bluuebunny/crossref_metadata_2025 huggingface dataset:
Opportunities for Petroleum Engineers in Overseas Work
Authors: McCobb H.W.
Published: December 2007

"Wanted, for overseas operations-switchers-with-their-brains-knocked-out." That's roustabout talk for petroleum engineers. While tinged with sarcasm, the men who work around drilling rigs pack a world of respect into the description.

Today, with more and more U. S. oil companies staking their future on foreign operations, there is an increasing demand for top petroleum engineers. The dynamic growth of foreign markets in recent years is the basic reason for increasing overseas participation. This sets off a chain reaction of competition in the already highly competitive oil industry. In the scramble for a share of the "market", companies compete for the best petroleum engineers while the engineers compete with each other for the desirable posts.

While this may sound like the promised land to both newly graduated as well as experienced petroleum engineers, it is not entirely a land of milk and honey.

The Overseas Outlook

Just what is the present outlook for petroleum engineers in overseas operations? Latest available figures show that some 150 oil companies are engaged in about 400 separate operations in 73 of the countries spread around the world. This is about double what it was some five years ago and would indicate a heavy demand for petroleum engineers. The demand ratio shrinks rapidly, however, because more of the opportunities are with relatively small companies just entering the foreign field than with the majors having long-established operations.

The demand is further whittled by restrictions, and understandable ones, placed on operations by the governments of the host countries. Just as we are desirous of opportunities for our nationals in the U. S., the governments of other countries want to assure technical development of their people. Consequently, the ratio of U. S. expatriates to foreign nationals is relatively small. The ratio will continue to shrink each year as more people of other nations are trained in such a technical field.

The world-wide business recession which plagued us for a year and a half also cut into the demand for petroleum engineers overseas. Happily, this now appears to be on the wane.
State-of-the-Art Summary for Underground Coal Gasification
Authors: Davis B.E. , Jennings J.W.
Published: December 2007

Distinguished Author Seriesarticles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleum engineering.

Introduction

Process Chemistry

Underground coal gasification Process Chemistry. Underground coal gasification (UCG) process chemistry has been studied extensively through physical and mathematical simulations. The basic chemistryis the same as for surface gasifiers although the reaction sequences arc lesswell defined. The primary reactions include:

Oxidation: C + O2 = CO2 + 94.05 kcal/mol 2C+01=2CO + 26.42 kcal/mol

Gasification:

C+H2O=CO+H,-31.4 kcal/mol C+Co2 =2CO - 41.2 kcal/mol

Pyrolysis: Pyrolysis: coal+heat=char+tar+water+gases

Secondary reactions involving, gasification products include:

Water gas shift:

CO + H2O=CO,+H,+9.8 kcal/mol

Methanation:

C + 2H2 = CH4 + 17.9 kcal/mol CO + 3H2 =CH4 + H4O + 49.3 kcal/mol 2CO + 2H2 =CH4 + C + CO2 + 59.0 kcal/mol

During the process all of these reactions can contribute to the finalproduct composition. Both thermodynamic and kinetic effects are significant. Residence times and temperature gradients in the reactor determine the degreeto which these effects are significant for a given coal seam.

Process Mechanics

Three distinctively different Process Mechanics. Three distinctively different activities must be completed to ensure a successful UCGoperation.Preparation of the process reactor. This includes selection anddetailed characterization of the geologic domain that will be affected by theprocess, as well as installation of process wells and preparation of the seamfor gasification.Gasification of the coal. This entails in-situ conversionof the coal to a gaseous mixture of CO, CO2, H2, CH4, and higher-molecular-weight compounds. The operation should be maintained so thatinflux of boundary strata and water and loss of product gas are minimal. product gas are minimal.Site restoration. Before a site can be abandoned, restoration of the facility to its original-use value must be demonstrated. After an acceptable site is chosen the process reactor is installed by drilling two wells into process reactor is installed by drilling two wells into the coatseam and establishing a highly permeable zone or link between the well pair. Wells should be completed into the lower third of the coal seam.

JPT

P. 15
Development and Field Use of a High-Frequency Gas-Operated Rotary-Percussion Drilling Tool
Authors: Howard G.C. , Vincent R.P. , Wilder L.B.
Published: December 2007

A successful air or gas-operated percussion tool has been developed and used in drilling nine wells - one each in New Mexico, Utah and Montana; five in Wyoming; and one in Alberta, Canada. Penetration rates with the percussion tool in these wells have averaged 2.5 times faster than those obtained with rotary gas drilling and approximately 5 times greater than rotary mud drilling. Laboratory and field tests indicate that bit footages with rotary-percussion drilling have averaged 1.3 to 4 times those observed with conventional air rotary. Evaluation of laboratory drilling tests and field results shows that, where air drilling is economical, the percussion tool should be used to further decrease well costs. The additional savings should increase the number of wells in which it is profitable to drill with air instead of with liquid-base drilling fluids.

Introduction

Holes have been drilled in the earth for centuries by variations in the cable tool or churn drilling method. With this percussive method, a heavy steel bit suspended on a cable is dropped a few feet onto the bottom of the well where the bit's kinetic energy is used to chip and crush the formations. The rotary drilling system, introduced to the oil industry around 1900, drilled faster and cheaper than cable tool drilling for most wells. With the development of roller rock bits, rotary drilling gained widespread use in all areas.

In an effort to further speed rotary drilling, air was substituted for liquid as the drilling fluid on an experimental basis on several wells in the early 1950's. Air drilling resulted in faster penetration, greater footage per bit, alleviation of lost circulation problems and lower drilling costs. As a result, at the present time air or gas drilling is a routine procedure in parts of Arkansas, Pennsylvania, West Texas and the San Juan basin. The biggest deterrent to widespread use of air drilling has been the water control problem, but, as solutions to this problem are perfected, the scope of rotary air drilling will undoubtedly grow.
Permeability of Idealized Fractured Rock
Authors: Parsons R.W.
Published: December 2007

The over-all apparent single-phase permeability of fracture-rock systems was studied using two different two-dimensional models. In a strict sense the results are applicable only to these models, yet may give some insight into real reservoir behavior.

The regular fracture-matrix model can have any number of regular fracture sets. All fractures within each set have the same orientation, width and spacing. The gross behavior is analytically equivalent to that of an anisotropic permeable medium.

In the heterogeneous fracture systems, individual fracture conductivities vary within a two-dimensional network pattern. A computer program calculates the overall permeability after the conductivities are randomly placed in the network. The calculated permeability depends upon the distribution of these conductivities and the particular fracture pattern into which they are placed.

Although detailed information on actual reservoir fracture systems is not available, this study shows bow some of the possible variables may affect observed gross reservoir characteristics.

INTRODUCTION

Characteristics of reservoir rocks are determined by direct (core analysis) or indirect (logging and production tests) examination. Both methods, singly and together, are widely used in reservoir evaluations. For fractured reservoirs a problem exists in relating characteristics of cores to the in situ reservoir properties. Knowing fracture characteristics can be of value in determining production mechanisms. Because of the limitations of observation, the intimate details of a fractured rock system will never be known. One approach in analyzing fractures is to study the behavior of some conceptually simple models.

The two models analyzed contain features which may be realistic, yet are mathematically tractable. Flow is considered in two dimensions only, with the plane of interest at right angles with the fractures. This concept represents the horizontal flow in a reservoir system with the fractures oriented vertically. Only single-phase, laminar flow is considered. The regular fracture-rock system permeability is calculable from a simple analytical expression. The heterogeneous system requires a computer program for calculating overall permeability.

FLOW IN A SINGLE FRACTURE

Fluid flow in a single fracture is assumed equal to laminar flow between two infinite parallel smooth plates. This is expressed as:1Equations 1 and 2

Turbulent flow in fractured reservoirs is quite unlikely. As with flow in circular pipes, a Reynolds number can be defined to characterize the flow regime (2Wv?/µ). Values of this dimensionless group at the- onset of the transition to turbulent flow vary from 1,800 to 4,000, depending on the reference.1-3 Surface roughness on the fracture faces lowers this number.2-4
Polymer Retention and Adsorption in the Flow of Polymer Solutions Through Porous Media
Authors: Cohen Yoram , Christ F. R.
Published: December 2007

A new experimental technique based on a surface treatment process was developed for determining mobility reduction as a result of polymer adsorption in flow of polymer solutions through porous media. The experimental method also allowed the direct determination of adsorptive and nonadsorptive polymer retention from flow experiments.

The adsorptive mobility reduction for the flow of polyacrylamide (J333™) mobility control polymer through silica sand was found to be as high as 14% at the lowest experimental stress level of 3.75 dynes/cm2 [0.375 Pa]. This corresponded to an effective hydrodynamic thickness (EHT) of the adsorbed polymer layer of 0.57 μm. Both the mobility reduction and the EHT decreased with an increase in shear stress. The amount of adsorptive polymer retention accounted for about 35.2% of the total retained polymer.
Laboratory Investigation of High-Temperature Surfactant Flooding
Authors: Ziegler V. M.
Published: December 2007

Experiments were conducted to evaluate the use of surfactants for improving heavy-oil recovery from the hot-water zone in a steamflood. Criteria used to screen surfactants for this high-temperature application included thermal stability, interfacial activity, and surfactant flood performance.

The thermal stabilities of several classes of sulfonate surfactants were measured. Surfactants exhibiting no thermal decomposition at elevated temperature (500°F [260°C]) were identified.

The phase behavior between heavy crude oil (14.5°API [0.969 g/cm3]) and surfactant solution was determined over a temperature range from 150 to 350°F [65 to 177°C]. Regions of high interfacial activity were generated by the addition of salt to the brine phase. Interfacial tension (IFT) measurements confirmed the high salinity requirement of the selected surfactant/brine/oil system at elevated temperature.

High-temperature (200 to 350°F [93 to 177°C]) surfactant floods were performed to study the effect of several variables on tertiary oil recovery. Variables studied included preflush slug size, surfactant slug size, surfactant concentration, flood temperature, core material, and mobility control. Improved oil recovery was obtained when a salinity-gradient flood design was used. For the most favorable systems, incremental oil recoveries up to 14% PV were achieved.

Estimates of field performance indicate an 8 to 32% increase in oil recovery when surfactant is used with steam.
Further Investigation of High-Temperature Alkaline Floods
Authors: Medizade Mason M. , Handy L. L.
Published: December 2007

Effectiveness of alkalies, such as NaOH, Na2SiO3, and Na2CO3, to recover residual oil during hot waterfloods (356°F [180°C]) was investigated and compared. These alkalies, with or without surfactants, may be added to steam to enhance oil recovery from that portion of the reservoir subjected to a hot waterflood during steam injection. Tertiary flood rate and concentration of the injected alkalies were changed and their corresponding effects on recovery efficiency, WOR, recovery mechanism, and alkali consumption were studied. Some lower-temperature floods were also performed with caustic. Dynamic interfacial tensions (IFT's) between the acidic crude oil and the alkaline solutions at different pH's were measured at elevated temperatures up to 356°F [180°C] with a drop-weight technique. For some alkalies (e.g., NaOH), the effects of salt and surfactant addition were also investigated.

The results show that dynamic IFT's between the acidic crude oil and the alkaline solutions increase with increase in temperature. At high temperatures, IFT values at low pH approach values obtained for distilled water. This is more pronounced for caustic than for sodium metasilicate and sodium carbonate. The same IFT values obtained for caustic at elevated temperatures can be obtained with sodium carbonate and sodium metasilicate at a lower solution pH. Although IFT and alkali consumption increase with an increase in temperature, recovery efficiencies obtained at high temperatures were comparable with those obtained at lower temperatures. This could result from ease in flow of emulsions at high temperature. Recovery efficiencies obtained with sodium metasilicate at 356°F [180°C] were higher than those for sodium carbonate and sodium hydroxide. These recoveries took place at IFT values as high as 1 dyne/cm [1 mN/m]. Oil was always recovered with the injected chemicals, and no significant oil bank was formed.
New Kinetic Models for Thermal Cracking of Crude Oils in In-Situ Combustion Processes
Authors: Lin C. Y. , Chen W. H. , Culham W. E.
Published: December 2007

This paper presents two kinetic models for representing the thermal cracking of crude oils, which incorporate the cracking rate parameters and stoichiometric coefficients to correlate experimental data. The models presented show that the first-order kinetics generally accepted for pure components are unsatisfactory for multicomponent systems characterized by pseudocomponents. We conclude that three corrections to the existing first-order model are needed for modeling thermal cracking of mixtures. First, the apparent reaction order is always greater than one. Second, the reaction order is a decreasing function of temperature. Third, coke may also be formed from intermediate products. These corrections are incorporated into the models.

In the first model, crude oil is split into two pseudocomponents, while in the second model, crude oil is represented by three pseudocomponents. The models can be easily extended to any number of pseudocomponents.

The models successfully correlated experimental data of four systems available in the literature. Furthermore, it was confirmed that coke is not always the sole source of the fuel burned in an in-situ combustion process.
Well Testing and Analysis Techniques for Layered Reservoirs
Authors: Kucuk F. , Karakas M. , Ayestaran L.
Published: December 2007

This paper presents new testing and analysis techniques to obtain individual-layer permeabilities and skin factors for layered reservoirs. The new multilayer testing technique consists of a number of sequential flow tests with a production logging tool that simultaneously measures the wellbore pressure and flow rate at the top of each layer.

Two different analysis techniques are presented to estimate layer parameters. The first technique, which is the logarithmic convolution method, estimates the approximate values of parameters. The second technique, which is the nonlinear least-squares estimation method, improves the first estimates.

It is shown that layer permeabilities and skin factors can be estimated uniquely from simultaneously measured wellbore pressure and flow-rate data that are acquired from all layers sequentially. It is also shown that these individual-layer parameters cannot be estimated from the conventional drawdown- or buildup-test wellbore pressure data. Several synthetic examples are presented to illustrate the application of multilayer testing and analysis techniques.
Effect of Fluid, Confining Pressure, and Temperature on Absolute Permeabilities of Low- Permeability Sandstones
Authors: Wei K. K. , Morrow N. R. , Brower K. R.
Published: December 2007

The combined effect of temperature, confining pressure, and test fluid on absolute permeabilities of low-permeability sandstones has been investigated. Absolute permeabilities to liquids were dependent on polarity but were always significantly less than Klinkenberg permeabilities for gases. Differences are ascribed to swelling and dispersion of fine particles. Changes in state of dispersion caused by ultrasonication were investigated by measurement of resulting changes in permeabilities. Nitrogen, brine, and distilled water were used as test fluids in a main series of tests for which temperatures ranged from 0 to 93°C [32 to 199°F] and confining pressures from 3.45 to 34.47 MPa [500 to 5,000 psi]. Absolute permeabilities of five formation samples of various origins differed by up to three orders of magnitude, with the highest permeability being a few millidarcies. All specimens showed marked reduction in permeability with increase in confining pressure. For all cores, however, absolute permeabilities to gas were essentially independent of temperature at all levels of confining pressure. Comparable measurements of brine permeability were made for two core samples and, as with gas flow results, no significant temperature effect was found. Klinkenberg slip factors, B, were found to vary linearly with absolute temperature, but gave positive intercepts on the temperature axis of B vs. T plots. The intercepts were larger for gases of higher boiling point. This deviation is shown to be mainly a result of the nonideal effect of temperature on gas viscosities.
Geology Drilling Log—A Computer Database System for Drilling Simulation
Authors: Onyia E. C.
Published: December 2007

Dramatic developments have occurred during this decade in the applications of computer simulation in drilling. Our high-fidelity Engineering Simulator for Drilling (ESD) has the distinctive capability to permit an operator to simulate drilling in different geographic locations using actual drilling and geologic data for that environment. The Geology Drilling Log (GDL) is a data base used by the ESD that not only gives the ESD the flexibility described, but also allows us to describe in sufficient details the properties of the rocks through which we drill. Engineering models and other simulation activities pool information from a GDL during simulation. This paper discusses the technique used to build a GDL and illustrates the steps necessary to build a similar data base for other drilling simulators.
Reservoir Sizing Using Inert and Chemically Reacting Tracers
Authors: Robinson Bruce A. , Tester Jefferson W. , Brown Lee F.
Published: December 2007

Nonreactive tracer tests in prototype hot, dry rock (HDR) geothermal reservoirs indicate multiple fracture flow paths that show increases in volume as a result of energy extraction. Tracer modal volumes can be correlated with estimated reservoir heat-transfer capacity. Chemically reactive tracers are proposed that will map the rate of advance of the cooled region of an HDR reservoir, providing advanced warning of thermal drawdown. Critical parameters are examined with a simplified reservoir model for screening purposes. Hydrolysis reactions are a promising class of reactions for reservoir temperatures ranging from 80 to 2OO°C [176 to 392°F]
The Effects of Salt, Gas, Temperature, and Pressure on the Compressibility of Water
Authors: Osif Terry L.
Published: December 2007

Laboratory measurements of compressibilities are presented that show that plots of the reciprocal of compressibility vs. pressure are linear for water and brines. The slopes of these plots are all the same, but the intercepts are linearly dependent on the temperature and salinity over the range of conditions studied (1,000 to 20,000 psi [6.9 to 138 MPa], 200 to 270°F [93.3 to 132°C], and 0 to 200 g/L). Dissolved gas has no effect on these compressibilities at gas/water ratios (GWR’s) of 13 scf/bbl [2.3 std m3/m3]. Even at GWR’s of 35 scf/bbl [6.3 std m3/m3], dissolved gas probably has no effect, but certainly causes no more than a 5% increase in the compressibility of brine.
Characteristics of a Retrograde Condensate Reservoir Containing a Large Quantity of Carbon Dioxide
Authors: Bauman W.E. , Miles F.V.
Published: December 2007

Introduction

The literature possesses limited data on reservoirs containing an appreciable quantity of carbon dioxide. The primary purpose of this paper is to present the fluid characteristics of a retrograde condensate system containing approximately 92 per cent carbon dioxide. The text includes the basic PVT studies as well as a discussion of surface separation equipment and problems associated with testing and producing the reservoir. Included also are geological and engineering characteristics of the reservoir and a review of corrosion problems.

General Description of Area

About eight miles northeast of Walden, Colo., in the North Park basin, there are at present four commercial oil fields producing from the Muddy, Dakota, Lakota and Morrison sands of Cretaceous age. These fields are not very significant in size, but each field is on a separate anticlinal structure, and the apparent variation in the nature of their reservoir fluids is quite unusual. Fig. 1 is a map of the area showing the four producing fields. The average elevation of this general area is 8,200 ft. This discussion will deal with the most recently discovered area situated in the South McCallum field, which produces condensate with a large quantity of carbon dioxide from the Muddy, Dakota and Lakota sands. The reservoir fluid is 92 per cent CO2, 3 per cent nitrogen and 5 per cent hydrocarbons.

This area, more specifically referred to as the Ballinger-Federal, was discovered in Oct., 1958 with the completion of Gulf Oil Corp.'s Ballinger-Federal No. 1, C-SW-SE Section 8–9N–78W, Jackson County, Colo., for a calculated absolute potential of 39,400 Mcf of CO2 and 542 B/D of 480 gravity condensate. The condensate is an almost clear liquid with a light golden color. A second well was completed in Dec., 1958 for a calculated absolute potential of 101 MMcf of CO2 and 1,390 B/D condensate. The produced GOR initially was approximately 72, - 600 cu ft/bbl. Both wells tested water in the Morrison sand at the approximate depth of 5,400 ft and are completed in the Muddy, Dakota and Lakota sands between 4,980 and 5,345 ft. Production from the three sands is commingled in the wellbore. The two wells are presently being produced at the rate of 200 B/D each.
Mobilization of Waterflood Residual Oil by Miscible Fluids
Authors: Holm L. W.
Published: December 2007

A study was conducted to determine how residual oil left by a waterflood is mobilized by miscible or low-interfacial-tension (IFT) fluids. Crude oils were used in the oil-displacement experiments with cores and sandpacks. In most previous investigations, refined oils were used. The residual crude oil was distinguished from injected oils by tagging of one or the other with olefins—hydrocarbons that are not present in crude oils but are easily and quantitatively distinguishable by analytical chromatographic techniques.

The study shows that residual crude oil left by a waterflood is more accessible to an injected miscible fluid than is a residual refined oil, presumably through crude-oil-wetted surfaces of the rock. The results of laboratory coreflood displacements of residual or mobile refined oils (decane, soltrol, mineral oil, etc.) are not representative of reservoir formations containing indigenous crude oil. The displacement of residual crude oil by solvent is more efficient than displacement of refined oil by that solvent. Also, the displacement of residual oil by an oil or solvent at favorable mobility ratio occurs as a bank of oil production at a high flowing oil saturation approaching one minus the immobile water saturation. This saturation in a given porous medium at oil breakthrough depends on the viscosity of the residual oil.
Elastomers Are Eliminated in High-Pressure Surface-Controlled Subsurface Safety Valves
Authors: Morris A. J.
Published: December 2007

Industry well completions are currently limited by the uncertain finite life of elastomers. The useful life of subsurface equipment with elastomeric seals is shortened by temperature, pressure, amines, acids, and completion fluids.

All-metal, hydraulically operated surface-controlled subsurface safety valves (SCSSV's) that meet and exceed all regulatory requirements and standards are now available with no elastomeric seals. This fully developed design, awarded the Special Meritorious Award for Engineering Innovation in May 1983, has been completely laboratory and field tested and is being used in critical service well completions.

Development of subsurface high-pressure completion equipment indicates that at 10,000-psi [69-MPa] working pressure; elastomers perform at minimum acceptable levels. The longevity of subsurface completion equipment is limited and uncertain. Combining sound engineering principles with state-of-the-art metallurgy, reducing galling tendencies of high-nickel/chrome alloys, and using diffused-surface alloys have resulted in the technology for all-metal hydraulically operated equipment. This technology is expandable to an entire subsurface completion system without any elastomers.
Effects of Wellbore Storage and Skin on Vertical-Permeability Testing
Authors: Kamal M. M.
Published: December 2007

Knowledge of the vertical permeability is needed to determine the optimal depletion scheme of most reservoirs. Current methods often render vertical-permeability tests uneconomical to conduct and/or to analyze, and methods are not available for test design. This paper presents a new method, based on type curves, to design and analyze vertical-permeability tests in the presence of wellbore storage and skin at both the active and measurement perforations. The method uses early-time data and thus reduces the test time and improves the economics of vertical-permeability testing. The new method is simple to use and practically eliminates the need for numerical simulators. A step-by-step example describing the design and analysis of a vertical-permeability test demonstrates the use of this method.
Tip Screenout Fracturing: A Technique for Soft, Unstable Formations
Authors: Smith M. B. , Miller W. K. , Haga J.
Published: December 2007

Several special stimulation techniques have been proposed for soft, unstable formations. One example is a combination of acid and proppant, which leaves the acid channels full of sand. This paper discusses an alternative completion technique that involves only normal sand fracture procedures and is effective where acid is ineffectual or undesirable. Because the procedure is aimed primarily at creating short, high-conductivity fractures in soft formations, its use can be extended to any formation where such a treatment is practical and economically feasible.

The fracture design is based on intentionally screening out the tip of the fracture with sand and then continuing to pump slurry to increase the fracture width and to pack the fracture with proppant to obtain high conductivity. Because this involves severe risk of a premature screenout, and because failure to achieve the tip screenout will not yield the desired stimulation, special prefracture tests are required to determine fracture design variables. The implementation and analysis of these tests are discussed, along with the theory behind the fracture design schedule. This theory is then compared with fracture pressure data and production performance from two wells completed in an Upper Cretaceous chalk formation in the Norwegian Sector of the North Sea.
Hydrodynamic Conditions of Hydrocarbon Accumulation Exemplified by the Carboniferous Formation in the Lublin Synclinorium, Poland
Authors: Zawisza Ludwik
Published: December 2007

Groundwater movement in a selected aquifer of a sedimentary basin in the Lublin synclinorium is considered on the basis of rock and fluid data, and conditions of migration and accumulation of hydrocarbons are presented. The problem of groundwater movement is solved analytically, taking into consideration variable density of water and variable permeability of rocks.

A modified theory is advanced to define more precisely the position of potential oil and gas traps. The theory introduced here is more universal than Hubbert's theory because it accepts both the variability of the oil, gas, and water density (static effect) and the groundwater motion (dynamic effect). The suggested method of determining the positions of potential hydrodynamic petroleum traps is comparatively simple to apply and gives good results in regions with high hydraulic gradients and high variability of salinity and hydrocarbon densities.
Application of Fracture Design Based on Pressure Analysis
Authors: Nolte K. G.
Published: December 2007

This paper describes case studies of fracturing pressure analysis for the Wattenberg field of the Denver basin and the Cotton Valley sand of east Texas. The studies show the benefits of pressure analysis and controlled pressure designs for fracture treatments. In addition, procedures for measuring fracturing pressures and considerations for the successful execution of minimal viscosity treatments are presented.
Triple-Porosity Systems for Representing Naturally Fractured Reservoirs
Authors: Abdassah Doddy , Ershaghi Iraj
Published: December 2007

This study develops an improved model for analysis of pressure transient tests of naturally fractured reservoirs. The development was prompted by observations of actual well tests that showed anomalous slope changes during the transition period and where the behavior could not be explained by dual-porosity models.

Geometrical configurations studied include both the strata model, where horizontal matrix layers are separated by fractures, and the uniformly distributed blocks, which are separated by an orthogonal set of fractures. These systems were assumed to be under gradient flow conditions. In both cases, two separate sets of matrix properties were assumed. The formulation of response was solved semianalytically. The solutions included the earlytime effects of both the afterflow and skin.

Observations made from the theoretical predictions are that the fracture-controlled early times and portions of the transition period will resemble the behavior of a dual-porosity system. The latter part of the transition zone, however, exhibits slope changes; the duration is a function of λ1/λ2 (ratio of interporosity flow coefficients for the two matrix types) and ω1/ω2 (ratio of fluid capacitance coefficients).

A correlation developed on the basis of numerous sensitivity runs allows the estimation of ω1/ω2 and λ1/λ2 with the times that correspond to the onset of anomalous slope changes. Because an infinite-acting slope may develop before the matrix blocks of the lowest λ show their existence during the anomalous slope changes, recognition of the various matrix properties emphasized in this study will also safeguard against extrapolation of incorrect late-time curves.
Incomplete LU Preconditioners for Conjugate-Gradient-Type Iterative Methods
Authors: Simon Horst D.
Published: December 2007

In recent years, such conjugate-gradient-type methods as orthomin have been used very successfully with various preconditioners to solve the unsymmetric linear systems that arise in reservoir simulation. Here these successful iterative methods are combined with a new set of preconditioners that have been derived from some powerful algorithms in direct sparse Gaussian elimination. The SPARSPAK implementations of minimum degree and nested dissection algorithms have been modified to yield incomplete LU factorizations. Their application to reservoir simulation problems is investigated here.
Effects of Gas Composition and Geothermal Properties on the Thickness and Depth of Natural-Gas-Hydrate Zones
Authors: Holder G.D. , Malone R.D. , Lawson W.F.
Published: December 2007

When natural gas and water contact at low temperature and high pressure, gas hydrates can form. In colder climates (such as Alaska, Northern Canada, and Siberia) and beneath the oceans, conditions are appropriate for gas-hydrate formation. This paper gives the depths and potential thicknesses of such hydrate formations as a function of the geothermal gradient, gas composition, and where appropriate, permafrost thickness. pressure gradient, and ocean-bottom temperature.

Analysis of Reservoir Conditions Where Hydrates Are Likely To Form

An accurate model for predicting hydrate equilibrium as a function of gas composition, temperature, and pressure has been used to generate hydrate-stability data. Figs. 1 through 6 present depth-vs.-temperature profiles for the earth and indicate hydrate-stability zones. The variables studied included permafrost thickness, geotherinal radients, gas composition, and pressure gradients on land and ocean depth, ocean-bottom temperature, and gas composition beneath the ocean. Except for the gas composition. these variables allow the pressure/temperature conditions in the earth to be determined. Together with gas composition, pressure and temperature determine whether hydrates are stable. These variables are cross-correlated so that any combination of permafrost thickness, gas composition, and geothermal permafrost thickness, gas composition, and geothermal gradient can be evaluated. Correlations presented in Figs. 7 through 11 show the effect that these variables have on hydrate-stability-zone thickness. All results were calculated with a computer program of excellent accuracy that calculates the minimum pressure required for hydrate stability given temperature, T, and gas composition. If the pressure calculated by the program is lower than the pressure determined from the pressure gradient in the pressure determined from the pressure gradient in the earth, the hydrates are stable; otherwise, the hydrates are not stable. Results of the depth/temperature studies are presented in Figs. 1 through 6 as outlined below. Table 1 shows the default values used for these calculations. These values are considered to be representative. Where differences in values are likely, the effects of changes in these values have been given in Figs. 1 through 11. The values studied are not the only possible conditions in the earth. The ranges of values used were chosen because they represent conditions where hydrates can form, but some values, such as geothermal gradient and average surface temperature, can vary with location.

P. 1379
Predicting Liquid Gradient in a Pumping-Well Annulus
Authors: Hasan A. Rashid , Kabir C. Shah , Rahman Rehana
Published: December 2007

This work proposes a hydrodynamic model for estimating gas void fraction, fg, in the bubbly and slug flow regimes. The model is developed from experimental work, involving an air/water system, and from theoretical arguments. The proposed model suggests that prediction of fg, and hence the bottomhole pressure (BHP), is dependent on such variables as tubing-to-casing-diameter ratio, densities of gas and liquid, and surface tension. Available correlations do not include these variables as flexible inputs for a given system.

Computation on a field example indicates that slug flow is the most dominant flow mechanism near the top of liquid column at the earliest times of a buildup test. As buildup progresses, transition from slug to bubbly flow occurs in the entire liquid column. Beyond the afterflow-dominated period, the effect of bubbly flow diminishes as gas flow becomes negligibly small. Comparisons of BHP's are made with the proposed and available correlations. Because the proposed model predicts fg between those of the Godbey-Dimon and Podio et al. correlations, BHP is predicted accordingly.
Evaluation of Oil Properties in After-Tax Dollars
Authors: Powell Douglas H.
Published: December 2007

Why do we talk about "pre-tax dollars" and "after-tax dollars"?

In choosing its investments, management today usually asks the question, "How soon will we have a full return of our investment after all income taxes?"

Contrary to our intentions, every business venture that we enter into today has some unseen "net profits interests" who get a major percentage of our net profits but stand none of our net losses if the venture is unsuccessful. This refers, of course, to the fact that, under the present rates of income taxes, the United States Government and the State of California (or some other state) get approximately 50 per cent of the net profits (if any) of any venture of a large corporation and varying percentages in the cases of small corporations, partnerships and individuals.

Field property valuations are ordinarily submitted on a strictly engineering basis, arriving at the present worth of the net cash recovery before income taxes for the estimated life of the property.

To convert these pre-tax dollars to the after-tax dollars so often wanted by management in weighing one proposed investment against another, it is necessary to estimate the income taxes payable by years. In an extractive industry such as ours, statutory depletion is an important element in this computation, as are the depreciation deduction and method of financing also. These computations are ordinarily done by accountants versed in income taxes.

This paper is presented to explain how accountants and petroleum engineers must sometimes work together to get the final solution desired in making a valuation of oil and gas properties in after-tax dollars.

Introduction

Income taxes have reached such high rates that all important business transactions made today are entered into only after consideration has been given to the impact of income taxes on the final net results. Most agreements are drawn in such a manner as to minimize income and other taxes as much as possible and avoid the payment of any unnecessary taxes.
A New Approach to Interference Test Analysis
Authors: El-Khatib Noaman A. F.
Published: December 2007

The line-source solution of the diffusivity equation is differentiated and rearranged so that a linear relation between the variables is obtained. A plot of log tp′ vs. 1/t yields a straight line whose intercept and slope are used to estimate the transmissivity, kh/μ, and the storativity, hϕct, respectively. The method is extended to handle two-rate tests, including buildup tests, and can be used for the analysis of the combined data of the two periods.
Revised Bean Performance Equation for East Baghdad Oil Wells
Authors: Al-Attar H. H. , Abdul-Majeed G. H.
Published: December 2007

A comparison of the existing correlations for the determination of multiphase fluid-flow performance through a wellhead choke is made. The comparison is based on statistical analysis with production data from 155 well tests, 20 of which are from the East Baghdad oil field. The comparison indicates the relative strengths and weaknesses of each correlation and should aid in the selection of a satisfactory correlation for different applications. No one method is found to be most accurate in all ranges of flow variables. The best overall comparison, however, is obtained with the Gilbert correlation that predicted measured production rates within an average error of 6.19%. This correlation is then revised in two forms to fit the observed data from the East Baghdad oil wells best.
The Utility of CO2 as an Energizing Component for Fracturing Fluids
Authors: Garbis Sam J. , Taylor J. Lawrence
Published: December 2007

The use of CO2 as an energizer in hydraulic fracturing fluids has increased dramatically in the past few years. The history of CO2 usage for this application is discussed briefly, and CO2 is compared with the other commonly used energizer, N2. The design considerations for using CO2 in a fracturing treatment, both as a minor (energizer) and a major (foam) component, are presented. Special consideration is devoted to CO2 foam because CO2 is pumped as a compressible liquid that changes to a gas downhole. This paper presents the calculations required to estimate the surface liquid CO2 volumes and injection rates needed to obtain the desired downhole foam properties. Also, the instrumentation required to meter the liquid CO2 safely and accurately is discussed.

Field results further evidence CO2's utility in hydraulic fracturing. This discussion includes a comparison of fracture stimulation with and without CO2 as an energizer as well as treatments that compare CO2 -energized fluids with N2-energized fluids. Economic considerations of pumping CO2 vs. N2 vs. no energizer are discussed. Conclusions suggest what further study is required to help improve design techniques and when CO2 should be considered as a component of a fracture stimulation treatment.
Quantitative Analysis of Factors Influencing Vertical and Lateral Fracture Growth
Authors: Settari Antonin
Published: December 2007

This paper presents contributions to the modeling of the vertical and lateral propagation of hydraulic fractures. The first part presents a method for the quantitative analysis of factors controlling vertical height growth in three-dimensional (3D) fracture propagation. Included are confining stress contrast, elastic stiffness contrast, fracture toughness, and influence of settled (or buoyant) proppant on height growth. A composite propagation function was formulated that can be implemented in a pseudo3D model of fracture geometry or in hand calculations. The second part extends the formulations of the lumped models for lateral fracture growth to handle dynamic conditions existing in the field. The new formulation can handle variable injection rates, fluid rheology changes, and multiple fluids and includes fracture toughness at the tip. The results are presented in the form of dimensionless charts, and their use is explained through an example.
Log Analysis Techniques for Quantifying the Permeability of Submillidarcy Sandstone Reservoirs
Authors: Kukal G. C. , Simons K. E.
Published: December 2007

A gradational diagenetic change from the "tubular" primary pore network of conventional sandstones to a pore geometry consisting of secondary-solution pores interconnected by narrow "slot-like" flow paths in low-permeability sandstones has necessitated the formulation of revised log-derived permeability equations. The equations are derived from Lower Mesaverde group core data and are tested for limitations by extrapolation to a. shallower Mesaverde interval and to a remote Travis Peak (Hosston) interval. An alternative method involving invasion inferences from a log-derived filtration index is used to complement the permeability analysis.
Development of an Efficient Algorithm for the Calculation of Two-Phase Flash Equilibria
Authors: Abhvani A. S. , Beaumont D. N.
Published: December 2007

This paper details the development of an efficient algorithm for the calculation of two-phase equilibrium in multicomponent hydrocarbon systems with an equation of state (EOS). A number of numerical solution algorithms are evaluated for speed and robustness. To ensure generality, the compositions used in the study range from a synthetic 3-component fluid to a real 20-component reservoir fluid, and the calculations are performed at different positions on the fluid-phase diagram.

The results of the study are used in the construction of a stable and efficient algorithm. Although the method was developed with reservoir engineering applications in mind, it should also be applicable in chemical, process, and petroleum engineering.
Approximate Partial-Penetration Pseudoskin for Infinite-Conductivity Wells
Authors: Papatzacos Paul
Published: December 2007

This paper presents a simple formula for the pseudoskin factor of a well with restricted flow entry where infinite conductivity is taken into account analytically. Comparisons with previously published results are shown graphically and in tabulated form.
Influence of Downhole Conditions on the Leakoff Properties of Fracturing Fluids
Authors: Ford William G. F. , Penny Glenn S.
Published: December 2007

Fluid loss under dynamic conditions, considering such realistic conditions as low-permeability core samples and extreme shear conditions, has been examined and is reported in this paper. Dynamic data of fluid loss as a function of time, pressure, and temperature have been developed.
Estimation of the Permeabilities and Skin Factors in Layered Reservoirs With Downhole Rate and Pressure Data
Authors: Shah Piyush C. , Karakas Metin , Kuchuk Fikri , Ayestaran Luis C.
Published: December 2007

This paper addresses the problem of estimating horizontal and vertical permeabilities, skin factor, and average fluid pressure within the drainage area in each layer in a multilayered reservoir in the presence of formation crossflow between the layers and commingling through the wellbore. A multistep testing procedure is proposed that involves downhole measurement of the pressure and fluid flow rate. The measurements are made successively above the individual layers as transients are induced in the reservoir. A history-matching procedure is used to analyze the data from the entire multistep test simultaneously. The performance of this approach is compared with that of separate, conventional interpretation of each step in five examples with synthetic data. The simultaneous analysis benefits from the synergy between the steps and consistently yields better estimates.

A linearized sensitivity analysis is developed to determine the probable errors in the parameter estimates. It indicates whether a given set of measurements with a given level of measurement noise contains sufficient information to determine the individual parameters uniquely.
Effect of Solvent on Steam Recovery of Heavy Oil
Authors: Shu W. R. , Hartman K. J.
Published: December 2007

Solvents and light ends of crudes are frequently used as diluents to facilitate pumping and pipeline transportation of heavy crudes. The use of solvent alone for in-situ recovery of heavy oil tends to be limited because of its high cost; however, the use of solvent as an additive to steam processes has been tested both in the laboratory and in the field. The results of these tests are mixed. In this study, we use numerical experiments to delineate the recovery mechanism of a steam-slug process when solvents are present. A good understanding of the mechanism will help provide an interpretation of the conditions under which solvents can improve steam oil recovery. The study focuses on the use of small quantities of solvent—i.e., no more than 10% of the steam volume.
A Simplified Performance-Predictive Model for In-Situ Combustion Processes
Authors: Genrich J. F. , Pope G. A.
Published: December 2007

A one-dimensional (ID) model to perform rapid calculations of fluid production history for dry and wet forward insitu combustion processes is presented. The predominantly explicit, discrete timestep formulation divides the reservoir into four zones of constant properties, separated by shock fronts. Model results are compared with a ID simulator study of a combustiontube experiment and with field data from the Suplacu de Barcau project.