bluuebunny/crossref_metadata_2025 huggingface dataset:
Surface Composition of Berea Sandstone
Authors: Ramirez W. F. , Oen A. C. , Strobel J. F. , Falconer J. L. , Evans H. E.
Published: December 2007

Auger electron spectroscopy (AES) was used to determine the surface composition of Berea sandstone. Changes in the surface composition resulting from cation exchange and surfactant adsorption have also been observed. Surface compositions obtained by AES were compared to bulk analysis as well as X-ray photoelectron spectroscopic analysis (XPS).
Pressure-Transient Analysis for Naturally Fractured Gas Reservoirs: Field Cases
Authors: Samanlego-V. F. , Cinco-Ley H.
Published: December 2007

This paper analyzes three field tests performed in two naturally fractured gas reservoirs. The interpretation can properly be accomplished by use of a single infinite-conductivity vertical-fracture model that considers (1) the intersection of the well by a planar fracture and (2) a homogeneous and isotropic matrix. Conditions of the tests include almost constant flow rate before shut-in in the first case and variable flow rate before shut-in in the second case. A square-root group tpp−tpp+Δtp+Δtp2 is discussed for test analysis where final flowing conditions are linear flow and the shut-in period does not meet the restriction tp > 10∆tmax. A new type curve in terms of pD/CfD vs. txfD/CfD2 corresponding to linear-flow conditions under the effect of wellbore storage is presented.
Natural Gas - Partner and Competitor
Authors: Davis W.B. , Schweizer J.L.
Published: December 2007

While producers look upon natural gas as a source of added income, it is also a direct competitor to products of crude oil at the consumer level. The growth rate of natural gas consumption has been greater than that of crude oil. This growth can be attributed mainly to the lower price per unit of energy for which gas is sold. The increase in the consumption of natural gas has had as great an impact on the domestic producer as have crude oil imports. The lower price of natural gas and its increased use have had the net effect of keeping the average wellhead price of hydrocarbon energy at approximately the same level for the past 30 years.

Therefore, it appears that many of the domestic producer's troubles today are caused not so much by the fact that he is selling two competing forms of energy, but that he is forced to sell one, natural gas, below its true market value because of artificially depressed prices. The best remedy for this situation lies in the freeing of natural gas prices from control and allowing them to compete in the open market. Every domestic producer of crude oil has a big stake in the solution of this problem whether he sells gas or not, since his oil is forced to compete with the under-priced gas for a portion of the energy market.

Introduction

The purpose of this paper is to emphasize the fact that natural gas is much more than just a source of additional revenue to the crude oil producer. We must recognize that while a small fraction of crude oil is used to make lubricants and for chemical feed stock, most of it is used as a source of energy. Natural gas, along with coal and other energy fuels, also serves the U. S. energy market. Consequently, natural gas is a competitor to crude oil at the consumer level, and the supply and price of natural gas are having a significant effect on crude oil demand. There is some question as to whether natural gas now is more important to oil producers as a source of revenue or as a competitor; however, it is reasonably certain that if artificial control of gas prices continues, the importance of gas as a competitor will grow much faster than its importance as a revenue source.
Dynamic Gas Slippage: A Unique Dual-Mechanism Approach to the Flow of Gas in Tight Formations
Authors: Ertekin Turgay , King Gregory R. , Schwerer Fred C.
Published: December 2007

A mathematical formulation, applicable to both numerical simulation and transient well analysis, that describes the flow of gas in very tight (k∞ <0.1 md) porous media and includes a dual-mechanism transport of gas is developed. Gas is assumed to be traveling under the influence of a concentration field and a pressure field. Transport through the concentration field is a Knudsen flow process and is modeled with Fick's law of diffusion. Transport through the pressure field is a laminar process and is modeled with Darcy's law (inertial/turbulent effects are ignored). The combination of these two flow mechanisms rigorously yields a composition-, pressure-, and saturation-dependent slippage factor. The pressure dependence arises from treating the gas as a real gas. The derived dynamic slippage is most applicable in reservoirs with permeabilities ≤0.01 md. The results indicate that in reservoirs of this type, differences between recoveries after 10 years of production with the dynamic-slip and constant-slip approaches were as great as 10%, depending on the initial gas saturation. If an economic production rate is considered, differences as great as 30% can be expected.
Soviets Relying on Turbodrill to Help Meet Future Production Quota
Authors: Salnikov I.S.
Published: December 2007

The Soviet Government has given its petroleum industry a 1965 production target of 4,800,000 B/D. The target centers on progress of Russian drilling technology and application of new developments and production techniques.

Performance of Soviet development rigs is estimated to increase from 3,180 ft/rig/month in 1956 to 5,800 ft/rig/ month in 1960. By far the greater part of Russian wells are drilled by turbodrill. Electrodrills and small turbodrills are being tested to improve drilling efficiency at depths below 7,000 ft where turbines have difficulty in making hole.

In production technology emphasis is being placed on supplementing natural reservoir energy by water injection. The current injection ratio is 1 bbl of water for each barrel of oil produced. Automation of crude oil production from wells to refineries is under study by technical groups. A concerted effort to reduce cost and improve efficiency of operations is now in progress.

Introduction

The Soviet Government recently announced a plan to boost crude oil production by 1965 to 4,800,000 B/D. During the same period natural gas output is scheduled to rise to 14.5 billion cu ft/ day. These targets in crude production amount to an average increase of slightly over 14 per cent per year for the seven-year period (1959–1965). In the light of their recent annual increases in production, 18.0 and 17.8 per cent for 1955 and 1956, respectively, the rates do not appear to be unreasonable targets. By implication these plans reflect the confidence of the Soviet Government in the ability of their petroleum technology to double current output and to reach a rate which is approximately half of U. S. production at this time.

Since World War II information on Russian technology has been scarce but in the past few years export of some 250 technical and scientific publications has been permitted. Among these are such journals on petroleum industry as Oil Worker, Oil Economy, Geology of Petroleum, Geophysics, etc. These publications are giving us a clear picture of Russian industry and its accomplishments and a better understanding of their petroleum technology. Much of the Soviet's ability to attain the targets set for 1960 and beyond will depend on their technical accomplishments. Therefore, a review of Russian petroleum technology should certainly give us a better understanding of their aims and efforts.
Discounted Cash Flow as a Measure of Market Value
Authors: Reynolds Fred S.
Published: December 2007

The discounted-cash-flow method has been used for years in the field of finance and banking. It has been gaining stature for several years in the money management for certain industries, and the oil and gas industry is rapidly recognizing its merit for choosing investment alternatives.

The method is suggested as a measure of market value because it is conceptually realistic and suffers from none of the limitations that the other yardsticks do.

Data are presented that are indicative of profitable levels of return. Comparisons of various measures of value for five actual sales or valuations are given, and the effects of using any one of the parameters of value have been calculated to show the superiority of the discounted-cash-flow method.

An oil and gas investor must place a time value on his money; hence, the discounted-cash-flow method is gaining its acceptance in directing management toward new capital expenditures. It is hoped the method will be utilized and accepted for determining fair market values.

Introduction

Most engineers whose profession involves evaluating oil, gas, or other mineral interests must sooner or later create hypothetical sales to ascertain the fair market values of mineral reserves. The principal causes for these perplexing situations are the necessities of providing bases for settling estate, gift and ad valorem taxes.

If an engineer were pursuing a valuation so that he could advise management or a client concerning the worth of an investment, his requirement would be extremely similar and should be treated no differently. Any profit-conscious investor must either determine if a desirable level of return is realized for a quoted price or the maximum price that can be paid to yield a desirable level of return. In essence then, this problem leans heavily on the basic requirements of engineering valuations; however, the engineer is often faced with defending his basis for determining worth in the ground in addition to the calculated reserves for the interest. The experienced engineer or investor can often determine the approximate value of an oil and gas interest by prudent examination of the engineering computations; however, many officials are reluctant to ascribe to the experience and prestige the valuator has attained in his profession. It then behooves appraisers to utilize a definitive concept for determining fair market values. There have been many concepts formulated and utilized, and each is characterized by varying intrinsic weaknesses. it is the purpose of this paper to propose a method that eliminates most of the conjectural features.
Methods for Field Monitoring of Oil-Based Drilling Fluids for Hydrogen Sulfide and Water Intrusions
Authors: Garrett R. L. , Carlton L. A. , Denekas M. O.
Published: December 2007

Analytical methods are presented for rig-site monitoring of oil muds for H2S and "active" sulfides (such as the neutralization products of lime and H2S) and for small changes in water content. Applications of the two methods are discussed. The sulfide method is a modification of the water-mud API Garrett Gas Train (GGT) procedure adapted to test a sample of whole oil mud. The water-content method is a modification of the conventional retort method that uses a necked-down, precision-calibrated (Kolmer) centrifuge tube as the retort liquid receiver. Additionally, an effective, high-zinc-content, sulfide-scavenging chemical, ZnO, is discussed for use in oil muds as an additive for converting the active sulfides into a more inert form, ZnS.
Experimental Study of Cuttings Transport in Directional Wells
Authors: Tomren P. H. , lyoho A. W. , Azar J. J.
Published: December 2007

A large-scale study of cuttings transport in directional wells is discussed in this paper. Previous investigators used unrealistically high fluid velocities and/or short test sections where steady-state conditions had not been established. This study used a 40-ft [12.2-m] test section. Pipe rotation and eccentricity, as well as several types of drilling muds and flow regimes, were studied. Annulus angles varied from 0 to 90°, and actual drilled cuttings were used.

The major factors affecting cuttings transport are drilling fluid velocity, hole inclination, and fluid rheological properties. Much higher annular velocities are required for effective hole cleaning in directional wells than in vertical wells. An increase in hole angle and/or drilling rate reduces the transport performance of drilling fluids. Hole angles of 40 to 50° are critical because of cuttings buildup and downward sliding of the bed of cuttings. High-viscosity muds were observed to provide better transport than low-viscosity muds.
Mechanisms of Foam Flow in Porous Media: Apparent Viscosity in Smooth Capillaries
Authors: Hirasaki G. J. , Lawson J. B.
Published: December 2007

The apparent viscosity of foam flowing through smooth capillaries was measured experimentally, and a mathematical model was developed. Foam texture (a measure of bubble volume) is a key parameter in determining the following properties of foam flowing through a capillary: (1) whether the foam exists as bulk foam or as a chain of bubbles where each pair of bubbles is separated by an individual lamella, (2) the number of lamellae per unit length of the capillary, and (3) the radius of curvature of the gas-liquid interface. The apparent viscosity is the sum of three contributions: (1) that from slugs of liquid between bubbles, (2) the resistance to deformation of the interface of a bubble passing through a capillary, and (3) the surface tension gradient that results when surface active material is swept from the front of a bubble and accumulates at the back of it. The sensitivity of both measured and calculated apparent viscosity is presented as a function of bubble size, capillary radius, ratio of bubble radius to capillary radius, velocity, quality, and surface tension gradient.
An Improved Acid for Calcium Sulfate-Bearing Formations
Authors: Dunlap Peggy M. , Hegwer John S.
Published: December 2007

An improved acid for the treatment of sulfate-containing limestones and dolomites is described. The acid is designed to reduce the reprecipitation of dissolved calcium sulfate and the possibility of plugging permeable flow channels. In addition, this improved acid has a much lower reaction rate than that of regular acid; the advantages of a "retarded" acid are obtainable.

Field testing of the acid has shown it suitable for use in sulfate-containing formations. Substantial improvements in productivity generally resulted.

Introduction

Acid treatments of limestones, dolomites and other formations bearing carbonate deposits are frequently unsuccessful when the calcareous formation contains sulfate, either as anhydrite (CaSO4) or gypsum (CaSO4 2H2O). Preliminary dissolution in acid followed by redeposition of calcium sulfate appears to be a major factor contributing to poor well performance after acidizing. The precipitate is usually the gypsum form of calcium sulfate, but in higher temperature formations it may be anhydrite. The freshly precipitated crystals are nearly always very small and needlelike. They may occupy a gross volume many times that of the original anhydrite crystals and will obviously constitute an impediment to flow through newly enlarged flow channels.

It is believed that the redeposition problem is most severe when anhydrite lines the fracture systems and large pores which supply the effective permeability of a formation. Microscopic inclusions of calcium sulfate also present large sulfate surface areas for dissolution in acid. In either case, great amounts of calcium sulfate may dissolve before the acid can be spent on formation carbonates. For regular spent acid (originally 15 per cent hydrochloric acid) the precipitate could be as much as 270 lb gypsum/1000 gal acid.

Two techniques have been applied by the industry for reducing sulfate plugging during acidizing. The method commonly employed in the field is the attempted removal of a quantity of regular treating acid before it has reacted completely with the formation. This is practiced because the solubility of calcium sulfate is greater in a solution that is still acidic than in one which has been largely spent on the formation rock. The chance of precipitative plugging is therefore reduced if the withdrawal is successful. However, it is often impossible to get the acid out of the formation before precipitation occurs.
A Compositional Formulation of the Pressure and Saturation Equations
Authors: Watts J. W.
Published: December 2007

This paper describes a sequential implicit formulation of the compositional reservoir flow equations. This procedure offers improved stability over implicit pressure, explicit saturation (IMPES) methods but, in general, is not as expensive computationally as fully implicit methods. It also possesses several other attractive features. It permits an efficient combination of compositional and black-oil capabilities in a single program. Important to this is the fact that it lends itself to a modular program design. Finally, it has a natural physical interpretation that can be very helpful in the understanding of model behavior.
Curvilinear Coordinate Systems for Reservoir Simulation
Authors: Leventhal S. H. , Klein M. H. , Culham W. E.
Published: December 2007

This paper presents a set of curvilinear coordinate transformations that lead to no mixed derivative terms in transformed flow equations. The transformations are created by examining the transformed flow equations and by showing that the mixed derivative terms are zero if the transformation satisfies a system of differential equations that depend on the geometry and rock property distribution within the reservoir. Numerical examples with a black-oil simulator are presented to show the increased accuracy resulting from the use of the curvilinear coordinate system and the importance of eliminating the mixed derivative terms.
A Fast Convolution Method for Implementing Single-Porosity Finite/Infinite Aquifer Models for Water-Influx Calculations
Authors: Leung W. F.
Published: December 2007

Existing aquifer models are either computationally inefficient or inaccurate for reservoir water-influx calculations. A new fast convolution method (FCM) that does not require lengthy data manipulation is used to implement four different single-porosity finite and infinite aquifer modeis for unsteady-state water-influx calculations. Numerical examples on circular and linear aquifers, together with a step-by-step calculation, are used to demonstrate the accuracy and efficiency of the models. These numerical studies show that the FCM approach is as much as 20% more accurate than the widely used methods for both finite and infinite aquifers. The models can be implemented readily in numerical reservoir simulators, as well as in hand computations.
Severe Slugging in Offshore Pipeline Riser-Pipe Systems
Authors: Schmidt Želimir , Doty Dale R. , Dutta-Roy Kunal
Published: December 2007

Severe slug flow (i.e., terrain-dominated slug flow) was studied in a simulated offshore pipeline riser-pipe system. Severe slug flow is characterized by extremely long liquid slugs generated at the base of the vertical riser. This phenomenon occurs at low gas and liquid flow rates and for negative pipeline inclinations. Slugging in some offshore platforms has required the use of operating procedures that drastically curtail production. Losses in flow capacity up to 50% have been reported.

A hydrodynamic model has been developed for severeslug flow. The model's predictions agree with experimental data. The model can be used to design new pipeline riser-pipe systems or to adjust the operation of existing systems to prevent the occurrence of severe slug flow. Also, a flow-regime map is presented for predicting the severe slug flow regime, where the boundaries are determined analytically. Finally, additional methods are proposed to prevent the flooding of separation facilities by riser-pipe generated slugs. This study is an extension of Ref. 1, in which severe slug flow was introduced and was only partially modeled.
Recording Downhole Formation Data While Drilling
Authors: Elliott L.R. , Barolak J.G. , Coope D.F.
Published: December 2007

An understanding of the formation is essential for effective drilling, casing and completion of oil and gas wells. Several methods and many tools are available to obtain information about the formation. Some of these tools collect or provide downhole data during the drilling process and are, therefore, termed measurement-while-drilling (MWD) tools. This paper describes a new MWD tool which records formation data during the drilling process. process. System hardware is described and its operation and rig impact outlined. A discussion of the theoretical implications of measuring formation data during the drilling process is presented. Field data are presented and compared with wireline data. From these data, excellent MWD log quality is demonstrated. MWD gamma ray logs are shown to have a superior bed resolution to those produced by wireline, for most cases, and the resistivity sensor, contained in the recording system, is demonstrated to be the most versatile MWD resistivity tool commercially available. It is seen from field history that recording formation data while drilling is a cost-effective and reliable method of obtaining formation information when compared to other available methods.

Introduction

A variety of MWD tools is commercially available which provide services ranging from only directional through multi-sensor packages which include various combinations of hole angle and direction, formation gamma and resistivity, and downhole temperature and pressure and weight and torque on bit. Except for the recording system discussed in this article, all commercial MWD systems depend on some form of mud-pulse telemetry for communication of the data from downhole to the surface. There are many cases when real time transfer of data is required. Tool face measurement during steering and WOB, for instance, would be of little use if not provided in real time. However, information obtained during drilling can provided in real time. However, information obtained during drilling can be of value when available at the completion of each bit run. Using this approach, a complex and costly portion of the MWD system can be eliminated, with concomitant advantages in cost, reliability and rig impact.

Many applications do exist for recording formation characteristics (lithology) during the drilling process. A recording MWD service can be used when drilling surface hole to identify shallow hydrocarbons and eliminate a wireline log. High-angle and difficult holes are easily logged with a recording MWD tool when wireline logging is difficult, costly or impossible.
Pressure Maintenance and Model Studies
Authors: Eckles W.W.
Published: December 2007

Pressure maintenance programs play an important role in the efficient and economical recovery of oil and gas. For this reason, it is advantageous to consider carefully all of the factors involved in the design of an efficient pressure maintenance program.

The purpose of this article is to

- review the methods of evaluating past reservoir performance and predicting future performance for various proposed plans of pressure maintenance operations, and

- discuss the use of potentiometric model studies in designing pressure maintenance programs.

The following aspects of model studies are discussed at length:

- purpose of model studies,

- how model studies are carried out,

- technique employed in the construction of potentiometric models,

- sweep patterns and how they are obtained from a potentiometric model, and

- model data and how it is used in evaluating a pressure maintenance waterflood program.

Since the ultimate recovery of hydrocarbons under certain pressure maintenance programs will depend on how the injected water, gas or other types of fluid will sweep the reservoir, it is concluded that model studies can play a very important part in evaluating various proposed plans of operation, in determining the best locations for injection wells, in determining the proper distribution of injection between wells and in picking locations of producing wells which would increase ultimate recovery and profit.

How Are the Injection Requirements for Pressure Maintenance Programs Determined?

The first signs of reservoir trouble generally are detected from a study of the reservoir behavior after the field has been developed and produced. Rapidly falling reservoir pressures, increasing gas-oil ratios and increasing water production may be the first indicators of trouble. One of the best recognized and most important tools for studying the past performance of a reservoir is the material balance which is discussed abundantly in the literature. Digital computers and electronic reservoir simulation are used for the prediction of future performance of the reservoir under various operating conditions. From these studies, the future needs for the pressure maintenance program can be determined. In other words, how much injection is needed to maintain the pressure at the desired level, or to stop shrinkage or expansion of the gas cap, and how much natural water influx, if any, may be experienced in the future for the different plans of operation?
The Sonic Log and The Delaware Sand
Authors: Millican Marcus L.
Published: December 2007

The objective of this study has been to develop a method of log interpretation in the Delaware sand whereby the effects of the shale contained within the sand can be recognized and accounted for in a quantitative solution for porosity and water saturation.

Both theoretical and empirical considerations are discussed. A simplified interpretation chart is presented which provides a means of amending the conventional porosity resolution of the Sonic log to compensate for the presence of shale. The amount of shale within the sand and its degree of lamination may be inferred from a calibrated gamma ray log. The resulting porosity value may then be used in conjunction with a knowledge of the formation resistivity to determine water saturation.

Of added interest, particularly in the Delaware sand, is an approximation of permeability which may be derived empirically from the simplified chart.

The discussion is illustrated by field examples.

Introduction

The performance of the Sonic log in defining the porosity fraction in clean, consolidated formations is well known, particularly in sandstones that are well compacted and free of shale. An approach to Sonic log porosity determination in shaly sands has been recently developed. This method involves correcting the Sonic log readings by means of an a factor, where a is the ratio of the pseudo-static SP to the static SP, and is a function of the amount of shale present.

This method is dependent upon a contrast between the salinities of the drilling fluid and the connate water in the formation, inasmuch as this contrast produces the SP effect. In wells drilled with salt mud, the contrast, and with it the means of obtaining the a correction, disappear.

In the Delaware basin, the large majority of rotary wells drilled to the uppermost sands of the Bell Canyon group employ salt mud as the drilling fluid. These sands have been the objective of most of the drilling exploration in the basin to date. A comparison of porosity values in these sands, as determined by core analysis, to Sonic log readings has indicated that a correction for the shaliness of the sand is needed. In the absence of an SP curve to determine the correction factor, the porosity resolution of the Sonic log in these sands has been questionable.
Reservoir Engineering in Coal Seams: Part 1—The Physical Process of Gas Storage and Movement in Coal Seams
Authors: Gray Ian
Published: December 2007

This is the first of two papers concerning the movement of gas in coal seams. It deals directly with the physical behavior of the coal seam as a reservoir. Coal seams show considerable differences in behavior from normal porous gas reservoirs in both the mode of gas storage and permeability characteristics. Most of the storage of gas in coal is by sorption into the coal structure, while the coal permeability is cleat-(fracture-) or joint-controlled and may vary over a wide range during production. This permeability fluctuation is not solely a phase relative permeability effect, but is rather a result of the opposing effects of effective stress increase with fluid pressure reduction and shrinkage of the coal. Reducing fluid pressure tends to close the cleats, reducing permeability, while shrinkage tends to open them.
Treatments To Improve the Performance of Injection, Disposal and Water Supply Wells
Authors: Moore J.M. , Rollins J.T.
Published: December 2007

Introduction

Service wells are necessary to the efficient recovery of petroleum. If costs are unnecessarily high due to wasted horsepower expended in operating these service wells, the net income from the lease is reduced. For maximum profits, service wells should be maintained at peak operating efficiency, the same as production wells. Many conditions can prevent service wells from Operating at peak efficiency. Evaluation of bottom-hole samples and surface conditions facilitate problem analysis and selection of remedial measures. Acidizing, fracturing, formation clean-up and similar techniques are designed to obtain and preserve maximum permeability in the critical area around the wellbore.

Classification

Service wells may be classified as:water injection wells,gas injection wells,brine disposal wells, andwater supply wells.

Problem identification and elimination can be greatly facilitated by an accurate analysis of well conditions and a subsequent recommendation for proper corrective treatments. Such treatments fall into three categories:initial treatments to permit new wells to operate at maximum capacity,preventive treatments to avoid difficulties inherent in a specific formation or area, andworkover treatments to restore maximum operating efficiency to formations which have been damaged.

l plugging of formation flow channels by various materials is the usual cause of inefficient operations. Such plugging may be due to one or more of the following:Mineral deposits ("gyp")Corrosion products (iron oxide, sulfide)Silicate particles (silt, clay and fine sand)Petroleum residuals (paraffin, asphalt, tar)Organic deposits (bacterial, algeal)
Mobility Weighting in Numerical Reservoir Simulation
Authors: Potempa T.
Published: December 2007

The sensitivity of a numerical steamflooding model toward mobility weighting and discretization procedures is examined in depth. Four numerical discretization schemes are used: a five-point finite-difference model, a nine-point method similar to that proposed by Yanosik and McCracken, a seven-point scheme, and a method related to the finite-element method. Three mobility-weighting schemes are studied, including the upstream mobility-weighting approach often used in simulation today. The results of this investigation demonstrate that both accurate numerical procedures and the correct mobility weighting are needed to produce realistic simulations in an example problem. In particular, the standard upstream mobility-weighting approach is shown to produce unrealistic simulations regardless of the discretization scheme used.
Pilot Propane Project Completed in West Texas Reef
Authors: Sturdivant W.C.
Published: December 2007

Injection of a 14,000-bbl "slug" of propane into a reef reservoir in an advanced stage of gas injection operations has resulted in miscible displacement of 100,000 bbl of stock-tank oil. Premature breakthrough of gas injected behind the slug is attributed to dilution of the propane slug, to unfavorable permeability distribution and to an insufficient amount of propane.

Introduction

The Millican field pilot propane project was intended to evaluate the applicability of the propane slug method to the Millican field (Fig. 1). A slug of 14,000 bbl of propane-butane mixture was injected in a single well followed by injected gas, and behavior of offset wells observed for two years.

Recognized hazards were the high gas saturation due to the past history of gas injection and the non-uniformity of reef rock. Also, economic considerations limited the amount of propane which could be injected in a possible field-wide application. Favorable factors were a light oil containing a high proportion of intermediate hydrocarbons (see Table 1), gas injection facilities already in operation and a supply Of propane from a nearby gasoline plant.

Despite the recognized hazards, project economics were considered favorable, since costs were low and any reduction in gas-oil ratio brought about by propane injection would be immediately reflected in increased oil production.

History of Millican Field

The Millican field, located in Coke County, Tex., produces from a Strawn reef limestone at 6,000 ft. Originally, the field had two small gas caps, and periodic material balance calculations indicate a closed reservoir. The oil was saturated at the original pressure of 2,540 psig at - 3,720 ft with 1,300 cu ft of gas per barrel and had a formation volume factor of 1.65.

From core analyses, average porosity of the productive section of the reef is estimated at 6.6 per cent, connate water saturation at 20 per cent, and average permeability, 10 md. The field is completely unitized and produced gas has been returned since early in the history of the field.
New Technique Provides Open-Hole Production Test of Wildcat Formations
Authors: Malone B.C. , Stokey Ernest W.
Published: December 2007

Introduction

It is becoming increasingly difficult to find proved oil reserves within the boundaries of the United States. In general, companies must drill much deeper in their search for oil.

The depth of present-day wildcat wells and the complex completion procedures used on such wells have brought about a large increase in the cost to put oil back in the tank battery. This skyrocketing of costs has stimulated a constant search for new or improved methods in every phase of drilling for oil.

A new testing technique which has helped to a great extent the struggle to cut the cost of finding oil reserves provides conclusive evaluation of questionable wildcat formations without the expense of running casing.

The technique and tools used were made available to the petroleum industry in the latter part of 1956. To date, conclusive information has been obtained on more than 200 wildcat formations located in Arizona, Utah, New Mexico, Colorado, Wyoming, Kansas, Oklahoma, Illinois, the Texas Panhandle, North Central Texas, the Permian Basin of West Texas, and Southwest Texas.

Successful open-hole production tests have been performed in porous lime, consolidated lime, fractured lime, vugular lime, conglomerate, consolidated sand, coarse sand, shaly sand and red shale.

Need of Supplement For Conventional Testing

The conventional drill-stem test is the most widely used method to obtain information for the evaluation of the potential production of a formation. When pressures and fluid are obtained in sufficient amounts, the drill-stem test gives exact and conclusive in formation on formation potential. However, quite often a drill-stem test is either void or obtains very little yield of fluid or pressure. This would lead to the normal conclusion of poor production potential.

When electric logs indicate possible fluid and a void drill-stem test results, it is possible that the formation has been blocked or plugged by the drilling mud. This blocking action can be of varying degrees. A partial block may occur to give only a slight show of formation pressures and fluid and, thus, indicate poor potential. Therefore, when test results are poor but logs give indication of production, the test is inconclusive. It then becomes necessary or desirable to more thoroughly test the zone, or zones. In order to obtain more conclusive in formation under such conditions, an acid treatment may be required to break down the suspected mud block. When the mud block has extended well into a permeable zone, a substantial treatment is often necessary. Very high pressures normally occur while breaking through these blocked permeable zones.
Casing Temperature Studies in Steam Injection Wells
Authors: Leutwyler Kurt
Published: December 2007

The key to realistic casing stress analysis in thermal recovery installations is accurate knowledge of the temperatures involved. Much information leading to prediction of heat losses from tubing string to wellbore has been published. This same information permits calculation of casing temperature under certain conditions. This paper reviews the basis for most of the published work, the line sources solution to the diffusivity equation and examines some of its application criteria in the light of unsteady-state conditions. An alternate finite differences method is presented for correlation, and experimental data pertaining to the heat transfer mechanism in the annulus is reported. In the light of the information presented in the paper, it appears that the assumption of a line source for the tubing-wellbore system is valid even for reasonably short periods of heat flow, such as "steam soak" operations. The empirically modified equation presented earlier matches computer derived results of the finite differences approach for periods as short as 50 hours. Previously predicted casing temperatures and the associated stress levels are thus verified based on these correlative computations and the reported experimental information. Fall-out from the computer output resulting in some studies of the influence of insulating cement properties on casing temperature, and experimentally studied effects of nitrogen placed in the annulus at various pressures, are described.

Introduction

Generally speaking, predictions of average casing temperatures have been based on an idealized model involving a centralized tubing string at uniform constant temperature radiating energy towards the casing under steady-state conditions. Heat is transferred away from the casing to the formation by unsteady-state conduction across thermal barriers consisting of cement and the mud sheath., Heat balances written on the casing permit prediction of instantaneous casing temperatures. During early periods of injection, casing temperature varies appreciably as a function of time; however, for long injection times this variation decays as heat flow from the wellbore to the formation stabilizes, and it becomes virtually negligible as conditions surrounding the wellbore become quasi-steady-state (Fig. 1). Carslaw and Jaeger describe a solution to the diffusivity equation for a line source (Fig. 2). A constant supply of heat is introduced into the medium from the line placed into the origin of the x-y coordinate system and parallel to the z-axis. Heat spreads outward in the infinite cylindrical solid and the temperature increase on a line going through point (x, y) parallel to the z-axis at a distance r can be predicted by:

.....(1)

JPT

P. 1157ˆ
Development of a New Aluminum/Polymer Gel System for Permeability Adjustment
Authors: Dovan H. T. , Hutchins R. D.
Published: December 2007

A new method for gelling Polyacrylamide with aluminum has been developed to reduce the effect of reservoir heterogeneity, resulting in improved waterflood efficiency and higher oil recovery. The method uses a soluble aluminum compound in a high-pH, nonreactive form that is mixed directly with the polymer at optimum concentrations. Polymer gelling occurs in the reservoir when reactive aluminum is generated by consumption of hydroxyl ions. Variations in gel strength and gel time are obtained by adjusting polymer and aluminate concentrations in the slug to the desired levels. This process has several advantages over the current aluminum citrate technology as well as the chromium redox bulk gel system. Although the process works best in freshwater systems, it can be modified to accommodate waters with higher brine content. Laboratory development of the process and a successful profile modification field trial are described.
Evaluation of an Analytic Technique for Estimating Swept Volume from Thermal Pressure Falloff Tests in Heterogeneous Systems
Authors: Fassihi Mohammad Reza
Published: December 2007

Several simulated pressure falloff tests were analyzed to see whether the swept volume estimated by an analytic technique agrees with the swept volume simulated with both a steamflood model and an in-situ combustion model. Several parameters, such as wellbore gridblock size, nonuniform permeability, layering, flowing noncondensable gas, and oil vaporization, were studied. The analyses of these runs also led to the evaluation of other parameters, such as permeability-thickness, kh, in the swept zone. For steamfloods, the analytically estimated swept volume in relatively homogeneous models is in agreement with the simulated swept volume. The calculated kh reflects the effective gas permeability-thickness at the average gas saturation behind the steam front. The presence of gas-saturated oil or flowing noncondensable gas ahead of the steam front causes a long transition between the end of the infinite-acting period and the start of pseudo steady state. For very heterogeneous reservoirs, there was a long transition period that masked the pseudosteady-state data.

For in-situ combustion, the onset of the pseudosteady-state period depends largely on gas mobility at the front. For high gas mobility, the analytically calculated swept volume was found to be highly overestimated. However, it approached the simulated swept volume as gas mobility decreased.
Transient Interfacial Tension Behavior of Crude-Oil/Caustic Interfaces
Authors: Sharma M. M. , Jang L. K. , Yen T. F.
Published: December 2007

A systematic study is conducted to describe the transient interfacial tension (IFT) behavior of crude-oil/caustic interfaces. The variation in this behavior with variation in the composition of the aqueous phase and other parameters is the focus of this study. It is found that at low pH values, the experimentally observed behavior is similar to that reported earlier. At high pH values, however, a maximum in IFT is observed, followed by a minimum at a late time. Sodium chloride is shown to have no significant effect on the shape of the transient IFT curve, but the absolute values of IFT are at lower NaCl concentrations. Divalent ions dramatically increase the IFT.

A chemical model that takes into account the kinetics and the detailed chemistry of the process is used to explain the observed phenomena. The phenomenological surface phase approach is used to model the interface. The resultant set of ordinary differential equations is linearized by making certain justifiable, simplifying assumptions. The analytical solution to the set of equations yields the variation of the various concentrations with time. The IFT is then related to the interfacial concentration of the surface-active species, As− by the Gibbs equation. The variation in the transient IFT behavior on changing the kinetic constants, phase volumes, and ionic concentrations is discussed. Finally it is shown that the extension of this model to a two-component model would successfully explain all the experimentally observed phenomena.
Effect of Oil Type on Solubilization by Amphiphiles
Authors: Bourrel M. , Verzaro F. , Chambu C.
Published: December 2007

Systems optimized for micellar flooding are not all equivalent in terms of solubilization, interfacial tensions (IFT's), and oil recovery efficiency. The basic conditions that promote high solubilization into microemulsions, a property correlated to the values of IFT's, were established in a previous paper. Changes in oil type, for example, have to be compensated for by adjustment of the lipophile of the surfactant; however, this is not always sufficient to guarantee a high solubilization.

The purpose of this paper is to investigate the influence on solubilization of the relationship between the oil type to be solubilized and the surfactant lipophile. We found that this relationship is a determining factor for solubilization at a given temperature and salinity. For example, we observed that for the alkane series, solubilization is not affected by the alkane carbon number (ACN), provided that the compensation be achieved by adjustment of the surfactant lipophile length. For other oils or mixture of oils, like crudes, however, this is not necessarily the case; the solubilization may be found to be more or less different from that of alkanes, depending on the structure of the surfactant lipophile.

A particularly interesting case of oil mixtures is mixtures of hydrocarbons and methane (under pressure), because this gas is often dissolved in substantial amounts in live crudes. The incidence of the presence of methane is shown to be a function of the amount of gas dissolved and of the nature of the dissolving hydrocarbon. An interpretation of the results is proposed, based on the oil/lipophile, oil/oil, and lipophile/lipophile interaction energies, which are involved in Winsor's R-theory.
Analysis of the Low-Tension Pilot at Big Muddy Field, Wyoming
Authors: Ferrell H. H. , King D. W. , Sheely C. Q.
Published: December 2007

Conoco Inc. initiated a low-tension pilot test in 1973 at the Big Muddy field east of Casper, WY. The process mobilized an oil bank ahead of the slug, reached a peak oil cut of 20 %, and recovered 36% of the residual oil saturation (ROS). Tracers were injected in the preflush and postflush to determine swept volumes and distributions of flow. Tracer responses showed that more than 95% of the flow to the center well of the five-spot came from the two northern injection wells. The overall performance of the pilot was analyzed with a numerical simulator.

As a result of the pilot and the supporting research, a nearby 90-acre [36A-ha] commercial demonstration low-tension flood was initiated in 1980 and was operated as an EOR project until July 1985, although oil production still continues.
A Demonstration of The Effect of "Dead-End" Volume On Pressure Transients in Porous Media
Authors: Fatt I.
Published: December 2007

Study of a model which contains "dead-end" pore volume indicates that pressure transients are influenced by the amount of dead-end pore volume and by the resistance of the flow path between the dead-end pore volume and the main flow channels. A semi-empirical method is demonstrated that makes possible measurement of the volume in the dead-end pores and the total pore volume. The difference between these two volumes is the volume of the flow channels. An indication of the flow resistance between the dead-end pore space and the main flow channels is also obtained.

Introduction

In some engineering calculations the distribution of pore volume in a petroleum reservoir need not be known. For example, a material balance calculation treats a reservoir as an oil-filled tank. In other calculations the distribution of pore volume appears implicitly through use of the porosity and the relative permeability and capillary pressure characteristics. It is the purpose of this paper to point out that under certain conditions the exact distribution of pore volume must be known in order to interpret correctly transient flow behavior.

Eqs. 1 and 2 for a one-dimensional system require that, at any point x and at any time t, the average velocity vector be in the x direction. Furthermore, at any x and t there can be only one value of P. Also, all of the fluid leaving an element dx must have been stored in that element since t=0 as a result of the compressibility of the fluid or must have come in from the adjacent downstream element. In other words, no fluid can be generated in dx. These conditions are fulfilled for a homogeneous, isotropic porous medium.

In fractured rock the over-all permeability of the system may be greater than that of the material making up the blocks. The blocks may then be sources. A vuggy limestone can be treated in a very similar manner. If there is a low permeability layer on the vug surface, the fluid in the vug may not be able to leave at a rate sufficient to make the pressure in the vug equal to that in the rock immediately around the vug. The vug then becomes a source and the system obeys Eq. 3 or Eq. 4.