bluuebunny/crossref_metadata_2025 huggingface dataset:
The Vertical Multiphase Flow of Oil and Gas At High Rates
Authors: Cornish R.E.
Published: December 2007

A method is presented for calculating the pressure drop in a vertical well flowing oil and gas. It is designed primarily for flow rates in excess of 5,000 BID in large-diameter tubing, casing, or casing annuli, and relies heavily on the use of PVT data.

Introduction

While many investigators have attempted to develop methods for predicting the pressure loss that occurs in a vertical wellbore in which oil and gas are flowing simultaneously, few have specifically considered casing annulus flow, and then only at relatively low rates. Most Middle East oil companies have studied the problem, but little has been published. High-rate wells, problem, but little has been published. High-rate wells, although few in number when compared with the total number of producing wells worldwide, account for a considerable proportion of the world's production; yet none of the presently published articles predicts the two-phase pressure drop with any precision. Sanchez has calculated the bottom-hole flowing pressure for many wells using the methods of Hagedorn and Brown, Duns and Ros, Orkiszewski, and Baxendell and Thomas. Included in Sanchez data are the first 10 wells listed in Table 1. Table 2 compares his results for these 10 wells with those found below.

The objective of this paper is to describe a more accurate means for calculating the two-phase pressure drop in a vertical wellbore for flow rates in excess of about 5,000 B/D, with large-diameter tubing, casing, or casing annulus "oil strings." The limitations to the range of application are discussed.

Pressure Traverse Equation Pressure Traverse Equation The pressure traverse equation, as used in this paper, is of the form (1)

This equation is similar in many ways to that of Poettmann and Carpenter and Hagedorn and Brown Poettmann and Carpenter and Hagedorn and Brown and can be derived from the general energy equation. The fundamental difference between this paper and the work of those previously mentioned is that no general correlations are made from masses of field or experimental data. The pressure traverse is evaluated using PVT data for the crude oil being considered, friction PVT data for the crude oil being considered, friction factors obtained from a standard Moody diagram or the Colebrook equation, and implicitly assumes no slippage between phases. The individual parameters and their treatment are discussed in the following sections.

Fluid Density

The fluid density is derived from PVT data for the flowing crude oil. These data are usually obtained from laboratory measurements made on a bottom-hole sample collected from the well and pressure sealed during transportation from the field.

JPT

P. 825
Analyzing Well Production Data Using Combined-Type-Curve and Decline-Curve Analysis Concepts
Authors: Agarwal Ram G. , Gardner David C. , Kleinsteiber Stanley W. , Fussell Del D.
Published: December 2007

This paper presents new production decline curves for analyzing well production data from radial and vertically fractured oil and gas wells. These curves have been developed by combining decline-curve and type-curve analysis concepts to result in a practical tool which we feel can more easily estimate the gas (or oil) in place as well as to estimate reservoir permeability, skin effect, fracture length, conductivity, etc. Accuracy of this new method has been verified with numerical simulations and the methods have been used to perform analyses using production data from several different kinds of gas wells. Field and simulated examples are included to demonstrate the applicability and versatility of this technology.

These new production decline-type curves represent an advancement over previous work because a clearer distinction can be made between transient- and boundary-dominated flow periods. They also provide a more direct and less ambiguous means of determining reserves. The new curves also contain derivative functions, similar to those used in the pressure transient literature to aid in the matching process. These production decline curves are, to our knowledge, the first to be published in this format specifically for hydraulically fractured wells of both infinite and finite conductivity. Finally, these new curves have been extended to utilize cumulative production data in addition to commonly used rate decline data.
Applications of Wireline Stress Measurements
Authors: Desroches Jean , Kurkjian A. L.
Published: December 2007

This paper describes applications of wireline stress measurements based on the microhydraulic fracturing and packer fracturing techniques.

New testing and interpretation procedures have been developed. These procedures make it possible to obtain reliable measurements of the minimum horizontal stress and also the maximum horizontal stress in a near-vertical openhole environment, or to conduct tests in a cased-hole environment.

Examples of stress tests carried out in a wide range of formations are presented, with applications to the design of hydraulic stimulations, the stability of deviated wells, screenless completions for sand control, and enhanced recovery programs.
Enriched-Gas Miscible Flooding: A Case History of the Levelland Unit Secondary Miscible Project
Authors: Brannan G. , Whitington H.M.
Published: December 2007

Performance is reviewed of an enriched hydrocarbon-gas Performance is reviewed of an enriched hydrocarbon-gas miscible-displacement process in the Levelland Unit. Cyclic injection of enriched gas and water has been in progress for about 4 years. No significant operational problems have been encountered. The project is experiencing response, but peak response has not yet been reached. Performance indicates this project will be an economic success. Performance indicates this project will be an economic success. Introduction

The Levelland Unit secondary miscible project consists of 28 injection wells and 40 producing wells in the west central portion of the Levelland Unit, Levelland field, Hockley County, Tex. (Fig. 1). Production is from the San Andres formation at an average depth of 4,900 ft. The discovery well for this reservoir was drilled in 1946. The field was developed originally on a well spacing of 42.5 acres/well.

In 1954, the Levelland Unit was formed to conduct secondary recovery operations. A pressure maintenance program was initiated in 1955, consisting of dry gas program was initiated in 1955, consisting of dry gas injection into 18 wells scattered within the unit. Three of these former dry gas injectors are located in the secondary miscible project. All dry gas injection operations had ceased by Feb. 1971. Water injection was initiated in parts of the Levelland Unit in Oct. 1964; however, water parts of the Levelland Unit in Oct. 1964; however, water injection in the area that became the secondary miscible project did not begin until later. project did not begin until later. In April 1970, the west central portion of the Levelland Unit was evaluated for infill drilling and possible miscible flooding. Infill development would establish a well spacing of 21.25 acres/well and was justified for either the straight waterflood case or for a miscible-flood case. All the proposed infill drilling has been completed. Original plans included miscible flooding of the entire west central portion of the unit. This was to be done in two phases beginning with 28 injection wells in the Phase 1 phases beginning with 28 injection wells in the Phase 1 area, with the remaining wells to the south to be converted at a later date; however, because of supply limitations of enriched gas, the Phase 2 area has remained on waterflood.

Enhanced recovery will not take place in the Phase 2 area as a secondary operation. If enhanced recovery takes place as a tertiary-type operation, it most likely will be a place as a tertiary-type operation, it most likely will be a CO2 miscible flood rather than hydrocarbon miscible because of an insufficient additional supply of enriched gas.

P. 919
A Review of Drill-Stem Testing Techniques and Analysis
Authors: Black W. Marshall
Published: December 2007

The present techniques of using the drill-stem test as a formation evaluation tool are discussed. The basic drill-stem test operation is divided for discussion into three phases: planning the test, performing the test, and interpretation, both qualitative and quantitative. The use of small bottom choices and large top choices is suggested in order to permit quantitative interpretation for gas-oil ratio, productivity, and permeability. The importance of measuring chloride content on a suite of samples taken from a recovered column of salt water is illustrated.

Introduction

A drill-stem test is a temporary completion of the well. Drill-stem tests are usually made for one or both of the following reasons:to determine the producible fluid content of a formation, andto determine the ability of a formation to produce.

Drill-Stem Testing Methods

The drill-stem test, or temporary completion, can be made either in open hole or inside casing through perforations. A drill-stem testing program can be planned for a well so that the tests will be made in accordance with one of three general methods:Test possibly productive intervals in open hole as the zones are penetrated; normally, this method is used in conjunction with coring and ether cuts may be used to detect hydrocarbon shows.Test possibly productive intervals in open hole after drilling deeper or reaching total depth; normally, this method requires that a cement plug be set for each test, unless straddle packer testing is employed. Sidewall cores and logs are commonly used to detect the shows.Test possibly productive intervals through perforations after casing has been set; log and core data may be used in selecting the intervals.

Drill-stem testing is widely used to confirm or prove the presence and/or the producibility of oil and gas that is detected by the other services. The testing program in a well can follow any one of the methods of drill-stem testing outlined in the preceding section; however, the method of testing cored shows as the prospective pays are penetrated is probably most widely used at present.
Quantitative Study of the Applicability of Fiber-Optic Gyroscopes for MWD Borehole Surveying
Authors: Noureldin Aboelmagd , Tabler Herb , Irvine-Halliday Dave , Mintchev M. P.
Published: December 2007

Horizontal drilling increases the productivity of the drilling processes, but inevitably requires a measurement-while-drilling surveying system employing three-axis accelerometers to determine the inclination and the tool face angles, and three-axis magnetometers to provide the azimuth. The magnetometer measurements are affected by drillstring magnetic interference and downhole ore deposits, which necessitates the installation of the magnetometers inside costly nonmagnetic drill collars. The aim of this article was to examine the usefulness of the fiber-optic gyroscope (FOG) to replace magnetometers for real-time monitoring of the azimuth. System analysis of the effect of the severe downhole environment on the FOG's overall performance is presented. This analysis includes modeling the effects of shock forces, vibrations due to mud pump noise, bending vibrations due to drill collar whirling and linear coupling between the axial and transverse modes of vibration. The results obtained show that the FOG has excellent immunity to shock and vibration. Moreover, since magnetic fields have only a minor effect on the FOG, it can be installed directly behind the drill bit, thus eliminating nonmagnetic drill collars. This improves the measurement accuracy and eliminates the cost associated with nonmagnetic drill collars.
Kinetics of the Secondary Reaction of HF on Alumino-Silicates
Authors: Gdanski R. D.
Published: December 2007

The standard description of HF acidizing chemistry clearly demonstrates a primary and secondary reaction of HF with alumino-silicates.1–7 Field experience has taught us that possible precipitation during the secondary reaction can adversely affect treatment success,8 especially in formations with high K-feldspar content or temperatures above 300°F. Recent work has also reported the existence of a tertiary reaction of HF with alumino-silicates.9

This paper reports the determination of the rate law for the secondary reaction and the kinetics for that reaction on kaolinite and feldspar over a broad temperature range. In addition, the kinetics of fluosilicate precipitation during the secondary reaction were studied and found to be fast but not instantaneous. These findings were made possible by recently applied experimental techniques including 19F nuclear magnetic resonance spectroscopy,9 fractional pore-volume flow experiments,10 and an accurate knowledge of the HF stoichiometry.11 Laboratory find- ings have been verified based on detailed analysis of flowback samples from field treatments.12

The reaction rate for the secondary reaction is much slower on feldspars than on clays. At temperatures below 125°F, the secondary reaction rate is very slow, which makes spent HF susceptible to fluosilicate precipitation if the HF is mixed with brines as it often is for disposal or injection well treatments. The difference in the kinetics between clays and feldspar allows one to design treatments at lower temperatures based on just the clay fraction. At temperatures above 150°F, the average mineralogy, clay mineralogy, and feldspar mineralogy should each be evaluated separately for potential fluosilicate precipitation. The fluid of choice is the one that passes all three conditions.

The rate law indicates that the speed of the reaction is independent of HCl concentration and would proceed to completion even in the absence of HCl. Chemically, one can accomplish this effect by using water as a proton source and by adjusting the stoichiometry based on a previously reported equilibrium.11 The kinetics for fluosilicate precipitation were fast, but not instantaneous. At very high temperatures, the secondary reaction is fast enough that fluosilicate precipitations can largely be avoided. Unfortunately, the silica gel precipitation then occurs so close to the wellbore that damage to permeability will likely occur. The equations recently developed for the HF acidizing process have been incorporated into a fully kinetic geochemical radial flow simulator. Calculations performed with this simulator have confirmed that a good knowledge of the formation mineralogy and acidizing kinetics is necessary for proper optimization of HF acidizing treatments.
Integrating Dynamic Data Into High-Resolution Reservoir Models Using Streamline-Based Analytic Sensitivity Coefficients
Authors: Vasco D. W. , Yoon Seongsik , Datta-Gupta Akhil
Published: December 2007

One of the outstanding challenges in reservoir characterization is to build high-resolution reservoir models that satisfy static as well as dynamic data. However, integration of dynamic data typically requires the solution of an inverse problem that can be computationally intensive and becomes practically infeasible for fine-scale reservoir models. A critical issue here is computation of sensitivity coefficients, the derivatives of dynamic production history with respect to model parameters such as permeability and porosity.

We propose a new analytic technique that has several advantages over existing approaches. First, the method utilizes an extremely efficient three-dimensional multiphase streamline simulator as a forward model. Second, the parameter sensitivities are formulated in terms of one-dimensional integrals of analytic functions along the streamlines. Thus, the computation of sensitivities for all model parameters requires only a single simulation run to construct the velocity field and generate the streamlines. The integration of dynamic data is then performed using a two-step iterative inversion that involves (i) "lining up" the breakthrough times at the producing wells and then (ii) matching the production history. Our approach follows from an analogy between streamlines and ray tracing in seismology. The inverse method is analogous to seismic waveform inversion and thus, allows us to utilize efficient methods from geophysical imaging.

We have applied the proposed approach to a highly heterogeneous carbonate reservoir in west Texas. The reservoir model consists of 50,000 cells and includes multiple patterns with 42 wells. Water-cut histories from 27 producing wells are utilized to characterize porosity and permeability distribution in the reservoir, a total of 100,000 parameters.
Visualization and Measurement of Gas Evolution and Flow of Heavy and Light Oil in Porous Media
Authors: Firoozabadi Abbas , Aronson Andrew
Published: December 2007

In a number of experiments, the efficiency of solution-gas drive for both light and heavy oils was studied. In these experiments a special coreholder was used to visually observe the formation of gas bubbles on the rock surface of a Berea core and the production from the core outlet. The results from all the experiments reveal that the critical gas saturation for three hydrocarbon liquids; 1. a light model oil, 2. an 11-API gravity oil, and 3. a 35-API gravity oil, does not exceed 3%. However, the gas mobility for the heavy oil is very low and for the light model oil very high. Consequently, solution-gas drive for a heavy oil of 11-API gravity is more efficient than for a light oil.
A Fast 3D Interface Simulator for Steamdrives
Authors: Godderij R. R. , Bruining Johannes , Molenaar J.
Published: December 2007

Here we describe a fast 3D steam drive simulator. We use an interface model, where the single-phase steam zone is separated from the two-phase liquid zone by the steam condensation front (SCF) which constitutes the interface. Steady-state heat balances applied at the interface reduce the steam problem to a problem of gas/oil/water flow. Heat losses are treated by a prescribed conversion of steam to water. The model incorporates gravity, viscous and capillary forces and handles arbitrary permeability distributions and well configurations.

We use a multigrid method to solve the pressure equation. The steam zone development is determined by a probabilistic method, which ensures that instability phenomena are properly treated. The oil/water flow problem in the liquid domain is solved as in conventional reservoir simulators. We validate the model with analytical models.

Example calculations for a thin medium-viscosity oil field show that a transition zone with a reduced oil viscosity just downstream of the SCF has a pronounced stabilizing effect. This, and the global heat loss effects are the reason for the high displacement efficiency of steam drives.
Foam Generation at Layer Boundaries in Porous Media
Authors: Rossen W. R.
Published: December 2007

Foam can be created by snap-off in a strongly water-wet porous medium as gas and surfactant solution flow across a sharp transition in permeability. A simple pore-network model shows that this depends on a large viscosity contrast between gas and liquid and the ratio of gas and liquid flow rates, but not on the ratio of pore-throat to pore-body diameters. The model explains a variety of experimental observations.
Effect of Wettability on Oil Recovery by Near-Miscible Gas Injection
Authors: Wylie Philip L. , Mohanty Kishore K.
Published: December 2007

Oil can become bypassed during gas injection as a result of gravitational, viscous, and heterogeneity effects. Mass transfer from the bypassed region to the flowing gas is dependent upon pressure-driven, gravity-driven, and capillary-driven crossflows as well as diffusion and dispersion. The focus of this study is on the influence that wettability has on bypassing and mass transfer. Experimental results reveal comparatively less bypassing occurs in a strongly oil-wet sandstone than in a water-wet sandstone for gravity-dominated, secondary gasfloods. Mass transfer under oil-wet conditions is enhanced, as a result of oil-wetting film connectivity, over that of water-wet conditions, where water shielding is significant.
Perforating Requirements for Fracture Stimulations
Authors: Behrmann L. A. , Nolte K. G.
Published: December 2007

Perforating provides the means of communication between the wellbore and the reservoir, and in a fracture-stimulated reservoir, the perforation is the fluid conduit between the fracture and the wellbore. The existence of, or lack of, a hydraulic microannulus critically affects the choice of perforating parameters. The existence of a microannulus is dependent on reservoir and wellbore properties, perforating parameters, and fracture stimulation execution.

Recommendations are provided to choose the best perforating parameters of: shot phasing, shot density, type of charge interval length and gun orientation. Recommendations are provided for hard and soft rock hydraulic fracturing and extreme overbalance stimulation.
Use of Carbon Dioxide for Water Injectivity Improvement
Authors: Ramsay H.J. , Small F.R.
Published: December 2007

Carbon dioxide (in most cases in the form of carbonated water) has been field proven as an effective agent for increasing water injection rates. Over 300 wells have been treated. In many of the injection wells, substantial water injectivity increases (several fold) have been realized. Various methods of treatments have been applied, but usually the treating materials consist of carbon dioxide, water, a non-ionic surfactant and LPG. Theory of application is briefly presented, along with the role played by the various materials. Methods of application broadly consist of

- injection of highly carbonated water, or

- injection of low level carbonated water or

- injection of slugs of carbon dioxide.

Combinations of these methods have also been used. Field results of the various methods of application are presented.

Introduction

Carbon dioxide has been utilized for some time in secondary recovery operations. One benefit of this utilization is increased water injectivity. However, until about 1 1/2 years ago, field experience with this agent was limited to the injection of fully carbonated water containing small concentrations of a non-ionic surfactant and limited amounts of LPG. At that time, it was decided to explore other methods of obtaining increased water injectivity with carbon dioxide. Also, it was deemed desirable to include a number of oil producing formations. Table 1 shows various formations treated with carbon dioxide. Almost 200 wells had been treated prior to 1962, utilizing three methods of application (listed in Table 1). However, this experience was largely limited to full carbonation treatments in only three formations, with about 80 per cent of these treatments in the Bartlesville sand. Since that time, water injectivity experience with carbon dioxide has been broadened to include 17 more formations. One hundred and thirty-four additional wells have been treated by all three modes of treatment during the past 1 1/2 years. Experience gained from these various treatments has been invaluable. It is the purpose of this paper to discuss briefly the methods and theory of application, to show field case histories of these methods of application and to present conclusions drawn from this range of experience.

Methods of Application

Various methods of application have been used in the field to obtain increased water injectivity. In the majority of the injection wells treated with carbon dioxide, carbonated water has been injected at a solution strength of 70 to 100 per cent of the total saturation at bottom-hole conditions. This method of application is referred to as "full carbonation".More recently, a series of field experiments has been conducted in which the water has been carbonated at a level of about 3 to 4 lb of CO2/bbl of water (26 to 35 scf/bbl).

JPT

P. 25^
Steady Flow Equations for Wells in Partial Water-Drive Reservoirs
Authors: Kumar Anil
Published: December 2007

This paper presents steady-state radial flow and pressure distribution equations for wells under partial water drive or fluid injection. A parameter f is introduced to characterize the strength of water drive or fluid injection and to show its influence on well productivity.

Introduction

No convenient method exists in petroleum literature to establish the well producing rate and pressure-distribution behavior for wells in partial water drive reservoirs and in fluid injection projects under steady conditions. Such behavior is understood for wells in closed or depletiontype circular reservoirs and in reservoirs with constant pressure at the outer boundary. The latter situation is encountered in an active water drive reservoir or in fully developed five-spot injection patterns. For most wells, a realistic condition at the reservoir drainage boundary is one of partial flow because of limited aquifer or fluid injection in the aquifer or both.

Brownscombe and Collins presented a producing rate equation for a well at steady flow in a closed reservoir. The corresponding flow equation for constant pressure is well known. The derivation of those equations is presented by Craft and Hawkins. Dietz suggested a method presented by Craft and Hawkins. Dietz suggested a method of incorporating the effect of partial water drive on drainage area mean pressure of a well by changing shape factor values.

Steady radial flow equations for a well in a circular partial water drive reservoir are developed in the partial water drive reservoir are developed in the following discussion.

Theory

Consider a well producing at a constant rate from a circular oil reservoir. The formation is assumed to be uniform in thickness, porosity, and permeability. The fluid has a constant viscosity and compressibility at reservoir temperature.

After the initial transients have died down, a well reaches steady flow conditions, where the time rate of change of pressure, dp/dt, is constant with time. It is normally termed pseudosteady or quasisteady state for nonzero values of this constant and "true" steady state when the constant is zero. Under true steady state, pressure at a point acquires a constant value with respect to pressure at a point acquires a constant value with respect to time. Under pseudosteady conditions the absolute value of pressure at a point is changing with time, but the time rate of change of pressure is constant.

Let us consider the flow rate across a radius r under the influence of the following conditions at the outer reservoir boundary at r :

1. No-Flow at r : In a closed or depletion-type reservoir, there is no flow across the outer reservoir boundary, implying that the pressure gradient (dp/dr) at r is zero. The fluid volume at the well (q) is produced solely by expansion of fluid in a cylindrical shell between the radii r and r . In other words: (1)

(2)

as rw less than less than re. The term [pi r h phi c (dp/dt)] represents the expansibility of the fluid contained between the radii re and rw .

JPT

P. 1654
The Planning and Drilling of a Wildcat Well in the Republic of Seychelles by an Operator/Contractor/ Integrated Services Alliance
Authors: Marshall D. W. , Heenan D. H. , Reynolds J. T.
Published: December 2007

Constant Bank-1 is a 3,200 m (10,500 ft) wildcat well located in 50 m (164 ft) of water on a carbonate bank in the Republic of Seychelles, a group of tropical islands in the Indian Ocean. In this article we describe the development of a contracting philosophy for planning and executing the project through the formation of an alliance comprised of operator, drilling contractor, and integrated services company. We examine the unique environmental and logistical features of this project and describe how the alliance addressed these critical issues by using the strengths of the respective companies to reduce risks and ensure a cost-effective, successful operation. The logistical management of this rank wildcat well, which was situated in a remote location offering no practical means of resupply and no local resources, was further complicated by the technical difficulties associated with the well.

We conclude by discussing the different objectives of each company in conjunction with the overall project objectives and describing how these respective goals were aligned to the mutual needs of the alliance. The lessons learned by the alliance members are noted and recommendations are made for approaching similar operations.
Comment on Interference Analysis for Anisotropic Formations
Authors: Matthews T.A.
Published: December 2007

Ramey's paper. "Interference Analysis for Anisotropic Formations - A Case History." (Oct. 1975 JPT. Pages 1290–1298)' is excellent and should form the basis for calculations for years to come.There is an interesting point on nonunique solutions that-should be made. Ramey states that "If C were known. data from only two wells arc sufficient. "His previous remarks indicate that multiple solutions are previous remarks indicate that multiple solutions are possible if both observation wells are on the same straight possible if both observation wells are on the same straight line with the injection well.What is not so obvious. however. is that two solutions are possible in the general case when data from two observation wells are used.Consider the case in which the lines containing the wells are at right angles to each other. Then there is a second solution with the same kxx and kyy as the first, but with the angle 0 being the negative of the first. Inspection of Figs. 1 and 2. and consideration of the fact that Points 1.D and 5-E are independent observation points. makes this clear.Ramey's calculation procedure gives just one answer unless the coordinate axes are rotated 900, putting Point 1-D at (–475. 0) and Point 5-E at (0. 475). This interchanges the values of kxx and kyy, leaves kry, kxx. and kyy the same. and gives an angle of 28 deg.

P. 1429
Oil Production - A Continuing Challenge
Authors: Suman John R.
Published: December 2007

Rock Oil

In 1855 "rock oil" (petroleum seepages), which sold for 30 to 40 dollars a barrel, was used for medicinal purposes and widely advertised is "good for man or beast." We are all familiar with Col. Drake's "rock oil test" which was drilled near an "old oil spring" at Titusville, Pa., in 1859. After drilling into hard rock at 36 ft, "Drake's Folly" became the joke of the countryside. After many disappointments, the test struck oil at 69 1/2 ft to open the first oil boom in the United States. Many wells were drilled in Pennsylvania, West Virginia, and New York during the next few years forcing the price of oil down to 10 to 20 cents per barrel.

Transportation and refining facilities as well as markets (mostly for lighting and lubrication), increased steadily during the next 40 years. Consequently, oil prices were generally sufficiently low to encourage new uses for oil, and they were sufficiently high to provide a reasonable profit for the new industry.

The completion of the gusher at Spindletop in 1901 by Capt. Anthony F. Lucas ushered in a new era in production and marketing, with the use of fuel oil being expanded rapidly during the next 10 years. It is significant to note that the initial flow of the Lucas well was 75,000 to 100.000 B/Dequal to 50 per cent of the daily oil production in the United States during 1900. In 1901 Capt. Lucas presented a paper on the Spindletop discovery before the AIME. One of the interesting points in his discussion concerned formation evaluation.

Overproduction

Almost before the excitement of the Spindletop discovery had subsided, overproduction became a pressing problem, During the next 25 years, markets as well as daily oil production increased steadily. The ability of the United States to supply the fuel needs for the machines of war during World War I was considered to be an important factor in winning the war. Following World War I, oil production continued to increase. In 1927, E. B. Reeser, president of Barnsdall Oil Co., wrote an article for the Oil and Gas Journal entitled, "A Challenge to the Oil industry." The theme was: "Overproduction must be regulated by cooperation or government supervision. Leaders should develop a plan."
A Theory for Pressure Transient Analysis in Naturally Fractured Reservoirs
Authors: Najurieta Humberto L.
Published: December 2007

Najurieta, Humberto L.,* SPE, Inst. Mexicano del Petroleo

A method to calculate the unsteady-state pressure behavior within the fractures of a homogeneously fractured reservoir is presented. The technique allows the analysis of pressure buildup and drawdown tests for layer- like and block-shaped fractured reservoirs. The fractures pressure is shown to depend on four parameters, and a method for its pressure is shown to depend on four parameters, and a method for its determination is proposed.

Introduction

The importance of the pressure behavior as a source of information on reservoir characteristics is evidenced by the extensive theoretical work developed in this field. Homogeneous reservoirs can be described theoretically for a great number of boundary and production conditions.The basic theory for the analysis of homogeneous isotropic reservoirs is based on the line-source solution to the radial diffusivity equation:

(1)

The solution is

(2)

Eq. 2 shows that homogeneous isotropic reservoirs can be described using at least two parameters: the reservoir transmissivity T=k h/mu and the reservoir diffusivity eta=k/phi muc. Several techniques are used widely to estimate these parameters; from them, we can calculated two unknowns (e.g., k and phi provided we know the remaining (h, mu, and c). The provided we know the remaining (h, mu, and c). The definition of the skin effect and the use of the superposition principle and image wells widen the practical applications of Eq. 2. practical applications of Eq. 2. Several authors have dealt with nonhomogeneous and nonisotropic reservoirs. The solutions proposed are complex and generally require computer handling.Among the heterogeneities in a reservoir, there is an important one that is due to the presence of natural matrix fractures. In this case the productive pay is fragmented by a spatial fracture network as a pay is fragmented by a spatial fracture network as a result of the natural geologic factors. Few authors have suggested theories to aid in calculating the characteristics of naturally fractured reservoirs. A detailed theory, developed by Warren and Root, based on the theoretical work by Barenblatt and Zheltov, assumes a network of orthogonal, equally spaced features. Thus, the reservoir is made up of blocks that are able to exchange fluids with the fractures.Barenblatt and Zheltov suggested that the flow from the matrix could be considered as a first approach in a semisteady-state regime. With this assumption Warren and Root developed the differential equations and obtained analytical solutions for well test analysis. When these solutions are plotted in a conventional way (e.g., a Horner plot), plotted in a conventional way (e.g., a Horner plot), they show two parallel straight lines connected by a transition zone of variable slope. The vertical distance between them is related to the relative storage capacity of the fractures and the slopes with the flow capacity of the reservoir.

JPT

p. 1241
Three-Phase Relative Permeability of Water-Wet, Oil-Wet, and Mixed-Wet Sandpacks
Authors: DiCarlo D. A. , Sahni Akshay , Blunt M. J.
Published: December 2007

We study three-phase flow in water-wet, oil-wet, mixed-wet, and fractionally wet sandpacks. We make the mixed-wet pack by invading a water-filled water-wet pack with crude oil and aging it for a week. This process mimics wettability changes in reservoir settings, leading to a realistic arrangement of wettability at the pore scale. We characterize the wettability of each sand pack by measuring the capillary pressure curves. We obtain the oil and water relative permeabilites during three-phase gravity drainage, by measuring the saturation in situ using computerized tomography scanning. In an analog experiment, we measure pressure gradients in the gas phase to obtain the gas relative permeability. Thus we determine all three relative permeabilities as a function of saturation for each wettability. We find that under uniform wetting, the relative permeabilities of the most-wetting phase (water in a water-wet pack, oil in an oil-wet pack) are similar. However, the relative permeabilities of the intermediate-wet phase (oil in a water-wet pack, water in a oil-wet pack) are very different at low saturations, with spreading oils showing a characteristic layer drainage regime. The mixed-wet pack also shows the layer drainage regime. We also find that the gas relative permeability is smaller in an oil-wet medium than in a water-wet medium. We explain the observations in terms of wetting, spreading, and the pore scale configurations of fluid.
Real-Time Pressure Diagnostics Used To Improve Pretreatment Frac Design: Case Studies in the Antrim Shale
Authors: Dozier G. C. , Sutton T. W.
Published: December 2007

This paper describes simple diagnostics steps which can be used ahead of any fracturing treatment to determine fluid and reservoir properties essential to fracturing success. It outlines a logical progression of diagnostic injections and the data obtained from each process. These diagnostic injections have been performed in the Antrim Shale of Northern Michigan to improve the fracture design by allowing real-time data analysis in a user-friendly fashion for quick interpretion on location.

Over 7,000 fracture treatments have been performed in the Antrim Shale of Northern Michigan. Very few have been altered significantly based on pressure data acquired from each preceding treatment. In essence, there has been very little evolution in how operators stimulate the Antrim. Primarily, this is due to the inability to accurately model (fracture) the effect of natural fractures in the Antrim Shale. Nevertheless, it is possible to use these models to analyze pretreatment pressure responses to produce a more efficient frac design and improve the resulting frac conductivity. As the industry moves away from the "cookie cutter" frac design toward one specific design, with minimal additional time and effort, for the well, a mere 10 mcf/d/well increase in production over a period of 10 to 15 years becomes very economical.

This paper will illustrate simple diagnostic tests that can be performed prior to each fracturing treatment to give good indication of fluid efficiency localized rock stress. Under real-time circumstances, a 10 to 15 min injection test followed by a complete falloff can yield an abundance of information regarding the viability of a particular fracturing treatment.

In the Antrim Shale of Northern Michigan, these diagnostic techniques have been used successfully to determine leakoff, closure, fracture extension, and various other parameters essential in designing a fracturing treatment. In addition, pretreatment results have been linked with the success or premature screen-out of particular wells in the Antrim. Through case studies, this paper will show a logical progression of data analysis based on diagnostic results. Resulting in a fracturing treatment that can be designed or altered on location based on actual reservoir response and measured stresses. In turn, operators can regain a measure of predictability in controlling fractured behavior by tailoring a unique solution for each well without excessive time or added cost.
Assessing the Feasibility of a Time-Lapse Seismic Reservoir Monitoring Project
Authors: Blonk B. , Calvert R. W. , Koster J. K. , van der Zee G.
Published: December 2007

We discuss a method to assess if a particular seismic survey may be suitable as a base survey for a time-lapse seismic monitoring project, and to predict if anticipated changes in the reservoir's acoustic properties could be interpreted on a repeat survey. Our approach is to generate a simulated repeat survey using a realistic noise realization estimated from the candidate base survey. This repeat survey contains seismic changes that have been modeled by integrating rock and fluid property data, as well as results from the flow simulator. The method can be used to reduce the risk of shooting a repeat survey on which meaningful seismic changes cannot be interpreted. It can also help in deciding the proper timing for an eventual reshoot. Furthermore, the method is valuable for assessing data quality before quantitative interpretation studies. We show an example from the Middle East illustrating a survey that is unfavorable as a base survey. Furthermore, we show examples from the North Sea where application of the method was key for deciding upon a repeat survey and upon the proper timing of a possible repeat survey.
Hydraulic Fracture Propagation in Layered Formations
Authors: Daneshy A.A.
Published: December 2007

This paper reports theoretical and experimental developments involving propagation of hydraulic fractures in layered formations.

Unobstructed fractures are shown experimentally to propagate with a decreasing fracturing fluid pressure. This general trend is in agreement with pressure. This general trend is in agreement with theoretical predictions. Restrictions in fracture propagation result in an increase in fluid pressure. propagation result in an increase in fluid pressure. The relative fracturability of rocks can be determined by a direct experiment, the results of which are clear, easy to interpret, and include all pertinent parameters, such as physical and pertinent parameters, such as physical and mechanical properties of rocks, as well as the reactions between formation and fracturing fluid (for example, leak-off).

Fracturing experiments with layered samples show that with strong bonding between rocks it is difficult to contain a fracture in a formation totally.

The strength of the interface between adjacent formations is shown theoretically to be an important factor in fracture containment. With a weak bonding, fracture containment is possible and is associated with slippage at the interface. The pattern of propagation then will depend on the relative propagation then will depend on the relative mechanical properties of fractured formations.

Introduction

Most industrial hydraulic fractures are created in layered formations. During propagation, these fractures encounter various formations with different physical and mechanical properties. This paper physical and mechanical properties. This paper discusses the effect of those properties on propagation of the fracture. propagation of the fracture.Most of the theoretical studies on fracture propagation have been extensions of Griffith's propagation have been extensions of Griffith's work. Based on an energy criterion, Griffith developed a relationship among fracture shape, material properties, and the external force needed for fracture propagation. The energy source in hydraulic fracturing is the fluid pressure inside the fracture. The relationship between this pressure and material properties is

(1)

(2)

in which

L = fracture extent (length of a two-dimensionalfracture or radius of a penny-shapedfracture)

E = Young's modulus of material

mu = Poisson's ratio of material

gamma = effective fracture surface energy of material

sigma = least in-situ principal stress

A similar equation for a three-dimensional fracture is derived in Appendix A in the form of

(3)

in which

hf = fracture height

E(k) = complete elliptic integral of the secondkind

K(k) = complete elliptic integral of the first kind

k = parameter of the elliptic integrals

Eqs. 1 through 3 show p to decrease with increasing L (Fig. 1) As the fracture becomes larger, it needs less pressure for propagation.

In deriving these equations, no allowance has been made for fluid leak-off into the formation.

SPEJ

P. 33
Use of Temperature Simulations in Water-Control Design
Authors: Hardy M. A. , van Batenburg D. W. , Botermans C. W.
Published: December 2007

In this article we discuss a method to predict the temperature in the near-wellbore area during water shut-off treatments. It is essential to have a good estimate of the temperature because it greatly influences the success rate of a treatment. We present some new views on how treatment temperatures can be predicted accurately in order to design and execute a successful treatment. It explains how a production operation simulator can be used with an advanced-processes reservoir simulator to give an accurate estimate of the wellbore temperatures in the treated area. These data allow treatments to be designed on the basis of realistic temperatures rather than on bottomhole static temperatures. The results of the simulations can be used to optimize treatment placement rates, fluid composition, and shut-in times.

Two case histories of recent jobs in the North Sea area are presented where simulations were used to design water-shut-off treatments and their placement. The first case illustrates how cooldown inside the reservoir was used to place a treatment that would otherwise have gelled spontaneously at the reservoir temperature. In the second case, temperature histories for different stages of the treatments were constructed from the simulation results. These temperature histories show that several different activator compositions and concentrations were required for the early, intermediate and final treatment stages.
Capillary Pressure Correlation for Mixed-Wet Reservoirs
Authors: Skjaeveland S. M. , Siqveland L. M. , Kjosavik A. , Thomas W. L. Hammervold , Virnovsky G. A.
Published: December 2007

For water-wet reservoirs, several expressions may be used to correlate capillary pressure, or height above the free water level, with the water saturation. These correlations all feature a vertical asymptote at the residual water saturation where the capillary pressure goes to plus infinity.

We have developed a general capillary pressure correlation that covers primary drainage, imbibition, secondary drainage, and hysteresis scanning loops. The graph exhibits an asymptote at the residual saturation of water and of oil where the capillary pressure goes to plus and minus infinity, respectively. The shape of the correlation is simple yet flexible as a sum of two terms, each with two adjustable parameters and is verified by laboratory experiments and well-log data. An associated hysteresis scheme is also verified by experimental data.

The correlation can be used to make representative capillary pressure curves for numerical simulation of reservoirs with varying wettability and to model and interpret flooding processes.
The Strategic Importance of Middle East Oil
Authors: Eller Ernest M.
Published: December 2007

Introduction

The Middle East is an area of decision for the United States in the critical years ahead. Few Americans realize this; they neither know how much nor care about the lands east of the Mediterranean. This lack of interest and understanding has spawned grave errors in our foreign policy that promise sorrows and dangers for the future. This is tragic, for the destiny of civilization has been decided there often in the past; and it may be again in our own lifetime. Many reasons will bring this about, but large among them looms oil.

We live in an age of oil. Oil means power for peace or war as the Communists press on relentlessly to rule the world. We, of course, get energy from many sources, and coal that made our industrial age possible is still a basic one. Someday we may be able to get all we need from the atom and the sun direct. But the energy that drives man over the earth, carries him across the sea, and hurls him through the air comes from oil. Without oil our machines, many of our factories, our way of life would come to a halt. Without oil we could not hold the sea, which permits us to hold together the far-flung fragments of the Free World and thereby keep an uneasy peace.

Without oil we could not fight a war with any hope of winning - if we could fight at all. Oil is a key to our survival. And the Middle East means oil for there lie most of the world's resources.

This Middle East oil will help shape our destiny through this second half of the 20th century. At the moment we in the West have uneasy control of it, without realizing its almost priceless value. Most of us accept this great blessing with a casual carelessness that is frightening.