bluuebunny/crossref_metadata_2025 huggingface dataset:
Foam as a Mobility Control Agent in Steam Injection Processes
Authors: Chiang Jin C. , Sawyal Subir K. , Castanier Louis M. , Brigham William E. , Sufi Arshad
Published: December 2007

Although our primary interest in studying the technique of mobility control by foaming agents was for steam injection processes, this method seems to offer excellent prospects of improving oil recovery efficiency in any type of gas drive process.

Laboratory studies showed that gravity override of injected gases in gas drive processes can be strikingly reduced and hence recovery increased by in-situ generation of foam. A two-dimensional, vertical plexiglas model holding a 4' × 1' × 0.25″ sandpack was used to investigate this phenomenon. Saturation of the sandpack by a surfactant solution instead of pure water sharply increased liquid recovery and breakthrough time in nitrogen flooding process. The improvement in production was shown to be due to a reduction of gravity override caused by in-situ generation of foam at the gas-liquid interface.

A large range of surfactant solutions of various concentrations with different amounts of monovalent and bivalent salts and alcohols has been studied as to their effectiveness as foamers. Surface tension, rate of drainage, bubble size and shape of the foams were measured in each case.

In-situ foaming in the model increased generally with surfactant concentration until the critical micelle concentration (CMC) was reached; above CMC additional amounts of surfactant had very little effect on the phenomenon.

Similar increase of recovery and delay in breakthrough time was observed in oil flooding processes. A slug of surfactant solution was injected into the pack saturated with oil, and water at irreducible water saturation, and then nitrogen was injected. Gravity override was much less than in the case when no surfactant was present.
The Need and Urgency for Unconventional Gas
Authors: Kuuskraa Vello A.
Published: December 2007

Despite the nation's preoccupation with oil, the colorful, turbulent history of coal and the controversy surrounding nuclear energy, neither oil, coal or nuclear is now the dominant U.S. energy source—since the mid-1970's the largest domestic energy source has been natural gas.

In the past year, the nation consumed nearly 80 quads (quadrillion or 1015 BTUs) of energy with domestically produced natural gas providing approximately 19 quads (19 Tcf). In comparison, domestic oil production was 18 quads (3 billion barrels), coal production was 14 quads (600 million tons) and nuclear energy in the form of electricity was 3 quads (250 million kilowatt-hours).

Natural gas is an economically preferable substitute for oil and an environmentally more acceptable source than coal or nuclear for many uses, such as industrial heating. Further, increased domestic supplies of natural gas could reduce imports, lessen the U.S. dependence on foreign energy sources, and help the balance of payments.
Gas Industry Estimates of Unconventional Gas Production 1980–2000
Authors: Lawrence G. H. , Davis O. C. , Linden H. R. , Lee B. S. , Schlesinger B. , McCormick W. T. , Kalisch R. B.
Published: December 2007

The authors of this paper prepared a series of analyses of the supplemental supply sources of natural gas. This study was developed for the use of the Gas Supply Committee of the American Gas Association. The authors operating as a task force prepared a series of individual studies which were then integrated into a single report which will be published as the proceedings of the Gas Supply Committee workshop II. This SPE-DOE paper has been taken from the broader study. It emphasizes the unconventional or non-conventional sources of natural gas and provides sufficient summary data on other supplies of natural gas to facilitate a review of the major findings of the task force with respect to the relative importance of unconventional sources of gas.

This paper provides a review of unconventional sources of gas from western tight sands, Devonian shale, gas from coal seams, SNG from peat, SNG from oil shale, gas from geopressured aquifers, gas from urban waste and animal residues and gas from biomass. The potential gas supplies from all sources are compared for four specific scenarios to illustrate the variability of the gas supply because of different national energy policies.
Effects of Fracture Fluids on Devonian Shales
Authors: Miller James F. , Boyer J. Parke , Kent Susan J. , Snyder M. Jack , Sharer John C.
Published: December 2007

The gas resource locked in the thick hydrocarbon-bearing Devonian shales which underlie much of the Eastern U.S. has been estimated to be up to three times the current proven gas reserves of this country. However, the economic feasibility of producing large quantities of gas from this resource remains in question due to the dense structure and low permeability of these shales. Hydraulic fracturing which usually must be employed to stimulate the gas flow involves significant risk of formation damage by the fracture fluids and resultant plugging of gas-flow channels. Thus, basic investigation of the effects of such fluids on the shale structure and properties, having the objective of developing fracture procedures and technology that will avoid the detrimental damage, is needed.

This paper describes the methods and presents initial results of a current laboratory investigation of the effects of various fluids such as liquid carbon dioxide, aqueous carbon dioxide, water and proprietary fluids on shale under simulated down-hole conditions. The effects, are evaluated by in situ measurements of permeability, before and after treatment with the fluid, under various applied pressures and pressure differentials. The nature and extent of the "skin effect." are evaluated by examination of the microstructure of the shale.

It is expected that the results will provide additional insight into the mechanisms of formation damage and will provide guidance to the design and utilization of commercial fracture technolgoy.
Utilizing Well Interference Data in Unconventional Gas Reservoirs
Authors: Sawyer W. K. , Alam J. , Rose W. D.
Published: December 2007

This paper describes the use of a dual porosity radial gas flow simulator for estimating values for the key parameters controlling gas production from the Devonian shale or similar unconventional resource. Using best estimates from the literature on shale fracture and matrix properties as a starting point, the model is used to history match production decline and cumulative production data from a Devonian shale well in Meigs County, Ohio. Three sets of parameters were obtained which gave good agreement with the production data. Utilizing simulated pressures at a distance of 96 feet (29.3 m) as a third matching parameter, it was possible to distinguish between the three cases and thus obtain a "more unique" match.

From the results obtained it is concluded that interference data can provide additional information needed for determining the key parameters that control shale well deliverability.
After the Technology, What Happens?
Authors: Merrill Timothy W.
Published: December 2007

An underlying premise to the Unconventional Gas Recovery (UGR) Program seems to be: given adequate technological solutions and proper economic incentive, the marketplace can accommodate any and all volumes of produced gas. My paper explores this hypothesis by examining the gas industry infrastructure as it exists today in the Appalachian Basin.

The UGR Program as structured by the Department of Energy (DOE) identifies four unconventional gas sources methane recovery from coal beds, eastern gas shales, western gas sands, and geopressurized acquifiers. The third category - western gas sands - may have evolved from a category which had been called "tight gas basins in a report written by Lewin and Associates, Inc. (published in summary form in The Oil and Gas Journal, June 12, 1978, under the title "Vast Potential Held by Four ‘Unconventional’ Gas Sources.)" On August 29, 1979 (Docket No. RM79-76) the Federal Energy Regulatory Commission (FERC) issued its Notice of Proposed Rulemaking in which it proposed to implement Section 107(b) and (c)(5) of the Natural Gas Policy Act (NGPA). Those sections of the NGPA charged FERC with setting incentive prices for gas produced under such conditions which present extraordinary risks or costs. The FERC has identified that gas produced from tight formations may indeed present such extraordinary risks and costs. Although the initial proposed rulemaking identified only western sand formations as qualifying for a tight sands definition, the tight sand definition guidelines would encompass - in some peoples’ minds - certain Appalachian sands.

Thus, it might be argued that three of the UGR programs (methane recovery from coal beds, eastern gas shales, and "tight sand formations") have particular relevance for the Appalachian gas producing, transmission, distribution, and gas usage industries. To proceed with the technology of UGR without a thorough knowledge of these industries may constitute a major oversight. Why invent a perfect mousetrap if no one wants it? It is conceivable that the technology to produce Devonian shales will be established someday and the price "right," but the gas not be produced for lack of a market. If such a conclusion seems incredible, I suggest that such a condition exists today. Conventional gas drilling programs in the Appalachian Basin are currently being either stabilized or reduced. Gas purchasers are not paying NGPA ceiling prices though we are all well aware that better than ceiling prices are being paid for other "commercial" sources of gas (Canadian, Mexican, LNG). The reason for such an apparent inconsistency lies not in any conspiracy theory or monopolistic domination, but in the history of Appalachian gas production and in its current industry infrastructure.
Utilization and Recovery Economics for Vertical Wells in Coalbed Methane
Authors: Gillies Alexander , Snygg Arnold J. , Dickehuth Debra
Published: December 2007

Previous economic studies of the recovery and utilization of methane from coalbeds using vertical wells were based on drainage in advance of mining where a single seam is drained with well spacing designed for rapid predrainage. A production economics study has been conducted which shows that the lower overall investment costs for wider spacing and increased production from multiple seams result in gas recovery at costs well below current prices for new gas imports. When applied to some of the thicker, deeper Western coals, the method also results in a favorable ROI.
Earth Stress Relationships in the Applachian Basin
Authors: McKetta Steven F.
Published: December 2007

This paper presents a derived stress ratio which permits the identification of the extent of the regional tectonic forces acting upon a formation. Once identified, these tectonic forces allow certain inferences to be made about the maximum potential of natural fracturing present in a formation. Investigation of three gas producing formations in the Appalachian Basin shows that the Berea sandstone, the Clinton sandstone and the Devonian Shale all display a similar tectonic relationship. This leads to the conclusion that much of the Basin can be categorized into different stress regions with each region relating the degree of natural fracturing present.
Unconventional Exploration for Natural Fractures
Authors: Hennington W. M.
Published: December 2007

This is a progress report on the evaluation of a new unconventional exploration technique for locating the natural fracture reservoirs in the Devonian - Ohio Shale. Five PHASE I tests have been drilled, cored, logged, cased and are currently being tested. Findings to date indicate that the technique has been successful in predicting the presence of natural fractures. In the six well PHASE II program, scheduled for later this year, the technique will be used to define the limits of these fracture systems. If PHASE II is successful, the project will have demonstrated that natural fracture reservoirs can be selectively located with a high degree of certainty.
Preliminary Results of the Wells-of-Opportunity Geopressured-Geothermal Testing Program
Authors: McCoy Rayford L. , Hartsock James H. , Dobson Richard J.
Published: December 2007

The Fairfax Foster Sutter No. 2 well located in the East Franklin area of St. Mary Parish and the Beulah Simon No. 2 well located in the Kaplan area of Vermilion Parish, Louisiana were the first successful tests of geopressured-geotherman (Geo2) aquifers under the Well of Opportunity (WOO) program. Gruy Federal assumed the Fairfax Foster Sutter operation on March 8, 1979 when the operator abandoned attempts to discover conventional hydrocarbons at a total depth of 16,340 ft. The Simon No. 2 well was acquired under similar circumstances approximately one month later at a total depth of 15,265 ft.

In both tests, the objectives were all accomplished and data were obtained which will contribute to the overall assessment of the geopressured-geothermal resource of the upper Gulf of Mexico basin. In both instances, the gas solubilities (22.8 and 24.0 scf/bbl) indicated that the waters were saturated with gas at reservoir conditions. The produced water was more saline than expected (190,000 mg/1 in one instance, 104,000 mg/1 in the other). {The high concentrations of dissolved solids in these waters created a scaling problem that required significant attention and will have to be addressed in future tests.1}
Test Results of Stimulated Wells in Devonian Shales
Authors: Kumar Raj M. , Hartsock James H. , Frohne K. H.
Published: December 2007

The long test times required to attain radial flow in stimulated Devonian shale gas wells are impractical. However, experience shows that a short test period (about two weeks) is sufficient to evaluate reservoir and fracture properties using conventional techniques followed by mathematical simulation of the observed pressures. History matches, whether unique or not (insufficient production data are available at present to establish uniqueness), give clear insight into reservoir properties, the effectiveness of frac treatment, and well deliverability.
Determining the Feasibility of Using Vertical Boreholes to Drain Gas from the Pocahontas No. 3 Coalbed, Buchanan County, Va
Authors: Trevits Michael A. , Richards Walter L. , Von Schonfeldt Hilmar A.
Published: December 2007

In July 1979, a project was established to determine the feasibility of using vertical boreholes to degasify the Pocahontas No. 3 coalbed in advance of mining. To date, three methane gas drainage boreholes have been completed near the Virginia Pocahontas No. 5 mine in Buchanan County, Va. Various coalbed reservoir tests and in-situ stress determinations have been performed. Hydraulic stimulation treatments were designed and implemented at two boreholes, followed by preliminary gas and water production testing.
Prediction Of CaCO3 Scale Under Downhole Conditions
Authors: Vetter O. J. , Kandarpa V.
Published: December 2007

CaCO3 is one of the most common scales in oilfield and geothermal operations. Various thermodynamic models have been reported in the literature to predict the precipitation of CaCO3. Each of these existing models has its limitation when applied to the real situations of the field operations. Some models (e.g., Stiff-Davis method) ignore many conditions leading to CaCO3 precipitation.

In the present paper, we describe a model to predict the CaCO3 scale formation at any location within the field as a function of water composition, temperature and pressure. This model is based on equilibrium thermodynamics, but uses only the experimentally measured parameters. The input data for the model are (1) one water analysis, (2) one pH measurement at any location in the field, (3) the temperature at which the only field pH measurement is made, (4) the CO2 concentration of the gases (if a gas phase exists upstream or at the point where the liquid sample is taken and the pH is measured), and (5) the amount of flash (if a gas phase exists upstream or at the point of sample collection). The model then takes these measured data and calculates the equilibrium brine composition (including pH) in the reservoir.

The calculated brine composition data can then be used either to predict the CaCO3 precipitation for any set of prescribed conditions or to predict the CaCO3 precipitation at various locations within an oilfield or geothermal operation. For a set of temperature and pressure, the model goes through a decision to determine whether a single phase or two phase condition exists for the brine.

For the case of the existence of the single phase brine, the model calculates the amount of CaCO3 precipitate taking into account the pertinent chemical reactions involving the various carbonate species.

For the case of the existence of two phase brine, the model first computes the CO3 emission and its effect on the pertinent reactions Involving the various carbonate species and, hence, calculates the amount of CaCO3 precipitate.
Successful Stimulation in the Rocky Mountain Area Using a New Acid Base Gel System
Authors: Coulter Gerald R. , Harris Larry E. , Klebenow Don E.
Published: December 2007

In hydraulic fracturing of some sandstone formations, it is desirable to use a low concentration of hydrochloric acid as the base fluid. This fluid is desired in these formations due to its superior fluid-rock compatibility characteristics. However, due to the rapid degradation of most gelling agents with hydrochloric acid, it has been difficult to place large quantities of propping agents.

A new gel system has been developed with imparts greater viscosity and a more stable get than previously available to the industry. This new gel system utilizes a low residue polymer, crosslinked with a unique crosslinker, in the presence of 3 to 5 percent HCl. The temperature stability and Theological properties of this get are presented in the paper.

A large number of treatments have been carried out with this gel system in various formations. For the purpose of this paper, we will discuss the treatments conducted in the Teapot formation in Wyoming.
The Use of Viscosity Stabilizers in High Temperature Fracturing
Authors: Elbel Jack L. , Thomas Ron L.
Published: December 2007

A new viscosity stabilizer that increases the high temperature performance of fracturing fluids has been developed. It reduces the rate of viscosity loss of the fracturing fluid during the treatment resulting in more efficient prop transport. This is especially important in massive hydraulic fracturing where the fluids are exposed to high temperatures for long periods of time.

The new stabilizer was developed as a replacement for methanol which has traditionally been used as a stabilizer in high temperature fracturing applications. Unlike methanol, the new stabilizer is nontoxic and nonflammable.

The effect of a stabilizer on the long-term rheological properties of fracturing fluids and the resulting effect on the predicted prop placement are discussed. A comparison of computer predicted fracture geometries is made for fluids containing methanol and the new stabilizer. Field treatments incorporating viscosity stabilizers are also discussed.
The Effects of Power Supply Integrity on Electric Submergible Pumping Systems
Authors: Stewart Richard E.
Published: December 2007

Little has been written regarding the effects of electric power integrity on submergible pumping systems. The remoteness of a site and/or the economics of the distribution system can result in power which affects equipment life and efficiency. Other installed electric devices or systems can also impact the quality of supply. The purpose of this paper is not to condemn the circumstances which lead to deficient power supply situations, but rather to address their effects and discuss practical means of correcting or minimizing their effects.
A Computer-Processed Wellsite Log Computation
Authors: Best D. L. , Gardner J. S. , Dumanoir J. L.
Published: December 2007

A new logging unit with an integrated system of surface instrumentation built around a computer allows digitally recorded logs to be merged, computed, and recorded on film at the well site.

The SCHLUMBERGER CYBERLOOK wellsite computer processing utilizes the recently introduced "Dual Water" interpretation model for reservoir analysis. This model considers a shaly, water-saturated formation to behave as if it contains two types of pore water: "clay water" near the surfaces of clay crystals and "far water" at a distance from the clay surfaces.

The processing is designed so that all required input parameters can be accurately selected from a first-pass merge. The computations, corrected for shale and light-hydrocarbon effects, are presented on film in a format that is easily interpreted, allowing decisions to be made at the wellsite.

Field experience has shown the processing to be very flexible, providing excellent results throughout North America in both sandstone and carbonate reservoirs.
Secondary Recovery by Butane Injection in San Pedro Block D
Authors: Moscrip Robert
Published: December 2007

A secondary recovery project involving butane injection followed by injected gas has been in progress in San Pedro Block D for six years. Data are presented covering both the primary and secondary phases of the depletion history. A discussion of the field operation is also presented.

Results or this field test indicate that substantial increases in oil recovery can be obtained by this secondary recovery process and that essentially all or the injected butane can be recovered with the produced fluids.

Introduction

The volume of butane extracted from natural gas in northwestern Peru has exceeded the market demand for many years. From 1941 until 1951, this excess butane was stored in a depleted reservoir. Although some additional oil was obtained as a result or butane storage, optimum recoveries from the butane injection process could not be expected in this reservoir because or unfavorable reservoir conditions. Therefore, San Pedro Block D was selected as a prospect for observing the operation or the solvent extraction process under controlled field conditions. The procedure used during the field test involved the injection or butane to form a flood bank followed by gas injection to drive the bank toward the producing well. Because the Block D reservoir was small and isolated from adjacent productive areas, the results or butane injection could be obtained in a very short time.

The San Pedro pool was discovered in May, 1946, with the completion or Well 3637 in the Parias sand. The results or subsequent development drilling indicated that the pool was divided into four small fault blocks. These blocks are labeled A, B, C, and D on the structure map in Fig. 1. Because this structure map differs somewhat from those normally used, it will be discussed in detail in the geological section.

Following the discovery well, three producers were completed in Block D by June, 1948. However, one or these was abandoned after producing only a small amount or oil. Subsequent pressure production behavior proved that the 20-acre Block D reservoir was isolated from the rest of the pool and that dissolved-gas drive provided the predominant source of reservoir energy. Therefore, secondary recovery operations were undertaken to increase the ultimate oil recovery from this block and, at the same time, to provide a controlled field test or the solvent extraction process.

The project was initiated in the Block D reservoir during Oct., 1951 by injecting butane into crestal Well 3794. During the 2.8-year period or butane injection, the rate or oil production from Well 3807, the well nearest to the point of injection.
A New Integrated Material Balance Equation for Reservoirs Containing Only Oil and Water: Line Drive
Authors: Lesem Louis B. , Guy W.T. , Crawford George W.
Published: December 2007

Some or the equations used by petroleum engineers in analyzing and forecasting the performance of oil fields depend only on the specification of the flux or pressure at a fixed boundary which is determined by the oil-water contact at the time of discovery. This method deals rigorously with the two-regional series-flow-problem actually involved in reservoir performance; namely, flow throughout the aquifer and within the reservoir proper. In the reservoir proper the two-phase liquid system [oil and water] and the pertinent physical properties of each at any time have considerable effect upon the behavior of the entire fluid flow system [aquifer-reservoir]. Consequently the equations developed by this analysis make possible the more accurate evaluation of reservoir performance and of oil-in-place from conventional pressure and production data and the more accurate forecasting of the future performance of a reservoir containing only oil and water subject to a linear drive.

Introduction

Several methods for the calculation of water influx into an oil reservoir have been published in which the mathematical treatment has been concerned only with flux in the communicating aquifer. For this reason the results obtained using these methods cannot be applied rigorously to predict the behavior of an oil reservoir subject to encroachment of water. A mathematical model which more nearly fits the existing physic situation in petroleum reservoirs is one that considers flow in both the oil and water bearing regions.

Although the oil-water boundary in a petroleum reservoir moves as oil is produced, the solution to the problem of flow in two regions having an immobile boundary should be a close approximation for short periods of time. If at the original oil-water boundary resistance to flow is high the relations developed are valid for longer periods of time.

The unsteady state flow of fluids in a homogeneous porous medium is assumed to obey the general heat flow equation. The fluid diffusivity in the outer regions differs from that in the inner region, and the inner region may be treated as a uniform fluid sink. The problem is solved in one-dimensional linear geometry.
Political Risk Insurance and Project Financing of Petroleum Projects BT the Overseas Investment Corporation
Authors: Mansbach B. Thomas
Published: December 2007

What is OPIC? U.S. Government Agency Designed to promote development through U.S. investment in LDC’sObligations are supported by the full faith and credit of the U.S. GovernmentOperate at a Profit - $58 million in 1979 Self-sustaingDue regard for risk managementNot in competition with commercial banks Operates either alone or in concert with: Commercial banksInternational financial institutions and regional development banksEximbank and other suppliers’ credit organizationsCurrent Status Five projects - Jordan, Ghana, Egypt, Greece and PakistanOver 75 registrations by more than 30 companies in 30 countriesOrganic program designed to meet industry needsAll information provided to OPIC is accepted on a privileged information basis Insurance Coverages Availability--Exploration and development/production stages Investor can take one or more of the coveragesInconvertibility - Coverage A Changes in currency transfer laws, regulations and procedures Active blockage -- 30 daysPassive blockage -- 60 daysDoes not cover devaluationMeasure of recovery -- transfer function: Local currency delivered in host country for dollars delivered in the U.S.Expropriation - Coverage B NationalizationCreeping ExpropriationMust last for six monthsExceptions: For example BankruptcyProvocationVoluntary agreementsNational government activity that does not violate international law standardsMeasure of recovery -- Net unrecovered costs (investment less cost recovery) in return for assignment of insured interest in project agreements In convession agreements, where there is no cost oil/profit oil formula, such a formula would be imputedWar/Revolution/Insurrection - Coverage C Damage to physical propertySpecial coverage for financial institutionsMeasure of recovery -- the lesser of original installed cost or cost of repair or replacementInterference with operations - Coverage D Closure of project due to personal physical hazard of project employees for six months due to war/revolution/insurrectionMeasure of recovery -- net unrecovered costs in return for assignment of insured interest in project agreementsDuring the first five years, either investor or OPIC may require a reassignment of interest in agreements to investor in exchange for return of compensation, without interest
SPE 921(A) Current Perspective On Gas Well Testing Objectives, Methods, Procedures, Analysis And Requirements Of Producers, Purchasers, Storers And Regulators - Producers
Authors: Schrenkel Jack
Published: December 2007

A brief review of the various methods of testing gas wells and examples of their interpretation is presented.

OBJECTIVES OF WELL TESTING - PRODUCERS

Gas wells are tested for several different reasons. Among these are tests to satisfy the requirements of State Regulatory Agencies, both for the initial test period and periodic testing for use in gas allocation formulas. Tests are made to determine present and future deliverability. Wells are tested to meet the requirements of pipe line companies as to contract specifications of deliverability, line pressure, volume, and quality of gas. Tests are also run to evaluate the efficiency of completion and to determine if the deliverability of the well can be permanently improved by various stimulation procedures.

One important objective is obtaining adequate physical tests to correctly select the production equipment in order that the maximum profit may be obtained from the gas supply and that delivery of gas can be maintained during severe weather conditions.

Well tests are used for the very important purpose of determining gas reserves. The two testing procedures which can be used to determine reserves are the "Reservoir Limit Test", which is a determination of the minimum amount of gas connected to the well from its drawdown characteristics, and the periodic measurements of bottom hole pressure plotted against the corresponding cumulative gas production. This data is used to supplement the reserve estimates made by the pore volume or volumetric method.
"Canadian Natural Gas Supply in the Context of North American Energy Requirements"
Authors: McNicholas John
Published: December 2007

I would like to begin my address by thanking the Society of Petroleum Engineers for the opportunity to speak to your Annual Conference about Canadian Natural Gas prospects and how they fit into the energy requirements of the North American continent over the next 20 years. It seems somehow an appropriate topic since the theme of this conference is "Energy Frontiers".

We in Canada are very optimistic about our future energy potential. We are one of the few industrialized countries which has benefited materially from the increase in real energy prices over the past 10 years. There is some truth in the comment that if OPEC had not existed Canada would have had to invent it. The fact of the matter is that Canada is a country which has a very large resource base and has a very exiciting energy future if energy prices are high but we are energy paupers if energy is cheap and abundant.

Our energy supplies are high cost compared to the costs of producing oil in the Middle East and if cheap energy prices, such as prevailed over the 1950's and 1960's, continued through the 1970's or 1980's much of our energy resource base would not be economic: this is true with a vengeance in terms of our future energy supplies which are typically at either a geographic or a cost or a technical frontier. So why are we optimistic? Why do we consider that we have an important role to play in the energy future of our continent? The answer, in large measure, lies in the fact that, as a country, we have barely begun to tap our frontier resource base; because recent trends in exploration in our conventional areas of exploration and production in Western Canada suggest a much larger potential than even the optimists would have suggested 3–5 years ago and because we know that the era of cheap energy is over.
An Alternate Approach to High Volume, A Long Stroke Pumper
Authors: Hollenbeck Alfred L.
Published: December 2007

In September, 1978, a long stroke pumping unit capable of operating with an eighty (80) foot stroke at three (3) strokes per minute was placed in operation at a site in Ventura, California. The unit has provided a measured production rate of 850 BFPD from a pump depth of 10,000 feet with standard API rod pump parts making up the down hole pump. The testing program of one million cycles has proved that the major elements of this pumper are practical and reliable for oil field service.
Thermal History Reconstruction and Estimation of Formation Temperature Using Wireline Formation Tester Measurements
Authors: Zazovsky A. , Haddad S. , Tertychnyi V.
Published: December 2007

A new method for estimating formation temperature from wireline formation tester temperature measurements has been developed1. This method is based on the reconstruction of thermal history, which involves drilling, no-mud-circulation and pumping-out phases, using the model of heat transport in the formation. The model calibration is achieved by fitting the predicted temperature at some intermediate distance from the borehole for the temperature data measured in flowline during pumping-out. The temperature found in intermediate zone is then extrapolated to the boundary of cooled zone surrounding borehole for estimating initial formation temperature.

The forward model used for thermal history simulation is simple and robust. It does not involve the borehole temperature modeling during drilling and can be calibrated with a single parameter - either the average mud temperature opposite the tested interval or the average heat flux from the formation during drilling. Although this model cannot predict accurately the initial phase of thermal history (drilling and no- mud-circulation), it becomes adequate for the pumping-out phase when the details of borehole temperature variation with time during drilling become insignificant. The only parameter that affects solution during this phase is the total amount of heat extracted from the formation during drilling.

This approach in order to be successful imposes some constraints on the timing of thermal history phases. In particular, the no-mud-circulation phase should not be too long and the pumping-out phase should not be too short, otherwise the deterioration of resolution may occur. The examples are given that illustrate the capabilities of new technique.
Preventing Differential Sticking and Mud Losses Drilling through Highly Depleted Sands – Fluids and Geomechanics Approach
Authors: Benaissa Saddok , Bachelot Alain , Ricaud Jean , Arquey Gerard , Yi Xianjie , Ong Seehong
Published: December 2007

Drilling through depleted sands can result in a multitude of problems such as lost returns, differential sticking, difficult logging and/or not being able to reach the target depth. Often curing lost circulation can be difficult and costly as a result of associated nonproductive time and escalating mud costs. Remedies such as cement plugs, squeezes, expandable liner and casing while drilling can be costly solutions.

The use of fluid management techniques, team efforts and proper engineering have lead to the development of an innovative approach to prevent problems and avoid the complex processes of curing mud losses and freeing stuck pipe. This new preventative approach with water-based mud has been applied in several fields, while drilling through a series of highly depleted sands and has proven to be very effective in preventing differential sticking and mud losses.

Although operationally successful, the geomechanics and the fluid design resulting in these successes are not well understood. A geomechanical analysis indicates that two mechanisms might contribute to the success: (1) The near wellbore region is turned into a non-porous rock because the particles in the new mud tend to block the pore spaces. The theory of poroelasticity indicates that fracturing pressure is increased by reducing the difference between mud pressure and the pore pressure immediately behind the borehole, which for non-porous rock is zero. (2) Because of this blockage, it is possible that the near wellbore rock strength is increased. This strengthening effect decreases tangential stress and increases fracturing pressure.

The geomechanics model can be used to define the operational limits of various mud weights with proper drilling fluids design. This model would enable a consistent and focused approach on drilling fluid design to effectively mitigate massive fluid losses associated with drilling through severely depleted sands or in narrow pore pressure/fracture gradient environments.
Reservoir Discription from Production Data
Authors: Callard Jeffrey G.
Published: December 2007

Reservoir limit test analysis for wells producing at constant pressure can be made from readily available production data or production decline curve plots. Constant pressure production is not uncommon for oil and gas wells flowing into separators, pipelines, or artificial lift wells produced at capacity.

Determination of reservoir pore volume contacted by a wellbore within either natural or no flow boundaries is the main objective of the reservoir limit test. When combined with infinite acting analysis for permeability, effective wellbore radius or fracture length can be determined.

A case history of a low permeability gas reservoir previously published1 is used to apply the techniques of transient rate analysis for a bounded reservoir in combination with pressure transient analysis for an infinite acting system to provide evaluation of sand frac stimulation treatments.
Reservoir Potential as a Function of the Geological Setting of Carbonate Rocks
Authors: Lapre J. F.
Published: December 2007

The geometry and reservoir properties of carbonate rocks often show a relationship with the original depositional conditions. The critical depositional parameters, with regard to the development of reservoir properties, are the sedimentary fabric and the genetic external geometry. The fabric can be defined as determining the ‘reservoir potential’.

Accordingly, it is of importance to know the reservoir potential of the various carbonate deposits, e.g. build-ups, shoals/banks, and carbonates of lagoonal to tidal nature. Their sedimentary-framework can comprise one, or both, of two basic types of reservoir potential – GRAIN-SUPPORTED, MUD-SUPPORTED ROCK.

Depending on burial compaction, shallow and deep-burial diagenesis, the reservoir potential can be – preserved – enhanced – destroyed. Also, either grain or mud support can be selectively enhanced or destroyed. Although often a grain-supported reservoir rock will have better reservoir potential than mud-supported rock, which it may retain, occasionally this relationship will be reversed by certain types of diagenesis.

The control of the distribution of the reservoir potential within the various carbonate deposits depends on the relationship in time between rate of carbonate growth and the evolution of the topographical relief of the marine shelfs. Examples of the control are shown.

In addition to the variation in the distribution of reservoir potential, the distribution of bed-parallel barriers to vertical cross-flow can be predicted on the basis of the overall characteristics of the sedimentary process. The rocks which most likely contain barriers to vertical cross-flow are the sediments which occur at the interface of cycles of deposition.

Schematic drawings and summary-diagrams of field studies demonstrate the above relationships, which can also be used for the design of sections for reservoir engineering simulation.
The use of Bottom Hole Pressure Analysis in Optimizing Frac Design-Anadarko Basin of Western Oklahoma
Authors: Lent J. T. , Nickell R. L. , Davis W. E. , Allam A. M.
Published: December 2007

For several years, fracture designs for the deep Morrow in the Anadarko Basin were made using assumptions of the formation parameters: Permeability, bottom hole pressure, and fracture conductivity. Recent pressure transient analyses have shown that these assumptions in some cases were incorrect for permeability and bottom hole pressure. In addition, laboratory testing with sintered bauxite proppants has produced a means of achieving sufficient fracture conductivity to sustain production increases obtained with successful fracture stimulation.
A New Method to Account for Producing Time Effects when Drawdown Type Curves are Used to Analyze Pressure Buildup and Other Test Data
Authors: Agarwal Ram G.
Published: December 2007

Currently, type curve analysis methods are being commonly used in conjunction with the conventional methods to obtain better interpretation of well test data. Although the majority of published type curves are based on pressure drawdown solutions, they are often applied indiscriminately to analyze both pressure drawdown and buildup data. Moreover, the limitations of drawdown type curves, to analyze pressure buildup data collected after short producing times, are not well understood by the practicing engineers. This may often result in an erroneous interpretation of such buildup tests. While analyzing buildup data by the conventional semi-log method, the Horner method takes into account the effect of producing time. On the other hand, for type curve analysis of the same set of buildup data, it is customary to ignore producing time effects and utilize the existing drawdown type curves. This causes discrepancies in results obtained by the Horner method and type curve methods. Although a few buildup type curves which account for the effect of producing times have appeared in the petroleum literature, they are either limited in scope or somewhat difficult to use.

In view of the preceding, a novel but simple method has been developed which eliminates the dependence on producing time effects and allows the user to utilize the existing drawdown type curves for analyzing pressure buildup data. This method may also be used to analyze two-rate, multiple-rate and other kinds of tests by type curve methods as well as the conventional methods. The method appears to work for both unfractured and fractured wells. Wellbore effects such as storage and/or damage may be taken into account except in certain cases.

The purpose of this paper is to present the new method and demonstrate its utility and application by means of example problems.
Colorado River Water-Energy-Politics
Authors: Fischer Roland C.
Published: December 2007

The Colorado River is one of the most controlled, one of the most controversial and the most litigated river in the world. Its limited water resources are the subject of intense competition for irrigation and municipal uses and soon that competition will increase as the energy resources of the Colorado River Basin are developed to help meet the energy challenges facing the United States. The competition for the waters of the Colorado River has been growing since before the turn of the century and shows no signs of decreasing. Historically, that competition has to a large extent been resolved in one political arena or another and like the competition, the politics surrounding Colorado River water show no signs of decreasing. Although a great deal has been written about the "Law of the River" which is generally thought of as meaning the two Congressionally-approved interstate compacts, (1922 and 1948); one international treaty (1944); and, the laws of the 7 states that comprise the Colorado River Basin, politics and to a fairly large degree emotion, have been a significant and often controlling means by which the waters have been allocated and applied to beneficial use. The seven basin states are California, Arizona and Nevada in the Lower Basin (below Lee Ferry, Arizona) and Colorado, Wyoming, Utah and New Mexico in the Upper Basin (above Lee Ferry, Arizona). Arizona and Utah are hydrologically partly in the upper and Lower Basins

The first of the landmark documents dealing with the division of the waters of the Colorado River and agreed to by the seven states and the United States is the Colorado River Compact of 1922, which provides for the equitable division and apportionment of the use of the waters of the Colorado River system. Even then California was growing faster than the other basin states and politics played an important role in the way the compact was finally ratified. Today California waters approximately 11 million people with Colorado River water and has 45 members in both houses of the United States Congress; Colorado has 7. These numbers speak volumes politically.

The Upper Basin states recognized early on that they would have to agree to apportion their waters by a more specific formula and in 1948 entered into the Upper Colorado River Compact which apportions the water among the 4 Upper Basin states: Colorado, 51.75%; New Mexico, 11.25%; Utah, 23%; Wyomong, 14%. This compact establishes the Upper Colorado River Commission and the Upper Basin states fund it in the same ratio as their share of the water. However, when the Upper Colorado River Basin Fund was established by the Colorado River Storage Project Act in 1956 the states agreed to share the fund with 46% to Colorado; 21.5% to Utah; 15.5% to Wyoming and 17% to New Mexico. Politics was instrumental in the decision to share the water and the money on different bases.
Prediction of Deliverability from a Multi – Well Gas Reservoir
Authors: Baldwin James O.
Published: December 2007

This paper describes a technique for accurately predicting gas deliverability from a multi-well gas reservoir. The computer program listed in APPENDIX A will simulate a gathering system which has a gas reservoir being drained with multiple wells and compressor stations – for example, an offshore gas reservoir being exploited by several platforms with each platform having its own compression facilities. By using this program, Marathon Oil Company has been able to quickly and accurately predict gas deliverability from an offshore gas field located in the Gulf of Mexico with varying horsepower availability at each compressor facility as well as account for increased well deliverability resulting from workovers, well recompletions, stimulations, etc.
A Method for Appraising the Feasibility of Field-Scale CO2 Miscible Flooding
Authors: Drennon M. D. , Kelm C. H. , Whitington H. M.
Published: December 2007

Amoco Production Company is actively investigating the potential for recovering tertiary oil. This paper describes the evaluation process of scoping studies performed to determine the economic feasibility of CO2 flooding West Texas properties which are currently being depleted by waterflood operations. This method was applied to the evaluation of eleven Amoco operated properties in seven fields in the Permian Basin, encompassing 2300 producers and 1600 injectors. Also included in this paper are a number of technical, operational and practical concerns which have been identified during the evaluation process.

The procedure used to evaluate the feasibility of CO2 flooding a property, as described herein, is as follows: 1)Develop a reservoir description by using a reservoir simulator to match past waterflood performance. Requisite to this process is an understanding of the performance being simulated.2)Predict future waterflood performance.3)Predict tertiary performance by employing a simulator of miscible CO2 displacement which contains the previously developed reservoir description.4)Generate incremental tertiary economics using predicted tertiary rates and reserves, along with estimates of necessary investments and operating costs.

This paper includes a discussion of the methods used to match past waterflood performance of entire properties. Where available, geological data was incorporated in developing reservoir descriptions. Detailed geological evaluations of the properties are in progress which are expected to contribute to and support future refinement to the performance derived reservoir descriptions. In several cases, completed geological evaluations support the reservoir descriptions generated through performance matching. Amoco has an extensive pilot program underway in West Texas which will demonstrate the validity of the prediction technique and provide data for development of improved prediction methods.