bluuebunny/crossref_metadata_2025 huggingface dataset:
Laboratory Tests on Collapse Resistance of Cemented Casing
Authors: Evans George W. , Harriman Don W.
Published: December 2007

Laboratory tests on collapse resistance of cemented casing give an insight into the role cement sheath strength and integrity have on the collapse resistance of tubular goods. A full cement sheath can materially improve the collapse resistance of the tubular goods-cement sheath structure. The stronger full cement sheaths offered the greatest resistance to collapse pressure. Cement sheaths that contain voids above a certain size give very limited improvement in collapse resistance.

Introduction

The role of the cement sheath relative to tubular goods performance in oil and gas wells has long performance in oil and gas wells has long been a subject of discussion. The questions generally raised concern the thickness, strength and configuration of the sheath and the effects of these upon burst and collapse resistance of cemented tubular goods. This study was initiated for the purpose of investigating the properties of the cement sheath with properties of the cement sheath with respect to their effect on the collapse resistance of the tubular goods cement sheath structure.

Collapse resistance of dual strings of mechanical tubing cemented together with sheaths of cement of various strengths and configurations was investigated. The tests considered conditions where collapsing forces were imposed on a bare cement sheath as well as a cement sheath surrounded by tubing. The dual tubular string collapse resistance was determined by applying hydraulic and mechanical loads to the structure.

Hydraulic Collapse Tests

Tests were first run to determine the hydraulic collapse pressure of uncemented tubing. pressure of uncemented tubing.
An Instrument for Measuring the Density of Air Entrained Fluids
Authors: Nickles S.K.
Published: December 2007

A simple solution to a problem which has often caused problem which has often caused significant error in the density measurement of fluids has been achieved. Some fluids, e.g., viscous cement slurries and drilling fluids, tend to entrain or trap a considerable volume of air. An instrument which effectively compensates for this air entrainment has recently been developed. In the petroleum industry, this instrument can be utilized at the surface of a gas or oil well site, and yet give a good indication of the density of a fluid at subsurface or downhole conditions. The basic concepts and physical premises on which the instrument premises on which the instrument was designed are discussed and analyzed in this paper.

History

The measurement and control of the density of drilling fluids (muds) and cement slurries has long been an important factor in the drilling of oil and gas wells. If the density of the fluid being pumped into the well is too low and a pumped into the well is too low and a high pressure zone is encountered, a blowout may quickly develop. on the other hand, if the fluid density is too high and a low pressure or "thief" zone is encountered, large quantities of expensive fluid can be lost to the formation which can also result in a blowout.

A variety of devices are used in determining the density of a fluid, with the conventional mud balance being the present recognized petroleum industry standard. The standard mud balance consists of a base and graduated arm with cup, lid, knife edge-type pivot point, sliding weight, bubble pivot point, sliding weight, bubble level and counterweight.
Electrical Conductivities in Shaly Sands - I. The Relation Between Hydrocarbon Saturation and Resistivity Index; II. The Temperature Coefficient of Electrical Conductivity
Authors: Waxman Monroe H. , Thomas E.C.
Published: December 2007

A simple physical model describing shaly sand conductivity was previously described by Waxman and Smits. The electrical conductivity of a water-saturated shaly sand was expressed as a function of a geometry factor, the brine conductivity, an effective concentration of clay exchange cations, and their equivalent ionic conductance. Experimental data support this relation. The model was extended to cases where the sands were oil-bearing. An expression was obtained relating the resistivity index to water saturation, brine conductivity, and the clay parameters mentioned above.

The assumptions involved in the model for oil-bearing sands have now been confirmed by additional laboratory conductivity measurements. We conclude that the effective concentration of clay exchange cations is increased by a quantity proportional to the decrease in water saturation. Twelve different rock samples from seven fields were utilized in these studies, incorporating a wide range of brine conductivities, oil saturations, and cation exchange capacities.

Further, the temperature coefficients of electrical conductivity were measured for a set of shaly sands equilibrated with salt solutions covering a wide range of concentrations. When compared at the same electrolyte concentration, these temperature coefficients increased systematically with increasing clay content of the sands.
Experiments on Effect of Water Injection Rate on Imbibition Rate in Fractured Reservoirs
Authors: Mannon Robert W. , Chilingar George V.
Published: December 2007

A relationship has been established in the laboratory between rate of water injection into a simulated fracture-matrix type reservoir model and rate of imbibition. In a series of experiments involving linear countercurrent flow, it was discovered that the higher the water injection rate, the higher the imbibition rate and the greater the indicated ultimate oil recovery.

The model consists of a horizontal slab of Berea sandstone having approximate dimensions of 6 in. × 6 in. × 112 in. sealed on all sides except for opposite 6 in. × 11 in. ends. Plates were placed across the exposed ends with a 0.001-in. to 0.002-in. clearance. Water was injected into the simulated fractures between the plates and the exposed sand faces.

Repeated runs, made using one side of the matrix block and then the opposite side, indicate that the water injection rate (same time duration):imbibition rate correlation is well defined. Two additional factors that dictate the nature of the injection rate-imbibition response are temperature and the condition of the sand face exposed to imbibition.

The results of the experimental work suggest that, under proper conditions, increased water injection rates may lead to higher production rates and oil recoveries in production rates and oil recoveries in reservoirs having fracture-matrix type porosity.

Introduction

Production of oil and gas from fractured reservoirs is common. Such reservoirs occur in various parts of the world. The host rock may be sandstone, siltstone, shale, limestone, or dolomite. Many of the reservoirs exhibit low values for permeability within the formation blocks themselves (called matrix permeability) and yield oil and gas at commercial rates due primarily to the existence of an elaborate primarily to the existence of an elaborate fracture system in the producing zone. Wells completed in low-permeability fractured reservoirs may flow initially at fairly high rates as the oil originally residing in the fractures moves rapidly to the wellbores. The movement of the oil from the matrix blocks to the fractures does not keep pace with the flow of oil from the fracture system to the wells, however, and the wells experience sharp decline in production rate. Early in the life of the pool, the wells may settle down at very low rates as the slow process of oil migration from the matrix blocks process of oil migration from the matrix blocks to the fractures and then eventually to the wells begins. The ultimate recovery from reservoirs of this type when subjected to solution gas drive is also very low.
Fundamental Study of Imbibition in Fissured Oil Fields
Authors: Iffly R. , Rousselet D.C. , Vermeulen J.L.
Published: December 2007

Waterflood efficiency of a fissured oil is closely dependent on the volume and speed of water imbibition in the elementary blocks.

A large number of laboratory tests have been performed on fluids and porous media taken from a performed on fluids and porous media taken from a field exploited by ELF, and have helped to ascertain the effect of the block height and permeability, and the conditions at their limits as well permeability, and the conditions at their limits as well (some figures may contain water or oil or may be tight), on oil recovery.

The results show how important are the physico-chemical bondings between connate water, physico-chemical bondings between connate water, injected brine, oil and rock at any time during imbibition: minor differences in lithology may consideration alter the recovery laws. Similarly, some organic molecules in the fluids influence oil recovery much more than one might expect according to the variations of cos alone. As one does not know how to represent these physico-chemical bondings, it is not permitted to perform laboratory experiments with fluids an/or core different from the real one (except for special cases).

Laboratory measurements, together with numerical simulations, have even results which allow to understand the role played by gravity, capillarity, boundary conditions, and end effects an the imbibition.

Introduction

The development of one of our off shore oil fields which is composed of alternating silt and fissured limestone layers has enabled us to make a detailed study of the effects of imbibition when the field is flooded with sea-water. Since the silt layers contain most of the oil and the limestone layers are continuous and largely fissured, it was possible to represent the situation by the following possible to represent the situation by the following elementary structural model (figure 1-a): a homogeneous matrice containing primarily oil and interstitial water, which is bordered on the top and bottom by two horizontal and parallel fissured Plans, which carry the intrusive water and drain Plans, which carry the intrusive water and drain off the oil displaced from the matrice by imbibition.

This model can be itself reduced to the experimental schema (figure 1-b),: a porous medium sample set up vertically and containing initially oil and water at irreductible saturation. Water is brought in contact with the top and bottom of the sample and its hydraulic potential is kept constant by means of a lateral by-pass. The displaced oil is collected selectively in two graduate tubes as shown in the figure 1-b. Such is the elementary schema considered in the present study.
Gasification and Hydrosulfurization Becoming Important Tools
Authors: Bertetti J.W.
Published: December 2007

This paper was prepared for the 47th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in San, Antonio, Tex., Oct. 8–11, 1972 Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

The concurrent problems of limited natural gas supply and the rapidly increasing demand for low sulfur fuel oils has spurred significant activity in many research organizations and in engineering-contracting companies.

New tools for the petroleum refining engineer have been provided by several licensors of proprietary catalysts and technology for converting naphtha to substitute natural gas, and several similarly providing for desulfurization of providing for desulfurization of petroleum stocks including heavy petroleum stocks including heavy residual fuel high in sulphur and in metals.

There are two new problems of special interest facing petroleum refining engineers. one is related to the fact that much of the fossil fuel consumed in the world contains so much sulfur that its combustion causes objectionable contamination of the atmosphere. The second arises from the fact that this country's major clean fuel, natural gas, is suddenly realized to be in short supply. The refinery engineer, thanks to the efforts of many research organizations, has the tools to desulfurize fuel oils and to convert oil stocks to substitute natural gas.

With respect to atmospheric pollution, it has been noted that most of the sulfur oxides in the air in industrial and congested areas is the result of combustion of coal and fuel oil, with each on the average contributing about one-half. Many of those who consume coal and oil fuels are under considerable pressure to reduce the emission of sulfur oxides.
Engineered Hcl-HF Treatments Provide Successful Stimulation in Cook Inlet
Authors: Wieland D.R. , Vinson M.E.
Published: December 2007

Successful stimulation of offshore wells in Cook Inlet, Alaska, has been accomplished using HF-HCl acid mixtures in carefully engineered treatments. Many stimulation techniques, including HF-HCl mixtures, have been tried previously but none have been effective. Due to the high solubilities of the producing formation, the Hemlock, in hydrofluoric acid, it was felt that HF-HCl mixtures could provide successful stimulation. The problem was approached from an engineering viewpoint with the aid of Acid Response Curves of the Hemlock. A treatment was designed which consisted of the following steps:Solvent preflush to cover the possibility of asphaltine or paraffin protective coating on the rock.A 2.5% HCl preflush to remove calcareous materials.A 12% HF-10% HCl stimulation stage using a mutual solvent.A 2.5% HCl overflush to maintain low pH and achieve penetration.

Due to the formation thickness a staged treatment was used, with each stage consisting of the above steps. With only slight variation in some materials, the same treatment was used on producers and on injection wells.

Production was more than doubled in producing wells with no appreciable decline after eight months. The injectors were increased by more than 500 percent and the injection profiles were extremely improved.

The purpose of this paper is to present the factors involved in design of treatments for the Hemlock in Cook Inlet, and show how these factors were used to arrive at successful stimulation treatments. A comparison of results with those of previously used treatments is presented.
Vertical Permeability Measurements Swan Hills Reef Complex
Authors: Gutek A.M.H. , Clark K.K.
Published: December 2007

This paper was prepared for the 47th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in San, Antonio, Tex., Oct. 8–11, 1972 Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

To obtain accurate data for use in calculating vertical fluid flow within a reservoir, in situ measurements of vertical permeability were conducted on five wells in the South Swan Hills Unit. These measurements quantified the permeability parameters for subsequent model permeability parameters for subsequent model studies of the Light Brown member of the Beaverhill Lake formation.

This paper presents a description of the data collection technique employed and the results for the vertical permeability measurements.

Included in the discussion is a treatment of the data analysis for a single measurement utilizing:the two techniques presently available in literature and a variable rate pressure matching procedure.

Based on pressure matching procedure. Based on the data obtained and the results of the testing as discussed in this paper, it can be concluded that a viable technique is available for measuring vertical permeability. Additional refinements in permeability. Additional refinements in the field operations associated with this type of pressure testings,, can be made, but overall a success ratio of 100% should not be expected.

The successful application of this type of measurement to relating core analysis data to the needs of an adequate reservoir description should be of interest to any performance study.

Introduction

Every reservoir engineer has probably recognized that the single, most probably recognized that the single, most important contributing factor to a useful simulation is the description of the reservoir being studied. The reservoir description must include permeability values which, will govern the fluid flow within the model. These-data are generally obtained from core analysis and may be tailored to reflect information available from pressure transient testing of producing or injection wells. In the case producing or injection wells. In the case of three dimensional or two dimensional cross sectional studies the vertical as well as the horizontal permeability must be quantified.
Drillstem Test Analysis Utilizing McKinley System of Afterflow Dominated Pressure Buildup
Authors: Milner E.E. , Warren D.A.
Published: December 2007

This paper was prepared for the 47th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in San, Antonio, Tex., Oct. 8–11, 1972 Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

In a wildcat well or early in the life of a reservoir, drill stem test data is quite often the only means available to estimate reservoir values of transmissibility, effective permeability, well bore damage, well bore permeability, well bore damage, well bore stimulation and productivity.

The Horner pressure buildup method is generally accepted as the best means of determining reservoir data from short time tests such as a drill stem test.

The Horner method requires that the steady state or straight line portion of the buildup curve be reached. For various reasons, approximately 25% of all drill stem tests run do not meet this requirement. This group of wells are the ones with the highest economic risk involved in making a decision on whether to abandon or complete.

A 1971 paper published by Mr. McKinley, "Transmissibility from Afterflow Dominated Pressure Buildup Data", gives a means to Pressure Buildup Data", gives a means to calculate reservoir values when pressure buildup curves are still under the influence of afterflow.

A research program was recently completed using drill stern test data to calculate transmissibility and effective permeability by the McKinley method and to compare the results obtained against the Horner method.

Fifty drill stem tests were chosen for analysis that had an appreciable afterflow period and steady state period on the same buildup curve. The comparison of results was very close as long as the basic assumptions were not deviated from too far. Most drill stem tests, where it is necessary to use the afterflow buildup method, do deviate considerably from these basic assumptions.

Therefore, it is necessary to use a correction factor in interpreting the afterflow method.
A New, Surface Recording, Down-Hole Pressure Gauge
Authors: Miller G.B. , Seeds R.W.S. , Shira H.W.
Published: December 2007

This paper was prepared for the 47th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in San, Antonio, Tex., Oct. 8–11, 1972 Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

A new, electronic, surface recording, down-hole pressure gauge utilizing a quartz transducer is described. pressure gauge utilizing a quartz transducer is described. Features of the gouge include wide range (0–12,000 psi), high resolution (0.01 psi), no hysteresis and high stability.

Operational principles of the gauge are described in general. Measurement techniques based on field experience are outlined. Field, Laboratory and calibration data are presented to illustrate the performance of the gouge.

Introduction

An extremely sensitive, high dynamic range, electronic pressure gauge has been developed. The specific pressure gauge has been developed. The specific configuration described herein has been designed for bottomhole placement in oil wells. Measurements are displayed and may be recorded on the ground surface.

The measurement range is from zero to 12 Kpsi and the resolution is better than 10 mpsi throughout the entire operating range. Accuracy is 0.025% of reading for pressures greater than one Kpsi. The precision is better than 150 mpsi throughout the precision is better than 150 mpsi throughout the entire range.

In addition to the surface recording capabilities of the instrument, other advantages include (1) the inherent ruggedness of the transducer, (2) high stability of calibration (good for at least one year), (3) simple operation, (4) low power consumption (16 watts total, 140 milliwatts down-hole) and (5) no observable hystersis. The down-hole sonde will operate continuously at ambient temperatures up to 150 deg. C (302 deg. F). The sonde case is constructed of 17-4-PH stainless steel.
Estimated Effect of Horizontal Fractures on Production Capacity
Authors: Crawford Paul B. , Landrum Bobby L.
Published: December 2007

An electrical model study has been made of the effect of horizontal fractures on the production capacity of fractured wells. For thin reservoirs it is shown that increases in production capacity by factors of 4 to 12 may be obtained if the radius of the fracture is between 0.2 and 0.6 the drainage radius. For thick reservoirs the increases in production capacity may be near 1.4 to 3.8 if the fractures are between the same radii as indicated above. For thin reservoirs there appears to be little difference in production capacity whether the fracture is located at the top, bottom or center of the pay. However, for thick reservoirs and long fractures the center of the pay is indicated to be more responsive than other locations. One large pancake fracture is shown to be more effective for increasing the production capacity than three fractures with one-third the radius. A single horizontal fracture whose radius is 0.6 the drainage radius may result in an increase in production capacity by a factor near 6. Three fractures whose radius is near 0.2 the drainage radius are indicated to result in an increase in production by a factor near 3.5. Inclined circular fractures are indicated to be slightly less effective than horizontal fractures of the same radius. Elliptical fractures produce approximately the same effect on the production capacity as circular horizontal fractures with the same radius as the average radius of the ellipse.

Introduction

Commercial reservoir fracturing techniques are believed to result in the creation of vertical, horizontal and perhaps inclined fractures, depending on the nature of the formation fractured and the fracturing process applied. The creation of fractures normally results in an increase in the production capacity of the well. Qualitatively, the production capacity is believed to increase as the size of the fracture increases.
A New Inhibitor for Corrosion In Aerated Sour Waters
Authors: Annand R.R. , Martin R.L.
Published: December 2007

Aggravated corrosion conditions caused by FeS sol ids and by mixed air plus H2S interactions are responsible for some of the highest equipment failure rates in the petroleum industry. laboratory studies have shown the existence of a transient, ionic, sulfur species which is formed when air and H2S react in an aqueous environment. Iron sulfide catalyzes the reaction to form the species and perhaps also its decay. In addition, the dispersed FeS particles cause an aggravation of the corrosion independent of its catalytic effect on the air/H2S reaction. Furthermore, deposits of FeS cause under-deposit corrosion when air is mixed with sour fluids. A new organic sulfo-phosphate composition has been found which effectively inhibits the most severe combinations of these conditions. It also inhibits cracking in H2S environments.

INTRODUCTION

Even after a considerable number of years of experience in this laboratory working on inhibition of H2S-caused corrosion in petroleum equipment, there remain a significant number of puzzling questions about the corrosion effects observed in the field. The work reported here covers experiments designed to try to elucidate the features of some of these puzzling occurrences and identify at least some of the causes. In addition, we have developed a corrosion inhibitor which is quite different from the conventional kind and is much more effective under the conditions described. Specifically, we have found that oxygen and iron sulfide solids are significant contributors to the corrosion process such that rates as high as several hundred MPY (mils penetration per year) have been observed both in the field and in the laboratory.
A New Sand Control System
Authors: Mann R.L. , Phansalkar A.K. , Landers J.E.
Published: December 2007

Publication Rights Reserved

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and considered for publication in one of the two SPE magazines with the paper.

A new system for controlling the problem of sand production in oil and gas wells has been developed and evaluated. This new technique involves placement of a permeable barrier between the formation and the producing wellbore. Slurry is mixed on the surface and then pumped into the well using standard cementing techniques. The permeability of the set material is as high as 5 darcys. Laboratory data, including pumpability, setting temperatures, permeabilities obtained, strength level obtained, etc., are presented. Development of permeability is an inherent characteristic of the slurry, and the system can be tailored for use under virtually all existing well conditions. Results to date indicate that this system should have wide application in the general field of sand control.

Introduction

The production of sand with oil and gas has long been a serious problem in the oil industry. It greatly complicates and in some cases prevents the production of oil and gas from unconsolidated formations. The influx of sand into the wellbore raises the economic limit on wells for various reasons which are listed below:The replacement or repair of lines, chokes, valves, and meters due to erosion by the flowing sand.Workovers due to the sanding out of wells.Loss of wells due to casing or liners collapsing.Removal of sand and silt from the produced crude.Lowering production rates to decrease sand cuts.Cleaning out of surface facilities.Extra expense of downhole sand control devices, etc.
Significance of Shale Gas as an Indicator of Abnormal Pressures
Authors: Fertl Walter H.
Published: December 2007

Drilling-mud logging through the years has primarily been a tool of the explorationist for formation evaluation. However, continuous well-site analysis of the mud and cutting returns has also become an important tool in drilling control.

The amount of the gas content in the mud system while drilling shales can be indicative of abnormal formation pressures. However, experience indicates that depending on the geological environment and the drilling technique applied such mud logging methods may or may not be directly related to downhole, in-situ pressure profiles.

Introduction

Modern drilling technology is based on three main concepts, namely: well planning, well control, and optimization of drilling operations.

Often there is only a fine line between minimum over-balance of the drilling mud and the possibility of a well kick. This in turn makes well control a must, and the ability to immediately recognize and evaluate abnormal, downhole pressure conditions is critical. Many pressure detection methods are available or have been proposed and numerous technical papers have been written on the subject.

The best approach for identification and evaluation still is the study of a combination of several surface measured parameters verified by the interpretation of open hole logging data.

The amount of the gas content in the mud system while drilling shales can be indicative of abnormal formation pressures. However, since the gas cut can be a function of the geological environment penetrated, the drilling technique applied, and the downhole penetrated, the drilling technique applied, and the downhole thermodynamic conditions prevailing, this gas parameter may not have any direct relation to in-situ pressure profiles.
A Preliminary Control Strategy for the Automatic Control of an Instrumented Diamond Drill
Authors: Everall M.D. , Dessureault M. , Cauchon A. , Tervo R.O.
Published: December 2007

A series of diamond drilling tests has been conducted with a laboratory instrumented diamond drill. During the tests the following measurements were gathered and studied: the thrust, the rpm, the penetration, the torque, the flow of drilling penetration, the torque, the flow of drilling fluids, the vibration and the bit wear. The laboratory diamond drill simulated the hydraulic type diamond drilling machine. Masonry type thin wall drill bits were tested in various rocks including limestones, granites, a quartzite and others. The data logging permitted the elaboration of a preliminary automatic control strategy. The preliminary automatic control strategy. The strategy was verified by simulating manually the control of the instrumented diamond drill. The strategy keeps the drill machine and bit system within normal operating conditions as it is faced with different ground and rock conditions attempting to maximize the rate of penetration and minimize the rate of wear of the bit. The application of such a control strategy on a field diamond drilling machine is discussed.

Introduction

One of the objectives of the Department of Energy, Mines and Resources is to improve the means of discovery, mining, processing, transportation and use of the processing, transportation and use of the mineral and energy resources available in Canada. The objective of the Mines Branch, Mining Research Centre in its Systems Engineering Program is to develop mining technology that is important for exploiting Canadian resources. The investigation of the application of automatic control to drilling processes was carried out by members of the Rock Fracture Group, Mining Research Centre in Quebec City, P. Q., under the Operations Control Project.

Diamond drilling is a standard well-known process for the boring of holes in rock. It is used extensively by the mining industry mainly for exploration work where the main purpose is to retrieve a rock core for further evaluation. The petroleum industry uses diamond drilling for exploration as well as for the boring of production wells in hard formations.
Diamond Drilling with Surfactants in Upper Michigan Conglomerates Using Surface-Set Bits
Authors: Unger Harold F. , Snowden Byron S. , Engelmann William H.
Published: December 2007

The effects of using surfactant solutions while diamond drilling in amygdaloidal basalt of the Upper Michigan Copper Mining District were investigated. Nonionic, anionic, and cationic surfactant solutions, all biodegradable, were tested with size AX surface-set bits mounted on a drill instrumented for continuous recording of thrust, rotational speed, and torque levels. Water flow and penetration rates were also recorded.

A drilling study was carried out, testing two rotational speed levels, two diamond bit grade levels, and four flushing agents (including water as control). The lower speed and higher thrust yielded faster penetration rates over those of the higher speed/lower thrust combination. Comparison of all low-speed/high-thrust groups of tests shows that the nonionic surfactant produced a 35-percent overall average increase over water, the anionic a 29-percent increase, and the cationic a 28-percent increase. These increases in penetration rates resulted in a 22- to 26-percent penetration rates resulted in a 22- to 26-percent reduction in cost over flushing with water alone.

Particle size analyses were run on drill cuttings produced by the three surfactant solutions and by water. All surfactant solutions showed a 20- to 50-percent increase in solids content over that of water alone. Since flushing rates were constant, these increases in solids content agree well with the above penetration rate changes.

The diamonds were recovered from each bit by matrix dissolution, and bit wear was measured in terms of total loss of weight. Flushing with surfactant solutions showed a savings in bit wear in most cases.

The drill team noted also that surfactant flushing improved recovery of drill core by allowing easier removal of the core from the barrel.

Introduction

Statement of Problems in the Native Copper Mining Industry

Exploration diamond drilling in the native copper mining industry of Upper Michigan started about 1882. The purpose has been to provide geological data, to map out ore provide geological data, to map out ore reserves, and to better plan mining operations. Since most of this diamond drilling has been from underground locations, only lightweight, low-powered drills can be used.
A Dimensionally Derived Rock Drillability Equation
Authors: Overton Harold L.
Published: December 2007

Introduction

In order to provide the drilling engineer with a generalized drillability equation that is portable, an analysis of the interaction of the rotating bit, circulation system and rock properties will be made. Many equations are in use in rotary properties will be made. Many equations are in use in rotary drilling. These are so numerous that handbooks must be used to classify them. Dimensional analysis can be used to simplify this situation, so that a generalized equation for all rock bits can be formulated.

DRILLABILITY

Drillability will be defined as the rate at which a given rock may be penetrated, in distance/time units, with a given bit configuration and specified drilling fluid medium. The specified conditions for both fluid and rock must include pressure, temperature and composition. Penetration rate is the measurement term for drillability, in velocity units (usually feet/hour, but also meters/hour).

Penetration rate, Rp = ft/hour, in English units = (hole volume/hour)

On an energy basis,

Rp = (V/energy absorbed)(energy/hour)

(1)

(2)

Using triangular teeth with rectangular bases, which is appropriate for narrow rolling cutters, and for tooth height, ht, and base area, At,

(3)

(4)

Noticing that one tooth of height, ht, makes one depth penetration of ht and that the force absorbed is the net bit weight applied to the borehole bottom, W.

(5)

The bit tooth is labeled as follows.
Stress-Strain and Failure Properties of a Porous Shale
Authors: Green Sidney J. , Griffin Robert M. , Pratt Howard R.
Published: December 2007

Unconfined and triaxial stress tests were conducted on dry and saturated shale from El Paso's Wagon Wheel No. 1 well. The material tested is in general a very competent shale containing stringers of silt and sand, producing local inhomogeneities which effect unconfined fracture, but do not significantly effect the behavior at higher mean normal pressures. Strong sensitivity of deviatoric maximum stress to mean pressure is observed for dry material, while little increase in deviatoric strength with pressure occurs for the fully saturated material. Dilation accompanies distortional deformation; however, softening or ease of compaction occurs at small distortional strains, before substantial dilation begins. In detail, the deviatoric stiffness (apparent shear modulus) and the pressure-volume relation (compressibility) are stress state and stress path dependent, while the deviatoric strength path dependent, while the deviatoric strength is only stress state dependent.

Introduction

Mechanical properties of a shale material were obtained for El Paso Natural Gas Company to be used in shock calculations to determine rock breakage, and hence increased permeability, caused by nuclear explosion. The samples tested were taken from a core at the 10,215–10,216 foot depth in El Paso's Wagon Wheel No. 1 well, NW/4 Section 5, Township 30N, Range 108W, Sublette County, Wyoming. Small samples were dry cored from the large core provided by El Paso and tested unconfined and provided by El Paso and tested unconfined and confined to pressures of 6 kbars. Both dry and fully saturated samples were tested, parallel and perpendicular to the large core parallel and perpendicular to the large core axis. Petrofabric analysis was made and photomicrographic observations taken to photomicrographic observations taken to predict and better understand the mechanism predict and better understand the mechanism of fracture.

Similar tests were previously conducted for El Paso on a large core of sandstone from 10180.4–10181.0 foot depth. These results are reported in Terra Tek report "Testing Program Conducted for El Paso Natural Gas Company" August, 1970.

EXPERIMENTAL TECHNIQUE

Test techniques are similar, and were described in detail in the previous El Paso report, and in other reports, and will therefore only briefly be covered here.
The DSP - A New Instrument for Estimation of the In-Situ Stress State at Depth
Authors: Roegiers J.C. , Fairhurst C. , Rosene R.B.
Published: December 2007

Determination of in situ tectonic stresses at depth can supply information which may be useful in predicting future movement in geologically active areas. These stresses can be determined by hydraulic fracturing and use of a new device, the deep stress probe (DSP). The DSP is hydraulically operated tool which is a combination straddle-packer and-impression packer which can determine the orientation packer which can determine the orientation (inclination) and azimuth of induced fractures.

This paper discusses results of two field tests recently conducted in the Granite Mountain Quarry near Marble Falls, Texas, to determine in situ tectonic stresses. This site had been used previously for near surface stress determination by over-coring. The experiments were performed in a 4 3/4-inch diameter hole, 1150 feet deep in granite. The borehole was fractured at various horizons, using different fracturing fluids to determine the most suitable system for future tests in hard rock. Downhole pressure readings were taken and oriented impression packers were used to determine the azimuth of the induced fractures. A downhole camera will be used to verify the fractures and to disclose any tendency of the fractures to heal.

Results of the DSP tests are compared with earlier results obtained by overcoring. The results suggest that lateral stresses at the depths tested are less than may be inferred from the surface tests.

Introduction

Determination of in-situ tectonic stresses at depth is an important aspect of various scientific and engineering problems related to underground construction and excavation. The behavior of rocks can supply information needed in the planning of underground construction, monitoring of tectonic activity, etc. It is felt that data gathered by monitoring tectonic activity in geologically active areas can be used to forecast probable periods of major disturbance. This could result in increased safety and decreased surface damage.

For the past decade, studies have been conducted at the University of Minnesota to develop a technique of measuring stresses at great depths.
Injection Water + Oxygen = Corrosion and/or Well Plugging Solids
Authors: Byars H.G. , Gallop B.R.
Published: December 2007

This paper was prepared for the Symposium on the Handling of Oilfield Waters of the Society of Petroleum Engineers of AIME, to be held in Los Angeles, Calif., Dec. 4–5, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Aeration of injection waters can create numerous problems. Corrosion of equipment, scale deposition and injection well plugging can reduce the profitability of a waterflood by affecting the ability to get the correct volumes of water into the proper zones at the proper time for efficient sweep and recovery. Operation of a "closed", air-free system will minimize many of these problems. problems. Practical approaches to the successful operation of such systems involve design and operation of water sources, oxygen removal from aerated sources, and maintenance of oxygen-free conditions throughout the system. Day-today operation, monitoring techniques and "oxygen conscious" personnel are important.

Introduction

If the statistics were available, we would probably find that aeration of the water is a bigger cause of problems in injection systems than any other single cause.

The role of oxygen in the corrosion reaction in water systems has long been recognized; and corrosion resistant materials, coatings and linings were used in early systems.

Oxygen (air) plays an equally important role in creating problems of deposits and injection well plugging. Aeration of a stable underground water results in the loss of stabilizing gases as well as oxidation of precipitable solids. This leads to the formation of scales, deposits and well plugging solids. Mixing an aerated supply water with a stable subsurface water can lead to similar problems. Installation of a "closed system" has been the approach to minimizing these effects.

The selection of the mode of operation of a water injection system is, of course, an economic balance which must consider the overall profit of a project throughout its life. Some factors are obvious, i.e., costs of failures, failure repairs and well cleanouts. However, many of the less obvious factors may be even more significant in a waterflood, such as, loss of injection capacity, plugging of tight zones, downtime, etc.
Simulation Of Gas-Condensate Reservoirs
Authors: Spivak A. , Dixon T.N.
Published: December 2007

This paper was prepared for the 3rd Numerical Simulation of Reservoir Performance Symposium of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Jan. 10–12, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

This paper describes a new method for simulating gas-condensate reservoirs. The simulator accounts for both retrograde condensation and vaporization of condensed liquid as well as arbitrary field shapes, well patterns and heterogeneities. The formulation of the simulator is based upon a formation volume factor or Beta-type analysis which is analogous to that used in black-oil simulation models. In the gas-condensate analogy, mass transfer between the gas and liquid hydrocarbon phases is handled by an rs term which has units of STB liquid/MCF dry gas and is similar to the Rs term in black-oil simulation.

Fluid properties for back-oil simulation models are usually obtained from laboratory PVT cell depletion data. This type of model is of questionable reliability only in special cases such as volatile-oil reservoirs where the reservoir pressure and temperature are close to the critical pressure and temperature of the oil. It is reasonable to assume, therefore, that reservoir fluids on the other side of the critical point (e.g., gas-condensate fluids) could be treated in an analogous manner. In other words, one would expect that gas-condensate reservoirs could be treated by a formation volume factor approach with fluid properties determined from laboratory depletion data. The simulator described in this paper employs such an approach.

The simulator handles three phases and consists of numerical solution of the continuity or mass balance equations for gas, liquid hydrocarbon and water in one, two and three dimensions.

Introduction

The proposed method assumes a condensate-gas to be a pseudo two-component system. The two pseudo-components are, at standard conditions pseudo-components are, at standard conditions of pressure and temperature, a dry gas and a hydrocarbon liquid. Each pseudo-component is itself a pseudo-component is itself a multi-component hydrocarbon fluid. The water phase, if present, constitutes a third "component".