bluuebunny/crossref_metadata_2025 huggingface dataset:
The Mechanics of Sand Movement in Fracturing
Authors: Kern L.R. , Perkins T.K. , Wyant R.E.
Published: December 2007

Introduction

Many factors influence the results of hydraulic fracturing to stimulate well productivity. Most of these factors have been studied and their effects discussed in the literature. However, the movement of sand through the crack during fracturing has received little consideration. Exactly where the sand goes in the fracture, how it gets there, and how this might influence results have not been studied, judging from published reports.

To get an answer to some of these questions we have studied sand movement through a simulated crack segment in the laboratory. Although the work is preliminary, we have answered some questions about sand movement in a semiquantitative sense. We are reporting our results at this time in the hope of stimulating interest and further study in this important aspect of fracturing.

Laboratory Experiments

Fig. 1 is a schematic diagram of equipment used in this study. A segment of a vertical crack 0.25-in. wide was formed between two Plexiglas plates, and movement of sand in fluid through the crack was observed under various conditions.

Sand and fluid were injected into the crack at constant rates. The top and bottom of the crack were closed so that the fluid flowed horizontally. Because of gravity most of the sand settled to the bottom before moving very far through the crack. If the fluid velocity exceeded a certain critical value, then all the sand injected was washed on through the crack even though it had settled to the bottom.

When the fluid velocity was less than this value when sand injection was started, most of the sand which settled in the crack remained in place until enough of the area open to fluid flow was blocked by the settled sand to increase the fluid velocity to the critical value. At this point all injected sand moved on through the crack even though it settled to the lower portion of the moving fluid section. All sand previously settled remained in place.
The Effect of Formation Flow on the Integrity of Perforated Casing
Authors: Pattillo Phillip D. , Smith Michael B.
Published: December 2007

This paper summarizes an analysis of formation/casing deformations in a chalk reservoir. The study is linked to the development of a poroelastic-plastic model of ductile rocks. Applications of the model include an analysis of chalk production into perforated casing and a discussion of the effects of such production on collapse integrity of the casing.
A Comparison of Theoretical Pressure Build-Up Curves with Field Curves Obtained from Bottom-Hole Shut-In Tests
Authors: Pitzer Sidney C. , Rice John D. , Thomas Clifford E.
Published: December 2007

Interpretation of pressure build-up data obtained in the conventional manner has often been difficult because of the deviation from theoretical behavior. Major causes of this deviation have been attributed to damage and afterflow, and to fluid redistribution in the wellbore which, in extreme cases, can result in a pressure hump in the early portion of the build-up curve.

Theoretical investigations show that bottomhole pressure is definitely influenced by phase redistribution in the tubing column during surface shut-in tests, and that the magnitude of the effect is sensitive to the producing gas-oil ratio and stabilized rate of flow in the well.

For field experiments a wire-line tubing packer, which can be run in the tubing against a stabilized flow rate, was developed for bottom-hole shut-in tests. By use of this bottom-hole shut-in method, pressure humps previously observed in surface shut-in tests were completely eliminated and the effects of afterflow minimized.

Analog and digital computer studies have been made to obtain theoretical curves for comparison with field curves, and remarkable agreement between the results of bottom-hole shut-in tests and theoretical curves has been obtained.

Introduction

Pressure build-up data from shut-in wells have been used by the petroleum industry to determine the permeability of the formation, to estimate wellbore damage, to evaluate the static reservoir pressure and to speculate reservoir volume. Calculation of these factors is based on methods of analysis developed for theoretical systems whose build-up curves have a characteristic shape when the wells are shut-in at the sand face. However, field curves obtained by conventional surface shut-in methods do not always exhibit this characteristic. Such factors as stratification, rock heterogeneities and irregular reservoir geometry can cause the character of a buildup curve to deviate from that predicted by theory for a simple system. In addition, all field build-up data are affected by the methods utilized in obtaining the measurements.
Effect of C7+ Properties on Equation-of-State Predictions
Authors: Whitson Curtis H.
Published: December 2007

This work studies the effect of heptanes-plus (C7+) characterization on equation-of-state (EOS) predictions. Both the Peng-Robinson EOS (PREOS) and a modified Redlich-Kwong EOS are used. Several characterization schemes found in the literature are used in the study. Six reservoir fluids with extended C7+ analysis have been chosen, representing a broad range of compositions and PVT data.

First, the study deals with methods for estimating specific gravities and boiling points of petroleum fractions, two properties usually required by critical property correlations. EOS predictions arc made by using critical properties based on specific gravities and boiling points measured experimentally and estimated with correlations.

Next, a review of critical-property correlations is given, including a review of commonly used correlations. Four correlations are chosen to study the effect of critical properties on EOS predictions. Results indicate that relatively small differences in critical properties and acentric factor can result in significant differences in EOS predictions.

Finally, a study is made of the effect that adjustments in C7+ critical properties Have on EOS predictions; adjustments of EOS constants (Ωa and Ωb) and binary interaction coefficients also are studied. The influence of individual and combined adjustments to C7+ properties are illustrated graphically. They provide qualitative guidelines that can be used when matching experimental PVT data with an EOS.
Case Histories Show Value of Corrosion Inhibitor Squeeze Treatment
Authors: Poetker Rupert H.
Published: December 2007

Introduction

The inefficiency of batch treatment down the annulus to prevent corrosion in gas-lift wells led to a search for a better method. Squeezing inhibitor into the formation was attempted and appeared to be an improvement over other methods of treatment. With these other methods it was difficult to get the chemical where it was needed because a high fluid leg would cause a major portion of the chemical to enter the tubing string at the working valve, which was too high to give complete protection.

A low fluid leg would cause the chemical to dehydrate and leave a gummy substance on the outside of the tubing and on the inside of the casing. This tendency could be partially overcome by using large amounts of diluent (5 to 10 bbl) with the chemical, but such treatment was time-consuming and expensive. Sticks and pellets were tried with poor results.

Theory of Squeeze

It was found that some inhibitors would adsorb to sand rapidly and would desorb slowly. Laboratory work indicated that this adsorption-desorption rate was sufficient to warrant field testing. The high chemical concentration (11,000 to 1 million ppm) in contact with the steel during the squeeze is also a factor. Limited field tests to evaluate these two factors have been performed, but are inconclusive.

Squeeze Treatment

Since Nov. 1954, 60 wells have been squeeze-treated with a total of 160 squeezes. These 60 wells are located in 10 different fields and produce from 19 separate reservoirs. They vary in depth from 3,000 to 12,000 ft. Of the 60 wells, four are natural flowing wells, 47 are gas-lift wells, eight are gas condensate wells, and one is a pumping well. From the information available, it appears that about 150 wells have received this inhibitor squeeze-type treatment. Approximately 350 separate squeeze treatments have been done in these 150 wells. A breakdown of these 150 wells as to method of production is as follows: gas-lift, 85; natural flow, 15; pumping, 20; and gas condensate, 30. Production from these wells, located in Texas, Louisiana and Arkansas, is both sweet and sour. Some are producing from sand and some from lime-stone formations.
Control of Injection Gas Composition in Enriched Gas-Drive Projects
Authors: Elliott J. Kelly , Johnson Harry C.
Published: December 2007

Introduction

One of the primary requirements for successful operation of an enriched gas-drive project is to control the composition of injection gas. This can become a serious and difficult problem, particularly in cases where the enrichment material is being furnished from a number of field-produced gas streams. It is possible to effect control of the injection gas composition through frequent or continuous sampling; however, this can be extremely costly and, in many cases, impractical due to laboratory requirements of time. Another alternative would be to provide a calculation technique which would be flexible and sufficiently accurate to predict composition of the liquid and gas streams of interest at any point in the system. The purpose of this paper is to discuss a technique that was used successfully on an operating enriched gas-drive project for developing information which could be used for controlling composition of the injected gas.

Field Operations

The particular field (hereafter called Example field) in the example operation being discussed is composed of four oil reservoirs (A, B, C and E) and one gas condensate reservoir (D). Casinghead gas from the oil reservoirs and gas from the gas condensate reservoir are gathered through a field gathering system as shown in Fig. 1 for injection into Reservoir C. The gas mixture which is recovered from the five reservoirs for injection purposes is composed of gases liberated in 19 individual separators, each operating at a separate temperature and pressure.

Proposed Calculation Technique

It is well known that vapor-liquid equilibrium calculations in general use throughout the petroleum industry can be used to predict reliably the phase behavior of hydrocarbon mixtures, particularly at pressures less than 1,000 psig. It is then a simple matter to account for the material on a component basis by making flash and material balance calculations at each separation point in a hydrocarbon system. Accordingly, it was proposed to use vapor-liquid equilibrium and material balance calculations with a medium-sized electronic digital computer as a basis for developing a control procedure for use in controlling injection gas composition in the enriched gas-drive project.
Application of a Reservoir Simulator Interfaced With a Surface Facility Network: A Case History
Authors: Breaux E. J. , Monroe S. A. , Blank L. S. , Yarberry D. W. , Al-Umran S. A.
Published: December 2007

Management requires dependable information upon which to base decisions regarding large investments. The system discussed in this paper proves to be a viable tool for effectively managing reservoir development and provides several alternatives upon which management could base such decisions.

A three-dimensional (3D), three-phase reservoir simulator is interfaced with a surface facility network simulator. The results are used in determining an integrated field development and operating plan for producing an onshore-offshore oil reservoir at a specified rate. Various aspects of alternative development and facility installation scenarios are investigated with the interfaced system. The requirements and sizing of major surface facilities and a drilling and workover program are determined over a 25-year study period. The most efficient development plan is one that combines cost-effective drilling and facilities scheduling while at the same time providing maximum operating flexibility and balanced reservoir development.

This technique has been applied to the future development planning of existing fields but is equally applicable to planning the development of new fields in any environment by altering the producing rules controls and reservoir and network models to account for the appropriate circumstances.
Laboratory Study Indicates Significant Effect of Pressure on Resistivity of Reservoir Rock
Authors: Glanville C.R.
Published: December 2007

The effect of overburden and fluid pressure on the resistivity of reservoir rock has been generally ignored in the quantitative interpretation of electrical logs. This paper shows from laboratory tests of two sandstone, two limestone and one dolomite formation that theoretical reservoir stress increases resistivity in varying amounts, depending upon depth (or stress) of formation, porosity, texture of rock and degree of water saturation.

The increased resistivity develops from increased formation resistivity factor and saturation exponent. In medium to low porosity the formation factor vs porosity relation is affected in such a manner that a given porosity represents a higher formation factor in stressed rock. Indications are that pressure effect is probably significant in many reservoirs of medium to low porosity, especially at greater depths, and should be considered in the interpretation of their electrical log resistivities.

A simple and useful technique for pressure analysis of core plug samples was developed in the study which should be adaptable for routine measurements (Fig. 1).

Introduction

The electrical resistivity measurement of reservoir rock has long been recognized as a reliable indicator of many important properties of the rock and of the fluids which it contains. Efforts to derive practical methods for analyzing electrical log recordings have been directed along two lines:correcting the "apparent" log resistivity to a "true" value by considering effects of the borehole, bed thickness, measuring system, etc., andinterpreting the true value of resistivity for whatever data it may reveal which is of practical value in the detection and/or evaluation of an oil or gas reservoir.

This paper deals only in the realm of the second item.

Among the most important factors known to affect the reservoir rock resistivity are temperature, porosity, permeability, salinity of contained water, degree of water saturation and abundance of clay minerals or "conductive solids". Much progress has been made by many investigators to express the effects of these variables.
Reduction of Grid-Orientation Effects in Reservoir Simulation With Generalized Upstream Weighting
Authors: Frauenthal James C. , di Franco Roland B. , Towler Brian F.
Published: December 2007

A generalization of upstream weighting is proposed as a method for reducing grid-orientation effects in reservoir simulation. For the two sample problems studied, a piston-flow waterflood and a realistic gas injection, the grid-orientation effect was almost completely eliminated. The new generalized upstream weighting (GUW) method is particularly attractive because it is fast and accurate, and can be added easily to an existing simulator that uses upstream weighting.
Analysis of Tight Gas Well Production Histories in the Rocky Mountains
Authors: Hale Brent W.
Published: December 2007

Monthly production records on more than 6,000 gas wells are analyzed to determine expected behavior of additional wells and to compare actual performance with theoretical performance as described by many authors. The wells analyzed are in the Rocky Mountains, ranging from the Green River basin of Wyoming to the San Juan basin of New Mexico. Most of these wells produce from low-permeability reservoirs and have been hydraulically fractured.

Production trends are studied with three different techniques: conventional semilog rate vs. time analysis, logarithmic rate vs. time analysis, and linear flow decline-curve analysis. The primary purpose of this study is to forecast future rates and reserves. The impact of well downtime and pressure variations on observed flow rates is reviewed.
Drilling From Floating Vessels Now Economically Carried Out Off California Coast
Authors: Rand W.W.
Published: December 2007

Introduction

Deep water occurs at short distances off the California coast, restricting the economic use of artificial islands and bottom-based platforms to a narrow coastal strip. Beginning in 1950, drilling from floating vessels has proved to be feasible and economically sound, and operators are now seeking methods of drilling oil wells from vessels. Significance of results so far achieved has made little impression on the industry, but extension of techniques now in use forecasts widespread use of floating drill rigs.

Search for California Tidelands Oil Began in 1945

Marine seismic methods were first used off the California coast in 1945, inaugurating the tidelands oil search program. In 1946 submarine coring began, with a simple weighted core tube, for sampling pre-recent formations efposed on the sea floor.

In order to take cores from formations buried by overburden, a jet tube and punch core device operable through the jet tube was developed. Early forms required a diver to guide the core tube into the jet tube after the hole had been jetted through overburden by high pressure sea water. Later improvements permitted dispensing with divers. In the fall of 1948, a converted minesweeper was equipped with a 1,000-lb dart, handled mechanically in a tilting cradle mounted overside. This was the first vessel to be outfitted specifically for submarine coring. Although experiments were performed on many types of jetting devices, it was found that a simple jet tool with projecting core barrel provided an accurate and fool-proof method of taking oriented and unoriented cores in areas where the subsea formation was buried under as much as 200 to 250 ft of overburden. Attempts to extend the range of the jetting method resulted in reaching depths up to 500 ft beneath the sea floor; however, at this depth the method is not commercially feasible.

As the need for deeper geological information became urgent, rotary drilling was introduced to offshore exploratory work in 1950. The first rotary unit utilized a seismic drill-type electrically driven rotary table mounted overside in a carriage having a fore and aft axis to compensate for roll of the vessel. In 1953 this unit was removed and replaced with a rotary having a double jack-knife mast with draw-works and rotary table patterned after conventional truck-mounted land rigs. By 1955 drilling vessels were being outfitted which permitted drilling through a caisson located near the center of the ship. These vessels were designed for drilling to about 7,500 ft and at least one ex-Navy barge has been modified to permit drilling to depths of about 10,000 ft (see Table 1).
In-Situ Leaching of South Texas Uranium Ores—Part 2: Oxidative Removal of Adsorbed Ammonium Ions With Sodium Hypochlorite
Authors: Paul J. M. , Johnson W. F. , Fletcher A. , VenutO P. B.
Published: December 2007

This paper reports a laboratory study of the oxidative destruction by sodium hypochlorite (NaOCl) of ammonium ions adsorbed on relatively reduced south Texas uranium ore. Included are an assessment of reaction stoichiometry, determination of some major reaction pathways and side reactions, and identification of several intermediates. Adsorbed ammonium ions were completely removed by 0.5% NaOCl, with the concentration of NH3 in the effluent falling to a very low value after 10 to 15 PV NaOCl oxidant. A small fraction (5 to 10%) of NaOCl was utilized in reacting with NH3. After the NH3 was nearly depleted, mono-, di-, and trichloramines, the expected intermediates in NaOCl oxidation of NH3, were observed. Chloramine decomposition studies showed that all three decomposed completely within 12 days. Since the ore was relatively highly reducing, the major part of the NaOCl was, not unexpectedly, consumed in side reactions. Substantial quantities of sulfate, reflecting oxidation of sulfide minerals such as pyrite, were formed, large amounts of uranium were leached out, and substantial amounts of calcium and magnesium ions were also produced during the presaturation with NH4HCO3 preceding the oxidation stage.
Volumetric Requirements for Foam and Mist Drilling Operations
Authors: Okpobiri Godwin A. , Ikoku Chi U.
Published: December 2007

State-of-the-art foam and mist drilling suggests a need for predictive models for volumetric requirements that properly account for frictional losses caused by the solid phase in solids/foam slurry flow, settling velocities of such solids, and pressure drop across bit nozzles during foam flow. The objective of this paper is to fulfill this need.

A model that predicts pressure drop across bit nozzles for foam and mist is presented. It accounts for the compressibility of foam but assumes negligible pressure losses resulting from friction and change in elevation.

A model has been developed for predicting minimum volumetric requirements for foam and mist drilling operations. It accounts for the frictional losses caused by the solid phase, pressure drop across bit nozzles, and particle-settling velocity. The technique offers a high degree of flexibility in the selection of wellhead injection pressures and volumetric injection rates.

Field application of this work can be accomplished by two primarily graphical methods that depend on compressor specifications: variable-backpressure and constant-backpressure schedules. Charts are presented for 7.875- and 9.00-in. [20.0- and 22.9-cm] hole sizes, and for 0.500-, 0.75-, and 1.00-in. [1.27-, 1.91-, and 2.54-cm] cutting sizes. Penetration rates range from 30 to 90 ft/hr [9 to 27 m/h].

Results indicate that volumetric requirements increase with increasing hole size, depth, and particle size. Increases in penetration rate cause only minor increases in volumetric requirements. All foam-drilling and well-cleanout operations can be accomplished within the laminar flow region with adherence to 0.55 minimum bottomhole and 0.96 maximum annular foam quality. Annular backpressures greater than atmospheric pressure are needed to maintain a bottomhole foam quality of 0.55 or more while reaching reasonable depths. To maintain constant depth as backpressure increases, however, both wellhead injection pressure and gas injection rate must be increased, and liquid flow rate decreased.
Surfactant and Polymer Losses During Flow Through Porous Media
Authors: Friedmann François
Published: December 2007

Experimental methods are presented to evaluate and to measure the major contributions to surfactant and polymer losses in Berea sandstone for various oil saturations (no oil to postwaterflood residual oil). The results of linear displacement experiments are shown, and chemical losses evaluated for various sequences of injected fluids. Surfactant and polymer losses are evaluated independently, then for simultaneous injection into the core. When oil is present, chemical losses are related to phase behavior properties with salinity requirement diagrams.1 Both a synthetic white oil and a reservoir stock-tank crude oil are used in the experiments.
A Comparison of Calculated krg/kro Ratios With a Correlation of Field Data
Authors: Torcaso Michael A. , Wyllie M.R.J.
Published: December 2007

It is shown that krg/kro ratios computed on the assumption that the average sandstone reservoir has a poresize distribution characterized by a linear 1/Pc2 saturation plot are in good agreement with corresponding krg/kro ratios obtained by Wahl, Mullins and Elfrink by the correlation of field measurements.

Equation for Calculating krg/kro Ratios

Methods of calculating relative permeability data have recently been reviewed and extended. It was shown that for sandstone reservoirs where 1/Pc2 is approximately a linear function of effective saturation (as suggested first by Corey) it is possible to express relative permeabilities in very simple terms. For systems wetted by connate water and producing oil and gas (gas saturation growing at the expense of oil) the expression for the krg/kro ratio is

....................(1)

The accuracy of Eq. 1 has been frequently confirmed in our laboratories; because of its simplicity we make routine use of it in the analytical solution of problems in reservoir engineering. Nevertheless, comparisons of the krg/kro ratios yielded by Eq. 1 with appropriate reservoir data have been few. The publication by Wahl, Mullins and Elfrink of an empirical equation for krg/kro ratios is thus of interest since this equation is specifically stated to be based on the correlation of field measurements made on sandstone reservoirs.
Fracturing Fluids: Fluid-Loss Measurements Under Dynamic Conditions
Authors: Roodhart L. P.
Published: December 2007

When filter-cake-building additives are used in fracturing fluids, the commonly applied static, 30-minute API filtration test is unsatisfactory, because in a dynamic situation (like fracturing) the formation of a thick filter cake will be inhibited by the shearing forces of the fracturing fluid. A dynamic, filter-cake-controlled, leakoff coefficient that is dependent on the shear rate and shear stress at the fracture face is, therefore, introduced. A test apparatus has been constructed in which the fluid leakoff is measured under conditions of temperature, rate of shear, duration of shear, and fluid-flow pattern as encountered under fracturing conditions. The effects of rock permeability, shear rate, and differential pressure on the dynamic leakoff coefficient are presented for various, commonly used fracturing-fluid/fluid-loss-additive combinations.
Economics and Finance -The Roots of Corporate Enterprise
Authors: Parker Charles F.
Published: December 2007

What Factors Does Management Consider Before Spending? Where Do Corporations Obtain Their Capital?

Corporate economics and finance is by no means a single subject; in fact, it's a whole "barrelful" of them. This paper concerns some of the broader aspects of just two of these subjects. (1) Where does a corporation get its capital? and (2) how does it determine the best way to employ its capital?

It has often been said, "money is the root of all evil." Personally, I don't believe this is true. But it is certainly true that money is the root of all corporate enterprise. A corporation must have it to be born and must use it wisely to stay alive.

Introduction

In corporate finance there are, broadly, two kinds of money, yours and someone else's.

"Your money" is the equity money, the capital invested in the business by the owners when they purchase and retain capital stock. A shareholder owns a fraction of the business and of its profits, and he shares in the risks. His income and the value of his shares vary with the success of the corporation. As a common shareowner he also shares the responsibility for control of the business.

Not all earnings are distributed to the share owners. Usually, a part of earnings is retained by the company and reinvested in the business. These retained earnings, occasionally referred to on the balance sheet as capital surplus, constitute additional equity money. This money also belongs to the share owner and the value of his shares increases as capital surplus accumulates.

How Corporations Are Financed

"Other people's" money may be obtained by borrowing. It can be borrowed directly from banks or other institutions (or from individuals). Bank loans are usually for relatively short terms, five years or less. Or a borrower may obtain money by issuing bonds. The bondholder then becomes a creditor and, as such, has no direct voice in the business. He merely holds a promise that he will be paid a fixed amount of interest each year plus principal by a predetermined maturity date.

Mortgage Bonds and Debentures are Secure Investments

There are broadly two kinds of bonds, the mortgage bond and the debenture.
Effect of Bit Hydraulic Horsepower on the Drilling Rate of a Polycrystalline Diamond Compact Bit
Authors: Holster Jesse L. , Kipp Robert J.
Published: December 2007

A laboratory drilling program was conducted to measure the effect of bit hydraulic horsepower on the drilling rate obtained with a polycrystalline diamond compact (PDC) bit. Drilling tests were conducted under simulated downhole conditions with an 8 1/2-in. [21.59-cm] diameter PDC bit fitted with four sets of five equal-sized nozzles. PDC bit fitted with four sets of five equal-sized nozzles. Mancos shale, Pierre shale, and Berea sandstone were drilled with both water- and oil-based drilling fluids to determine the interactions among bit hydraulics, rock characteristics, and the drilling fluid. For the range of drilling conditions and rocks examined, the results indicated that bit hydraulic horsepower had a significant influence on the drilling rate. The degree to which drilling rate was affected by bit hydraulic horsepower was dependent on the rock/drilling-fluid combination.

Introduction

Proper hydraulic design for effective cleaning and Proper hydraulic design for effective cleaning and cooling of PDC bits has been recognized as a major factor in their successful application since these bits were introduced. Historically, there have been two approaches to the hydraulic design of PDC bits:natural diamond-bit flow-distribution systems (water courses with large total flow areas) andhigh-velocity jet nozzles.

Both types have been used with varying degrees of success but often for unrecognized reasons. The water-course-type hydraulic designs were characteristic of most early matrix-bodied PDC bits. Nozzled bits evolved from the steel-bodied bits with stud-mounted cutters, although matrix-bodied bits are now available with jet nozzles. An increasing number of commercial PDC bits are becoming available with interchangeable nozzles, providing the flexibility of rig-site hydraulics optimization, providing the flexibility of rig-site hydraulics optimization, With these interchangeable nozzles, the hydraulic energy (or power) of the drilling fluid that is dissipated across the bit face can be adjusted to match that portion of the rig's hydraulic power that is available for the bit after other system losses have been considered. Unfortunately, the benefit in increased drilling rate that can be expected by an optimization of bit hydraulic horsepower has yet to be adequately defined quantitatively for PDC bits. The objective of our work was to determine experimentally the effect of bit hydraulic horsepower on the drilling rate achieved with a jet-nozzled PDC bit while three rock types were drilled with both oil- and water-based drilling fluids.

PDC Bit Hydraulics-Background PDC Bit Hydraulics-

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Field Application of Diamond-Bit Hydraulic-Lift Principles
Authors: Winters Warren J. , Warren T. M.
Published: December 2007

Hydraulic lift can have a major effect on the operation of diamond drill bits. The actual weight on bit (WOB) is less than the measured weight by the amount of hydraulic lift, or pumpoff force, acting beneath the bit. Pumpoff forces in excess of 15,000 lbf [67 kNJ have been recorded.

Historically, the hydraulic-lift effect has been recognized but not understood well enough to be accounted for reliably. Failure to account for hydraulic lift can adversely affect actual bit performance and interpretation of the results. It is now possible to determine hydraulic lift reliably with the practical techniques presented here.

Field tests show that pumpoff force tends to double as the bit dulls. Appropriate WOB adjustments, determined through pumpoff tests run on the rig, are required to maintain bit performance. The applications to diamond bits run on mud motors are particularly advantageous.
Rheological Characterization of Fracturing Fluids by Using Laser Anemometry
Authors: Guillot Dominique , Dunand Alain
Published: December 2007

In this paper we describe the use of a novel technique, laser Doppler anemometry (LDA), to obtain information on fracturing fluid behavior. This technique permits measurement of fluid velocity at any point in a flow system. By scanning across the flow geometry, it is possible to obtain the velocity profile, which is related, in turn, to the rheology of the fluid.

At low shear rates, velocity profiles obtained for aqueous solutions of hydroxypropyl guar showed significant deviations from those calculated using known power law parameters. The investigation was extended by conducting a series of rheological experiments using rotational and capillary viscometers over a wide shear-rate range (10−2 to 2 × l03 seconds−1). The data have been fitted to a three-parameter Ellis model, and the velocity profiles calculated from these data agree well with experimental ones.

The immediate results of this work are of interest in proppant transport modeling and correlate well with published data that show that apparent viscosities obtained from proppant settling velocities are lower than those obtained from power law parameters.
An Analytical Extension of the Dykstra-Parsons Vertical Stratification Discrete Solution to a Continuous, Real-Time Basis
Authors: Reznik A. A. , Enick Robert M. , Panvelker Sudhir B.
Published: December 2007

Analytically exact and continuous solutions are developed for the space-time relationships of a linear waterflood in a vertically stratified reservoir model. The solutions represent simple extensions of the analytical, but discrete, spatial relationships of Dykstra and Parsons to analytically continuous expressions. Explicit solutions for time are presented that permit the coupling of all instantaneous and cumulative performance parameters to a completely rational time basis.

The continuous nature of the solutions permits unusual fluid behavior to be observed between successive bed breakthrough points. Although the model assumes pistonlike displacement, these novel phenomena do not appear to be artifacts of this limiting assumption.

This work develops the concept of a bed property time that forms the basis for a generalized bed-ordering parameter. For the case of constant injection pressure, property time is shown to be identical to the real or process time. For the common case of constant overall injection rate, the customary use of property time concepts to determine real or process time is shown to be completely erroneous, yielding values that are incorrect both in magnitude and in trend.

A bed flood-front passing phenomenon is presented that allows the flood fronts of "slower" beds initially to lead those of "faster" beds if specified constraints are satisfied. It is shown that these constraints can be satisfied for moderate bed-fluid property variations.

The analytical nature of the solutions provides greater insight into the controlling factors of such processes. The use of real time as a process parameter provides a more realistic basis for comparative performance between floods under the same or different injection conditions. The relationship between injected PV and time can be used to extend the linear model to approximate predictions for stratified, nonlinear, pattern floods.
The Fenske Conservation Method for Pressure Transient Solutions With Storage
Authors: Horne Roland N.
Published: December 2007

A method for determining pressure transient solutions for wells with storage (and skin) is presented; this method is based on an approach developed by Fenske1 in the groundwater literature. By specifically conserving the entire mass of the system, including the wellbore or wellbores, it is possible to generate many common type curves. The procedure can be developed in an exact manner, in which case it is equivalent to existing techniques; however, a simple approximation step makes possible the generation of common solutions without recourse to numerical or ornate analytical techniques. In some cases, the approximation provides equivalent solutions with substantially less computation; in other cases, the solutions are significantly in error, although perhaps still usable. The achievement of computationally rapid, closed-form solutions is of significant advantage for current developments in computerized interpretation. The evaluation of a solution can be hastened by three orders of magnitude over conventional methods in some cases.

Examples given in this paper demonstrate the application of the approximate Fenske method and its exact generalization. The approximate method gives agreement within 2% of the standard single-well, storage, and skin type curves. However, as the storage becomes small, as for example in the cylindrical wellbore case (where it is zero), the accuracy becomes unacceptable at early time. As an example of how the method can be applied to configurations other than those developed by Fenske, the derivation of the method for the slug test problem is demonstrated. The slug test solution obtained by the approximate method is within acceptable accuracy.

The Fenske method is applicable to a wide variety of problems with storage and skin, probably including problems as yet unsolved. An approximate form is available for fast calculation, and die more correct form is equivalent to standard analytical methods.
Experts Discuss Future of the Turbodrill
Authors: Jones John M. , Bingman W.E. , Mitchell J.A. , Brantly M.M.
Published: December 2007

Turbodrill Components Appraised in Field Test Program by W.E. Bingman

Turbodrill Operational Characteristics by J.A. Mitchell

Why the French Turned to the Turbodrill by M.M. Brantly

Featured at the first 1959 meeting of the Mid-Continent Section Study Group which recently met in Tulsa, Okla., were reports of turbodrill operational characteristics, an appraisal of turbine components by a coordinated field test program, a first-hand account of latest developments of the turbine by the French and a panel moderated question and answer session.

The panel, moderated by Arthur A. Lubinski, Pan American Petroleum Corp., Tulsa, Okla., consisted of four authorities on turbodrilling. Panelists were Joseph A. Mitchell, manager, field and technical service department, Turbodrill Div., Dresser Industries, Inc., Dallas; W. E. Bingman, turbodrill project engineer for Shell Oil Co., Midland, Tex.; M. M. Brantly, president of Brantly Drilling Co., Inc., Midland; and Madden T. Works, manager of operations for Dresser's Turbodrill Div., Dallas.

During the question and answer session inquiries from the floor regarding aspects of turbo drilling resulted in comments by the panel on fishing operations, costs of renting the turbo drill, excessive wear of thrust bearings due to abrasive fluids and many other topics of general industry interest in the turbine.

Comparison of Fishing Operations

In answer to a query to compare the rotary in the U. S. with the turbodrill in Europe regarding time spent on fishing operations, the consensus of the panel was that the percentage of time spent on fishing in this country is about the same in rotary drilling as with the turbine in France.

Further discussion among the panelists indicated that in rotary drilling in France the percentage of time spent on fishing operations is several times greater than in the U. S. In other words, because of the difference in drill pipe quality, fishing considerations are important in drilling economics in the U. S. mainly for exceptional cases such as the drilling string being subjected to a high level of shock and vibration when drilling very large holes (15 in. or larger). In such cases turbodrilling with rock bits results in savings.

Turbine Life Depends on Thrust Bearing

The panel generally agreed that the life of a turbine is about 100 hours. The part which generally needs replacing at this time is the thrust bearing which wears out due to abrasive mud conditions.

At this point the question was raised as to whether the use of extreme pressure lubricants would sufficiently prevent thrust bearing wear of rock bits by abrasive fluids in order that they might be economically used with the turbodrill. In answer, the panel jointly opined that these lubricants might somewhat improve rock bit performance, but limited field experience has not indicated sufficient improvement to make rock bit usage generally attractive in turbodrilling.
Matching Simulator Wellblock Pressures With Observed Buildup Pressures in Two-Layer Reservoirs
Authors: Litlehamar Terje , Larsen Leif
Published: December 2007

An equation is given for the buildup time at which the wellbore pressure should match the kh average of the simulator wellblock pressures in history-matching procedures of two-layer reservoirs. The equation takes into account contrasts in flow capacities, porosity/compressibility/thickness products, and skin factors and makes use of fractional flow rates given by the simulator. The equation is derived for reservoirs without crossflow, but it can also be used for reservoirs with interlayer crossflow. Also included is a method to handle cases when only a single buildup pressure is recorded. To check the validity of the results, data from a three-dimensional (3D) reservoir simulator were compared with buildup data from an analytical solution for systems without crossflow and with data from a radial reservoir simulator for systems with crossflow.
Oil Production from Frozen Reservoir Rocks, Umiat, Alaska
Authors: Baptist Oren C.
Published: December 2007

The Umiat oil field is in Naval Petroleum Reserve No.4 between the Brooks Range and Arctic Ocean in far-northern Alaska. The Umiat anticline has been tested by 11 wells, six of which produced oil; however, the productive capacity and recoverable reserves of the field are subject to considerable speculation because of unusual reservoir conditions and because several wells appear to have been seriously damaged during drilling and completion.

Oil is produced at depths of 275 to 1,100 ft; the depth to the bottom of the permanently frozen zone varies from about 800 to 1,100 ft, so that most of the oil reserves are in the permafrost. Reservoir pressures are estimated to range from 50 to 350 psi, increasing with depth, and the small amount of gas dissolved in the oil is the major source of energy for production.

Laboratory tests were made on cores under simulated permafrost conditions to estimate oil recoverable by solution-gas expansion from low saturation pressures. The cores were also tested for clay content and susceptibility to productivity impairment by swelling days and increased water content if exposed to fresh water.

The results indicate that oil can be produced from reservoir rocks in the permafrost and that substantial amounts of oil can be produced from depletion-drive reservoirs by a pressure drop of as little as 100 psi below the saturation pressure. Freezing of formation water reduces oil productivity much more than that due to increased oil viscosity. Failure of wells drilled with water-base mud to produce is attributed to freezing of water in the area immediately surrounding the wellbore. Swelling clays apparently contributed very little to the plugging of the wells.

Introduction

Naval Petroleum Reserve No.4 lies between the Brooks Range and the Arctic Ocean in northern Alaska. The Umiat oil field is located in the southeastern part of the Reserve and is about 180 miles southeast of Point Barrow (the only permanent settlement in the Reserve and the primary supply point for drilling of the wells at Umiat).
Relating Slim-Hole Drilling Performance to South Louisiana Drilling Problems
Authors: Pedersen Jan N.
Published: December 2007

Slim-hole drilling has been utilized in many areas of the world to reduce drilling costs. It has been used successfully in exploratory as well as in development drilling, and many published articles have pointed to the savings made possible with slim-hole drilling. Until the present, however, very little slim-hole drilling has been attempted in South Louisiana, principally because of the deep drilling depths and the complex hole problems encountered. Deeper drilling and complex hole problems mean higher costs which may make certain exploratory drilling prospects unattractive or may preclude further development of oil or gas discoveries. This paper recounts some of the advantages of slim-hole drilling and suggests how proper application of slim-hole drilling techniques could appreciably reduce exploratory and development drilling costs in South Louisiana.

Introduction

The uses of slim-hole drilling are listed in Table 1. It is significant to note that the slim hole is not intended to replace the conventional-size hole. The smaller diameter hole imposes restrictions on formation evaluation tools, fishing tools and completion tools, and these limitations should be recognized when planning slim-hole drilling. However, these limitations can be tolerated if the wells fall within the categories listed in Table 1.

Certainly there are many opportunities for drilling cost reductions through slim-hole drilling in South Louisiana. However, recognition of limitations and careful planning to operate within these limitations are essential to any slim-hole drilling operation.

Drill Tubing Increases Rig Depth Capacity

Probably the most significant contribution to the success of slim-hole drilling has been the use of drill tubing or thin-walled drill pipe. In addition to reducing the weight of the drill string, the use of drill tubing has resulted in a more efficient hydraulic system in drilling slim holes.
A Laboratory Technique for Measuring Dielectric Properties of Core Samples at Ultrahigh Frequencies
Authors: Shen Liang C.
Published: December 2007

This paper describes an automated laboratory system that can measure accurately the dielectric properties of core samples in the ultrahigh-frequency (UHF) range. The system consists of a precision coaxial-line sample holder, a network analyzer, a plotter, a printer, and a desk computer. The computer is for measurement control, data acquisition, and data analysis. A new method is developed to measure and to compensate for the error of the network analyzer system. This method uses a brass sample and does not require standard terminations. A procedure for core sample preparation is also recommended to ensure accuracy of the data.
Identifiability of Estimates of Two-Phase Reservoir Properties in History Matching
Authors: Watson A. T. , Gavalas G. R. , Seinfeld J. H.
Published: December 2007

Since the number of parameters to be estimated in a reservoir history match is potentially quite large, it is important to determine which parameters can be estimated with reasonable accuracy from the available data. This aspect can be called determining the identifiability of the parameters. The identifiability of porosity and absolute and relative permeabilities on the basis of flow and pressure data in a two-phase (oil/water) reservoir is considered. The question posed is: How accurately can one expect to estimate spatially variable porosity and absolute permeability and relative permeabilities given typical production and pressure data? To gain insight into this question, analytical solutions for pressure and saturation in a one-dimensional (ID) waterflood are used. The following conclusions are obtained.

1. Only the average value of the porosity can be determined on the basis of water/oil flow measurements.

2. The permeability distribution can be determined from pressure drop data with an accuracy depending on the mobility ratio.

3. Exponents in a power function representation of the relative permeabilities can be determined from WOR data alone but not nearly so accurately as when pressure drop and flow data are used simultaneously.