bluuebunny/crossref_metadata_2025 huggingface dataset:
Moncrief (Pittsburgh) Unit Waterflood A Case History of High Pressure and Wide Spacing
Authors: Gaskill Robert A.
Published: December 2007

Introduction

The Moncrief field is located approximately 6 miles north of the city of Winnsboro, Franklin County, Tex. The field is productive in two reservoirs—the Smackover Lime at 12,200 ft, which is gas productive, and the Pittsburgh oil sand at 8,250 ft. As originally developed, after discovery in March, 1964, the Moncrief field Pittsburgh sand produced from ten 160-acre spaced wells which proved approximately 1,562 acres of reservoir areal extent.

Early observation of performance indicated that the Pittsburgh sand reservoir was producing under a primarily rock and fluid compressibility mechanism, and that the pressure and well capacities were depleting rapidly. With the realization that the supplementary solution gas energy available would be deficient for efficient exploitation of the field, efforts were begun to unitize the reservoir for pressure maintenance. The Pittsburgh reservoir was unitized for a flooding operation effective March 1, 1967.

GEOLOGY AND RESERVOIR CHARACTERISTICS

The Moncrief field is geologically part of an elongated anticlinal system which trends into the New Hope field structural trend to the northeast. The Pittsburgh reservoir, as developed on the crest of the structure, exhibits approximately 70 ft of closure and reaches a maximum thickness of 23 ft in the Unit Well 1-1. The lithology is described as that of a fine grained sandstone by core analysis and sample descriptions. Fig. 1 is a contour map indicating the structural attitude of the Pittsburgh zone.

The reservoir is bounded by an acquifer to the north and south at a subsea depth at about -7,780 ft. However, the effect of the aquifer is largely nullified by the thinning nature of the sand and the adverse permeability development along these flanks. Fig. 2 is an isopachous of the Pittsburgh net sand interval. A permeability pinchout is evidenced on the western permeability pinchout is evidenced on the western end of the reservoir trend by the distinctive difference in the crude gravity in the westerly direction. A test in the Humble-Winnsboro Fish and Hunt Club No. 1, located about three-quarters of a mile west of the unit boundary, yielded a 40 degrees API gravity crude. The Moncrief Pittsburgh sand produces 32 degrees API gravity crude. The Pittsburgh reservoir permeability is believed to Pittsburgh reservoir permeability is believed to discontinue at its eastern extremity somewhere within the west half of the M. Oliphant Survey. Again, the differential in the crude gravities lends support to this conclusion along with the apparent general thinning in sand development in the easterly direction. Further, the Moncrief Pittsburg field demonstrated no evidence of Pittsburg field demonstrated no evidence of pressure depletion when discovered in March, 1964, pressure depletion when discovered in March, 1964, with a reservoir pressure of 3,703 psig.
Chemistry of Interstitial Solutions in Shales Versus that in Associated Sandstones
Authors: Chilingar George V. , Rieke Herman H. , Sawabini Stan T.
Published: December 2007

Experimental results obtained by the writers show that the salinity of squeezed-out solutions from muds progressively changes with increasing overburden pressure. Both marine muds and clays plus sea water mixtures were used. Experimental results also show that the salinity of water remaining in shales should be considerably lower than that in associated sandstones. Yet, log analysts in their calculations assume that salinity of interstitial waters in shales and in sands is the same. This may result in erroneous interpretations.

Field data show a typical pattern of decreasing salinity of produced water with time in zones which receive most of their water from associated shales. This supports the above-mentioned conclusion based on laboratory data.

Introduction

Large amounts of water are squeezed out of the continental and marine sediments during compaction and lithification. The overburden pressures on these sediments may reach pressures on these sediments may reach magnitudes of 14,000 to 36,000 psi in geosynclinal basins. Most of the salts present in the waters, which are trapped during sedimentation,, are squeezed out during the initial stages of compaction. The laboratory results obtained by Buneeva et al. Kryukov and Komarova, Kryukov and Zhuchkova, Rieke et al. and Chilingarian and Rieke showed that mineralization of squeezed-out solutions progressively decreases with increasing overburden pressure.

Very little is known of the actual porosity of shale and the actual salinity of the contained water. It seems that if one could be determined the other probably could be calculated. The actual salinity of formation waters of the sands usually ranges from three times the salinity of sea water to one-fourth times the salinity of sea water [average salinity of sea water = 35 degrees/oo], and may range from greater than 10 times salinity of sea water to virtually fresh water. Recently, Foster and Whalen presented a technique for estimating formation pressures from electrical logs. This technique has been found especially applicable in the offshore Louisiana area in detecting abnormally high reservoir pressures. These authors, however, assumed that pressures. These authors, however, assumed that the water resistivity values in shales are equal to, or of the same magnitude, as that calculated for nearby sands. Consequently, solution Of this problem [chemistry of interstitial waters in shales vs chemistry of waters in associated sandstones] is of great practical importance.
A Method of Predicting Saturation Exponents in Logging
Authors: Von Gonten W.D. , Osoba J.S.
Published: December 2007

Water saturation is calculated from resistivity logs by using the relationship

where n is the saturation exponent. From this equation, it is evident that in order to calculate accurate water saturations from logs, the value of n must be known.

In this research project, saturation exponents and electrical formation factors were measured using three different salinity waters on 63 core samples from two wells in the same field. Porosity and permeability were also determined on each of the cores. The log readings from the SP Log, Density Log, Gamma Ray. Log, and Sidewall Neutron Log were read to coincide with each core sample. The lithology of samples ranged from clean to shaly fine grained sandstone.

Both the saturation exponent and formation factor were found to be greatly affected by the saturating water resistivity. The three waters used had resistivities of 0.06, 0.2, and 2.0 Ohm-Meters. As the water resistivity increased, the saturation exponent and formation factor decreased. The saturation exponent averaged about 2.03 for the 0.06 Ohm-Meter water but decreased to an average of about 1.21 for the resistive 2.0 Ohm-Meter water.

All of the core analysis and well log data was used in a regression analysis computer program to predict saturation exponent. Saturation exponent was predicted with the computer program to an average error of about 9 percent. Water resistivity was by far the most percent. Water resistivity was by far the most important independent variable in the prediction equation and permeability was second. By using water resistivity by itself, the saturation exponent was predicted with an average error of 15 percent.

This research shows that in either shaly sand or formation with high water resistivity large errors in determining water saturation can be made by assuming that the saturation exponent is equal to 2. This work further shows that saturation exponent can be predicted from routine core analysis and well log data.
Petroleum Engineering: A 20-Year Look in the Future
Authors: Kohlhaas C.A.
Published: December 2007

As part of a continuing effort to improve petroleum-engineering education at the Colorado School of Mines, the petroleum-engineering department has petroleum-engineering department has prepared a plan of operation enumerating prepared a plan of operation enumerating goals for the department and describing policy, staff, facilities, and policy, staff, facilities, and curriculum for attainment of those goals. Departmental plans are for a nominal period of ten years. Preparation for long-term careers requires an analysis of the professional environment for several years beyond the period of formal education. Therefore, for design of curricula and course content for the next ten years, the career environment has been evaluated for approximately the next twenty years. Due to the close relationship between the petroleum industry and the petroleum-engineering profession and petroleum-engineering profession and also due to the dependence of petroleum engineers on this industry for employment, part of the departments evaluation program consisted of surveying major oil companies for their opinion regarding future responsibilities and activities of engineers. The companies produce approximately half the United produce approximately half the United States' oil and provide a cross-section of the present and future course of the industry. The responses were used to supplement the knowledge, experience, opinions, and other evaluations of the department. The general health of the oil industry is expected to remain good although not booming. Increased costs due to greater regulation, pollution control, higher taxes, offshore and Alaskan development, and increased imports will all tend to force the industry to move future development programs overseas. Political problems in other countries will tend to limit profits and restrict foreign investment opportunities, however. It is not expected that demand for petroleum products will decrease for some time. Demand should increase due to population growth, industrialization of foreign countries, and development of markets for new products. Coal will probably be used products. Coal will probably be used as a supplementary energy source. It is not expected that oil shale will play a vital role in the nation's play a vital role in the nation's economy in the near future. Other energy sources which will come into use will supplement, rather than replace, petroleum. petroleum. Pollution problems, tax controversies, and the North Slope discoveries have focused considerable attention on the oil industry. No longer will the petroleum engineer be able to drill his wells and produce his oil in comfortable obscurity. His actions will be scrutinized with microscopic thoroughness by social scientists, citizen groups journalists, conservationists, economists, and an ever-increasing army of government bureaucrats.
The Goals of Engineering Education Report in Retrospect
Authors: Higdon Archie
Published: December 2007

Background

The Goals report was the fifth national evaluation and in-depth study of engineering education in the current century. The Mann Report 1907–18, the Wickenden Report 1923–30, the Hammond Report of 1940, updated in 1944, and the Grinter Report 1952–55, preceded the Goals Report 1962–68.

No other academic discipline or field of study has subjected itself to such intensive study. Furthermore, no other undergraduate educational program of this age requires its students to study such a broad spectrum of subject matter. Engineering education combines an understanding of this technological age in which we live as a key part of a broad liberal education and yet still finds time for specialization in a branch of engineering.

A four-year undergraduate program in any of the engineering disciplines today includes approximately one year (one-fourth of the program) in mathematics and basic sciences, program) in mathematics and basic sciences, one year in the engineering sciences, onehalf year in the social sciences and humanities, one-half year in analysis, synthesis, and design, plus another half year in courses in the specific engineering specialty, with the remaining half year for miscellaneous courses including composition, speech, graphics, and physical education. Please understand that these are very general averages and that some programs vary quite a bit from these data.

The Goals Report

The Preliminary Goals Report was published in October, 1965, and immediately published in October, 1965, and immediately became an extremely controversial document. In retrospect, this was very fortunate because engineering educators as well as practicing engineers everywhere became keenly practicing engineers everywhere became keenly aware of engineering educational problems and aspirations. In order to debate the issues effectively, engineers were forced to study the pros and the cons of each recommendation. The Preliminary Report contained fourteen specific recommendations. Even today, there is more heat than light in some discussions of some of those fourteen issues but the study and the dialogue alone made the time, effort, and money used to prepare the report well worth it.

After regional meetings across the nation on the Preliminary Report, followed by much study by the Goals staff and the Boards of Analysts, the Interim Goals Report was published in April, 1967. Much of the furor published in April, 1967. Much of the furor had subsided by this time and the Interim Report was rather generally accepted. Naturally, some people continued to oppose some aspects of the modified report.
Progressive Cavity Pumps Deliver Highest Mechanical Efficiency/Lowest Operating Cost in Mature Permian Basin Waterflood
Authors: Wright D. W. , Adair R. L.
Published: December 2007

Results of a field test study proved that progressive Cavity (PC) pumping systems provide greater mechanical efficiency and less electrical usage than beam and electrical submersible pumping (esp) systems in mature waterflood producing wells. These systems were evaluated in Permian Basin wells ranging from 3800 feet to 5000 feet in depth and production rates ranging from 500 barrels per day to 1000 barrel per day.

Operating facilities were used to monitor production, fluid shots were used to monitor fluid levels, and inline mechanical kw-hr meters were used to measure electrical usages before and after PC pump system installations. Mechanical efficiencies were calculated based upon this data. Production tests indicate that total well productivity was increased and an incremental oil increase was realized where PC pumping systems replaced beam lift systems previously thought to be optimum.

Increased water production due to waterflooding has necessitated lift revisions and beam pump optimization. When a beam lift system has reached maximum potential, a larger lift system becomes necessary. Esp systems provide increased lift capability, but at a much lower efficiency. The criteria used for selecting the test wells was maximized beam lift and economically marginal esp producing systems. The purpose for the field test was to determine if PC pumping systems were an economic alternative to lift these high WOR wells when compared to beam and esp systems.

A field test study was began in 1991 to evaluate mechanical and electrical efficiencies of PC pumping systems in the environment stated above. A comparative analysis to beam and esp lift systems was then performed. This paper presents the results of that analysis and confirms that PC pumping systems are the most cost effective artificial lift systems in mature Permian Basin waterlood producing wells.
Biopolymers as Free Water and Settling Control Agent
Authors: Ganguli K. K.
Published: December 2007

The free water and the solids settling problems exhibited in a cement slurry lead to variation in the density of set cement and channeling. The present study has demonstrated that inclusion of certain biopolymer in the slurry designs can eliminate both the free water and the solids settling problems.
Enhancing Performance of Submersibles Operating in Miscible Flood Conditions
Authors: Durham M. O. , Miller Gerald
Published: December 2007

A submersible system is the most effective equipment for producing large quantities of fluid in a marginal environment. A miscible flood presents a unique set of conditions for operating submersible systems. Some of the conditions encountered include depth, small diameter well bores, high horsepower, temperature, gas production, power system disturbances, hydrogen sulfide, asphaltines, and changing conditions.

The design of equipment, selection of materials, and operating requirements require special consideration. Techniques that enhance submersible performance are identified. Although none of these may be dramatic, the combination is dynamite.

The paper gives the operating conditions and experience with each component of the submersible system. The authors describe problems with and recommendations for selecting pumps, motors, seals, gas separators, cable, and variable frequency drives. Special attention is given to metallurgy, elastomers, training, and checklists necessary for successful operation. An extensive set of curves track the performance before and after changes.
Determination of Hydraulic Fracture Direction, San Juan Basin, New Mexico
Authors: Yale D. P. , Strubhar M. K. , El Rabaa A. W.
Published: December 2007

Reservoir management of hydraulically fractured reservoirs can be improved with knowledge of the orientation of hydraulic fractures. Fracture direction can affect where wells are placed, the design of well patterns for EOR floods, the design of fracture treatments, and the stability and fracturing of horizontal wells. This paper presents a field study of the determination of hydraulic fracture direction in the San Juan basin in northwest New Mexico. Data from six different fracture direction techniques were integrated to improve the determination of fracture direction. Integrating results from the six techniques not only improves the accuracy of the results but also allows us to compare the techniques to one another on the basis of reliability of results, operational requirements, and cost effectiveness.

The average of all the data from each of the four wells suggests a hydraulic fracture direction of 41° azimuth in this area of northwest New Mexico. The trends agree with regional in-situ stress direction for the area1. There were only small variations between wells and the fracture direction was consistent with depth over the 300 feet of formation tested. The direction of natural fractures as seen in the core and in the borehole televiewer was similar to the hydraulic fracture direction.

Based on this study and other published reports2-13 on hydraulic fracture/in-situ stress direction, we believe hydraulic fracture direction is best determined by integrating results from multiple techniques in several wells in an area. We find that the ability to determine fracture direction is most affected by the horizontal stress contrast in the area and the presence of paleo-imprints on the rocks. Fracture direction can strongly affect the recovery of hydrocarbons from hydraulically fractured fields and should be a datum that is collected routinely in the development of such fields.
Modelling Natural Gas Markets: Answering the "What It's"
Authors: Davis D. D , Harris J. M. , Bohlen P. S
Published: December 2007

Extensive market research has shown that volatility is the only characteristic that is constant in the natural gas marketplace. Methods which simply tie natural gas prices to crude oil prices as a predictor are, at best, inadequate and dangerous.

A more useful and realistic gas market assessment can be obtained by studying the relationship among key parameters within the market. Among others, population-weighted heating degree days, amount of gas in storage, demand growth, total deliverability, seasonal volatility, and net imports all have a profound influence on price.

These factors are presented in four separate cases using a dynamic, intertemporial simulation model. To address more "What IP questions, the algorithm is perturbed with variables such as the assumption of the mildest winter on record, followed by the coldest spring on record. The four cases presented are considered to be "mainstream" conditions that will most likely exist, however, some extremes are imposed to account for the unusual.
Measurements of Effective Fracture Toughness Values for Hydraulic Fracture: Dependence on Pressure and Fluid Rheology
Authors: Holder Jon , Morita Nobuo , Kenrick A. J. , Thallak Sitharam , Gray K. E.
Published: December 2007

Results from a series of laboratory hydrofracture tests, in which different fracture fluids, fracture fluid injection rates, confining pressures, and test specimen mechanical and fluid transport properties were used, are presented and discussed. Fracture fluids included various simple linear viscous (Newtonian) fluids and different combinations of three types of commercial fracture fluids: linear gels, cross-linked gels, and combinations of gels with suspended solids. Systematic variations in the behavior of fracture initiation pressures, and fracture fluid pressures during stages of stable fracture propagation, are observed to depend on fluid flow resistance, leak-off rate, and fracture fluid rheology. Post-test inspections of hydrofracture surfaces indicate the presence of a dry zone near the fracture tip. The effective hydrofracture toughness parameters determined from the tests with fracture fluid gels are substantially higher than the normal Mode-I toughness values, determined for the same material. The behavior is interpreted to be the consequence of a build-up of solids at the fracture tip, from dehydration of fracture fluids containing gels and/or solids.
Analysis of Observed Friction Pressures Recorded While Fracturing in Highly Deviated Wellbores
Authors: Bilden D. M. , Spearman J. W. , Hudson H. G.
Published: December 2007

In deviated wellbores, the relationship between friction pressure and hydrostatic pressure differs from that in vertical wellbores. The change in this relationship increases the need for accurate slurry friction pressure modeling. Because of deviation, incremental slurry friction pressure changes are more significant than incremental changes in hydrostatic pressures. Real-time calculation of an accurate bottomhole treating pressure in deviated wellbores is more difficult to achieve, than in vertical wells, because of the lack of accurate slurry friction models.

"Abnormal" surface treating pressures, which are caused by this change in relationship, were recorded while fracturing deviated wells in the Prudhoe Bay Field in Alaska. The significance of this relationship is presented along with observed slurry friction pressure data obtained through the use of bottomhole pressure recorders. A methodology and mathematical model for more accurate calculation of slurry friction pressure is presented for these conditions.
Automatic Type-Curve Matching for Horizontal Wells
Authors: Thompson L. G. , Temeng K. O.
Published: December 2007

This paper considers the design of an algorithm for analyzing multirate horizontal well pressure transient data using nonlinear regression techniques. Measured data is modeled using the analytical solution for a uniform-flux horizontal well in a rectangular parallelepiped reservoir. Parameter optimization is achieved using the public-domain Levenberg-Marquardt algorithm, LMDER, from Argonne national Laboratory.

We focus on efficient methods for calculation of analytical partial derivatives of the model pressure response which are required by the optimization routine. Complete expressions for all required partial derivatives are provided in Appendices, along with details on a method of evaluating these derivatives which requires minimal computational effort. We demonstrate the utility of the method by analyzing field buildup pressure data.
Through-Tubing Perforating With Pivoting Shaped Charges
Authors: Lopez-de-Cardenas J. E. , Brooks J. E. , Jensen Max
Published: December 2007

A new through-tubing gun with pivoting shaped charges, capable of going through narrow tubing restrictions but with performance comparable to the largest guns, is presented. Calculated production results show improvements of 20 to 100 percent over conventional through-tubing guns and results similar to the larger guns. Field results show significant increases in well production.
A New Correlation Developed Between Archie's Parameters and Continuous Phase Change Saturation Interval
Authors: Unalmiser Servet , Bova J. A.
Published: December 2007

The establishment of correlations between the continuous phase change saturation interval (ds) and Archie variables "m" and "n" allow for a cost effective and quick method of obtaining critical data used in the formation evaluation of oil reservoirs. This is significant since the direct electrical measurements conventionally used to obtain these variables is both time consuming and expensive. Conventional mercury injection tests can be utilized to predict electrical parameters based on the porosity/permeability ratio of the rock sample.

The measurement of electrical properties were performed with a true four pole configuration at five different frequencies ranging from 0.5 kHz to 10 kHz. Continuous Resistivity and Capacitance Measurements have been accomplished under simulated net overburden pressure. Following the measurement of the fully brine saturated sample, the desaturation was initiated through a semi-permeable membrane without removing the sample. The Rock/Fluid equilibrium at each capillary pressure was determined based on a continuous resistance measurement and corresponding volume of expelled brine. Completing the resistivity measurements, samples were extracted and mercury was injected from low vacuum, 20 microns of mercury pressure, up to 4500 psi. Following the first injection cycle, mercury was ejected down to atmospheric pressure and then second injection cycle performed up to 4500 psi. The transient saturation between mercury and mercury vapor, where continuous phase changes take place, has been succesfully correlated with the electrical parameters.

The correlation developed between continuous phase change saturation interval (ds), and Archie's parameters exhibit two opposite trends based on the permeability/porosity ratio of the samples: (1) Both cementation factor and saturation exponent, for the group of samples with (k/ø) less than one are directly proportional with the continuous phase change saturation interval. (2) The group of samples having (k/ø) more than one display an inverse proportion between (ds) and Archie's Parameters.
Measurement of Composition of Drilling Mud by X-Ray Fluorescence
Authors: Houwen O. H. , Gilmour Alan , Sanders M. W. , Anderson D. R. , Prouvost Laurent , White D. B.
Published: December 2007

An evaluation is described of the concept of measuring solids in drilling fluids by X-Ray Fluorescence, which is illustrated for water base muds. The performance of the calibration model obtained was tested against a variety of fluid compositions.

The calibration was based on measurements of a learning set of muds in which barite content ranged up to 1550 kg/m3. Drilled solids were simulated by calcium carbonate in concentrations ranging up to 300 kg/m3. Potassium and sodium salts were present in concentrations of up to 200 kg/m3 KCl or 250 kg/m3 NaCl.

A standardized software package has been developed, which utilises some of the potential outputs from the XRF measurement. The algorithm implemented uses barium fluorescence and backscattering intensity together with fluid density to predict the concentration of barite and water. From these primary outputs, and the chloride content supplied from an external source, the concentration of Low Gravity Solids is also determined.

The accuracy of the predictions from the technique has been determined for muds in which compositions conformed to the bounds of the calibration fluids, and also for muds in which LGS were simulated by mixtures of kaolinite, illite, quartz and anhydrite, rather than by the calcium carbonate used in the calibration. It was found that the nature of the LGS has little or no influence on the predictions.

Effects of likely contaminants in water base muds were explored by adding realistic amounts of ferrochrome lignosulphonate, iron filings, pipe dope or oil. No significant influence on the predictions was found. No adverse effects from variation in particle size of LGS were observed in experiments in which sized fractions of ground illite were used, ranging from below 75 microns to larger than 4 mm.

To simulate a field situation, a base mud containing 3 vol.% LGS was contaminated with varying amounts of kaolinite, illite, quartz, anhydrite and dolomite, which in each case raised LGS content to 8 or 11 vol.%. No significant variation in results due to the different nature of these solids was seen. Analysis of the accuracy obtained in these experiments suggests that the resolution by which variations in LGS content can be detected is approximately 0.3 vol.% absolute. This contrasts favourably with the traditional mud retort technique, which is estimated to be some ten times less precise.
Increasing Drilling Instrumentation Demands: Integration and Ergonomic Studies
Authors: Knutson Michael , Weare Barry
Published: December 2007

Over the years, drillers worldwide have seen their duties and responsibilities escalate with increasing requirements for more sophisticated monitoring and control equipment. An abundance of these devices are flooding the driller's station. These demands are brought on by more stringent safety requirements and intense pressures of economically developing marginal oilfields.

The first attempts to cope with this influx of devices were to stack specific function consoles around the driller. This method is still used in some applications, creating an intensely cluttered and highly inefficient work area.

The solution to this problem is to combine the monitoring and control equipment into a custom-configured consolidated driller's console. Many considerations are undertaken in order to successfully design and manufacture an efficiently integrated console, which will become the driller's primary tool. Concerns of placing primary instrumentation in direct access to the driller, avoiding instrumentation duplication and maintaining sight of work area while monitoring instruments are considered. Another is logically grouping instruments for simplicity in use and proper interpretation. These concerns and many more have promoted the extensive ergonomic studies to develop today's strategic Driller's command console.

One highly efficient console design was accomplished through the collaboration of Shell UK with KCA Engineering and MartinDecker TOTCO.
Improving Marine Safety on Mobile Offshore Drilling Units
Authors: Vermersch J. A. , Day J. B. , Christman S. A. , Nolop N. C.
Published: December 2007

In 1982, Exxon initiated an enhanced worldwide marine safety program for mobile offshore drilling units (MODUs) operating for the corporation's affiliates. A task force was commissioned to survey, from a marine operations standpoint, selected MODUs to identify ways to maximize the effective use of existing marine safety equipment, practices, and training for emergencies including vessel abandonment. The effort resulted in specific goals to reduce the likelihood of serious mishaps and to improve the crew's chances of survival in the event rig abandonment were necessary. The goals were to (1) develop and implement a set of safety guidelines for MODUs operating for Exxon, (2) work to help upgrade industry standards and practices, (3) assess marine safety systems as part of the initial rig selection process, and (4) conduct effective, comprehensive structural inspections on selected rigs.

Marine safety guidelines were developed to address several main areas, including emergency response, rig abandonment, personnel qualifications, stability procedures, and fire protection. The guidelines have been used in over 90 marine safety surveys (assessments) to date. A comprehensive onboard safety school was developed emphasizing effective scenario emergency drills and offshore survival. Over 35 of these schools have been conducted in cooperation with the drilling contractors.

The content of the marine safety guidelines and the schools have been used in efforts to upgrade industry standards through the American Petroleum Institute (API), United Kingdom Offshore Operators Association (UKOOA), the Oil Industry International Exploration and Production Forum (E&P Forum), International Maritime Organization (IMO), and the U. S. Coast Guard (USCG).
Use of Time-Shared Computer Terminals for Quick Turn-Around Log Analysis
Authors: Shelby Bertram S.
Published: December 2007

Commercial Time Sharing Computer Services have been utilized by the headquarters staff of the author's company since November, 1967. The service has been by the General Electric Mark I and Mark II Information Processing Centers located in Dallas, Texas; Teaneck, New Jersey; and Cleveland, Ohio. Ready access to these computers by phone service through standard teletype terminals has allowed the continuous development of a fast and comprehensive group of programs for well log analysis. The ability to share the use of these programs with remote field office locations through common computer memory networks has allowed expanded application of these log analysis programs. The great flexibility and ease programs. The great flexibility and ease with which problem solutions can be programmed provides adaptability to programmed provides adaptability to unusual well log analysis problems and applications. Time shared computer programing has provided the remote user programing has provided the remote user with engineering analysis graphics with repeatable formatting, and has allowed, after the description of the program, non-technical and technical aids to accomplish well log analysis with unwavering reliability.

Time sharing computer analysis has decreased the time required to do detailed well log calculations and allowed the inclusion of additional reconnaissance parameters not normally calculated during parameters not normally calculated during quick-look manual calculations of logs. Time sharing has provided an excellent tool for the company log analysts to better and more quickly serve the needs of engineers and geologists.

LOG ANALYSIS BY COMPUTERS

The application of computers to the calculations of log analyses is not new to the oil industry. These analyses are commonly made at the site of the computing facility which is normally staffed by computer trained formation evaluation specialists.
Elimination of High Bit Noise Levels in the Kuparuk Field, Alaska
Authors: Fitzpatrick Ellen , Knowlton Helene , Green Randy
Published: December 2007

In the Kuparuk Field of Alaska a project was undertaken to drill the entire 8-1/2 in. hole interval with a single polycrystalline diamond compact (PDC) bit while achieving a substantial improvement in penetration rate and maintaining the directional control of the steerable turbine assembly. The baseline drillability of the formations ranged from instantaneous rates of 400 ft/hr in the soft shales to 30 ft/hr in the hard formation. Water-base mud was the drilling fluid used.

A very simple acoustic emissions monitoring technique was assembled to confirm that bit whirl was the mechanism causing premature bit failure. Surface measurements of acoustic emissions were correlated with downhole accelerometer, weight-on-bit and torque-on-bit data.

It was proved that the baseline bit was whirling. A new series of bits was designed to drill without the excessive vibrations caused by whirling and to complete the entire interval. Utilizing data from downhole sensors, directional drillers learned how to optimize drilling parameters. At the conclusion of a one-year test program, the average penetration rate of the 8-1/2 in. interval jumped from 135 ft/hr to 240 ft/hr. Drilling costs of the 8-1/2 in. section were cut in half.
Integrated Incentive Drilling Contracting: An Operator's View
Authors: Bartstra R. M. , Prifti P. J. , Fleck A. R.
Published: December 2007

This paper describes the process by which one operating company within the Shell group constructed, tendered and negotiated a contract with a drilling contractor in line with the philosophy of Drilling in the Nineties. It highlights the shortcomings, achievements and qualifications that were encountered.
Field Tests of a Low-Cost Lateral Drilling Tool
Authors: Winters W. J. , Mount H. B. , DeNitto P. J. , Dykstra M. W.
Published: December 2007

Field tests of a low-cost short radius lateral drilling system are described. The uniqueness of this system lies in its simplicity and the fact that it was used on workover rigs in West Texas to laterally recomplete 6 production and 2 injection wells for an average cost of $116,500 including plugback, drilling, and stimulation. The authors advocate using this type of tool to laterally recomplete the industry's large capital resource of existing wells. Unusual technical developments including a miniature electronic survey instrument, a simple mud-pulse directional orientation sensor, improvements to flexible drill pipe for short radius wells, and advances in logging and stimulating short radius wells are discussed.
Techniques for Successful Application of Dynamic Analysis in the Prevention of Field-Induced Vibration Damage in MWD Tools
Authors: Field D. J. , Swarbrick A. J. , Haduch G. A.
Published: December 2007

This paper describes a set of analysis techniques which have successfully reduced vibration damage to MWD tools and their associated down hole assemblies. Owing to the sensitive nature of MWD tools and the instruments which they contain, the use of such equipment demands that conditions which lead to severe and damaging vibrations be identified and avoided. With careful consideration of input parameters, judicious "post processing" of results, and continuous correlation with field data, the authors are able to demonstrate a method which fosters improved drillstring design decisions while mitigating vibration damage and associated failures.

The routine utilisation of this method provides three significant benefits. First, avoidance of potentially damaging operating conditions results in documented savings in time and cost. Secondly, the accumulated database of field cases provides historical information which results in improved design decisions and fewer problems on future wells. Finally, the database of field results defines a reference point for continual refinement and enhancement of the methodology. Field cases are presented which illuminate these benefits.

The dynamic analysis procedure used in this work identifies the critical speeds for a given down hole assembly by determining the three dimensional vibrational response due to a selected excitation. Although the analysis techniques described herein were developed specifically for this appli cation, these guidelines are generally applicable to other types of dynamic down hole assembly analysis.
Current Investment Practices and Procedures: Results of a Survey of U.S. Oil and Gas Producers and Petroleum Consultants
Authors: Dougherty E. L. , Sarkar Jayati
Published: December 2007

Based on a survey of investment practices of U.S. oil and gas companies, this paper assesses investment techniques in current use and the impact of environmental and tax regulations. Questionnaires sent to selected oil and gas companies, professional consultants, and bank engineers concentrated on seven major areas: capital availability, investment analysis techniques, cost of capital, risk analysis, impact of environmental regulations, valuation of property acquisitions and miscellaneous investment considerations. Replies were analyzed to obtain the distribution of responses for each question, and cross-correlations between size of capital budget and responses in the major areas.

In the areas of capital rationing, impact of environmental regulations and investment evaluation methods, significant differences in the responses across firm size or between firms and consultants are not apparent. Differences are apparent for determination of discount rates, causes of capital limitations, value of nominal discount rates and effect of AMT.

The average nominal aftertax discount rates reported by firms and consultants are 14% and 13%, respectively. A little over half of our responding firms report that AMT has had a negative impact on investment. Results are compared to those of a similar study [1], showing the trend in investment analysis and the broadening scope of concerns in picking good investments.
Risk Analysis as Applied to Drilling and Developing an Exploration Prospect
Authors: Cowan J.V.
Published: December 2007

This paper was prepared for the 44th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Denver, Colo., September, 28-October 1, 1969. 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.

Measuring the effects of uncertainties on the financial outcome of proposed hydrocarbon exploration ventures is a common necessity in the petroleum industry. To perform such measurements a risk analysis perform such measurements a risk analysis model has been constructed and computerized. Cumulative probability distributions of basic financial indices are developed by repeatedly solving the model using input variables sampled at random. Fundamental statistical measurements which further describe these distributions are also computed. The scope of the analysis begins with the exploration phase and ends w hen the producing rate reaches phase and ends w hen the producing rate reaches an economic limit. During each simulation of exploiting the prospect many checks are made to verify the economic feasibility of continuing capital expenditures. The model defines the probabilities of an acceptable monetary return while the financial outlay is still minimal.

Introduction

Significant amount of risk capital must be committed to initiate most hydrocarbon exploration plays. As reserve potentials dwindle, and costs increase, management must carefully pre-judge the economics of each possibly exploration venture. Also, they must possibly exploration venture. Also, they must somehow judge the odds of attaining the necessary economic incentive to justify these expenditures.

It is the nature of hydrocarbon exploration to be laden with uncertainties. These uncertainties present a series of fundamental questions which must be answered sequentially before risk capital is exposed:

Will geophysical/geological studies locate a prospective anomaly on openacreage? If so, will a wildcat well drilled into the prospect find hydrocarbons that can be produced at commercialrates? Given a successful wildcat, will the delineation of the find prove the reserves necessary to justify expenditures for production facilities and the development of the discovery?
An Alternative Approach to Modeling Uncertainty in Hydrocarbon Economic Analysis
Authors: Behrens A. M. , Choobineh F. F.
Published: December 2007

Probability has been the traditional approach for representing uncertainty in hydrocarbon economic analyses. Probability, however, often cannot sufficiently represent the type of uncertainty commonly encountered in practice, since the prevalent uncertainty is frequently a result of the inherent vagueness of parameters values rather than randomness of the parameters.

An alternative approach to probability that provides a better representation of economic uncertainty is possibility distributions or fuzzy numbers. The theoretical requirements of possibility distributions are less stringent than those of probability, making them easier to apply in many economic analysis situations. This paper advocates the use of possibility distributions in oil and gas economic analysis.
Fluid Properties and Particle Size Requirements for Effective Acid Fluid-Loss Control
Authors: Gdanski R. D.
Published: December 2007

Control of acid fluid loss during fracture acidizing treatments is recognized as being a dominating limiting factor in the effective use of such treatments. This paper will discuss the importance of adequate acid viscosity, proper acid concentration, and proper particle size distribution for maximizing acid fluid loss control. The recommendations are based on laboratory testing which utilizes a severe acid fluid loss test. The test involves the use of a hollow core reactor under conditions of several hundred psi radial pressure drop across about a 5/8 inch thick wall. The pressure drop was from the inside of the limestone core to the outside. Parameters investigated included acid viscosity, acid concentration, and fluid loss additive particle size distribution. It was discovered that simply viscosifying the acid provided a remarkable improvement in acid fluid loss control. This enhancement was most pronounced in very low permeability limestone cores. The nature of the viscosifying agent was found to be a secondary effect with polymeric materials being more effective than surfactant type viscosifiers. A viscosity of 20 cp at 511/sec at the treating temperature was found to be an optimum value. It was also shown that the higher acid concentrations caused poorer fluid loss control. The effect of particle size distribution of a silica fluid loss additive was studied and indicated the particles with sizes larger than 80 mesh were key to successful acid fluid loss control. Silica flour was found to provide little enhancement of acid fluid loss control. The principles learned from the laboratory tests can be used to design improved fracture acidizing treatments. Indeed, these principles have been used successfully.
Interpretation of Directional Gamma Ray Logging Data for Hydraulic Fracture Orientation
Authors: Simpson G. A. , Gadeken L. L.
Published: December 2007

A new directional gamma ray tool has been developed and is being incorporated into an innovative togging service. The service determines the azimuthal pattern of gamma ray emission from a completion material that has been tagged with a radioactive isotope. This paper discusses the interpretation of directional gamma ray logging data following hydraulic fracturing operations. By measuring the intensity of gamma rays emitted from tagged material placed in the induced fracture, the directional gamma ray measurement can be combined with auxiliary wellbore survey information to assist in the determination of propagation azimuth. Such results have a variety of applications – for example, designing a systematic well placement scheme to optimize reservoir drainage efficiency.

Log examples derived from prototype tool measurements following hydraulic fracturing operations are presented and the analysis of the data is discussed. The interpretation of directional gamma ray data is adversely affected by damage to the near-wellbore region during fracturing operations. Data interpretation was found to be more consistent and reliable following micro-frac or mini-frac stress determination operations. In addition, where perforations were oriented in the direction of the anticipated fracture propagation, directional gamma ray data demonstrated an improvement in fracture efficiency.