bluuebunny/crossref_metadata_2025 huggingface dataset:
Gas Injection In City Of Inglewood Pool Inglewood Oil Field - California
Authors: Hedjazi A.K.
Published: December 2007

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

This paper was prepared for the 38th Annual California Regional Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Los Angeles, California, October 26 and 27, 1967. 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 City of Inglewood Pool gas injection project, Inglewood Oil Field, California provides a 3 year case history of successful gas injection operations in a depletion type reservoir producing 290 API oil.

The pool is a stratigraphic trap which pinches out abruptly upstructure. The structure dips about 300 at the crest, with dips of 600 on the flanks near the oil/water contact. The average depth to the top of the zone is 9,000 feet. The average porosity is 13.8% and the arithmetic average air permeabilities is 8.7 md. The reservoir had an original gas cap of approximately 7-1/2% of the total hydrocarbon reservoir pore volume.

The original reservoir pressure, estimated at 4,350 psia, had declined to 2,800 psia prior to initiating gas injection. Injection into 8 crestal well was initiated in February 1964 at 3,800 MCF/D and 3,000 psig. Approximately 1,400,000 MCF of gas had been injected into the pool when injection was increased to 6,000 MCF/D in September 1964. To date, 5,900,000 MCF of gas have been injected with a resulting average reservoir pressure increase of 475 psi to 3,275 psia.

Reservoir calculations indicated that only 12.5% of the original oil in place could be recovered by normal depletion, but that recovery could be increased to 22.8% by gas injection.

Current production is 820 B/D oil, which represents a gain of 580 B/D over normal depletion. Cumulative additional oil recovery to date is about 500,000 barrels.

Introduction

The Inglewood Oil Field is located about 10 miles southwest of the Los Angeles Civic Center (Figure 1). The City of Inglewood Zone is the next-to-deepest zone of eight major producing intervals in the field. The sand is of Upper Miocene age (Figure 2).

The City of Inglewood Pool, discovered in 1960, lies between 8,000 and 10,000 feet vertical depth. It contains 12 producing wells and 2 injection wells drilled on about 16-acre spacing. Dry gas injection was initiated in February 1964 and expended to full scale by September 1964.
The Ocean Odyssey: Well Control Project II
Authors: Gillespie J. D. , Wann K. E.
Published: December 2007

On September 22, 1988, a blowout occurred on the semi-submersible "Ocean Odyssey" in the UK sector of the North Sea. This paper will detail the uncertainties faced by the blowout control team when planning the abandonment of this well and describe some of the novel techniques implemented in this project. This case history shows that direct wellbore intervention into a subsea blowout can be an effective well control method.
Practical Application of Real-Time Expert System for Automatic Well Control
Authors: Lloyd G. M. , Bode D. J. , Nickens H. V. , Varnado S. G.
Published: December 2007

Expert systems are receiving widespread interest in many fields. One critical application in the drilling industry that is ideally suited to use this technology is automated well control. In some drilling situations, particularly slim hole drilling, the reaction time between detection of a kick and the need to take corrective action may be only a fraction of a minute. In this application, a significant amount of data must, be continuously collected, processed, and analyzed in a short period of time. Expert systems can automate these functions.

This paper describes the design, development, and testing of an expert system for well control (XWC) on a slim hole drilling rig. The use of an expert system operating in real time to perform complex analysis of the drilling data from rig sensors can significantly reduce false alarm rates as well as the probability of a small kick developing into an uncontrolled situation. The system is unique in several ways. First, it operates in real time. It samples flow in, flow out, and other parameters, processes the data, and transfers the information to the expert system. Second, the system can be classified as a true hybrid system in that extensive algorithmic calculations and models are incorporated where necessary. Finally, the entire system has been validated in a test well.
Field Evaluations Confirm Superior Benefits of MMLHC Fluid System on Hole Cleaning, Borehole Stability, and Rate of Penetration
Authors: Burba J. L. , Tehan W. F. , Hamilton F. D. , Holman W. E. , Porzucek C. , Christenson C. P. , McKenzie J.
Published: December 2007

Over the last several years, the Dow Chemical Company and Westbridge Oilfield Products have been developing a novel drilling fluid system based on mixed metal layered hydroxide (MMLHC) chemistry. Among the significant advantages that these compounds provide is unparalleled solids suspension capabilities arising from a gel structure that breaks very easily and recovers rapidly. Conventional rheological models do not adequately describe the rheology of this system. Thus, a number of unconventional measurements, based on material science considerations have been utilized to develop a working rheological model from which effects of the fluid on drilling rate, bit usage, hole stability, and drilling fluid cost can be projected.
U.S. Demand For Atomic And Conventional Energy By 1982 A 15-Year Forecast With Emphasis On Petroleum
Authors: Lichtblau John H.
Published: December 2007

1967 California Regional Meeting, Oct. 26–27, 1967 Los Angeles, CA.

I have taken as my assignment the outlook for all energy sources over the next 15 years, with particular emphasis on the impact of atomic energy on fossil fuels, especially petroleum. I've limited myself to a 15-year forecast because I believe this is the longest period for which it is reasonable to assume no major commercial impact from new technological developments except those already visible, at least in embryonic form, at the beginning of the period. Thus, the only new forms of energy sources or energy uses of economic significance by 1982 will be those whose commercial potential is already fairly well recognized today. By the same token, none of the significant energy sources and uses of today are likely to have disappeared by the end of our forecast period. In short, while our 15-year limit may render our outlook a bit less glamorous than the exciting forecasts of life and technology in the 21st century so frequently heard these days, it also avoids the snares and pitfalls of a soaring imagination, particularly if one takes as one's inspiration the phenomenal and historically unique technological progress of tile last 100 years. Looking ahead to 1982, it seems clear that the principal new development in the U.S. energy sector will be the dynamic growth of atomic energy. This growth has been predicted ever since that "Day of a Thousand Suns" back in June 1945.
Jackups for the Nineties: What Should the Industry Expect?
Authors: Springett C. N.
Published: December 2007

Despite the prolonged downturn in the offshore drilling industry, there may be room for cautious optimism with respect to some specialized segments of the marketplace. The most interesting, and in many ways most challenging area, concerns the move towards bigger and more sophisticated jack-ups in deep water, harsh environments. This paper describes the challenge in terms of the technical and regulatory requirements but emphasizes the spirited discussions currently underway throughout the industry concerning the most appropriate way to make site specific structural assessments of jack-ups.

Although reference is made to "Galaxy I," a new super jack-up under construction in Singapore for Santa Fe, the primary thrust of the paper is to describe what an operator should be able to expect from the new generation of large jack-ups in the nineties. Performance is defined in terms of environmental capability, the analysis techniques used to validate the design and the equipment and configuration necessary to satisfy both efficient production drilling in the cantilever or skid-off mode and deep high pressure wild-cat drilling.
Maximum Movement of the Drilling Riser
Authors: Movsumov A. A. , Tagiev A. H.
Published: December 2007

When disconnected, the drilling riser (even without buoancy modules) can collide with different parts of & moonpool and the floating rig itself. The collision may result in severe damage of the telescopic joint, and extra bending stresses. Calculations were made to find out the maximum movement (upward and lateral) of the disconnected riser as a function of the initial, vertical force applied to the riser.

Using the same approach, bending stresses due to rig heave with a riser, connected to the wellhead, are being investigated.
Prediction of Steamflood Performance in Heavy Oil Reservoirs Using Correlations Developed by Factorial Design Method
Authors: Chu C.
Published: December 2007

By using the factorial design method, statistically significant correlations have been developed which enable one to predict steamflood performance in terms of project life, oil recovery and cumulative steam-oil ratio. The effects of various reservoir rock and fluid properties and steamflood design and operating variables on steamflood performance were discusssed.
Evaluation of Radioactive Tracer Surveys for Steam Injection Wells
Authors: Griston S.
Published: December 2007

The proper distribution of steam over the injection zone is critical to the efficient operation of a steamflood project. Many factors affect downhole steam distribution, such as differences in relative injectivity between perforations and gravity segregation of the phases. Surveys can be run in the wellbore to determine the steam injection profile. These profiles can then indicate which parts of the reservoir have been steamed and which may have been bypassed.

Because steam consists of liquid and vapor phases, running profile surveys and interpreting the results are not straightforward. These surveys must be designed to generate information about the flow of both phases. Additionally, the survey results must be interpreted with a knowledge about the characteristics of the two-phase flow. In recent years, radioactive tracer surveys have become the most common method used to obtain steam profiles. The main emphasis has been on the use of inert radioactive gases for vapor profiling. Although radioactive tracer surveys are commonly used to obtain water or gas injection profiles, little is known about the reliability and accuracy of applying this method to profiling steam injection wells.

This paper presents the results of field testing and evaluation of vapor phase profile surveys using radioactive Krypton and Xenon gas tracers. Emphasis is given to surveying (or logging) procedures and data analysis methods and to determining the reliability and accuracy of vapor injection profiles. Existing data analysis and interpretation methods are reviewed and a new, automated method is presented that gives more consistent and reliable evaluation of tracer measurements. The accuracy of tracer measurements and resulting vapor injection profiles are discussed. Factors affecting repeatability of tracer measurements, such as tracer radiation intensity, wellhead steam conditions, and well completion are also discussed.
Current Practice in the Interpretation of Microfrac Tests in Oil Sands
Authors: Proskin S. A. , Scott J. D. , Chhina H. S.
Published: December 2007

Small volume hydraulic fracture tests, defined as microfrac tests, are conducted to determine the in situ principal stresses in oil formations. Interpretation difficulties arise when the tests are conducted in relatively shallow, unconsolidated sands which are typical of the oil sand deposits in Alberta, Canada. Interpretation methods for such tests are outlined and their use is discussed. Three microfrac case histories in the Athabasca oil sands deposit are presented and analyzed. Recommendations are given for performing microfrac tests in these formations.
Synthetic Polymer Developed for Cement Fluid-Loss Control
Authors: Strange A. F. , Brothers L. E.
Published: December 2007

A new fluid loss additive has been developed for a broad range of applications. A synthetic polymer has been used to control fluid loss values to meet specific requirements in the design of lightweight, standard-weight, and heavyweight slurries at circulating temperatures from 180°F to 400°F. Polymer-containing slurries mixed with fresh water, sea water, and water containing potassium chloride or sodium chloride (up to saturation) exhibit fluid loss values as low as 20 cc/30 min within these temperature ranges.

Various methods of determining fluid loss at temperatures above 190°F are utilized within the industry. These methods are explained and compared. The new additive does not have a pronounced affect on cement slurry viscosity. Slurries may be formulated to have low fluid loss values while being neither overly-viscous nor overly-dispersed. Such properties permit displacement without undue friction pressure at reasonable annular velocities, thus helping improve displacement mechanics and ensure efficient drilling fluid removal.

Results of using this polymer have been to help improve the probability of obtaining a successful cement job by (1) minimizing the risk of bridging, (2) enhancing displacement mechanics, and (3) providing early casing protection. Field case histories are provided.
Development of Sockeye Field in Offshore California: A Case History
Authors: Sankur V. , Weber L. S. , Masoner L. O.
Published: December 2007

Sockeye Field, discovered in 1970, lies offshore California in the Santa Barbara Channel. The decision to develop the field was made in 1983 based on 1979–83 exploration drilling. Platform Gail was installed in 1987 and development drilling commenced in June 1988. Currently there are eleven development wells with plans for two more (two duals and eleven single completions).

This project has taken 20 years to reach the development stage since the lease sale in 1968. This long time span was partly due to permitting delays encountered in offshore California projects and a Santa Barbara Channel drilling moratorium in the 1970's.

The field produces from five reservoirs; Middle and Upper Sespe Sands, Lower and Upper Topanga Sands, and the Monterey Formation. Sespe Sands are fluvial channel deposits with individual sand bodies with limited areal extents. The Middle Sespe produces dry sweet gas and the Upper Sespe produces sweet 29° API gravity oil. The Topanga Sands were deposited in a near shore environment and are more continuous in nature. Lower Topanga Sands contain sweet oil whereas Upper Topanga Sands test a low gravity 18° API sour oil. The Monterey Formation is composed of thin beds of cherts, porcellanites, siliceous shales, mudstones, and dolostones. The fractured Lower Monterey produces heavy sour oil, similar to that of the Upper Topanga.

To minimize risk, delineation wells were drilled early in the development program to ensure that reserves warranted additional investment in wells and facilities. Nine wells were completed during the first phase of the drilling program. Gas production from these wells was projected to exceed the capacity of the Carpinteria Gas Plant. The drilling rig was put on standby to evaluate various facilities modifications to handle production. At the conclusion of the evaluation, drilling was resumed with plans to drill four more wells.

Reservoir information was obtained through an integrated program of formation evaluation, core analysis, production logging and build-up and interference testing.
Hot Waterflood in a Post-Steamflood Reservoir: A Case History in the Kern River Field, California
Authors: Dorna R. G.
Published: December 2007

Texaco converted 275 steam displacement patterns to hot waterflood pilots in the Kern River Field. This test program was designed to evaluate hot water injection as a viable recovery mechanism in a post steamflood reservoir.

Response to hot water injection was typified by a decline in oil production and a corresponding increase in water production. Investigation into the reservoir rock and fluid properties indicated that a mobility ratio of 3.8 in combination with a highly permeable sand and steam desaturated area would not allow the formation of an effective immiscible displacement bank. The monitoring program demonstrated that oil resaturation occurred in areas where the injection water filled the steam desaturated zone. Temperature data from observation wells showed that hot water was ineffective at transferring heat to the reservoir.
A Study of the Post-Breakthrough Characteristics of Waterfloods
Authors: Lo K. K. , Warner H. R. , Johnson J. B.
Published: December 2007

This paper presents results that theoretically and numerically support the log(WOR) vs cumulative oil plot for waterflood analysis. This plotting technique has traditionally been used to estimate the ultimate oil recovery from waterflooding; the results derived in this paper give other practical uses for this plot such as evaluating the efficiency of current waterflooding operations, estimating the original oil in place (OOIP), or determining the in situ water-oil relative permeability characteristics of the reservoir. The study results, primarily utilizing the dependence of the slope of the log(WOR) vs cumulative oil plot on various reservoir parameters, are based on the one-dimensional Buckley-Leverett theory after water breakthrough and multi-dimensional numerical simulations. Also the effect on this slope caused by different reservoir layering, flood configurations, and operational changes are presented. This approach has been applied to estimate the original oil in place for two actual waterfloods and a comparison of these OOIP values is made to those calculated by volumetric methods.
A Laboratory Screening Method for a Pilot Caustic Steamflood
Authors: Okoye C. U. , Hayatdavoudi A. , Ping-Hu W. , Oungpasuk P. , Yousef M.
Published: December 2007

This paper presents the screening tests conducted to determine the feasibility of caustic steamflood at Schewing formation in Bayou Bleu Field Louisiana. The evaluation process and methods include a broad range of laboratory tests which can be applicable for screening any field trial of chemical steamflood or ordinary steamflood. The minerology, and rock properties such as porosity and permeability were determined by core analysis. The mineralogy test consists of petrographic study of thin sections, scanning electron microspy, EDAX and x-ray diffraction of formation rock samples before and after treatment with varying concentrations of caustic solutions. The reservoir fluid analysis involved the determination of oil: gravity, density and viscosity at varying temperatures and caustic concentrations. Also the PVT parameters and the acid number of the oil. were determined.

The criteria used for screening various concentrations of caustic solution for high temperature application include: the effect of temperature on caustic-oil and caustic-rock interaction, the reaction kinetics of caustic-oil and caustic-rock, caustic-oil relative permeabilities, caustic-oil interfacial tension and oil recovery performance. The most favorable designed caustic steamflood recovered 15% more of initial oil-in-place than the conventional steamflood.

Estimates of field performance ranged from 10% to 25 of more additional oil recovery by caustic steamflood than by conventional steamflood. Based on these screening test a field trial of cyclic caustic steam injection was carried out as a prelude to a proposed 5-spot caustic steamflood pilot project.
A New Method for Stabilizing Fines and Controlling Dissolution During Sandstone Acidizing
Authors: Kalfayan L. J. , Watkins D. R.
Published: December 2007

A new fines stabilizing method which prevents migration of clay and non-clay siliceous fines, and controls formation dissolution during sandstone acidizing, has been developed.

The method employs an organosilane compound which can be added directly to acid mixtures, such as hydrochloric (HC1) and hydrochloric-hydrofluoric (HC1-HF) acid. The organosilane additive reacts in situ to stabilize potentially mobile siliceous fines, and as an additive to HC1-HF acid mixtures, reduces the potentially damaging effects of excessive mineral dissolution by HF.

This paper describes the use of and the mechanism by which the organosilane acid additive stabilizes fines, and reduces dissolution of sandstone by HF acid.

Results of laboratory core flow tests which show the beneficial effects of employing both a proper HF acid concentration and the organosilane fines-fixing agent are presented. Results of a field test are also presented.
The Evaluation of Temperature Logging in Thermal Application
Authors: Fialka B. N. , Pyszka M. H. , Chhina H. S.
Published: December 2007

When evaluating the technical success of thermal operations, one of the most important factors to be determined is how efficiently the heat is distributed within the reservoir. Temperature logging is the standard diagnostic technique for monitoring the vertical heat distribution in the near wellbore region of a well subjected to thermal operations. This paper deals specifically with the use of the log-inject-log temperature logging procedure in a cyclic steam application. In particular, the limitations of the procedure and the value of the information obtained is established using field examples from an experimental cyclic steam pilot project in the Cold Lake region of Alberta, Canada.

Presently, there are conflicting opinions regarding the suitability of various operating procedures for thermal logging and the analysis of the data. This uncertainty was addressed by mathematically modelling certain aspects of the log-inject-log temperature logging procedure. Numerous factors were found to influence the measured wellbore temperature: the treatment of the wellbore prior to logging, the accuracy of the logging tool, influx of reservoir fluids into the wellbore and the bottomhole pressure. The effect of each of these factors on the temperature logs taken was investigated which contributed to the development of a recommended temperature logging procedure.
X-Ray Scanning in Petroleum Engineering Laboratory Research
Authors: Castanier L. M. , Pettit P. A.
Published: December 2007

This paper summarizes applications of Computerized Axial Tomography to a variety of experimental problems in reservoir engineering and Enhanced Oil Recovery research.

Stanford University acquired a used medical Cat scanner in 1987. The system has been modified for determination of heterogeneities and measurement of In-Situ saturations in multiphase flow experiments. The poster presentation will include a description of the equipment, a poster presentation will include a description of the equipment, a discussion of the various types of softwares used for interpretation and display of the results and several examples of applications. Among those emphasis will be placed on the following:

- Verification of homogeneity in sandpacks – Foam flow (Determination of liquid and gas saturations in two phase systems) – Three dimensional steam injection model – Studies of flow through fractured media – relative permeability studies

Discussions of our answers to specific problems as well as example pictures of scans of cores and fluids will be presented. Cat Scanning is now used as a powerful tool to complement existing laboratory measurement, it can be used in a broad range of experiments including high pressure and high temperature thermal recovery corefloods.
A Method for the Determination of Relative Permeability Ratios Using Visual Columns
Authors: Alcocer C. F.
Published: December 2007

A laboratory research was conducted to generate an analytical method to determine relative permeability ratios from experimental data obtained during immiscible displacements of hydrocarbons in unconsolidated reservoir using visual cylindrical model. This paper presents: a) the design, construction and uses of visual columns of immiscible displacements; b) the mathematical description and application of a new technique to generate relative permeability ratios as a function of the permeability ratios as a function of the displacement fluid saturation; and c) a study of the advance of the displacement front. The displacement of the front is an Irregular 3-D surface that was treated as 2-D problem by using intersections of the front problem by using intersections of the front surface with the boundary of the visual cylindrical model. This treatment of the data allowed us to formulate empirical equations for wall-effects in laboratory reservoir models and develop a method to determine relative permeability rating. Twelve flooding tests were run in the laboratory using water as displacing fluid and hydrocarbon displaced fluid. The rate of displacement varied from 0.345 cc/sec. to 9.77 cc/sec. Reservoir models were made of resistant transparent plastic columns with 100 cm length, 9 cm internal diameter and 0.5 cm thickness. The porous media was unconsolidated 140-200 mesh sand pack with 33.9% and porosity and permeability of 945 ml the first column and 34.96% porosity and 835 ml of permeability the second one.

The main and secondary objectives of this research were accomplished. The analytical method generated similar relative permeability ratio curves to those produced permeability ratio curves to those produced by conventional multi-phase flow tests in the laboratory. This new method proved very useful to save time during enhanced oil recovery tests in the laboratory there relative permeability ratios are needed data. The efficiency of the water flooding displacements and results of wall-effect equations generated in this work are in reasonable agreement with previous investigators.

P. 601
A Unique Method for Installing Slimline Fiberglass Liners in a CO2 Miscible Flood
Authors: Lacy R. D. , Talley C. L.
Published: December 2007

A major obstacle to the successful implementation of an enhanced oil recovery project is the proper completion of the injection wells to prevent fluid loss. The injectants are often expensive and highly corrosive. Further, economics dictate in many cases that the wells to be completed and used as the input wells for the injectant be existing wells; the economics simply do not allow for the drilling of new injection wells. These wells were originally designed without this purpose in mind and are very often old, at least thirty years. Most of these wells suffer from poor casing integrity and small casing sizes. Again, economics do not allow for the use of corrosion resistant high nickel chrome alloy liners.

To solve these problems, a unique completion method was designed using fiberglass casing and a drillable permanent packer as the liner hanger. The permanent packer was also used as the injection packer. This system allows the use of corrosion resistant fiberglass for control of the corrosive injection fluids and imparts the ability to drill out the permanent packer and the fiberglass liner to prevent the loss of the well bore in the future, if mechanical problems do arise.

This paper will describe in detail the development of the injection system, and the remedial procedures required. Case histories from an operator in southeastern New Mexico will demonstrate the successful recompletion of existing well bores into injection wells, supported by injection profite data that demonstrates injected fluid control. Economics demonstrating cost effectiveness of the unique completion design are also presented.
Well Performance Visualization and Analysis
Authors: McCoy J. N. , Podio A. L.
Published: December 2007

A system has been developed based on a powerful portable microcomputer and an integrated data acquisition instrumentation package which allows real-time visualization of pumping well performance.The system integrates all the necessary elements to obtain a complete analysis of the performance of the pumping system which includes the pumping unit (beam or submersible), the wellbore, and the reservoir.

The data acquisition package consists of the necessary analog and digital input channels to process data from standard transducers such as pressure, temperature, rod load, displacement, etc. so that detailed surface unit performance curves such as dynamometer, speed, acceleration, power etc. can be obtained and analyzed. When the instrument is used in conjunction with an acoustic pulse generator and receiver, it digitizes and records the reflected acoustic signals which are digitally filtered and automatically processed to determine the liquid level. This is undertaken under program control so that a recording of fluid level vs, time is obtained concurrently with the pumping performance parameters. Fluid level data is processed by the software to calculate bottom-hole pressure as well as flow into and out of the well bore. Changing the well from flowing to shut in conditions allows recording of pressure buildup data which is then interpreted in terms of reservoir parameters. Alternatively, pump start-up after shutting in the well in for stabilization, provides draw-down testing capability. The analog/digital electronics system contains outputs of a 12 volts relay driver and also normally open/closed contacts for external control of gas-gun valves, motors, variable speed drives, casing vent valves, etc. These outputs are computer controlled and can be actuated depending upon input data, operator keyboard entry and/or time.

Graphic display of the various diagnostic parameters allows complete visualization of the performance of the whole pumping system including the reservoir, wellbore and pumping unit. The system can be used as a diagnostic tool to optimize pumping well performance on a periodic basis. The present performance of the well is compared to the performance recorded previously and in the case where significant changes are noted a more detailed analysis is undertaken. In critical well applications, the system can function as a stand-alone dedicated controller.
High Fracture Conductivity Yields Attractive Results
Authors: Kolb R. J.
Published: December 2007

Field tests suggest propped hydraulic fractures designed with high fracture conductivities are cost effective treatments with attractive economic results. With careful consideration to detail, accurate predictions of production response to fracture treatments can also be made. Treatments performed on the Grayburg-San Andres formation in the McElroy Field near Crane, Texas have been evaluated to demonstrate these points.
Evaluation of Alternating Phase Fracture Acidizing Treatment Using Measured Bottomhole Pressure
Authors: Wehunt C. D.
Published: December 2007

Net fracturing pressure calculated from measured bottom hole pressure verifies the effectiveness of the alternating phase technique for controlling acid fluid loss. Results of before and after job simulation cases modelling the process are shown. Subsequent pressure buildup data are also presented.
Inverse VSP—A New Technology for Imaging and Monitoring Reservoirs
Authors: Hardage Bob A.
Published: December 2007

During the past decade, the oil and gas industry has recorded a large number of vertical seismic profiles (VSPs) in order to acquire improved structural, stratigraphic and seismic calibration information in the immediate vicinity of selected study wells. As is the progressive nature of the technology that the oil/gas industry uses in its exploration and development efforts, those companies who actively use VSP data are continually striving to find techniques whereby an increased volume of VSP data can be recorded in a study well at minimal additional cost. The inverse VSP concept has been developed to satisfy this objective.

Significant progress is currently being made in inverse VSP technology, so it is essential that a description of the equipment, field procedures and potential applications involved in this new type of borehole seismic measurement be available to the industry. This documentation is particularly important for those people who are responsible for evaluating reservoirs for purposes of calculating reserves in place, compiling data for unitization arbitration, or planning secondary recovery processes. Hopefully this paper will be a step in helping to disseminate this information throughout the industry.

In forward VSP, a geophone is positioned at various depths in a well in order to record the transmitted and reflected wavefields created by a seismic energy source located on the surface of the earth. In inverse VSP, the spatial positions of the source and receiver are reversed, with the source being manipulated at various depths in a well and the receiver(s) located on the surface of the earth. In concept, the raypaths between source and receivers, and consequently the travel times, are identical in these two recording geometries, as shown in Figure 1. In addition, the subsurface coordinates of the reflection points created by either measurement method coincide if the radiation patterns created by the surface and borehole sources are reasonably equivalent.
The Fluid Flow Simulation Equations
Authors: Breitenbach E.A. , Thurnau D.H. , van Poolen H.K.
Published: December 2007

American Institute of Mining, Metallurgical and Petroleum Engineers Inc.

A fundamental flow equation can be derived for each of the oil, water, and gas phases by combining the law of conservation of mass, a law of force, and thermodynamic relationships that describe the pressure-volume-temperature behavior of the fluids. The law of conservation of mass states that the sum of mass flow into a cell equals the change of mass within a cell. The law of force describing flow through porousmedia is Darcy's law, which assumes that flow is within the laminar flow regime described by the law. The thermodynamic relationships used to describe the fluid behavior must (because of the lack of accurate analytical expressions) be those found experimentally in a "PVT" study. The first part of this report shows how these laws can be combined to give equations describing fluid flow through porous media.

The next step in the development is the cabining of these equations with auxiliary equations so that the number of dependent variables is reduced. The result is an equation that can be assumed to be in terms of oil pressure only, so that it may be solved implicitly pressure only, so that it may be solved implicitly for pressures at the new time level. Separate from this pressure equation are the equations that are solved explicitly for saturations, using the newly computed pressures. Hence, there are three equations developed in final, finite difference form in this paper. 1) a pressure equation, 2) an oil saturation equation, pressure equation, 2) an oil saturation equation, and 3) a water saturation equation.

The logic used in the computation of all pertinent terms is given in the final section pertinent terms is given in the final section of this report.

Introduction

The general aspects of numerical fluid flow simulation has been given elsewhere (1). The present paper gives the derivation of the fluid present paper gives the derivation of the fluid flow simulation equations. The numerical solution of these equations is given in (2).

FUNDAMENTAL FLOW EQUATIONS

Fig. 1 shows a differential element of porous media. Pounds of oil (w o) are flowing porous media. Pounds of oil (w o) are flowing into or out of two faces, with a well (w op)in the center of the elements.

Weight rates of flow, rather than mass rates, are used here to simplify the final algebra; of course, this necessitates the assumption of constant acceleration of gravity. The rate of depletion (ROD) of oil from this element can then be defined as:

..........................................(1)

where ROD is the rate of oil removal from the element in lb/day at reservoir conditions.
Steam-Foam Pilot Project at Dome-Tumbador, Midway Sunset Field: Part 2
Authors: Mohammadi S. S. , Tenzer J. R.
Published: December 2007

A steam-foam pilot project was conducted in the Dome-Tumbador leases, Midway Sunset field. The pilot consisted of four inverted five-spot patterns with a confined producer covering 5.2 acres [2.1 ha]. The injection phase lasted 3.7 years. During this period, steam-foam was generated by continuous injection of steam with NaCl, alpha olefin sodium sulfonate (AOS) and nitrogen. Incremental oil due to foam was 6.0% 00IP. The AOS use was approximately 5.3 lbs [2.4 kg] active matter per barrel of incremental oil. A heat distribution analysis using neutron and temperature logs from two observation wells showed that foam had improved areal and vertical sweeps. Finally, a comparison between in situ foam volumes in Midway Sunset and a similar project conducted by Shell in two Kern River pilots showed that the rate of foam propagation in Midway Sunset is about 4.5 times faster than in Kern River.
The Development of a Probabilistic Physical Model for Foam Generation by Snapoff in Regular Square Grid Network Systems
Authors: Armitage P. , Dawe R. A.
Published: December 2007

This paper assesses the degree of influence snap-off, leading to either a bubble flowing or pore blocking mechanism, has on the pressure profiles and sweep efficiencies generated as a result of bubble production and foam propagation through regular square grid networks. A visual single pore model in which bubbles of known size can be generated leading to either of the two mechanisms was developed. New 2-D visual square grid networks have been developed in which different numbers (0,39,185) of these single pore bubble germination sites are incorporated as a fraction of the total number of sites available (800). In effect what has been created is a series of pre-determined, probablistic physical models for bubble generation by snap-off. These models have been used in a series of systematic drainage displacements.

These experiments have yielded quantitative information on how bubble production and the subsequent flowing bubbles or pore blocking can affect a foam's ability to control the mobility of the gas phase. These studies allow for a more competent evaluation of the importance of both of these mechanisms in improving the sweep efficiency.
Design of a Novel Flooding System for an Oil-Wet Central Texas Carbonate Reservoir
Authors: Olsen D. K. , Hicks M. D. , Hurd B. G. , Sinnokrot A. A. , Sweigart C. N.
Published: December 2007

Alkaline-surfactant-polymer flooding (ASP) as a method for oil recovery has traditionally been applied to sandstone reservoirs. This paper describes the first application of ASP technology with wettability alteration in a carbonate reservoir and compares laboratory performance of alternate chemical flooding processes. The oil-wet Cretaceous Upper Edwards reservoir, located in Central Texas, has characteristics generally favorable for chemical flooding. The reservoir has low brine salinity, low temperature, moderate oil viscosity, high residual oil saturation, and a diverse carbonate lithology without anhydrite or gypsum. This reservoir targeted for EOR, is currently produced by a strong, natural water drive from wells on a 2-acre spacing. Extensive reservoir characterization has been performed to establish the extent of the resource.

A laboratory study was conducted to compare alternative EOR processes for individual geologic zones identified by describing and subdividing the reservoir. Coreflood experiments using fresh Upper Edwards reservoir core, have given post-waterflood oil recoveries of 45.3%, 10.0%, and 11.6% from small, low-concentration slugs of alkaline-surfactant-polymer, alkaline-polymer, and polymer formulations, respectively. These laboratory evaluations have shown that ASP formulations of sodium tripolyphosphate and sodium carbonate along with a low concentration of petroleum sulfonate maintain interfacial activity upon extensive dilution with reservoir brine and give significantly better oil recovery than alkaline-polymer or polymer formulations. The results indicate that a cost effective alkaline-surfactant-polymer process can be designed for application in a carbonate reservoir.
Co-Deployment of Surfactant/Polymer and Miscible Gas Enhanced Oil Recovery Processes: A Simulation Study
Authors: Barker J. W.
Published: December 2007

A reservoir simulator capable of modelling both surfactant/polymer flooding and gas displacement processes (immiscible or miscible) is described. Novel extensions to existing phase behaviour and relative permeability models are used to represent interactions between the two processes. Results are presented quantifying the possibilities for combined chemical and miscible EOR.
Percolation Theory of Foam in Porous Media
Authors: Chou S. I.
Published: December 2007

A statistical network model and percolation theory are presented to describe the behavior of foam in porous media. Central to the present theory are constrained pore throat and pore body size distribution functions which characterize the converging/diverging nature of the pore geometry and the assumption that foam lamellae are generated by snap-off in pores with an aspect ratio greater than some critical value. Foam lamellae are not always stable; they may break-and-remake. Permeability reduction results from blockage of the flow channels. The probability of snap-off and the percolating conductivity of the network are calculated, approximated by a Bethe tree, which relates to two-phase permeabilities.

Results show that foam generation critically depends on the pore size distributions and that a strong foam could be generated by the snap-off mechanism, provided that the average pore aspect ratio is sufficiently large. Consistent with experimental observations, the theory predicts that gas relative permeability is greatly decreased by foam and approaches zero at the trapped gas saturation corresponding to the minimum gas saturation below which the gas channels become discontinuous. Because snap-off occurs only in gas-occupied pores, the water relative permeability is not affected by foam. Thus, the theory is able to describe quantitatively gas and water relative permeabilities with or without foam.

The predicted relative permeabilities together with Darcy's law of two-phase flow explain much of the anomalous behaviors of foam in porous media, including the near-constancy of steady state saturation in the presence of a strong foam and the seemingly contradictory effects of gas and liquid flow rates on foam. The possibility of foam generation by imbibition and the effects of rock permeability, wettability, and the presence of residual oil on foam displacements are also discussed.
Results and Difficulties of the World's Largest In-Situ Combustion Process: Suplacu de Barcau Field, Romania
Authors: Carcoana A.
Published: December 2007

The Suplacu de Barcau oil reservoir, a monocline with 5° average dip north and located in the northwestern part of Romania, is a shallow unconsolidated sand with high porosity and permeability and with 295 MM bbls (46.9 × 106sm3) of 2000 cp original oil in place. After a pilot test was initiated up the structure in 1964 the inverted five-spot combustion pattern was expanded and gradually replaced by a line of injection wells.

The actual five miles long in-situ combustion front is moving down dip being sustained by injecting 120 MM scf/day (3.36 × 10 sm3/day) into 100 injection wells. The balance is maintained by the oil, water, combustion gases and nitrogen produced through 600 wells influenced by combustion.

The burning front advancing down structure is followed by the line of injection wells, transferring the air injection to the producers exceeded by the front.

The difficulties encountered are related with mud and steam volcanos appearing high structurally in isolated areas, and with the evacuation of large volumes of combustion gas sometimes containing CO. Also the presence of hazardous gas in the basement of some village houses which overlap the combustion zone is threatening the area. Remedial work is needed also to overcome other difficulties such as injectivity reduction, rebel emulsions, excessive heating of some of the producers, and failure to avoid the back pressure which inhibits flow from the formation into the producer's well bores.
Injection/Production Monitoring: An Effective Method for Reservoir Characterization
Authors: Honarpour M. M. , Tomutsa L.
Published: December 2007

Geological heterogeneities controlling fluid flow paths in the Department of Energy Tertiary Incentive Project (TIP) area in Unit ‘A’ of Bell Creek (MT) field were identified and described using injection, production, pressure, pressure falloff, and pulse test data. Monthly injection rate and pressure data, over a period of 10 years of linedrive waterflooding followed by 6 years of 20-acre, five-spot, water and micellar-polymer injection, were analyzed using the Hall plot method. Water production front tracking and mathematical simulation results were integrated with information obtained from geological analysis and provided an improved interwell formation characterization. This integrative approach provided information about interwell reservoir properties such as directional transmissivities, fluid flow patterns, residual oil saturation, degree of continuity, presence of flow barriers, and permeability conduits.

In the TIP area, analysis of the injection data with the Hall method provided distinct directional formation transmissivity for the preflush, micellar, and polymer stages of injection. Analyses of pressure-pulse and falloff tests conducted before the application of the chemical flood provided a baseline for comparing directional flow characteristics. The influence of various geological heterogeneities such as faults/permeability variations on fluid flow characteristics of the reservoir at various stages of linedrive waterflooding and chemical flooding was identified. The results show good agreement with any complement information obtained from geological, petrophysical, and petrographical analyses. They also indicate that the effects of micellar and polymer adsorption/retention on fluid flow charcteristies of a reservoir can be quantified using the Hall plot method.

Analyzing injection-production-pressure data and front monitoring during waterflooding proved to be an effective method for characterizing candidate reservoirs for enhanced recovery and for monitoring their performance in a continuous manner.