling the demulsifier, injection equipment, heater fuel, etc.

Current methods of treating oil-water emulsions utilize natural settling, chemical dehydration, and/or electrical dehydration techniques to effect separation. Sonic energy may be used to cause either agglomeration or dispersion of immiscible liquids, depending upon frequency, wave energy, geometry, etc. A detailed literature survey revealed that, while a considerable amount of work has been done on sonic vibration as a coagulating force in aerosols and dust-gas systems, relatively little has been published on the use of this same force in separation of immiscible liquid systems. It is the purpose of this paper to present the results of an experimental investigation showing the capability of ultrasonic treatment to increase the rate of coalescence and settling of naturally occurring crude oil-water emulsions and increase the rate of dispersion of chemical demulsifying agents.
A Model for Prediction of Recovery and Pressure History for 2-D Displacement of Oil Through Porous Media by Gas/Surfactant
Authors: Mahmood S. M. , Tariq S. M. , Brigham W. E.
Published: December 2007

The problem of predicting recovery and pressure behavior during gas/surfactant solution flooding is too complex to be treated analytically with the current state of knowledge. In the early stages of such displacements, the gas and surfactants are macroscopically dissociated and segregated, each flowing in separate channels. The in situ generation of foam does not seem to initiate until a certain mass of surfactant has been injected. Frontal advance theories such as the Buckley-Leverett theory or the Dietz model assume the injected fluid to be single phase, homogeneous, and non-reactive. Since these criteria are not met by the flow of gas and surfactant solution, these theories fail to accurately predict the recovery performance of such displacements.

Based on the observations made during a series of experiments on a scaled-model, a semi-analytical model is proposed to predict the oil recovery and pressure history from two-dimensional (x,z) systems undergoing gas/surfactant injection. The model is based on the concept of a combination flood, in which gas/foam and surfactant solution flow in separate gravity tongues. The gas/foam displacement is assumed to follow the Buckley Leverett theory, whereas the surfactant displacement follows the Dietz model. The displacements through these tongues are mutually dependent and, therefore, these theories are combined at each stage. The predictions from the model gave a good match with the experimental results for a fairly broad range of operating conditions. The semi-analytical approach adopted in developing the combination drive model has potential for application to certain other types of frontal behaviors.
Effect of Dispersion Factors on Slug Size for Miscible Displacement in Stratified Oil Reservoirs
Authors: Iqbal G. M. , Tiab D.
Published: December 2007

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

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

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

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

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

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

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

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

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

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

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

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

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

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.
A Critical Evaluation of Recovery Deformation Measurements as a Means of In-Situ Stress Determination
Authors: Blanton T. L. , Teufel L. W.
Published: December 2007

The recovery strain method of stress determination involves a number of assumptions and idealizations that raise questions about its general applicability. Issues of particular concern are gradual removal of stresses during core retrieval, the effect of pore pressure and temperature, working with deviated wells, and observed expansions and contractions in the same core. A procedure is outlined that takes into account the effects of pore pressure, temperature, and anisotropies in the core and can be applied to core from deviated wells by making measurements on appropriate axes. Equations derived in this study for calculating stresses from recovery strains include the effect of gradual unloading experienced by core during its retrieval. Application of the equations to field data show that the effect of gradual unloading is small in most cases but can be significant under certain conditions. One particularly interesting result of the theoretical analysis is that for high Poisson's ratios and deviatoric stresses, core will actually contract. Favorable comparisons of stresses determined by the recovery strain method to those obtained from hydraulic fracturing and overcoring at sites in Colorado, Oklahoma, Nevada, and the North Sea support the practicality of this method.
Design Formulae for 2-D and 3-D Vertical Hydraulic Fractures: Model Comparison and Parametric Studies
Authors: Meyer B. R.
Published: December 2007

This paper presents asymtotic analytical and numerical solutions for two-dimensional (2-D) and three-dimensional (3-D) type hydraulic fracture geometries. The fracture propagation models investigated include: a Geertsma-Deklerk (GDK), a Perkins-Kern/Nordgren (PKN) and a 3-D type model.

Comprehensive 2-D and 3-D design formulae for power-law fracturing fluids are given for various cases of fluid loss and containment. These formulae can be used to benchmark 2-D and 3-D hydraulic fracturing simulators. Characteristics of equilibrium 3-D height growth are also discussed. Parametric studies based on the design formulae are performed to show the effect of any one variable.

Typical fracture designs are simulated for various containment and leak-off examples using each of the fracture propagation models, along with a comparison of proppant scheduling and design. The simulation studies identify and illustrate the basic characteristics and design differences of each model.
Laboratory Studies for the Design and Analysis of Hydraulic Fractured Stimulations in Lenticular, Tight Gas Reservoirs
Authors: Sattler A. R. , Hudson P. J. , Raible C. J. , Gall B. L. , Maloney D. R.
Published: December 2007

Laboratory studies were used as an aid in designing stimulation treatments and to assist in the analysis of production results. These analyses were done in conjunction with coastal zone stimulation operations at the Department of Energy's Multiwell Experiment near Rifle, Colorado. A multitreatment stimulation plan was designed for the coastal zone because of apparent damage to the paludal zone formations in prior stimulation operations. The stimulation plan was made to minimize the use of water-based, gelled fluids. Two small stimulations were performed in the same coastal interval: an unpropped nitrogen gas frac and a propped, nitrogen foam frac. Gas production decreased from that of the gas frac after the nitrogen foam stimulation and formation damage was apparent. The laboratory program was used to (1) aid stimulation design; (2) help eliminate several possible causes of damage such as permeability degradation in the matrix rock, a gel block in the sand pack, proppant effects, or imbibition of brine from workover operations; and (3) examine the more probable causes, damage that may be centered around fluid effects in the natural fracture system. A unique explanation is not possible because there are some aspects of these damage mechanisms that cannot be verified in the laboratory. However, comparable damage mechanisms that have been seen in cracked core are described. Also, other postulated forms of fluid damage are discussed, largely in terms of natural fractures in core in combination with other measured core properties.
Co-Production of the N.E. Hitchcock Field, Galveston, Texas
Authors: Randolph P. L. , Wible J. L.
Published: December 2007

The history of primary production and the onset of co-production from the Frio 9100 sand at the N.E. Hitchcock reservoir was previously described by L. Anderson.1 This paper summarizes co-production recovery since its onset in 1983 and then provides details of current operating characteristics for three wells at locations on the structure that result in quite different producing characteristics.

High brine rate production at the Prets Unit No. 1 well commenced three years ago. The produced gas/brine ratio of about 240 SCF/STB provides sufficient natural lift to maintain flow of about 4400 STB/D of brine, 55 STB/D of oil and 1050 MCF/D of gas through 2-7/8 inch tubing.

The other two wells are structurally lower and are being produced with artificial lift to achieve brine rates in the range of 4200 to 5000 STB/D. Produced gas/brine ratios are about 90 SCF/STB and 45 SCF/STB and oil production is similarly less than for the Prets well.

Surface equipment and operating procedures being used for secondary recovery of gas previously trapped by imbibition during primary production are described.
A Joint Venture Methane Drainage Project in Australia's Sydney Basin
Authors: Richards W. L.
Published: December 2007

A joint venture test project for methane drainage was conducted by Methane Drainage Ventures (MDV) at Australian Iron and Steel Pty. Ltd's (AI&S) Appin Colliery, Appin, New South Wales, Australia. The project for methane drainage in advance of longwall mining included five (5) horizontal boreholes into the Bulli Coalbed of the Illawarrg Coal Measure in the south Sydney Basin, Australia.

Peak gas flowrates from a total of 1 380m (4500 ft) of horizontal boreholes reached 17,000 m3 per day (600,000 standard cubic ft/d). The total horizontal drilling project was conducted in eight months of 1981. Produced gas of 97% methane was safely vented both during and after the test project due to the efforts of the colliery operators.

Test drilling was successfully conducted from two separate mining sections on opposite sides of the colliery. Data collected during and after the drilling campaign were used to define the properties of the coalbed. Computer simulation was used to predict commercial gas production.

The Appin project and a concurrent exploration corehole project were conducted to provide data to evaluate the Sydney Basin. Results of the evaluation indicate commercial feasibility of methane drainage for natural gas production. A subsequent design was completed for a natural gas production facility utilizing methane drainage technology.
Deep Source Gas Potential Along the West Coast of the U.S.
Authors: Gwilliam W. J. , Cohen K. K.
Published: December 2007

Deep Source Gas research is focused on the hypothesis that natural gas is generated in sediments carried to great depths at convergent plate boundaries in the earth's crust. These deeply emplaced sediments may source gas to shallower, drillable traps through deep fracture systems. Many areas of North America are believed to have experienced plate tectonic convergence. The western Cordilleran geologic province in particular appears to have thrust fault structures (associated with subduction and obduction) that enabled deep emplacement of hydrocarbon-generating sediments during more recent geologic ages (during the last 180 million years). The specific area of interest in this province encompasses approximately 1.5 million square miles of the western U.S. (including Alaska) and Canada; other portions of this same province extend southward into Mexico and Central and South America.

The ongoing research consists of basic studies of hydrocarbon generation, stability, and preservation at depths in excess of 30,000 feet in addition to a comprehensive evaluation of the geologic structures, stratigraphy, and geochemistry of the above region.

Results to date include geologic and geophysical evidence of deeply emplaced sedimentary rock units at depths exceeding 30,000 feet in western Washington and south central Alaska, a new methodology for verifying deep methane stability via fluid inclusion studies, and a preliminary gas resource estimate of 3,000 Tcf. If only a fraction of the gas thought to exist is found to be recoverable, it could have a profound influence upon the international energy industry.
Daily Drilling Reporting System: Design/Usage
Authors: Quay B. K.
Published: December 2007

A daily reporting system for drilling operations is a relatively recent focus of emphasis for the drilling industry. While many of the major (or very large) operators have had drilling operations data bases for many years, it has only been with the development of the microcomputer as a viable and cost-effective tool for either the individual engineer or the smaller operator that a drilling data base concept has been more widely accepted and requested. With the markedly increased availability of software development tools for the microcomputer, the concept of developing a generic, i.e. commercial reporting system becomes very attractive. This paper will discuss some of the considerations for the design of a commercial reporting system. The problems and/or successes involved with the actual usage of the software will also be discussed.

One of the major goals for any commercial software package is the maintenance of a high level of application to a wide range of users. One way in which this goal can be accomplished is through careful design and implementation of the application. Design steps must be identified and followed in order that as many areas of interest are covered as is possible. The following lists some of some of the questions which should be considered as the design progresses. ◦Who are the users of the package?◦What will be their "style" of usage?◦What reporting requirements do these users already have and what reporting requirements can be foreseen?◦What kind of input "forms" are currently available?
Dynamometer Analysis Using a Digitizer and an IBM PC
Authors: Gray C. R.
Published: December 2007

This paper presents techniques which will allow Engineers to interface a digitizer to IBM PC's (or compatibles) through an asynchronous communications adapter port (RS232). Also presented is a sample application program which uses this interface to perform pumping unit torsional analyses. The same interface could be adapted to other engineering programs, e.g. well log analysis, mapping, etc.
An Integrated Reservoir Database Management System
Authors: Eskijian M. L.
Published: December 2007

An integrated reservoir database, incorporating production, injection, bottomhole locations, pressure histories, completion intervals, well identification and other information can be easily assembled and made operational within only a few hours. This entire effort can be performed by an engineer, without any programming expertise. This database can then be used to perform any sort of calculation, to search for specific production or well information or to sort for a potential problem (i.e. high water cut or low production areas, etc).
BOAST-DRC: Black Oil and Condensate Reservoir Simulation on an IBM-PC
Authors: Fanchi J. R.
Published: December 2007

BOAST-DRC is a three-dimensional, three-phase simulator designed for microcomputer applications. It may be used for either black-oil or retrograde condensate reservoir simulation. The program formulation, and solutions to problems encountered in preparing a microcomputer version are presented. Results for several test problems, including the first (black-oil) and third (condensate) SPE Comparative Solution Projects, are shown.
Putting a New Face on Business Presentations Using PC Graphics
Authors: Ainsbury R. D.
Published: December 2007

During the past twelve months the PC press has been heralding the arrival of PC graphics. There are many different products, perhaps too many, which are available to help PC users prepare effective business presentations. Selection of the right product(s) is important, but putting it to good use is fundamental.
The Joint Applications of Commercial and Self-Developed Softwares That Enhance Microcomputer Uses
Authors: Yu J. P. , Stark J. J. , Flinder H.
Published: December 2007

The use of microcomputers in the petroleum industry is growing rapidly; and word processors, spreadsheets, data bases and engineering programs are the most popular types of software being used. This paper presents the results obtained using a combination of commercial software and engineering application programs developed at West Virginia University. Two major types of this combined application are described in case studies. The first case uses a spreadsheet as both a storage area for well data and as a method for information analysis and presentation. Advantages gained include ease of operation, cost reduction and time savings. The second case combines an engineering program with a Monte Carlo simulation technique to evaluate reserves. The procedure is readily performed with a microcomputer and allows rigorous statistical testing of results obtained using the limited data commonly available. Computer usage of the types discussed could lead to faster and cheaper reserves analysis and thereby to more effective development and recovery of our petroleum resources.
The Computer Van System: Advanced Well Analysis Technology
Authors: Hudgins T. A.
Published: December 2007

This paper discusses the application of microcomputers to oil and gas operations analysis. Computers, sensing devices with associated signal conditioning electronics, and computer programs are combined and packaged in a vehicle similar to a cargo van.
Hydrocarbon Activity in an Era of Low Oil Prices
Authors: Woods T. J. , Holtberg P. D.
Published: December 2007

Recent declines in oil and gas prices have led to concerns about the future levels of oil and gas production in the lower-48 United States. The long-term outlook for lower-48 gas production has been analyzed from the perspectives of lower-48 resource base. The effects on this long-term outlook of the decline in oil and gas prices since the beginning of 1986 have also been assessed. The analysis indicates that lower-48 oil and gas production could be kept near current levels, despite the decline in oil and gas prices. Improved recovery of both oil-in-place and gas-in-place will play a major role in future lower-48 production. Without improved recovery, lower-48 oil and gas production cannot be stabilized. The declines in oil and gas prices have severely reduced net industry cash flow. As a result, despite favorable resource economics, many parts of the industry are unable to undertake much exploration or development activity.
Orcutt Third Zone Waterflood: A Successful Project
Authors: Stracke K.J. , Case C.H. , Baer P.J.
Published: December 2007

This paper was prepared for the 41st Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Dallas, Tex., Oct. 2–5, 1966. 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 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.

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.

The Orcutt field, Santa Barbara County, California, was discovered in 1902. The Third Zone waterflood began in 1950 with a one well pilot test. The present Third Zone waterflood was initiated in 1963.

The development of the project from the pilot to its current status is reviewed. The response attributable to pilot, peripheral and pattern injection is discussed along with operating principles which are followed.

It is concluded that the change from a peripheral injection plan to pattern injection has been beneficial because of the reduced project life and improved well performance.

Introduction

The Orcutt field is located approximately 175 miles northwest of Los Angeles, California, (Fig. 1) and 8 miles south of Santa Maria in Santa Barbara County.

Careaga 10, the discovery well, was drilled in 1902 by the Western Union Oil Company (Shell Oil). Union Oil Company's first well in the Orcutt field, Hartnell 1, was completed that same year. This well, together with the discovery of the Lompoc field, nine miles south of the Orcutt area, was of particular significance as they were the forerunners to other fields that Union would produce in the Central California Coastal area.

There are three productive horizons underlying the Orcutt field. These are designated as the First, Second and Third Zones. This report is concerned with water injection into the Third Zone. The present areal extent of the project is outlined in Fig. 2.

RESERVOIR CHARACTERISTICS

Structure

The productive portion of the Orcutt Third Zone reservoir lies within a faulted anticlinal dome. Contours on top of the Third Zone, Fig. 3, show the attitude of the structure.
Use of Bottomhole Transient Rate Data To Enhance Transient Pressure Analysis
Authors: Ahmed U. , Watson J. T.
Published: December 2007

Efficient development of hydrocarbon zones requires the knowledge of average formation permeability, skin factor, reservoir pressure, formation continuity, reservoir boundaries, drive mechanism, and fluid properties (PVT relationship). The technique most respected and most widely used to determine the first five of these seven parameters is called transient pressure testing. This technique also allows one to make qualitative inference of the last two parameters. Yet, the conventional transient pressure technique, at times, is unable to provide accurate and detailed answers and quite often may not even assure a valid test.

Recent publications have suggested that inclusion of transient rate data along with the pressure data may allow one to eliminate some inadequacies associated with conventional pressure testing. In this paper, we extend the study by presenting several field examples of oil and gas wells, illustrating that inclusion of transient rate information in transient pressure testing (1) eliminates inaccuracies; (2) allows correct interpretation in the presence of fluid segregation within the wellbore; (3) allows determination of near wellbore skin condition and overall skin factor; (4) makes analysis possible when data are influenced by boundary effects; (5) allows more definite differentiation between matrix reservoir behavior and naturally fractured, multilayer flow effects and other flow patterns; and (6) assures a valid test. Apart from these aspects, this technique allows one to perform a well test of relatively short duration.