bluuebunny/crossref_metadata_2025 huggingface dataset:
Constitutive Equations of Shale and Clay Swelling: Theoretical Model and Laboratory Test Under Confining Pressure
Authors: Zhou Z. H. , Huang R. Z. , Chen Y. F.
Published: December 2007

Shale is a rock likely to cause problems in oil drilling and production. The main problems in shale and clay swelling studies published so far are: (1) there is little connection of swelling test results with possible engineering applications, especially to stress-strain analysis; (2) the advances in the microscopic swelling research are not applied in the macroscopic mechanical swelling research; and (3) most tests do not consider the effects of confining pressure on water content, swelling amount and Young's modulus.

Based on the published microscopic swelling data, this paper derives a general swelling model which includes the effects of water content and stress state (and transversely isotropic mechanical properties for the sedimentary formation, if needed). The parameters in the derived constitutive equations are determined by swelling tests under different confining pressure levels. The test apparatus and procedures are described. The test results have verified the proposed model to show the higher the confining pressure the lower the final water content and swelling amount. Based on rock mechanics theory and the experimental research, constitutive equations of shale from Daqing Oilfield, China, have been proposed. Discussions and suggestions for further research are given at the end of the paper.
Recent Advances in the Fluid Mechanics and Rheology of Fracturing Fluids
Authors: Shah S. N. , Lord D. L. , Tan H. C.
Published: December 2007

Numerous advances have been made in rheology of fracturing fluids over the past decade. This paper describes the state-of-the-art fracturing fluid technology. In particular it gives a comprehensive review of the current literature on fracturing fluid rheology. It describes various fluids available today for the fracturing process and provides a review of the presently available methods and procedures to characterize the simple as well as more complex fluids. Further, our intention is to review and describe current laboratory methods for prediction of friction pressure under simulated field conditions within the wellbore. This includes uncrosslinked and crosslinked fluids with and without proppant.

This paper also describes the use of pipe and rotational viscometers to simulate laminar flow, of these non-Newtonian and time dependent fluids within the fracture. Application of data collected during these various laboratory simulations to predict wellbore hydraulics and fracturing fluid rheology is described. Finally, the paper summarizes findings, addresses future needs, and presents recommendations.
Optimizing Fracture Acidizing Treatment Design by Integrating Core Testing, Fieid Testing, and Computer Simulation
Authors: Van Domelen M. S.
Published: December 2007

Many hydrocarbon-bearing carbonate formations are routinely stimulated by fracture acidizing. Concurrent with the desire for increased production is the need to optimize treatment design and to predict well response following treatment. Simulation of the fracture acidizing process is complicated by the fact that the rate and extent of chemical reaction must be predicted, in addition to modelling the growth of the hydraulic fracture. Treatment design is further complicated by the fact that reactive and non-reactive fluids display different leakoff characteristics and overall leakoff rates tend to increase throughout an acidizing treatment.

This paper describes the use of a fracture acidizing simulator which dynamically couples fracture geometry and acid spending calculations. The simulator has the ability to accept data which describe the specific reactivity and etching characteristics of a given formation. The inadequacies of utilizing standard reactivity data and generalized etched conductivity correlations are illustrated.

The paper takes an engineering approach to acidizing treatment design. It reviews various core tests which can be performed to evaluate the feasibility of successfully stimulating a formation by fracture acidizing and shows how the data can be used in conjunction with computer design programs. Field tests which allow estimation of in-situ fluid leakoff characteristics are reviewed and related to acidizing treatment design.

Case histories are given which illustrate how fracture acidizing treatment design can be optimized by integrating core testing, field testing, and computer simulation.
Review of Coalbed Methane Well Stimulation
Authors: Palmer I. D.
Published: December 2007

Coalbed methane is an abundant resource in the U.S.A., for example, in the San Juan Basin (50 TCF), and Black Warrior Basin (20 TCF). Amoco has drilled many wells in both basins in the last few years. Different completions and stimulations have been tried, and these are summarized as follows:

Openhole cavity - This has worked best in areas of the San Juan Basin where reservoir pressure and permeability are high. The wells can be prolific producers (up to 12 MMCFD). The physical mechanisms involved in the completion are discussed, and these are used to try to understand the difference in gas production between cavity completions and gel fracture stimulations. Gel fracture treatments - These stimulations are conducted through perforations in coal seams, and sometimes two or more stages are used per well. High fracture conductivities are achieved by using 12/20 mesh sand to concentrations of 10 ppg, and the viscous gel should mean most of the coal seams are propped. Graduated proppant treatments (40/70 sand preceding the main 12/20 sand) are often used to alleviate screen-outs. Although some gel damage to the coal formation is evident, moderate productivity increases have been achieved. Water fracture treatments - Because of gel damage to the formation, fracturing treatments have been conducted using water as fracture fluid, plus 12/20 sand to concentrations of a few ppg. Although not all coal seams are expected to be propped (due to low viscosity of water), gas production is greater in general than offset wells References and illustrations at end of paper. with gel fracture treatments, and the water fractures are cheaper. Sandless water fracture treatments - Recently water fracture treatments have been performed without sand, using ball sealers to open up more seams. Although their gas production may not be as good as wells fractured with water and sand, they can be substantially cheaper.

Fracture designs are summarized, and gas production is compared for the different completion/stimulation techniques.

Fracture treatments in general appear to fall into two different classes: First, those in which significant fracture height growth occurs, accompanied by falling pressures (vertical fractures). The second class are those which are largely confined by the coal seams, and are accompanied by steady or rising pressures, prop-pant-induced pressure increases, and ISIP values greater than 1 psi/ft (T-fractures). Interpretations of fracture geometry, height growth or confinement, fracturing pressure, and proppant-induced behavior, are summarized.
A Survey of Continuing Education in Petroleum Engineering
Authors: Calhoun J. C.
Published: December 2007

Continuing education courses in petroleum engineering are offered through several channels, some of which are open to the general profession and some of which are arranged on a private basis for selected clients. The principal sources for these courses are (1) the major oil producing companies, (2) the academic petroleum engineering departments, (3) individuals and organizations engaged in continuing education for profit, and (4) the Society of Petroleum Engineers. The petroleum engineering profession generally is aware of the availability of continuing education courses through these channels, but no group within the profession provides a comprehensive clearinghouse function. There is a lack of information on the scope and totality of the activity and this paper is intended to assist in filling that need.

Early in its development, the petroleum industry recognized that the practitioners of petroleum engineering needed to have a first hand knowledge of the natural situations from which oil was produced and of the manner in which those situations influenced the application of basic engineering concepts. This led, in the first quarter of the century, to the establishment of company training programs, which at first were concerned with the operational techniques of drilling for and producing petroleum rather than with engineering concepts. According to the API History of Petroleum Engineering the first such organized activity began in 1916 as the Doherty Training School associated with the Empire Gas and Fuel Company at Bartlesville, Oklahoma.

Universities in the petroleum regions also played a role in the development of technological personnel for the industry by offering special short term training programs such as the Natural Gas Measurement Course at the University of Oklahoma, or by conducting organized extension courses in the field that were patterned after the agricultural model. An extension program in oil and gas production that existed at Penn State as early as the 1930s is now extinct, but an organized Petroleum Extension Service is still operated by the University of Texas.
Undergraduate and Graduate Petroleum Engineering Education in the U.S.
Authors: Von Gonten W. D. , Whiting R. L.
Published: December 2007

Petroleum Engineering educational programs produce graduates primarily for die upstream sector of the petroleum industry. This paper will present a summary of both the undergraduate and graduate petroleum engineering programs in the United States.

The undergraduate portion of the paper will address the curriculum, accreditation, enrollments, student recruitment, faculty, jobs, starting salaries, and a historical perspective.

The graduate section will address both master and doctoral level programs including the number and size of programs, curriculum, admission requirements, program administration, jobs, salaries, and a historical perspective.
Microbit Studies of the Effect of Fluid Properties And Hydraulics on Drilling Rate, II
Authors: Eckel John R.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper was prepared for the 43rd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Sept. 29-Oct. 2, 1968. 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 request 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 discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Microbit studies presented to the SPE of the AIME in 1966 (SPE 1520) showed that in one rock under fixed conditions of bit weight, rotary speed, and differential pressure, drilling rate could be expressed as a simple power function of mud flow properties and power function of mud flow properties and hydraulic parameters. A logical question arose: "Are these reported results general?"

To resolve this question, the results of additional microbit studies are reported in this paper. These tests were conducted with bit weights 500 pounds less and greater than the original 1000 pounds test condition, rotary speeds of 150 rpm and 45 rpm in addition to the original 75 rpm value, and differential pressures of 0 and 50 psi in addition to the original 500 psi test condition. Tests were also run in Carthage marble as well as additional tests in the original Indiana limestone.

Under all of these conditions, the original relationship of rate of penetration to fluid properties and hydraulics was unchanged. Changes in the various parameters caused changes in the drilling rate, but not in the effect of fluid properties and hydraulics.

There was no detectable interaction between the variables, indicating that an equation of the form,

can be satisfactorily used for calculating drilling rate.

Introduction

An earlier paper, "Microbit Studies of the Effect of Fluid Properties and Hydraulics on Drilling Rate" (SPE 1570, published in 1966), presented the results of a laboratory study indicating that drilling rate can be expressed as an exponential function of a pseudo Reynolds number involving flow rate, pseudo Reynolds number involving flow rate, nozzle size, and fluid viscosity and density. For non-Newtonian fluids, the "viscosity" is that at hole bottom, near bit-nozzle, shear rates. A relatively simple expression for drilling rate,

can be used to cover the range of greatest variation—that is, for values of the Reynolds number between about 5 and 100.
The Use of Real-Time Downhole Shock Measurements To Improve BHA Component Reliability
Authors: Alley S. D. , Sutherland G. B.
Published: December 2007

A database consisting of 150 bit runs over 29 wells was compiled. Trend analysis was performed on the data to determine the driving force behind downhole shocks. A statistical analysis, specifically used for analyzing fatigue life phenomenon, was used to predict a Mean Shock Between Failure (MSBF) for a downhole tool component

Data analysis revealed that high shock levels occurred in both horizontal and vertical wells. The analysis also confirmed that downhole vibration is a strong function of RPM and WOB. The data shows that pendulum assemblies with tricone bits using high WOB results in extremely high levels of downhole shocks.

Downhole shock data transmitted in real time will allow the operator to vary drilling parameters to reduce the downhole shock level and increase the life of the drillstring and its components. The data demonstrates that cumulative shock cycles should be used with cumulative pump time to enhance BHA component reliability through improved maintenance scheduling.
Development of Air Drilling Motor Holds Promise for Specialized Directional Drilling Applications
Authors: Shale L.
Published: December 2007

The development of a new motor designed specifically for use in holes drilled with air and mist is chronicled, from initial use of modified mud motors in air drilling applications, through development to date of an air drilling motor currently in use.

Until recently, air drilling was accomplished using either an air hammer or, for a more directionally controlled well, a Moineau type positive displacement mud motor (PDM) adapted to an air drilling environment. In such cases, bottom hole assembly performance proved heavily dependent on motor life and lithology type.1 Greatly reduced stator life and accelerated damage to bearings designed for mud lubrication meant that conventional motor runs on air usually were shorter than with mud systems. Ultimately, conventional PDMs exhibit many economic limitations when used on air for directional drilling.

The new air drilling motor, which features a Moineau motor with a novel geometrical design of the power section, an adjustable kick off sub and a modified bearing assembly, represents the latest step in the continuing development of a downhole motor suitable for directional and horizontal drilling using air or mist. This design has been successful in US air drilling applications, which are detailed in case histories.
Deviation Control With Steerable System Lowers Well Costs in Southern Oklahoma
Authors: Schellenberg S. , Rogers T. , Smith L.
Published: December 2007

This paper describes case histories of wells drilled primarily in two fields in Southern Oklahoma, Southwest Davis and Cottonwood Creek, which are located in an area of known deviation problems. Past operations in this "crooked hole country" have employed conventional means of drilling these problem wells, including running relatively light weights and stiff, packed hole assemblies. Ordinarily, conventional directional tools are used to direct the hole to a specified location.

In an attempt to control deviation problems and increase penetration rates, a steerable system was incorporated into the drilling program for the 8-3/4″ hole size, at depths that ranged from 2000 to more than 8000 feet. While directional tools were used to direct the hole to a specified location, use of the steerable system resulted in a drastic reduction in the number of days required to drill the interval.
Improved Drilling Performance, Efficiency, and Operations Using an Advanced Real-Time Information System for Drilling
Authors: Onoe Y. , Yoder D. , Lawrence M.
Published: December 2007

An Advanced Real-Time Information System for Drilling has been under continuous development and rig-site testing since 1986. The objectives of this system are to provide significant increases in drilling efficiency and engineering accuracy while at the same time to enhance operational safety and optimize the data management associated with drilling operations.

Three important attributes distinguish this system from other "real-time" systems either existing or under development. First, the system provides "real-time" engineering models for decision support augmented by a "real-time" expert system. Second, the system can be interfaced with any data acquisition hardware. Third, it addresses a wider range of data analysis and engineering functionality.

This paper describes the concepts, design and capabilities of this system. Additionally, scenarios for its utilization in the field to optimize drilling operations are provided.
Advanced Drilling Technology for the Continental Deep Drilling Program (KTB): Part of International Lithosphere Research
Authors: Rischmüller H. , Chur C. , Engeser B. , Hoffers B. , Sperber A. , Viet T. Tran , Wohlgemuth L.
Published: December 2007

In scientific research drillingf the borehole may be reviewed as an endoscope into the Earth, as it happens to be the case, for example, in the international Ocean Drilling Program (ODP) and the Continental Deep Drilling Program of Germany (KTB). Development of the drilling technology in the last 15 years took place mainly in the two areas of deep and ultradeep drilling, and of horizontal drilling. The impact of big geoscientific research programs on deep drilling technology is remarkable. Scientific drilling projects need intensive and expansive R&D efforts on the one hand and produce an outstanding spin-off on the other hand.

The German Continental Deep Drilling Project (KTB) is part of the international lithosphere research. The two boreholes of the project penetrate crystalline rock from the beginning. The 4,000 m deep pilot hole was drilled from September, 1987 to April, 1989. The ultradeep hole, planned for at least 10,000 m depth, started being drilled in October, 1990. The pilot hole was drilled by applying a large diameter thin kerf wire line coring technology, which was improved to a high extent during drilling. A newly developed synthetic clay based mud has been used succesfully. For ultradeep drilling, a straight vertical wellbore trajectory is a must, to minimize drag, torque, and wear. To obtain a vertical wellbore course, active vertical drilling systems were developed and for the first time successfully utilized at the KTB. A new heavy, technologically advanced drilling rig has been constructed and is working satisfactorily.
Preacquisition/Predivestiture Environmental Auditing
Authors: Holliday G. H.
Published: December 2007

United States Congress passed stringent environmental statutes which Environmental Protection Agency [EPA] implemented via regulations. The statutes and regulations can mandate costly remediation action on property owners, whether the owner caused the environmental problem or not.

Accordingly, financing of property acquisitions is hampered and, in some cases, made impossible by environmental liabilities found on the property. Thus, financial institutions require preacquisition audits [environmental site assessments] of properties prior to funding. This paper discusses the use of preacquisition audits by sellers, purchasers and financial institutions and some of the findings associated with the audits.
Transient Rate Behavior of Finite-Conductivity Asymmetrically Fractured Wells Producing at Constant Pressure
Authors: Resurreicão C. E. S. , Fernando R.
Published: December 2007

The transient rate behavior of finite-conductivity asymmetrically fractured wells producing at constant pressure is presented in this work. A new semi-analytical solution is obtained by means of the Green’s functions method. Two sets of type curves are developed: log-log curves of l/qwD versus tDxf, intended for rate performance forecasting, and log-log curves of (1/qwD)/(2∂(1/qwD)∂ln tDxf) versus CfD2tDxf, for use in fracture characterization. The various transient flow periods are documented.

Asymmetry is measured by the parameter a, which varies from zero, in the symmetric case, to one, in the case of a well located at the tip of the fracture. Analysis of results indicate that the occurrence and duration of the bilinear flow period is greatly influenced by the asymmetry of the fracture. It is also found that the late time transient rate behavior of the well is not practically affected by asymmetry when a ≤ 0.4, in the whole range of fracture conductivities examined, 0.1 ≤ CfD ≤ ∞. No effects are either evidenced when CfD is larger than approximately 30. Correlations to calculate pseudo-skin factors caused by fracture asymmetry are provided.

An example of application is included to illustrate the use of the type curves for fracture characterization and for production forecasting of the well.
Nonisothermal Unsteady Gas Flow in a Coupled Reservoir-Wellbore System
Authors: Dias S. G. , Bannwart A. C. , Serra K. V.
Published: December 2007

The objective of this work is to investigate the behavior of a coupled wellbore-gas-reservoir system. Initially, the system is at static conditions and may flow at constant surface rate. Non-isothermal flow is considered in the reservoir and in the tubing string. The partial differential equations and auxiliary conditions which govern the flow in the reservoir are coupled with the wellbore equations - modified by the method of characteristics - using a finite difference scheme. Results of pressure and temperature versus time can be displayed in many different positions. Particularly, the downhole wellbore flowing pressure, usually used in well test analysis, is investigated in depth. A damaged region around the well is considered. Comparison with isothermal systems showed that for long-time flow regimes the conventional semilog analysis is of good accuracy. However, for short-time analysis influenced by wellbore storage significant errors may occur which depend upon the flow parameters and thermal properties of the system.
Modeling Reservoir Heterogeneity in a Fluvial Sandstone: The Gypsy Sandstone of Oklahoma
Authors: O’Meara D. J. , Haynes B. , Doyle J. D. , Sweet M. L. , Langlais V.
Published: December 2007

Reservoir simulation models based on detailed outcrop description provide a means to evaluate the importance of various types of heterogeneity on reservoir performance. This study models tracer flow in a multistoried fluvial sequence, the Pennsylvanian Gypsy sandstone. To better understand the effects of heterogeneity on a subsurface fluvial reservoir, three-dimensional reservoir simulation models were constructed incorporating information from correlative rocks which outcrop fifteen miles from the subsurface site. The heterogeneity considered in this study is the higher-order architecture of the Gypsy i.e. its channel sandbody configuration.

At the five acre subsurface site, six wells penetrate the Gypsy from 890 ft to 1000 ft measured depth and encounter a depositionally similar fluvial sequence as at outcrop. The wells comprise an inverted five spot with one observation well. Within this site, Gypsy net sandstone varies from 27 ft to 60 ft. Cores indicate that the number of channel sandbodies varies from three to as many as six. Gypsy channel sandbodies can be subdivided into three intervals primarily on correlation of laterally continuous mudstone and siltstone bodies. Within these intervals, correlation of individual channel sandbodies is uncertain.

Due to uncertainty in channel sandbody distribution, the general approach is to develop multiple reservoir models. Each of these models honors well data but differ in configuration of channel sandbody orientation. However, for each, interpretation of channel sandbody configuration is constrained by information on channel patterns from the outcrop and by local net sandstone trends surrounding the subsurface site.
Scale of Heterogeneity and Fluid Flow Response in Carbonate Ramp Reservoirs: San Andres Outcrop, Algerita Escarpment, New Mexico
Authors: Lucia F. J. , Senger R. K. , Fogg G. E. , Kerans C. , Kasap E.
Published: December 2007

Regional to interwell scales of heterogeneity are exposed in the San Andres outcrops along the Algerita Escarpment in the Guadalupe Mountains of New Mexico. The regional strati-graphic framework is composed of five sequences: a lower to middle San Andres sequence and four upper San Andres sequences. Each sequence is composed of systems tracts that contain a number of parasequences. Stacking patterns of parasequences and of fades and rock-fabric successions within parasequences are systematic and provide the necessary geologic framework for petrophysical quantification of geologic models.

Detailed geologic mapping at the interwell scale in a 2,500-ft-long and 160-ft-high outcrop of the basal upper San Andres sequence in a ramp-crest facies tract shows a geologic model composed of nine shoaling-upward parasequences 10 to 40 ft thick. The parasequences are composed of vertical and lateral successions of dolomitized mud-dominated to gram-dominated rock fabrics. Low permeability mudstones and wackestones, typically found at the base of parasequences, display variable degrees of lateral continuity. High permeability is restricted to grain-dominated packstones and grainstones containing inter-granular porosity that are typically found at the top of parasequences, although mud-dominated packstones and wackestone may also occur at the top of parasequences. Some parasequences are capped by tidal-flat facies which are considered to be tight by analogy with subsurface tidal flat facies. The grainstones of parasequence 7 are unique having high volumes of moldic (separate-vug) porosity and anomalously low permeability values.
Pressure Buildup Testing as an Aid in Well Stimulation: Case History
Authors: Robinson J. C. , Chu W-C. , Woods M. E. , Hutchison H. W.
Published: December 2007

Pressure transient testing and stimulation treatment programs are presented for four development/exploratory wells located in the Sand Dunes Field in Wyoming’s Powder River Basin. While pressure buildup tests conducted during initial completion yielded relatively high permeabilities and severe skin for all but the initial well, core analyses yielded much lower permeabilities and suggested low susceptibility to damage. The core data were discounted, and the buildup test data were relied upon to design small hydraulic fracture treatments to overcome suspected near-wellbore damage. As a result of the treatments, significant increases in productivity occurred which verified the buildup interpretation.

For all four wells, stimulation treatment data and pre-and post-stimulation buildup test analyses are presented. Application of the pressure derivative analysis technique is demonstrated. Through comparison of pressure responses in damaged and improved systems, qualitative as well as conventional quantitative transient test analysis techniques are presented.

The utility of pressure buildup testing for identifying stimulation candidates and providing reliable fracture design data is illustrated. Relying on core data in this field would have resulted in inappropriately designed, less cost-effective hydraulic fracture treatments, and serious underestimation of production potential. The effectiveness of small hydraulic fracturing treatments designed solely to penetrate extremely high skin is demonstrated.
The Value of Reservoir Test Systems (Exploratory Phase) in High-Cost Offshore Areas
Authors: Allison M. F.
Published: December 2007

Offshore projects can be very expensive and risky, especially in deep waters now being explored. This analysis was performed to determine the benefits which would be realized from extended reservoir testing of offshore prospects in the Gulf of Mexico prior to committing to full field development. The analysis investigates whether extended testing is beneficial where development costs are high (over ± $250MM) and possibly very risky.

When large reserves are discovered, will the expense of extended testing be justified? To determine this, test objectives are established. The expected production rates, reservoir size, and facilities needs are considered. Then a risk analysis of four specific test systems is performed to determine how valuable each would be in terms of reducing economic risk. These test systems alone can be very expensive, so the cost of each system must be justified by quantifying its value using risk analysis. Two examples are used to conclude that unless development costs are extremely high, elaborate and costly test systems cannot be justified a majority of the time, but the appropriate test system should be used in proportion to the investment.

This evaluation was first proposed to determine specific design criteria and objectives of extended tests in deep water prospects. Four specific test systems were considered:
A Better Environmental Management System
Authors: Jennett L. E.
Published: December 2007

This presentation will address how to organize and strengthen a company-wide environmental program, how to market the issue internally and how to define and implement accountability in the field. Long range planning for environmental management for the next decade will be discussed. The data for the recommendations was obtained from experience in developing a management program for oilfield service operations as well as interviews with different companies on the success and failures of corporate programs.
A New Technique for Servicing Horizontal Wells
Authors: Tailby R. J. , Yonker J. H. , Pearce J. L.
Published: December 2007

The drilling of horizontal wells is accepted and well-known technology. Many of them have been completed specifically as horizontal wells, but few have been subsequently serviced to their full advantage. This paper presents a completion method and maintenance technique that allows the operator control of individual zones in a long horizontal well. The technique has been prototype tested and shown to be feasible for most basic well operations.
Thru-Tubing Inflatable Workover Systems
Authors: Coronado M. P. , Mody R. K. , Craig G. C.
Published: December 2007

Recent technological advances in inflatable packing element design has allowed non-conventional workover techniques to be accomplished through the production tubing. The improved capabilities of these elements, coupled with new tool designs allowing workovers to be completed with coiled tubing or electric wireline, has seen growing applications. These workovers include, selective and zonal chemical treatments, temporary and permanent plugback operations, intermediate zone blankoff, production and injection flow profile modifications and formation fracturing. They are completed without pulling the production tubing from the well, and thus do not require a rig on the well. Since these tools are snubbed in the well with coiled tubing or electric wireline, thus eliminating the need to kill the well, heavy weight kill fluids, which may cause formation damage, are not required. These tools have been designed to operate with hydraulic pressure and workstring tension within the coiled tubing limitations.

The advancement of this technology has led to a major cost saving alternative to conventional rig workover techniques. The recent improvements made in this equipment has substantially improved the capabilities and reliability of these methods. Major operating companies, utilizing these methods, have realized substantial cost savings in their workover programs.

This equipment has been designed to run through major sizes of production tubing and set in the larger production casing below. The inflatable elements have the capability of being set in casing diameters over three times their run-in diameter. The tools may also be utilized in wells with much higher temperatures than previous technology allowed.

This paper outlines the development of these Thru-Tubing systems and application techniques that have been developed as a result of their field use. It discusses case histories of applications using this technology and the resulting increase in well performance. This paper also describes auxiliary equipment that has been developed to allow these tool systems to be used safely on coiled tubing and electric wireline.
The Effect of Temperature on Minifrac Pressure Decline
Authors: Zhu Ding , Hill A. D.
Published: December 2007

This paper will present a mathematical and numerical model to simulate temperature and pressure behavior and their interference including the effect of fracturing fluid compressibility during a minifrac pressure test. The numerical solution and the approximate analytical solution of the Perkins-Kern-Nordgren1,2 (PKN) model were employed to calculate the fracture geometry, namely fracture length, L, and width, w, before shut-in. After shut-in, linear elastic theory was used to calculate the fracture width from simulated pressure.

The results of the model indicate that the fracture temperature changes significantly during a minifrac test, and the pressure is higher and declines at a slower rate for a compressible fluid compared with an incompressible fluid. The fluid loss coefficient estimated from the pressure decline by the standard analysis will be low if the fluid is compressible. This effect tends to be more severe if the fluid is confined (i.e., the fluid loss coefficient is low). In extreme cases of a highly compressible fluid and a low fluid loss coefficient, the model predicts that pressure can actually increase after shut-in. Most importantly, it is observed from this work that the error in estimating the fluid loss coefficient, using the standard analysis, decreases when shut-in time increases. Therefore, the error in estimating the fluid loss coefficient can be minimized by using pressure data from later in the shut-in period.
Modelling Steam-Assisted Gravity Drainage Process in the UTF Pilot Project
Authors: Siu A. L. , Nghiem L. X. , Gittins S. D. , Nzekwu B. I. , Redford D. A.
Published: December 2007

The Underground Test Facility is designed to test the application of the steam-assisted gravity drainage process for the in situ recovery of bitumen, using horizontal wells drilled from tunnels below the pay zone.

This paper presents a history match of the early injection and production data from the first well pair drilled in the pilot project. The field data showed high oil recoveries and large well head differentials between the injection pressure and the production pressure. The wells were 150 m long, with 93 m inclined and 57 m horizontal.

The history match was performed with a coupled reservoir / wellbore simulator. The wellbore equations take into account frictional and hydrostatic pressure drops, as well as the heat transfer between tubing flow and annulus flow

Simulation results indicated that most of the pressure drop occurred in the injection tubing. The substantial pressure drop (650 kPa) even in this short well implies that frictional pressure drop calculations should be included in designing longer wells for commercial projects.

The presence of shale streaks between the wells delayed the development of the steam chamber locally, and reduced the simulated bitumen production rates.
Engineering Training -- The University Viewpoint
Authors: Miller Frank G.
Published: December 2007

1961 California Regional Meeting, Bakersfield, Nov. 2–3, 1961

We have one overriding problem in petroleum engineering education today. That problem is how to attract sufficient freshman students of high caliber.

There are some apparent reasons for this, and some potential solutions which I should like to propose. That there are many other ways to get at the problem I have no doubt; it is my primary purpose here to delineate the problem and, hopefully, to stir some interest in solving it.

First, let me point out that there seems to be reasonable agreement among industry, government, and the educational world on just what sort of graduates ought to be coming out of our petroleum engineering curricula. That we need leadership in our newcomers is plain; we also agree that this leadership must come from a combination of talents, primarily two: sound technical training, foundational for as far as the individual cans advance in petroleum engineering, and breadth of view, so that the individual does not become bogged down in a narrow specialization, losing his view of the horizons of this vital field of endeavor.

As far as technical training is concerned, we are sorely pressed. Petroleum engineering has mushroomed in the past decade. One man can not be well informed on all phases of the subject, all techniques. Indeed, it is a monumental task to keep abreast of the vast outpourings of literature in even one phase.
Reservoir Gas Management in the Brae Area of the North Sea
Authors: Phillips I. C.
Published: December 2007

ABSTRACT AND SUMMARY

This paper traces the development of a group of North Sea oil and gas condensate fields, known as the Brae Area, highlighting the considerable gas management challenges.

South Brae, a black oil field, was first on production in 1983. Approximately 40 Bcf (1.1 × 109 m3) of associated sour gas had to be temporarily stored in the reservoir, creating reservoir management complications as the gas cap has fingered downdip to producing wells, and calcium carbonate scale formation has been exacerbated.

Early in 1988 came North Brae, a gas condensate field developed by gas cycling. Along with residual North Brae gas, the gas temporarily stored in South Brae is injected into the reservoir, to enhance pressure maintenance. The liquid recovery benefits of this development technique are examined.

In 1989, Central Brae, a small oil field similar to South Brae, was developed as a subsea satellite to South Brae. Its gas is also used to enhance North Brae liquid recovery.

The recently approved East Brae field is another giant gas condensate reservoir, due onstream in 1993. This field will also be developed by gas cycling, using some

North Brae gas to enhance pressure maintenance. The paper examines the inter-relationship between gas sales, availability of gas for injection into East Brae (from Brae and other fields) and the degree of pressure maintenance (and hence liquid recovery) anticipated for East Brae.
A Practical Approach to Original Gas-In-Place Estimation: Development of the South Wilburton Field
Authors: Guardia M. A. , Hackney R. M.
Published: December 2007

Based on actual field data from the South Wilburton field in eastern Oklahoma, this paper presents an approach to original gas in place (OGIP) estimation in gas fields during early development. This approach integrates material balance and Fetkovich decline curve analysis, both classical techniques. These classical techniques are enhanced with modern digital tools such as digital recorders and microcomputers, which in many cases eliminate the requirement for lengthy shut-ins and extensive manipulation and filtering of data. Thus, OGIP estimates can be arrived at quickly and in a practical manner during the development of a new field with confidence stemming from convergence of the two techniques. This allows the working interest owner to reassess and modify developmental strategies and play participation. The approach has been utilized in the development of the South Wilburton field and has assisted developmental decision making.
North Sea Chalk Reservoirs: An Appealing Target for Horizontal Wells?
Authors: Selvig A. , Kossack C. A.
Published: December 2007

North Sea chalk reservoirs are characterized by thick formations, low kv/kh-ratios and a low to medium degree of fracturing. Primary recoveries are generally low, in the range of 15-20%. Utilization of horizontal wells could be an efficient tool to increase production rates and improve recoveries from these fields.

A comparative dual porosity reservoir simulation study of horizontal and vertical wells in a North Sea naturally fractured chalk reservoir has been performed. The numerical results are compared to single phase, analytical solutions to investigate the validity of the latter approach. A future strategy for the application of horizontal wells in these fields is also discussed.

The study shows that analytical approaches are valid only for initial screening purposes. To ensure an improved productivity, horizontal wellbore sections should be drilled as long as possible (> 600 m) to maximize the benefit of the steeply dipping natural fracture pattern present in the fields. Numerical results are presented which identify the sensitivity of the horizontal well performance to key properties of the chalks and to different horizontal well trajectories. The study verifies that horizontal water injectors may enable injection into the low-productivity flank intervals of the chalk reservoirs. In a waterflooding environment, the study shows that horizontal wells can be utilized to minimize water production and thereby sustain the future production from the chalk fields.
Site Selection, Well Planning, and Collision-Avoidance Considerations for the Piper Field Redevelopment
Authors: Taylor D. P. , Johnstone J. A.
Published: December 2007

This paper focuses on the unique problems that were confronted in the process of formulating and implementing a field redevelopment strategy for the Piper field, located in Block 15/17 of the UK North Sea continental shelf. The original Piper A development, including 56 directionally-drilled wells, was lost on 6 July 1988.

The process of selecting a site for the Piper B drilling template is reviewed in the context of:

the proximity of oil and gas pipeline networks serving the Tartan and Claymore platforms; the proximity to subsea wells and debris at the Piper A site; the presence of shallow gas hazards in areas adjacent to the Piper A site; the requirement for directing some replacement wells to the original Piper A targets; the requirement for directing other replacement wells to revised targets.

The drilling of Piper B redevelopment wells in close proximity to the Piper A well cluster requires an unusually rigorous and comprehensive approach to collision avoidance, as the possibility for deep intersection with existing wellbores poses a substantial drilling hazard. Key considerations in the planning and execution of Piper B directional drilling include:

the QC of survey records for the original Piper A wells; the quantification of survey errors in the original Piper A surveys; the assignment of error models for the calculation of positional uncertainty; the generation and maintenance of clearance reports.

To date, six directional wells and two sidetracks have been safely drilled through the Piper B template. Strategic site selection and the highest standards of directional well planning and collision avoidance surveillance have been key ingredients of the ongoing and successful redevelopment of the Piper field.
The VASPS Subsea Separation and Pumping System Applied to Marginal Field Developments
Authors: Baker A. C. , Entress J. H.
Published: December 2007

A series of studies has been undertaken in order to quantify the benefits of various alternatives for the remote production of subsea oil reservoirs. Subsea separation and pumping appears to have significant advantages for remote production over longer distances and particularly in deep water when compared to alternative technologies such as multiphase pumping. The concept involves the separation of gas and liquids at or near the wellhead; with the liquids being pumped in single phase back to shore, or to a remote production facility, and the separated gas flowing back to the same location under wellhead pressure.

A novel separation and pumping system has been conceived which allows an integrated separator and pump to be installed within a conventional 30" conductor in a dummy well. This novel configuration has been called VASPS (Vertical Annular Separation and Pumping System).

A detailed series of hydraulic studies has been undertaken which indicate that the system is capable of producing over distances up to 100 km and that well deliverabilities are significantly enhanced at increased water depths. The authors believe this to be a significant conclusion as there is an increased economic incentive to employ remote subsea production in deep water.
Electrical Submersible Pumps in Subsea Completions
Authors: Scott P. A. , Bowring M. , Coleman B.
Published: December 2007

Electrical Submersible Pumps (ESP's) are being utilised on production platforms as a method of artificial lift for enhanced recovery of oil. With more subsea fields being developed, it is apparent that there will be a demand for this technology in subsea completions. This paper presents the technical issues involved with the installation of ESP's in a subsea completion and describes a system for low cost installation and recovery of the ESP without the requirement to recover the tree. The system utilises existing workover equipment and techniques to provide a safe environment for atubing orcable suspended pump application.
Getting More Out of Drilling Data by Analysis-While-Drilling
Authors: Hytten N. , Havrevold L. , Parigot P.
Published: December 2007

To ensure a safe and optimized drilling operation a number of parameters are continuously monitored through drilling instrumentation systems, MWD and mud logging services. It is up to the driller, the supervisor and the service personnel to analyze these parameters to ensure appropriate actions at the right time throughout the drilling operation.

This task has become more and more demanding due to the increased complexity of the rigs, more difficult drilling conditions and to the increasing number of parameters to be analyzed. Efficient and accurate manual interpretation of the drilling data has become an overwhelming task, and accidents and drilling problems do occur.

The use of a real-time computerized analysis tool for drilling data not only has proven that problems can be detected earlier and hence avoided, but also helps in gaining a better knowledge and understanding of the drilling operation itself, thus improving the overall performance of the operation.

This paper describes an expert system project that has developed into a full commercial service activity (AWD - Analysis While Drilling), now being offered on a worldwide market as a natural extension of today's MWD and mud logging services.
Single-Stack Wellhead System for Jackup Drilling Rig
Authors: Allen D. W. , Kelly J. H. , Omsberg N. P.
Published: December 2007

Phillips Petroleum identified surface wellhead and blowout preventer (BOP) nipple up and nipple down time as an area where significant improvements in safety and savings in rig time could be made on the Audrey field in the southern North Sea UK sector.

With a view toward future use on central North Sea high-temperature, high-pressure exploration and development wells drilled from heavy jack-up rigs, a unitized wellhead system designed for use with a single 18-3/4" BOP stack and a mudline suspension system has been fabricated and used successfully on three development wells on the Audrey Phase II Project and on one exploration well in the southern North Sea.