bluuebunny/crossref_metadata_2025 huggingface dataset:
CT Studies of Surfactant-Induced CO2 Mobility Control
Authors: Wellington S. L. , Vinegar H. J.
Published: December 2007

Foam mobility control for was studied by Computerized Tomography (CT) in tertiary first-contact miscible corefloods. The CT images show that injection of 0.05 wt% Neodol 25–12 Ethoxy Glycerol Sulfonate (NEGS 25–12S) in brine prevents gravity and viscous instabilities, and enables CO2 to displace all the oil from cores in a piston-like manner.

Surfactant screening tests, designed to test the debilitating effect of temperature, salinity, and crude oils on foam performance, are described. NEGS is both temperature and salinity tolerant: it forms stable foams with CO2 in the presence of oil to at least 76 deg C with hard brines containing at least 18 wt% TDS.

CT studies revealed a combination of factors contributing to effective CO2 mobility control. These include both increases in apparent CO2 viscosity and capillary pressure changes which produce a high-saturation brine bank insitu. This brine bank separating the CO2 and oil banks further reduces CO2 mobility through relative permeability effects but does not impair oil recovery efficiency by brine-shielding mechanisms.
The Application of a 2-D Compositional, Radial Model To Predict Single-Well Performance in a Rich Gas Condensate Reservoir
Authors: Clark T. J.
Published: December 2007

This paper illustrates the use of a two dimensional (2-D), compositional, radial model to simulate a producing well in the Nugget reservoir of the Anschutz Ranch East Unit. The single well model used an eleven layer vertically heterogeneous reservoir description (kv > 0) with a nine component fluid characterization to predict producing well behavior and condensate saturation development both before and after the breakthrough of injection gas (used for reservoir pressure maintenance). The simulation effort showed that there would be no detrimental effect on condensate recovery or well performance caused by removing the Unit imposed 3,500 psi (24 132 kPa) bottom hole pressure drawdown limit. The simulation work also indicated that the extreme gas productivity increase experienced after breakthrough was the result of lower gas viscosity and higher gas relative permeability in the breakthrough layers, and that a single layer could be responsible for the majority of the gas productivity increase.
A PDC Solution to Drilling Sticky Formations With Noninhibited Water-Base Drilling Fluid: Experience in the Provincia Field in Colombia
Authors: Koskie E. T. , Appen H. E.
Published: December 2007

This case history documents the successful drilling of sticky clays, clay-stones and shales with non-inhibited, water base drilling fluid using a Polycrystalline Diamond Compact (PDC) bit designed specifically for this application. In the Provincia field of Colombia, where sticky clays, claystones and shales present just this sort of problem, a fishtail-style PDC bit has been found to be the best solution to date to drill these formations. It's use has resulted in a reduction in drilling time per well in this field of about 30%, i.e. a savings of from five to seven days per well.
Damage Ratio from With Variable Drill-Stem Tests Back Pressure
Authors: Kazemi Hossein
Published: December 2007

The drill-stem test [DST] is a temporary completion designed to sample the reservoir fluid and to establish the possibility of commercial production. It also yields values for the permeability capacity of the formation, for wellbore damage and for static reservoir pressure. The conventional interpretation is based on the assumption that the production rate is constant during the flow period.

In fact, flow is not constant because the fluid column rising in the drill pipe exerts a time-variable back pressure on the face of the formation exposed in the wellbore. The effect of the resulting variable flow rate on damage ratio obtained from conventional DST analysis is studied in this paper. For the case of high fluid productivity, conventional analysis yields a higher formation capacity and a lower damage ratio than the true values. The error in the damage ratio is particularly large. The method of Odeh and Selig1 will improve the flow capacity calculation considerably. However, they do not calculate the formation damage. A method for calculating the damage ratio is suggested here.

INTRODUCTION

The drill-stem test [DST] is a production test carried out through a temporary completion; it is designed to sample the reservoir fluid and to determine the possibility of commercial production. The test is carried out by attaching a fluid sampler to the drill collar and lowering the sampler to the zone to be tested. One or more packers, which are part of the tool, are set to isolate the formation from the mud column in the wellbore; then the formation fluid is directed into the sampler and subsequently into the drill pipe. A clock-driven recording gauge records the pressure variations. After a short period of production, the valve between the drill string and the sampler is closed; the recording of the bottom-hole pressure continues and corresponds to a short buildup test. The plot of this pressure on a linear scale vs [T+ ?]/? on a logarithmic scale is a curve, an analysis of which yields values for formation capacity [kh], wellbore damage, and static reservoir pressure.2
U.S. Natural Gas Regulation and Markets: Changing the Rules To Fit the Game
Authors: Jimison J. W.
Published: December 2007

Order 436 is the Federal Energy Regulatory Commission's bid to convert the natural gas pipeline industry, traditionally regulated as a natural monopoly, into a semi-competitive and more efficient transportation industry. This paper analyzes the market environment into which Order 436 was introduced, reviews the background and provisions of the landmark action, and assesses its effects, particularly on the pipeline industry. The paper concludes that the Order puts many pipelines into an untenable position given the current market context and has not fully anticipated further market changes.
The Role of Commercial and Strategic Inventories
Authors: Krapels E. N.
Published: December 2007

Petroleum inventories have commercial and strategic implications. In the commercial sphere, the level of petroleum inventories is an indicator of the direction of oil prices in the short term, and a force directly influencing oil prices. As a direct force, the importance of inventories on oil prices has increased since 1978. This increase is due in the first place to the very large size of the storage sector of the oil industry. The system's capacity makes it possible for large volumes to go into and out of the storage system. The size of the flows has become larger since 1978 as a result of the increased uncertainty about the security of supply (1979-81), the decline in demand (1982-1985), and changes in the relations between exporting country governments and oil companies. In the strategic sphere, the increase in government-owned emergency stocks has changed the balance of power in future efforts by oil exporters to impose embargoes or sharp price increases.
Energy Policy and Tax Reform
Authors: Cummings J. R.
Published: December 2007

This paper discusses the history of energy tax reform, as well as the outlook for future changes. Particular emphasis is placed on an explanation of the tax provisions granted to the industry over the years to search for and produce domestic oil and gas and the gradual reduction in those provisions. The paper goes on to discuss the future of energy tax reform, including the impact of a possible import fee.
The Politics of Energy Policy: The Corporate Perspective
Authors: Scott J. N.
Published: December 2007

The energy industry has long been the target for governmental taxation and control. Examples abound, dating back to the early days of this century when the oil and gas industry was developing and coming right down to the second session of this 99th congress. As early as 1906, the Hepburn Act provided for regulations of oil pipelines. A committee chaired by Senator LaFollette in the '20's investigated the petroleum industry with some legislators at that time attempting to set the stage for regulation. Questioning was fierce! During many of these early years the debate over depletion allowance was an annual occurrence. During the 1930's, under the National Industrial Recovery Act, controls were placed on the oil industry though not others. Then, in 1954, came the landmark Phillips case on which the Supreme Court ruled that natural gas prices could be controlled at the wellhead. After 32 years, we are still trying to correct that mistake.

The decade of the '70's was a particularly difficult period for the industry from a political standpoint. Twice, events outside the United States caused supply disruptions and fears that the country was running out of fuel supplies. For some, the oil and gas industry became the scapegoat. There were rumors that loaded tankers were waiting offshore and that gas wells were shut in to force prices higher. There were divestiture bills, windfall profits taxes, and other negative legislative actions. To some extent, the political mood was punitive.

When the hysteria subsided and common sense began to prevail, there seemed to be a basic realization that the oil industry didn't cause the problem (although some, even today, may find it difficult to admit), but that we must have a strong industry with adequate incentive to develop our country's energy resources. There seemed to be a near consensus that the United States should strive for energy independence. There was legislation to encourage leasing of promising offshore areas, to develop alternate energy sources, to encourage conservation, and, to some extent, develop new supplies of natural gas.
Case History Study of Fracture Height Containment in East Texas
Authors: Arp M. E. , Hilton R. E.
Published: December 2007

A discussion of the problems associated with fracture height containment in several producing horizons in East Texas is presented along with a field-proven solution. Fracture height containment has plagued operators in East Texas for years. Fracturing of producing intervals, such as the Georgetown, Buda, Woodbine, Travis Peak and Pettit Lime, has in many cases resulted in unsatisfactory production. The poor production can in many cases be attributed to fracturing out of zone. A technique has been developed to minimize fracture height growth. This patented technique incorporates non-reactive diverting agents to bridge above and below the pay zone. This results in a planned screenout in the vertical directions thus forcing the fracturing fluid to propagate the fracture in the horizontal direction.

Several case histories are presented to show the effectiveness of the technique.
Financial Institution Borrowing Guidelines for Reserve Base Borrowing and Documentation
Authors: Richter T. H.
Published: December 2007

The independent operator has relied on various sources of revenue for decades. The financial institution has been providing assistance for over 50 years. The secured oil and gas reserve loan may be the most common type of financing sought by the independent. Due to possible tax legislation, the investor marketplace is questionable, thus there is increased pressure on financial institutions borrowing to necessitate the fundings for drilling acquisitions and normal operating capital.

Traditional lending institutions now face problems involving energy and energy related loans. The review efforts by these institutions and regulatory agencies have increased loan process analysis to the point that all areas of the financial situation of the operator must be addressed. The rewards of this research can benefit the independent in several areas. Having gathered all data, evaluated it, prepared the presentation and submitting it in a knowledgeable fashion will enable the financial institution to properly and expeditiously reply to the independent operator's loan request.

In order for the independent to achieve this goal, he must be knowledgeable of the information required, the format in which the information should be presented, the relative values the institution places on each item of the package and what it tells the institution. With this information at hand, the independent operator can present a well researched loan proposal and achieve his objective – the loan!
Mechanical Performance of Fiberglass Laminates for Sucker Rod Applications
Authors: Gauchel J. V.
Published: December 2007

This paper will present the results of a program designed to evaluate the tensile, shear, and tensile/tensile fatigue performance versus temperature of typical FRP pultruded laminates used in sucker rods. The predictability of performance and its sensitivity to process conditions will also be discussed.
Roller Rock Bit Hydraulic Program
Authors: Skalle P.
Published: December 2007

In the past the hydraulic program of rock bits with exchangeable nozzles has been determined by optimizing bit hydraulics, i.e. jet impact force, bit hydraulic horsepower etc. Bit hydraulics, however, is alone insufficient as criteria. This paper applied instead rate of penetration as criteria which is a more general and fundamental approach to determine the hydraulic program. The only factors in the rate of penetration equation which are of importance are the hydraulic functions, i.e. functions of pump flow rate and bit nozzle size. It is shown that the only hydraulic functions which have an influence on rate of penetration are bit hydraulics, and the difference between dynamic mud pressure and pore pressure at the bottom of the well. To be able to estimate the hydraulic program, unknown constants must be determined. Therefore, previously known and new empirical constants of the hydraulic functions have been estimated. The optimal solution has been worked into a general computer program, and typical sample calculations show clearly that this new approach has a distinguished effect on existing hydraulic programs.
The Use of a Drilling Model in Simulation, Optimization, and Formation Description
Authors: Malguarnera S. C.
Published: December 2007

A system of equations constituting a drilling model has been developed with the capability to handle all bit, mud and formation types. This model has been used in three application programs:

DRLSIM. A bit run time simulation DRLOPT. An optimization program which predicts termination mechanisms and cost per foot for a range of operating conditions. FORMDES. Foot-by-foot drilling data is used to produce drilling resistance, pore pressure and fracture gradient logs.
Identification, Evaluation, and Treatment of Formation Damage, Offshore Louisiana
Authors: Schaible D. F. , Akpan B. , Ayoub J. A.
Published: December 2007

A field case is presented for an offshore Louisiana oil well on which severe formation damage was identified, evaluated, and successfully treated. The emphasis of the paper is directed towards the techniques employed to identify the presence of the formation damage, evaluate its possible sources, and formulate an acid system which would effectively treat the formation damage.

A comprehensive study of transient pressure test data, nodal1 analysis curves, and production logs was performed to identify the presence of formation damage. After the existence of the formation damage was confirmed, extensive sidewall core studies were undertaken in an attempt to isolate possible causes of the damage. The results of these studies provided information which was used to formulate an acid system which would effectively remove the formation damage from the affected well.

In conclusion, post treatment transient pressure test results and nodal analysis plots are presented to illustrate the success of the acid stimulation performed on the well.
Remedial Methods for Bacterial Formation Damage by Application of Oxidizers
Authors: Ghalambor A. , Hayatdavoudi A. , Beladi K. , Mathemeier P. F.
Published: December 2007

One of the known causes of formation damage in producing wells is through the plugging of the formation by microorganisms. The result of the formation plugging will be a reduction in permeability. There is no effective means to date that can effectively deal with this type of formation damage, which can occur during drilling, completion, or secondary recovery operations. The biocide treatment used in waterflood operations is only effective in killing the microorganisms that are in the water prior to pumping it down the hole, but it will not be effective as far as the future growth of the microorganisms is concerned in the formation. A series of experiments were conducted using cores of Berea sandstone. The permeabilities of the cores were determined after preparation. The cores were then injected with micrococcus luteus bacteria at several different pressures. The permeabilities of the cores were determined again by the same technique under the same conditions. A 50% to 75% decrease in permeability was resulted from bacterial injection (depending on whether the core was cut horizontally or vertically along the formation bedding plane). The cores were examined with a scanning electron microscope (SEM). The SEM study showed that the pore sizes ranging from 0.4 to 10 microns were seriously plugged by the microorganisms. The damage was minimal for the pores larger than 50 microns. The cores were then injected with various volumes of a 2% concentration of oxidizers at several different pressures. The two oxidizers used were sodium hypochlorite and potassium hypochlorite. The results of flushing the cores with an oxidizer was partial restoration of the original permeability. Depending on the core sample, the permeability of the damaged cores was improved by 3% to 25% for the rate of treatment in the study. In the last phase of the study, corrosion tests were conducted. The results of the corrosion test showed that for the same time of exposure of corrosion coupons to the oxidizers, the amount of corrosion was found to be higher than the amount of corrosion for a drilling or some packer fluids. The exposure time of an oxidizer in a field application will be much less than the exposure time of drilling or packer fluids, and therefore, the corrosion for the oxidizer can be considered as insignificant.
Well Return Analysis Causes Re-Evaluation of HCl Theories
Authors: Gdanski R. D. , Peavy M. A.
Published: December 2007

Twenty-five acid return samples taken extensively throughout the post-treatment flow from an offshore Louisiana well showed almost complete consumption of excess hydrochloric acid (HCl) by the HF acidizing chemical process. The high HCl consumption was not due to dissolution of carbonate minerals. This observation appears to run counter to the oil industry belief of several decades that HCl was not significantly consumed in the process of stimulation with HF acid apart from calcite dissolution. Acid returns analysis also revealed an efficient ion exchange acid spending process, almost complete reprecipitation of silicon with an associated dissolution of aluminum, and good surface tension reduction for most of the acid returns.
Formation Damage Tests of High-Density Brine Completion Fluids
Authors: Morgenthaler L. N.
Published: December 2007

Laboratory core flow tests were conducted to assess the formation damage potential of brines with densities between 13.4 and 19.2 pounds per gallon (ppg). Unfavorable fluid/rock interactions are not evident. Recovery of oil permeability is slow but complete, in agreement with established displacement theories. Observed damage effects are the result of instability of the brine or incompatibility with water in the cores. The effectiveness of ZnBr2 in preventing impairment suggests acid soluble impairing materials.
Heavyweight Brines and Corrosion Inhibitors Commonly Used in Brines Affect Various Types of Packer Elements
Authors: Hudson T. E.
Published: December 2007

The use of brines in oil and gas wells as a completion fluid, workover fluid and packer fluid is a common practice. Salts commonly used to make these brines are KCl, NaCl, CaCl2, CaBr2 and ZnBr2.

Under certain conditions these brines are corrosive, and corrosion inhibitors are usually added to reduce their corrosivity on the tubing, casing and downhole tools used in the well. Brines also come into contact with the elastomers (packer elements) used on the downhole tools. Failure of the packer element either by hardening or softening can significantly reduce the time interval between workover operations.

This study encompassed the testing of various types of commonly used packer elements at 250°F (121°C) and 350°F (177°C). These elastomers were tested for 7 and 70 days. The physical properties of packer elements observed throughout the test periods were hardness, tensile strength and elongation.

Brines selected for use in these tests were 14.5 lb/gal (1.74 g/cc) and 16.5 lb/gal (1.98 g/cc) which used CaCl2, CaBr2 and ZnBr2 as weighting agents. Corrosion inhibitors tested were (1) a film-forming amine and (2) a low-molecular-weight organic product which contained sulfur.

The types of rubber elements used in this study were 80-durometer chlorinated polyethylene (CPE), 70-durometer nitrile and 90-durometer nitrile elastomers.
Sand Control Techniques in Shengli Oilfield
Authors: Chen Detan , Zhou Boqi , Liu Zhengze
Published: December 2007

Shengli Oilfield has been developed for more than twenty years. The problem of sand production has existed since its development. About one third of the total oil wells in Shengli have sand problems. This paper describes the techniques of sand control in Shengli Oilfield. Three sections are presented: —Chemical sand control;—*Sand control in steam soaking wells;—Mechanicals and control.

In the past twenty years, twenty-six fields have been put into production in Shengli. The amount of cumulative oil production has reached 240 million tons.

The geological structure of Shengli Oilfieldis very complicated, oil fields are located in many depression basins. The reservoir rocks are Tertiary sandstones of younger geological age, very unconsolidated and produced with different degrees of sand production troubles.

There are sand problems in 2/3 of the reservoir and 1/3 of the producing wells in Shengli Oil Field. Some of these wells have been plugged by sand to a height of 98 — 271 meters. Some of the flowing wells produce oil with a sand content as high as 40% from the start of the production. Due to the severe sand problems some wells cannot even be tested for reservoir parameters in some new exploration areas. For example, in Gudao Field the averaged cumulative sand production per well reached 25 cu. m. and the total cumulative amount of sand produced reached 20000 cu. m. during six years of production: i.e. 11 cu. m. sand per 10,000 t. of oil. Under such circumstances, the research work on sand control techniques and its generalized application have great significance in maintaining peak oil production in Shengli Oilfield.

Shengli Oilfield has a history of 20 years of sand control. Because of the very complicated geological conditions such as multiple faults, great differences in their vertical and horizontal distribution and the wide range of formation permeabilities and oil viscosities existing in various oil pools and very different bottom conditions occurring in the sand producing wells, various sand control techniques are needed for effective treatment. These techniques in Shengli Oilfield are characterized by simplicity, effectiveness and economy. Two types and 8 techniques are mainly used and 3,965 operations had been conducted by the end of 1984.

The sand control techniques of Shengli Oilfield are described in following three sections: —Chemical sand control;—Thermal well sand control;—Mechanical sand control.
Geological Features of Fault Block Oil Fields with Multiple Rock Salt Layers and their Development by Water Flooding
Authors: Yang Shoushan
Published: December 2007

Oil fields located in salt lake fault basins, affected both by the faults and rock salt, have their unique geological features. As wellas Certain production characteristics and special problems in the development by water flooding. The disadvantages are salt and gypsum precipitation and serious corrosion, and the advantages are the good conformance in reversed cyclothem oil reservoir and high oil displacement efficiency of the salt water. Thus it is obviously favorable to develop oil reservoirs with steep structure with high salt content by peripheral water injection. Good results have been made in Jianghan oil region by giving reasonable development and scientific management according to the geological features of such oilfields.
Production Technology of Daqing Oil-Field During its High Water-Cut Stage
Authors: Wang Demin , Tand Jiali
Published: December 2007

This paper discusses the development characteristics and production technology of Daqing Oil Field in its high water-cut stage. Emphasis is placed on the importance of the complete set of technologies of electrical submersible pumps and high volume rod pumps during the transformation of the production mode of Daqing oil wells from flowing to artificial lift. Also, the results of application of the other three production technologies during the high water-cut stage are expounded.
Parameter Estimation in a Naturally Fractured Reservoir by the Method of Cybernetics
Authors: Qi Yufeng , Zhang Xin
Published: December 2007

This article presents an approach for solving the transient flow equations. By means of semi-discretization an approximate analytical solution of a set of partial differential equations describing the compressible fluid flow through naturally fractured formation is derived in a clear and applicable form

P(t)   =   P(O)   +   W(t)Q(O)   + ∫ o t W(t-) Q ¯ · (τ)d

under the most general conditions the details of derivation and the physical concepts of each parameter in that expression are given. Based on those equations, some important parameters such as transmissibility between wells from one porevolumes of each block as well as the location of some faults can be identified by conventional data or well testing data. This method is a new development in the interpretation of well testing data. This paper is a generalization of paper (1)(2) into three dimensions and doubleporosity media.
The Effect of Rock Bit Cutting Structure on Rock Breaking Efficiency
Authors: Hou Jikang , Luo Zhaofeng
Published: December 2007

A study of the effect of rock bit cutting structure on rock breaking efficiency was made with full scale bits for soft to medium formations on a laboratory testing rig. An analysis of the relationship between rock breakage and cutting structure based on the drilling rate, bottom hole pattern and operating parameters revealed the advantages and weak points of the cutting structures. Improvement of cutting structure for some of the tested bits will be adopted in new designs. This approach is also suitable for studying bits for medium to very hard formations.
Single-Well Tracer Test in Complex Pore Systems
Authors: Deans H. A. , Carlisle C. T.
Published: December 2007

About 22 single-well chemical tracer tests have been performed in carbonate formations since 1971, to determine residual oil saturation after water flooding. The results in almost every case have been very different from equivalent tests run in sandstone reservoirs.

The tracer profiles observed in carbonate tests show a set of characteristic distortions. Among these are poor apparent material balance; excessive early dilution of tracers; early arrival of poorly defined peaks for tracers that were displaced away from the well during injection; and abnormally large mean retention volumes, caused by extended concentration tails.

A modified form of the "dead-end" pore model has been shown to reproduce all of these features. The various parameters examined in the model relate to the fraction of the pore space which is non-flowing, connected to the flowing fraction only by diffusion paths. Diffusion of each tracer in the non-flowing pore fraction is a function of tracer distribution coefficient; mixing length in the flowing fraction, equivalent to the usual dispersion parameter; and the residual oil saturation in both pore fractions.

This model has been used to simulate single-well tracer tests in west Texas dolomites, Canadian reefs, and other carbonate formations. The best-fit values of non-flowing fraction of pore space have been 0.40–0.75. The observed diffusion effects, which are a ratio of test duration to the characteristic time of diffusion of tracer in the non-flowing pores, varies from less than 0.5 to more than 5, depending on the test. In the higher range of the diffusion parameter, the tracer profiles approach ideal shape. This indicates that the distribution of tracer between the two pore fractions is near equilibrium. For low values of the diffusion parameter, the profiles are extremely distorted. Slow diffusion limits the access of the tracers to the non-flowing fraction of the pore space.
Characterization of Sandstone Reservoirs for Enhanced Oil Recovery: The Permian Upper Minnelusa Formation, Powder River Basin, Wyoming
Authors: Schenk C. J. , Schmoker J. W. , Scheffler J. M.
Published: December 2007

Upper Minnelusa sandstones form a complex group of reservoirs because of variations in regional setting, sedimentology, and diagenetic alteration. Structural lineaments separate the reservoirs into northern and southern zones. Production in the north is from a single pay sand, and in the south from multi-pay sands due to differential erosion on top of the Upper Minnelusa. The intercalation of eolian dune, interdune, and sabkha sandstones with marine sandstones, carbonates, and anhydrites results in significant reservoir heterogeneity. Diagenetic alterations further enhance heterogeneity, because the degree of cementation and dissolution is partly facies-related.
Mobility-Controlled Steam Drive "MCSD" by the Application of Additives Soluble in Hot Water
Authors: Heinemann Z. , Kratzer D. , Steiner P.
Published: December 2007

Oil recovery by steam and hot water flooding is improved by the application of chemicals which precipitate at the steam or temperature front by conversion from the vaporized or liquid state into the solid crystalline form. The precipitated chemicals form a temporary substance zone in which the permeability for steam and hot water is reduced. The crystallized chemicals are again sublimed or dissolved by the spreading steam/hot water front. The chemicals improve the displacement efficiency of hot water and the sweep efficiency of steam and hot water.
Tricritical Points and the Design of High-Salinity Surfactants for Low-Tension Enhanced Oil Recovery
Authors: Smith D. H.
Published: December 2007

A major objective of low-tension, surfactant-polymer flooding is the design of surfactants for high-salinity reservoirs. In this technology the irreducible oil saturation, hence the recoverable oil, depends on the interfacial tension between the aqueous and oleic phases.

In the three phase systems that are usually employed, the "oil-water" tension depends on the thermodynamic distance of the system from a tricritical point, which is a point Where all three of the phases become a single phase. The tension, γol-aq, varies as γol-aq ~ |T − Ttc|2, where T is the reservoir temperature and Ttc is the temperature of the tricritical point.

Hence, optimal high-salinity surfactant design requires the ability to create systems with tricritical points at temperatures and salinities that are set by each individiual oil reservoir. The development of this ability requires methods for the prediction and control of the locations of tricritical points.

Tricritical points can only occur in phase diagrams with at least four dimensions, which makes their study difficult. Many of these difficulties can be overcome by means of a step-by-step consideration of critical points and phase behavior in diagrams of lower dimensionalities. A step-by-step approach to tricritical points and lines is described.

Analysis of existing data shows that tricritical points of commonly used "cosurfactants" (alcohols and nonionic surfactants) are at "negative" reservoir salinities. For such materials interfacial tensions must inevitably increase and oil recoveries fall as they are used in reservoirs of increasing salinity, even if the "optimal salinity" of the surfactant matches the salinity of the reservoir in all cases.

Addition of an ionic surfactant (eg, petroleum sulfonate) creates a tricritical point at zero (rather than negative) salinity, but this amount of improvement is too small to be satisfactory.

In the most desireable behavior, the lines of critical endpoints converge with increasing salinity and the tricritical points are at positive, controllable salinities. For this behavior optimal interfacial tensions decrease and oil recoveries can increase as the surfactants are used in reservoirs of greater and greater salinity.

Surfactant designers should measure and report critical endpoints at different temperatures (not just optimal salinities at a single temperature), so that the thermodynamic limits on high-salinity surfactants can be better ascertained.
Screening and Evaluation of Enhanced Oil Recovery at Teapot Dome in the Shannon Sandstone: A Shallow, Heterogeneous Light-Oil Reservoir
Authors: Chappelle H. H. , Emsurak G. P. , Obernyer S. L.
Published: December 2007

Pilot testing results and geologic characteristics have been used to identify methods by which oil recovery may be increased in the Shannon sandstone at Naval Petroleum Reserve NO. 3 (NPR-3), and to identify reservoir zones amenable to enhanced oil recovery (EOR) application. Extensive natural fractures have been found to be the prime influence on fluid flow and pressure distribution in this shallow reservoir. Thermal processes of in-situ combustion and steam drive have been successful in displacing potentially economic quantities of oil while immiscible displacement processes of waterflood and polymer-improved waterflood have not. A geologic characterization study based on facies description has identified the potential resource for further development of the reservoir/including the possible application of EOR. These findings will be used to determine the development of this reservoir by infill drilling and enhanced recovery.
Investigation of Phase Behavior Predictions With a Chemical-Association Equation of State
Authors: Li Y.-K. , Nghiem L. X. , Heidemann R. A.
Published: December 2007

An approach of applying the chemical-association theory to a cubic equation of state to model nonideal behavior is proposed. In this approach, the molecules in solution are assumed to interact with each other to form new chemical species which are in chemical equilibrium. The parameters of the chemical-association model are obtained by fitting the equation of state to experimental data for binary pairs. The approach is tested against experimental data for mixtures containing CH4, CO2, H2S and H2O. Improvements in liquid composition prediction are obtained over the usual cubic equation of state. A stagewise procedure for phase and chemical equilibrium is also proposed.
Prediction of Vapor and Liquid Viscosities from the Lawal-Lake-Silberberg Equation of State
Authors: Lawal A. S.
Published: December 2007

A difficulty in modeling multicontact miscibility processes is achievement of consistent, stable convergence of gas and oil phase compositions, densities, and viscosities as the critical point is approached. The use of an equation of state offers the advantage of a single, consistent source of calculating K-values and phase densities. The criterion of stable convergence viscosity in the vicinity of critical regions is not often met without fine tuning with laboratory data as phase viscosity correlations are usually developed independent of each other.

The present study extends the van der Waals model to viscosity by drawing an analogy between the graphs of PVT and PμT. Vapor and liquid viscosities based solely upon pure component critical data and acentric factor were derived from the Lawal-Lake-Silberberg (LLS) equation of state for methane through eicosane, i-butane, neo-pentane, carbon dioxide, and nitrogen. The 6718 experimental data used cover a range of temperatures from −183°F to 482°F and pressure up to 20,000 psia. For the twenty-four components, the average absolute deviation of the predicted viscosities from experimental is 5.9%. A mixing rule which relates mixture parameters to composition and pure component constants is proposed and comparisons of 9,000 experimental data with computed viscosities for several binary, multicomponents, natural gases and complex systems resulted in an average absolute deviation of 3.5%. The extension of the mixing rules to predictions of reservoir oil viscosity was generally within +8% of the experimental values. Extensive comparisons of the LLS viscosity equation with other methods of predicting reservoir oil viscosity are made and found to be generally superior in ease of use and in accuracy.

The prediction of vapor and liquid viscosities from the LLS equation of state makes the present work very attractive for compositional reservoir simulators and other applications which are repetitive in nature. The use of an equation of state to predict phase viscosities offers an opportunity to make calculations in the critical region without the computational problems commonly associated with that effort. The internal consistency and the convergence of vapor and liquid viscosities at the critical point have heretofore been unattainable.
Case History of a Successful Rocky Mountain Pilot CO2 Flood
Authors: Hoiland R. C. , Joyner H. D. , Stalder J. L.
Published: December 2007

Conoco Inc. conducted a miscible CO2 pilot flood in the Shannon formation in the West Sussex Unit, Johnson County, Wyoming, starting in August, 1982. The test involved one injection well and three producing wells encompassing 9.6 acres. A five-month water preflush with a tracer preceded injection of 206 MMSCF of CO2 (about 30% PV) which was trucked as a cryogenic liquid from the McCallum Field in northern Colorado. A water post-flush (about 70% PV) completed the test in late 1985. Computer simulations predicted the test should produce 19.5 Mbbls of enhanced oil recovery, but only two of the three producing wells showed significant response during the test yielding a 16.0 MBO tertiary recovery. The test demonstrated the ability of carbon dioxide to mobilize and displace additional oil volumes from the Shannon reservoir, following waterflooding operation, in spite of adverse permeability variation and complex reservoir faulting. This paper discusses reservoir history and description, pilot operations, performance, pressure transient testing, tracer testing, and implications for commercial CO2 flood expansion in the area.
Chemical Consumption During Alkaline Flooding: A Comparative Evaluation
Authors: Cheng K. H.
Published: December 2007

Chemical consumption under alkaline flooding conditions can be significantly decreased with the use of Na2CO3. We have found significantly lower ion exchange and mineral dissolution in the presence of Na2CO3 as compared to caustic and silicate. These results are based on laboratory studies with alkaline solutions in the presence of Wilmington sand, Ottawa sand and dolomite. Furthermore, Na2CO3 offers an additional advantage upon contact with hard water. The resulting carbonate precipitates do not adversely effect permeability as compared to the precipitates of the hydroxides or the silicates. It is therefore suggested that the use of Na2CO3 for alkaline flooding will result in shorter alkali breakthrough times and increased tertiary oil recovery.
New Polymers for EOR Applications
Authors: Ryles R. G. , Cicchiello J. V.
Published: December 2007

New water-soluble polymers for use both as mobility control reagents and in profile modification systems are described. They have excellent long-term thermal stability properties even in the presence of high concentrations of divalent metal ions.

Additionally, the mobility control reagents have improved resistance to mechanical degradation, excellent injectivity, low adsorption and generate cost effective resistance to flow in porous media.

The thermal stability of hydrogels prepared from a new polymer and polyvalent metal ions is compared with Xanthan and anionic polyacrylamide analogs. The Xanthan gels were found to be unstable at temperatures >50°C. The polyacrylamide system could be optimized to give good long-term stability at 90°C. Above this temperature, degradation of the gel was observed. The new polymer composition gave gels which were stable to at least 120°C.
Field-Scale Polymer Flooding at Remote Site Presents Special Challenges
Authors: Hoelscher L. E. , Tan H. C. , Fullbright B. M.
Published: December 2007

Establishment of a polymer-augmented waterflood in the Twin Peaks (Strawn, Upper) Field in King County, Texas required overcoming several major technical and logistical problems caused largely by the remote field location. This field, located on the S. B. Burnett Estate Lease, had been waterflooded for approximately five years prior to the decision to begin polymer-augmented waterflooding to improve the mobility ratio and areal sweep of injected fluids.

Problems concerning the absence of a fresh water source and supplying/transporting polymer to a remote field location were solved through the development of (1) a portable on-site automatic polymer manufacturing plant, and (2) a method for treating the available source brine for use as polymer mix water. These developments, along with detailed analysis of Twin Peaks (Strawn, Upper) Field -- including geology, development, performance, and reservoir engineering -- illustrate the feasibility of conducting polymer-augmented waterflood operations, even in remote field locations.
The Chateaurenard (France) Industrial Microemulsion Pilot Design and Performance
Authors: Chapotin D. , Lomer J. -F. , Putz A.
Published: December 2007

The Industrial Microemulsion Pilot (I.M.P.) test is an application to a significant part of the Chateaurenard field of the enhanced recovery technics already used with success on a small scale during the first Method Pilot.

The method involves the injection of a microemulsion slug displaced in the formation by viscous solutions of polymers.

The I.M.P. has been initiated by Elf Aquitaine in 1983: the prime objectives were to assess the efficiency of the recovery mechanisms on a large pattern and evaluate the economic constraints of chemical flooding in an industrial environment.

The test is implemented on a four adjacent five spot panel, with an enclosed pore volume of 224,000 m3 (1.4 × 10 bbl); the spacing between the production wells is 280 m on average.

The chemicals injected consist of a microemulsion of petroleum sulfonates, alcohols, field oil and brine, displaced by solutions of partially hydrolyzed polyacrylamides diluted with field water. The amount of surfactant active matter has been reduced to 0.36 % of the exploitable pore volume, in comparison with 1.02 % on the Method Pilot.

The exploitation started in June 1983; the microemulsion injection phase lasted 40 days. The injection of the concentrated polymer buffer amounting to 0.41 of the enclosed pore volume has been completed; it is now being followed by an equal volume of gradually more diluted solutions.

A significant increase in oil production has been observed on 7 of the 9 producers of the pilot, with the arrivals of very well defined oil banks on these wells. Between June 16, 1983 and December 31, 1985, the total oil production rose to 35,100 m3 (220,700 bbl) of which 18,800 m3 (118,200 bbl) are attributed to chemical injection; at that time, the overall injection was 142,000 m3. The total cumulated production predicted by numerical simulations is 57,000 m3 (358,500 bbl), i.e. 52 % of the remaining oil in place at the start of the operation.

From an economic analysis of the operations, and with the particular cost structure associated with the operation of this field, the cost of tertiary oil is about 40 US $/barrel for micellar recovery. A breakdown of the costs involved shows that the chemical products represent 41 % of the expenses and are a heavy burden to the project. Reducing the amount of chemicals would thus be of great benefit for the chemical process. Recent laboratory studies have shown this could be achieved in Chateaurenard conditions through the injection of an alkaline preflush, ahead of the micellar slug.
In-Situ Polymerization Controls CO2/Water Channeling at Lick Creek
Authors: Woods P. , Schramko K. , Turner D. , Dalrymple D. , Vinson E.
Published: December 2007

In the Lick Creek Field of Bradley County, Arkansas, Phillips Petroleum Company has used a single stage, nonionic polymer treatment to combat severe channeling problems in a CO2 water-alternating-gas (WAG) operation. After treating two of the 23 injection wells in the field, production has increased by 65 bbl/day.

The field, consisting of 23 injection wells and 38 producers, was unitized in 1976 to initiate CO2 injection into the reservoir. Alternating CO2 and water (WAG) flooding techniques have been used. Channels had developed throughout the field and flooding was becoming uneconomical. Previous E0R treatments using an anionic polyacrylamide were successful for only a few cycles of CO2-water injection. Failure was attributed to the inability of anionic crosslinked polymer to withstand the acidic environment created by CO2.

The successful treatments were composed of single stages of injection of a low viscosity monomer solution containing an organic crosslinker. The rigid polymer gel which is formed in-situ to block high permeability channels has remained stable in the CO2 environment.

Laboratory studies dealing with the CO2 resistance of the polymer, tracer surveys, job design considerations, and field results are presented.
Development of Effective Methods for Placing Competent Cement Plugs
Authors: Bour D. L. , Sutton D. L. , Creel P. G.
Published: December 2007

A problem that has existed in oil well drilling operations is the successful placement of competent cement plugs at desired well depths. Repetitive attempts and failures in obtaining good cement plugs have cost many oil companies a considerable amount of capital both in extra rig time and service company expenses. This problem has recently been investigated with a unique 1/3 scale test model that allows visual observation of cement flow path and behavior of various well fluids during an actual job simulation. Test procedures and results are presented and discussed. Included in the results is a newly developed method which provides for successful plug jobs in severe well conditions. Field results of this method, which are also presented, confirm the results and demonstrate its value in field operations.
Properties of Homogeneous Reservoirs, Naturally Fractured Reservoirs, and Hydraulically Fractured Reservoirs From Decline Curve Analysis
Authors: Blasingame T. A. , Lee W. J.
Published: December 2007

This paper proposes analysis techniques for post-transient, flow at constant bottomhole pressure. Rate-time decline curves approximate this flow regime. Reservoir characteristics for homogeneous reservoirs, vertically-fractured reservoirs, and naturally-fractured reservoirs can be obtained using these techniques. These analysis techniques are based on the exponential, post-transient, constant-pressure radial flow solutions for each case. We show that theory predicts a linear relation between log (rate) and time for these curves. Thus, a straight line on a semi-log rate vs. time plot may be the line predicted by the analytical solution for that reservoir. If so, important formation characteristics can be estimated analytically. Reservoir pore volume is determined directly while other reservoir characteristics are calculated indirectly. These new techniques are a very powerful extension of transient well testing.