bluuebunny/crossref_metadata_2025 huggingface dataset:
Reservoir Simulation Applied to the Development of the Magnus Field
Authors: Wood A. R. O.
Published: December 2007

The Magnus field, which is the most northerly developed field in the North Sea, was discovered in 1974. Appraisal drilling during 1976 and 1977 confirmed the presence of a major oil field. The development plan for the Magnus field was approved by the UK Government in December 1978, but was modified in December 1982 following further drilling.

The emplacement of a single steel platform jacket in Magnus was successfully completed in April 1982. First oil production from satellite wells tied to the platform by subsea pipelines, began in August 1983. The water injection system was commissioned in mid 1984 when the first well was turned around to injection. By the end of 1987 a total of 19 development wells had been drilled and the field had produced 195 million stb from estimated reserves of 665 million stb.

This paper describes the reservoir simulation studies conducted to support the development of Magnus. Reservoir simulation played a significant role in designing the original development and modifying it as it has proceeded.
The Evolution and Future Trends in Remote Subsea Maintenance
Authors: Rule D. D. , Rickey W. P.
Published: December 2007

An approach to maintenance has a very fundamental effect on the configuration of a subsea production system and more significantly on the investment and operating costs of that system. As subsea production techniques have developed, a variety of maintenance philosophies have been utilized ranging from dedicated manipulators to ROVs and including either modular and/or component approaches for manifolds and wellheads and TFL or wireline techniques for downhole work.

This paper describes the evolution of these remote techniques from the earliest drilling based approaches to the latest philosophies employing the current generation of commercially available ROVs and workboats of opportunities. It will compare approaches suitable for large multi-well templates as contrasted with the marginal single well satellite and discuss the effects of enhanced reliability versus maintainability. Specific examples, including the Exxon SPS, the Zinc project, and the Exxon Deepwater Integrated Production System (EDIPS) R&D project will be examined.

Future trends are discussed with particular emphasis on the role of ROV versus diver assisted techniques in more moderate water depths.
Multiphase Technology: Is it of Interest for Future Field Developments?
Authors: Furuholt E. M.
Published: December 2007

Multiphase transport systems are already commonly in use for short transport distances or "pleasant" fluids. Application of multiphase technology in field developments may result in 10-40% reduction of investment costs. An unmanned wellhead platform combined with multiphase transport may be equally cost-effective as a subsea system, even in large water depths. The main technical problem areas are discussed and some conslusions are drawn as to the future use of multiphase technology.
Reservoir Modeling of Low-Sinuosity Channel Sands: A Network Approach
Authors: Martin J. H. , Evans A. J. , Raper J. K.
Published: December 2007

The prediction of sand body connectivity at an appraisal stage is vital for planning development of channelised fluvial reservoirs. There has been recently considerable interest in the use of stochastic techniques to model channel sand body distributions. However, several problems are encountered. These include: othe uncertainty of geological input dataothe difficulty of honouring specific well dataothe large number of realisations which may be needed to quantify possible reservoir performance.

We present an alternative deterministic approach, based upon geological modelling, well test analysis and simulation. This relies on the concept that localised channel systems can be expanded to represent an extensive regional network. An areal description of reservoir transmissibility anisotrophy, readily accommodated in conventional reservoir simulation grids, is generated by deriving equivalent channel dimensions and flow characteristics and by defining distances between channel interconnections (repeat lengths).

The technique is applied to the Lower and Middle Statfjord units of a North Sea (Norwegian Sector) field.
Safety Valve Technology for the 1990's
Authors: Going W. S. , Pringle R. E.
Published: December 2007

Searching for petroleum continues to encounter more challenging environments both at surface and subsurface with new demands on equipment. Subsurface safety valves for the 1990's environments are designed and developed today with deep setting capabilities, pressure ratings, material technologies and special features that were unavailable five years ago. This paper presents safety valve designs that are now in operation having no setting depth limit, others solving high- temperature and high pressure problems. An equalizing safety valve that out-lasts workover programs with new technology in an energy dissipation feature is presented as well as a valve to operate in 800°F temper?atures in steam injection applications. A liquid level controlled valve set at packer depth eliminates well killing when tripping pipe for electrical submersible pump repairs.
An Implicit in Pressure and Saturations Approach to Fully Compositional Simulation
Authors: Quandalle P. , Savary D.
Published: December 2007

This paper presents a consistent implicit in pressure and saturations approach for solving the equations of a fully compositional, isothermal, three phase, numerical simulator. It is based on an original choice of the primary variables for which the partial derivatives for all the pertinent equations are written. For three phase flow (oil, gas, and water) of water plus Nc hydrocarbon components, the primary variables are the pressure P, the water and gas saturations Sw and Sg (Sw and one compositional variable Co for single phase oil or gas), plus Nc-2 compositional variables Ci. A given set of Ci variables characterizes the composition of the oil and gas phases in thermodynamic equilibrium at pressure P, in the Nc component system. Their choice as well as their use with a cubic equation of state are discussed in the paper.

This new approach is supported by a simulation test and is shown to be a suitable compromise between the explicit scheme, which lacks numerical stability, and the fully implicit scheme for which computer time and memory requirements may be prohibitive as the number of hydrocarbon components increases.
Two Models for the Waterflooding of Naturally Fractured Reservoirs
Authors: Douglas J. , Arbogast T. , Purdue U. , Leme P. J. Paes
Published: December 2007

Two models are described to simulate the waterflooding of a naturally fractured reservoir. The first is the relatively standard double porosity model in which the matrix is a distributed source to the fracture system. We explicitly describe the influence of the fracture system on the matrix by imposing the proper boundary conditions on the matrix equations. The second model is a limit form of this model for small matrix blocks. It assumes a capillary equilibrium between the matrix and fracture systems. Finite difference procedures are given for these models. These procedures completely separate the matrix block calculations from the fracture calculations. Numerical results are presented to illustrate and contrast the two models.
Introductory Work in Scale Inhibitor Squeeze Performance: Core Tests and Field Results
Authors: King G. E. , Warden S. L.
Published: December 2007

The occurrence of calcium sulfate scale in wells has recently become a sporadic major problem in producing wells in some CO2 floods.1 The problem has also been observed in wells where a potential scaling factor exists and the produced water has more than a fraction of a percent of carbon dioxide gas. Where calcium ion and sulfate ion concentrations are sufficiently large, accelerated deposition of calcium sulfate has been seen in the CO2 floods. Deposition occurs most frequently on pumps and where outgassing of CO2 or turbulence is involved.2

This paper reports the results of a study to determine the cause of accelerated formation of calcium sulfate scale in CO2 environments and find scale inhibitors which can be used to prevent precipitation of calcium sulfate. An additional goal of the study was to gain a more complete understanding of factors affecting the inhibitor squeeze process, so that longer squeeze life could be obtained. The data reflects findings of research into factors affecting scale precipitation, scale inhibitor screening tests, and initial results on inhibitor placement and flowback in cores.
The Evaluation of Scale Inhibitors for High BaSO4 Scaling Potential Using a New Tube/Filter Blocking Apparatus
Authors: Schalge A. L. , Dormish F. L.
Published: December 2007

A new and novel tube/filter blocking apparatus was used to evaluate scale inhibitors under dynamic flowing conditions. The apparatus gives reproducible results for high total dissolved solids (tds) brines which contain high barium and sulfate levels. This reproducibility is achieved by balancing the tds levels of the incompatible brines prior to mixing. Inhibitor efficiency as determined by the tube/filter blocking unit compliments those from the traditional static jar test for barium sulfate.

The ability of the inhibitors to prevent barium sulfate formation in the capillary tube and/or filter was measured at various formation water/seawater mixing ratios, inhibitor concentration levels, temperatures, pH values, and CO2 saturation levels.

The instrument is simple to use and requires a minimum amount of operator attention when in use.
Monitoring Sessile Bacteria Contamination and the Associated Corrosion in a West Texas Water Injection System
Authors: Kochelek J. T. , Stone P. J.
Published: December 2007

This McElroy San Andres waterflood involves the commingle and injection of approximately 130,000 barrels per day of San Andres-Grayberg produced water and Hendrick Reef make-up water. After mixing, the water is skimmed and filtered before injection. Although the produced water contains relatively low levels of microbial contamination, the Hendrick Reef water is severely contaminated and causes contamination throughout the system downstream of the commingle tanks.

Monitoring of the planktonic microbial populations using culture media and ATP photometry had historically indicated levels of aerobes, anaerobes and SRB in the system as high a 1,000,000 bacteria per milliliter of water. However, this level of contamination did not seem to cause any operational problems. The filtration system operated smoothly and hydrogen sulfide was not a concern because of the high levels that naturally occur in the San Andres produced water in this area (700–1000 ppm). Any increase in hydrogen sulfide attributable to SRB activity would not be significant. Corrosion rates, as monitored by weight loss coupons and linear polarization probes, appeared acceptable and averaged somewhere less than 2.0 mils per year.

One problem that did exist within the injection system was an erratic and unexplained increase in total suspended solids in the water at the injection wells. The levels were occasionally considerably higher than in the water exiting the water plant. There were also injection difficulties in some of the wells. The solids that collected at the injection wells were most often identified as iron sulfide and paraffin with trace levels of calcium carbonate and calcium sulfate.

This paper will present information gathered regarding the use of probes designed to measure sessile microbial activity and the associated underdeposit corrosion. It will also address the analysis of wellhead deposits from the waterflood injection system and the effect of fluid velocities on deposition rates. A final discussion will involve some measures for possible control of the problem.
Phase Behavior and Solution Properties of Ethoxylated Anionic Surfactants
Authors: Skauge A. , Palmgren O.
Published: December 2007

The surfactant class of ethoxylated anionics have been tested by measurements of solubility in brine and phase behavior in mixtures of NaCl brine and heptane at a WOR=2. The influence of changes in the lipophilic structure or degree of ethoxylation on the formation of multi-phase microemulsions is studied. In this paper we have studied alkyl- and alkylbenzene- ethoxy sulfonates with different chain length, branching and degree of ethoxylation. Nonylbenzene and dodecylbenzene surfactants are tested with both ethoxy sulfonate and ethoxy methylcarboxylate as the hydrophilic head group.

The solubility of the ethoxylated anionics in brine equivalent to seawater salinity, is characterized by the surfactant activity in solution at 22°C and for some surfactants also by the minimum cosolvent requirement. Phase behavior studies were conducted at 90°C. The optimal salinity and solubilization parameter at optimum was measured for all the 46 different surfactants at a given set of conditions.
The Role of the Engineer as a Citizen
Authors: Clewell D.H.
Published: December 2007

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

This paper was prepared for the 42nd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Oct. 1–4, 1967. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

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

Opportunities for the engineer to exercise his responsibilities as a citizen are better than ever before. With the advent of the Industrial Revolution, the engineer became so influential that, rather than merely serving society, he found himself altering the course of society. He also found himself creating new problems in the course of solving existing ones. At the same time, the engineer has had to adapt to an enormous acceleration in the development and application of technology. For individuals and organizations this has meant that change has become a way of life. Today's engineer adapts to change and serves society better by solving problems through systems engineering. Systems may be industrial — transportation, for example, or geographic, such as a large urban complex. A new problem of the urban system is environmental pollution, and it is a problem susceptible of solution by a systems engineering approach. Pollution from the internal combustion engine, a significant part of the problem, may ultimately be eliminated through application of a systems approach involving both fuel and engine. A number of oil and automotive companies are involved in programs to accomplish this purpose. These programs are prime examples of opportunities for the engineer to practice good citizenship.
The Effectiveness of Acid Fractures and Their Production Behavior
Authors: Ben-Naceur K. , Economides Michael J.
Published: December 2007

Acid fracturing has been a widely used stimulation technique for carbonate reservoirs. While the etching action of the acid would imply an open fracture (with infinite conductivity), the strength of the reservoir rock leads to a significant reduction of the apparent conductivity after closure. In addition, acid fractures are invariably shorter than propped fractures as a result of acid spending patterns and the creation of "wormholes". Consequently, acid fractures are not automatically indicated for all carbonate formations. Instead, a comparison of the production performance of both acid and propped fractures is always necessary.

This paper presents an outline of the propagation mechanism of acid fractures including reaction kinetics and fluid leakoff, and the resulting penetration. Upon closure, the impact of the effective stress upon fracture conductivity is shown using a compilation of published data. The time dependency of the effective stress around the fracture is quantified along with its influence on the production performance using a poroelastic model. Dimensionless cumulative production type curves are given for a range of fracture in-situ conductivities (for propped fractures), and the formation effective stress (for acidized fractures). A comparison of this performance leads to a correlation between propped fracture conductivity and formation effective stress to produce a desired cumulative production within the same time period.

For a given carbonate formation and a given effective stress, a comparison of expected performance leads to a relationship between fracture conductivity and the ratio of the lengths of a propped and an acid fracture. This allows the choice of the appropriate stimulation treatment. Additional effects, such as conductivity variation along the fracture resulting from nonhomogeneous etching profiles and wormhole development, are examined.
The Evaluation and Optimization of Hydraulic Fracturing Treatments for the Big Injun Formation in West Virginia
Authors: Aminian K. , Ameri S. , Bright D. , Yost A. B.
Published: December 2007

Most gas wells which are completed in low permeability (tight) formations of the Appalachian Basin, such as Big Injun, require stimulation to achieve commercial production. The general responsiveness of these formations to a certain set of the stimulation treatments design parameters remains uncertain. Although the stimulation treatments have enhanced the production, the question that needs to be answered is whether the treatment designs are simply standard approaches based on past practices or they represent the optimum designs.

The stimulation and production data from a number of Big Injun wells in West Virginia have been collected and analyzed in order to develop the optimum design guidelines for successful applications. The production data were analyzed with the aid of production decline type curve to establish basic reservoir parameters. A commercial simulator and stimulation data were then utilized to match the production history in order to evaluate the formation characteristics. The results of history matching were then utilized to optimize the treatments on each well. Cost analyses were subsequently performed to select the most economic treatment. The results of this preliminary study indicated that the optimum treatment designs based on the reservoir parameters can further improve the economic production. The general guidelines have been established for more effective and economical fracturing treatment for the Big Injun Formation.
Gas Production Strategies for Devonian/Mississippian Clastics of the Appalachian Basin: A Case Study in the Plateau Region of Virginia
Authors: Kuuskraa V. A. , Kelafant J. R.
Published: December 2007

The Devonian/Mississippian Age clastics continue to be a major source of natural gas production in the Appalachian Basin. However, the generally low productivity of these sands and shales calls for innovative development strategies, particularly during this period of low gas prices. This paper examines a series of such alternative development strategies, including drilling for deeper pay, using improved well logging to better identify productive net pay, and larger stimulation treatments.

The plateau region of Southwest Virginia was selected as a case study for three reasons. First, gas production in this area has increased four-fold over the past five years (4 Bcf in 1983 vs. 20 Bcf in 1987). Second, drilling activity was up 50% in 1986 counter to a sharp drop for the basin as a whole. Third, by multiply completing and properly stimulating wells in the full tight gas/Devonian shale sequence, this area offers the promise of attractive gas recoveries per well.

Average reservoir parameters were derived for the study area to enable simulations to be run. Past and current drilling, completion, and operating practices were then analyzed to determine average cumulative 20-year productions in the region. After representative reservoir properties and completion practices were established, the effects of larger stimulations and improved pay selection were simulated. The results indicate that current reserves per well can be almost doubled using improved pay selection, larger stimulations and multiple well completions.
Rheological Characterization of Borate Crosslinked Fracturing Fluids Employing a Simulated Field Procedure
Authors: Shah S. N. , Harris P. C. , Tan H. C.
Published: December 2007

To design a successful hydraulic fracturing treatment employing borate crosslinked gels, accurate measurements of rheological properties of such fluids are required. Rheological characterization of borate crosslinked gels has been difficult with the rotational type viscometer. In this paper, we present the rheological properties of various borate crosslinked fluids employing a new procedure which simulates field pumping conditions, i.e. crosslinking the fluid on the fly, and fluid flow down tubing or casing and in the fracture.

The effects of fluid pH, gelling agent concentration, type of gelling agent, and temperature on the rheological properties of fluids have been measured. It was found that these parameters have significant effect on the final viscosity of gel in the fracture.

From the laboratory test data, correlations to estimate friction pressures in field size tubulars have been developed. It is also shown that in conjunction with field calibrations, these correlations can aid in accurate prediction of friction pressure of borate crosslinked fluids.
Factors Controlling Occurrence of Morrow and Cherokee Sands and Their Relation to Production in the Anadarko Basin
Authors: Forgotson James M.
Published: December 2007

Stratigraphic and lithologic data from 1200 wells in the panhandle areas of Texas and Oklahoma and 600 wells in northwestern Oklahoma were recorded in a form suitable for computer processing. Maps were prepared for each of three subdivisions of the Morrow in the Panhandle area and for each of seven operational units selected to subdivided the lower Morrow in northwestern Oklahoma. These isopach and quantitative facies maps showing areal variation in thickness and rock types were used in combination with detailed stratigraphic relationships based on electric log correlations to interpret the depositional history and predict areas most favorable for development of porous sandstones.

In the panhandles of Texas and Oklahoma and in northwestern Oklahoma, the Morrow Formation is the basal transgressive predominantly clastic unit of the Pennsylvanian system, unconformably overlying the Mississippian. The upper boundary is delineated by the base of the "Thirteen-finger" limestone, an electric log marker, and the lower boundary by the Pennsylvanian-Mississippian contact. Lower Morrow and basal Cherokee sandstone accumulations correlate closely with the residual structure on the top of the Mississippian unconformity of topography or early Pennsylvanian structural movement on the deposition of these sandstones. Apparently significant structure existed before or developed during deposition of these units. Isopachous and structural data indicate continued activity of these structures throughout Morrow deposition.

Distribution of coarse terrigenous clastics within the predominantly fine terrigenous clastic Morrow Formation suggests one source of sand west of the Panhandle area and a second source on the northeast. The Wichita-Amarillo uplift south of the depositional basin began to supply coarse clastic material during deposition of the upper Morrow unit. In the Panhandle area, widespread sheet sandstone and sandstone beds at parallel trends of early Morrow shorelines are interpreted to be near shore marine sediments deposited as the early Morrow sea overlaps onto the shelf areas. The thin lenticular upper Morrow sandstone bodies are interpreted as having been deposited by a complex stream system flowing southeast toward the basin axis.
Valuation of Oil and Gas Reserves by the Comparative Method
Authors: Strevig William E.
Published: December 2007

Valuations of oil and gas reserves are performed in different ways. The purpose, perspective and technique for the process is diverse. This paper will briefly review some concepts for oil and gas reserve valuations, including the advantages and disadvantages of two particular approaches to value, the income and comparative approach. Also included in this discussion are the market place for reserves, some "how to" ideas and conclusions for developing the best possible estimates of reserve values.
How Superconductor Applications will Affect Oil and Gas Demand - an Update
Authors: Starks L. A.
Published: December 2007

Oil and gas companies should and do hedge their reliance on production of petroleum commodities. One hedge is an awareness of technologies that could affect the demand for energy. Thus, oil and gas companies should, at a minimum, monitor the developing applications in superconductivity. These applications have the potential to reduce oil demand an estimated 5% and gas demand an estimated 9% from the levels to which they would otherwise rise.
Fundamental Testing and Production Surveillance
Authors: Merryman C.J.
Published: December 2007

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

This paper was prepared for the 42nd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Oct. 1–4, 1967. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

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

With the changes of automation, increased job responsibilities, greater number of wells per man, and a steadily increasing number of wells under various stages of secondary recovery operations, proper production surveillance has become a major challenge. True, automatic equipment records well production accurately but well test equipment capacity and improvement appraisals still require trained personnel.

Engineering duties and, in many cases, reduced engineering manpower may leave an overall testing program foundering. Reservoir engineers continue to rely on reported field tests to guide future programs and expenditures. It is mandatory that tests not only reflect production but be accompanied with proper data to reflect true well capacity. To insure this level of operation the following program is suggested:

Continuous training and orientation. Complete test procedure. Adequate test facilities.

This program is explained with recommendations for necessary tools and practices.

Introduction

Well testing may be generally defined as a measurement of production during a given time interval, usually twenty-four hours. Tests are required for the many needs of production evaluation and for allowable proration by regulatory bodies. Actually, well tests are the pulse-beat of our industry, the indicator of change and the warning light defining future needs. Accurate tests represent equity at the unit bargaining table, permit efficient scheduling of work and are basic to sound budget estimates. Improved communications have made it possible to have current data available to everyone concerned and well test results play a greater part in decisions than ever before.
A New Concept of Continuous Flow Gas Lift By Multipoint Injection
Authors: Raggio Jerry
Published: December 2007

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

This paper was prepared for the 42nd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Oct.1–4, 1967. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

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

Continuous flow gas lift by single point injection is generally considered to be the most efficient method of lifting fluid from an oil well. However, for points of injection below 4000 feet, a homogeneous mixture of the gas and liquid from the point of injection to the surface is usually not realized in actual field operations. The liquid tends to separate from the gas causing turbulence and/or slippage which results in slug type lift.

This paper is a result of a detailed analysis of four (4) installations designed for continuous flow gas lift by multipoint injection plus three years of numerous field applications. In the absence of accurate flowing pressure surveys on three of the wells, it was necessary to use other means of determining points of injection. However, this was not difficult in most cases because several design changes were required on each well before continuous flow was achieved. Additionally, these were problem gas lift wells prior to the installation of the multipoint designs and the maximum points of injection were known.

The relative merits of multipoint versus single point injection for continuous flow gas lift can only be determined conclusively by extensive experimental work. Nevertheless, the results of the tests conducted thus far, though admittedly limited in scope, do indicate:A variance between flowing pressure gradient predictions based on published curves and actual gradients obtained by multipoint injection.That deeper points of injection and higher rates of production are possible by multipoint injection than was ever before attainable by continuous flow gas lift.
New Results for Pressure Transient Behavior of Hydraulically Fractured Wells
Authors: Wilkinson D. J.
Published: December 2007

A number of new results for pressure transient behavior of hydraulically fractured wells are presented. The fracture is considered to be fully penetrating with the well located at its center, and to be of dimensionless conductivity FD. The solutions are obtained in the Laplace transform domain, and so may be easily combined with wellbore storage. For the case of an infinite conductivity fracture (FD → ∞), it is shown that the exact solution (exhibiting early time linear flow in the formation and late time radial flow) may be written in terms of so-called Painlevé functions; this representation is much more convenient than the Mathieu function solution given in the literature, because the Painlevé function may be easily computed as the solution to a (non-linear) ordinary differential equation. In the case of a low conductivity fracture (FD → 0) the fracture may considered to be infinite in length; in this limit it is shown that the exact solution (exhibiting early time linear flow in the fracture, intermediate time bilinear flow and late time radial flow) may be written in closed form in terms of elementary functions. It is observed that the early time part of this solution is valid even in the case of a high conductivity fracture. By use of the method of matched asymptotics, the above solutions are combined to obtain a new Laplace domain solution which works well for all values of FD and for all times. The solution compares well with numerical results given in the literature, exhibits all known flow regimes, and may be coded very efficiently on a computer.
Pressure Transient Behavior in Multilayer Vertically Fractured Gas Reservoir With Finite Conductivity
Authors: Okoye C. U. , Oshinuga A. D. , Ghalambor A.
Published: December 2007

This paper presents a new model for pressure transient in wells intercepted by finite-conductivity vertical fracture in closed square multilayer double porosity reservoirs. Analytical, semi-analytical and numerical solutions are given. The set of asymptotic analytical solutions are for early, intermediate and late times and can be used to analyze transient pressure data if the flow period is known or can be identified. The general semi-analytical solution is for all times and was used to generate type curves. The numerical solution was used to verify and validate the general purpose semi-analytical solution and vice versa. The two solutions agree within six percent.

The type curves were used to match a set of drawdown pressure data for a tight gas reservoir in order to determine fracture conductivity and fracture half-length. The results of the analysis are in good agreement with published results.

We believe that the model presented in this study may be more appropriate for expressing the pressure transient response in multilayer fractured tight gas reservoirs than the existing model particularly when the fracture conductivity is finite.
A Comparative Study of Future Possible Conventional and Unconventional Gas, Rocky Mountain Region
Authors: Nilson G. J. , Haas M. R. , Kelso B. S.
Published: December 2007

Many studies have been made relative to the gas resource potential of the Rocky Mountain region, but a search of the literature has revealed few forecasts as to what gas may be actually producible under a variety of wellhead price conditions. This study provides such forecasts and shows how the undedicated Rocky Mountain gas resources could compete with the Permian and Anadarko basins in the national gas market.

The principal analytic tool used in this study was a model developed by ICF-Lewin Energy, Inc. entitled "The Oil and Gas Replacement Cost Analysis Model" (REPCO).1 This system provides the user with a resource base that is disaggregated by geographic, depth, resource quality, and certainty that is served by a flexible decision oriented software package. The system was designed to assist producers, pipelines, distribution companies and large-volume industrial consumers to respond to the challenge of changes in the regulatory climate and falling product prices.

The largest single factor on the horizon for the realization of the Rocky's deliverability potential is the Thermal Enhanced Oil Recovery (EOR) market in California. The need there for long term, reliable supplies of natural gas has been the subject of great interest to pipeline companies who are competing for that market. The geographic proximity of the Rocky Mountain region together with the large resource base makes the area the prime candidate for providing that supply.
Innovative Techniques for Converting Old Waterflood Injectors to State-of-the-Art CO2 Injectors
Authors: Bowser P. D. , Corey J. D. , Darr C. D. K. , Caro D. A.
Published: December 2007

The success of a CO2 flood largely depends on the quality of its injection wells. The wells must confine injection to the desired pay intervals and withstand the corrosive nature of CO2 for the life of the flood. These are difficult goals to achieve considering the primary candidates for CO2 flooding are mature waterfloods where the wells may have been in service for forty years or more. Casing and cementing practices of the past were often inadequate for a long waterflood life, and are certainly unacceptable for a long term tertiary recovery project.

This paper describes innovative techniques employed in the MCA Unit, located in southeast New Mexico, for converting old waterflood injection wells into state-of-the-art CO2 injection wells. The solutions developed for the MCA CO2 Project have considerable application to other CO2 projects and can be profitably employed to improve waterflood recovery as well.
New Cement System Improves Bonding in the Stony Creek Field, Williston Basin, North Dakota
Authors: Morris B. V. , Shumaker E. F. , Ramsey L. K.
Published: December 2007

Salt sequences that occur in the Williston Basin pose numerous drilling and completion problems. Probably the most severe of these is the collapse of the casing caused by the plastic flow of the salt. Over the years it has been observed that a high percentage of these collapse problems have occurred in the top part of the washed out salt section. In these cases, a typical bond log showed good-to-excellent bond across the salt with poor-to-no bonding at the top of the salt section where collapse occurred.

This paper describes work done in the Stony Creek Field of North Dakota with the objective of eliminating the area of poor bonding at the top of the washed out salt sections. The Stony Creek Field was discovered in 1987 with the Mission Canyon formation being the primary producing horizon. A new cement system is described which was placed across the primary sections of three wells. Bond logs were run comparing the results of the new cement system to that of a conventionally cemented well. The results showed the new system to be successful in eliminating the bonding problems in the top of the salt zone. To date, the wells have not experienced collapse problems.
Desorption of Hydrocarbons From an Unconsolidated Sand
Authors: Oxford Charles W. , Huntington R.L.
Published: December 2007

Both pressure depletion and constant pressure flow "sweep" methods have been studied for the recovery of some pure hydrocarbons by desorption from an unconsolidated sand.

Several factors which were thought to contribute to the desorption of hydrocarbons have been treated separately. They were [a] rate of gas flow, [b] original liquid saturation, [c] reservoir temperature, and [d] presence of water and brine.

The effect of pressure, size and shape of interfacial surface, presence of other components, and interfacial tension have been treated theoretically. Equations for the calculation of theoretical pressure-specific gravity curves and their limitations are presented.

Pure hydrocarbons, n-hexane and n-heptane, and a pure gas [nitrogen] were employed in most of the experiments. In addition, a run was made with a hydrocarbon condensate as the saturating liquid.

Data and graphs have been presented for desorption of pure hydrocarbons at pressures ranging from 50 psia to 4,000 psia, with liquid saturation of 5 to 25 per cent, water content of 5 to 25 per cent, and withdrawal rates of 0.034 to 0.900 reservoir volumes per minute. Theoretical curves have been shown with the experimentally determined points.

Data and graphs have also been presented for atmospheric sweep studies, together with curves based on equilibrium conditions. Hydrocarbon concentrations of 5.1 per cent to 34 per cent, and sweep velocities of 1.159 to 13.66 reservoir volumes per minute were employed.

Introduction

During the past 20 years, [1932–1952] many condensate reservoirs have been discovered in the United States, particularly in the Gulf Coast region. Most of these reservoirs have been produced by a combination of gas cycling and slow pressure depletion in order to recover the liquefiable components from the single-phase fluids originally existing within the reservoirs.

Although a record of the composition of the produced fluids has been kept on some of these reservoirs, very little laboratory work has been done on small scale replicas so as to obtain some idea of the effect of such variables as fluid flow withdrawal and cycling rates, pressure, temperature, percentage of liquid hydrocarbon and water saturation within the reservoir, etc.
Comparing Openhole Cavity and Cased Hole Hydraulic Fracture Completion Techniques, San Juan Basin, New Mexico
Authors: Logan T. L , Clark W. F. , McBane R. A.
Published: December 2007

Completion technology has evolved significantly since the first San Juan Basin coalbed methane wells drilled in the 1950's. Initially wells were completed openhole, however, hole stability was a major problem in addition to the inability to isolate different coal seams. A cased hole type completion was later adopted utilizing perforations and hydraulic fracture stimulations. Recently openhole type completions are again popular with some San Juan Basin operators, in which a large cavity is created in the coal seams of the openhole interval. The openhole section is then lined with pre-perforated uncemented casing. Both cased hole with fracture stimulations and openhole cavity completion techniques are currently being used in the San Juan Basin at the Northeast Blanco Unit operated by Blackwood and Nichols Company, Ltd. This provides a unique opportunity to compare the techniques to determine which technique is best.
Insights and Analysis From the Rock Creek Project: A Reservoir Engineering Approach
Authors: Zuber M. D. , Boyer C. M. , Schraufnagel R. A. , Saulsberry J.
Published: December 2007

Since 1984, the Gas Research Institute has been conducting field evaluations of coalbed methane technology at the Rock Creek Project site near Birmingham, Alabama. This paper presents and discusses preliminary conclusions based on initial reservoir engineering analysis of data gathered from field experiments performed at Rock Creek.

Major conclusions from the analysis performed to date are 1) post shut-in methane production is not significantly reduced by water influx during normal shut-in periods, 2) long-term methane recovery from a well is not a function of initial water pumping rate, provided the initial rate is above the minimum required to initiate desorption, and 3) well-to-well interference is the primary mechanism for efficient recovery of coalbed methane.

Ongoing reservoir engineering analysis will provide further insights toward characterizing methane production from multi-zone completion wells and establishing a rationale for dewatering coalbed methane wells.
Flow Analysis In Producing Wells
Authors: Curtis M.R.
Published: December 2007

Curtis, M.R., Member AIME, Schlumberger Well Services, Houston, Texas

This paper was prepared for the 42nd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held In Houston. Tex., Oct. 1–4, 1967. Permission to copy Is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

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

Production Logs provide information for downhole flow analysis of producing wells. These flow analyses determine the various amounts, types, and depths of fluid entry into the casing. This information may be used to study a reservoir, to catalogue an initial completion, or to engineer remedial action.

Gradiomanometer and Flowmeter surveys are used to analyze two-phase, bubble-flow production. The average density of the flowing fluids is obtained from the Gradiomanometer; the total flow rate from the Flowmeter.

Two facts complicate mathematical flow analyses. First, the bubbles of the lighter phase travel upwards at a greater velocity than the continuous heavier phase. Second, the down-hole volumetric fractions of the phases are different from surface fractions. It is necessary to consider the slippage velocities and the phase holdups in analyzing the down-hole flow.

Charts have been prepared to provide a simple and fast graphical means of flow analysis. Each individual chart is prepared for a specific casing size, tool size, and slippage velocity. The latter can he estimated with reasonable accuracy from knowledge of the densities of fluids being produced. On the charts, Gradiomanometer and Flowmeter data are used to graphically compute a flow analysis.

The charts may also be used when only a Gradiomanometer is available. In this less accurate application it is assumed that only a single fluid phase enters at any given level, and that a zone without change on the Gradiomanometer is not producing any fluid.

The Gradiomanometer-Flowmeter method of analysis is effective in high-flow-rate oil wells producing gas or water, and in low-to medium-flow-rate gas wells producing oil or water.
Enhancing Borehole Image Data on a High-Resolution PC
Authors: Wong S. A. , Startzman R. A. , Kuo T-B.
Published: December 2007

Because most downhole reservoir evaluation tools are unable to successfully detect very thin bedding, it is difficult to evaluate the production potential of laminated formations and small natural fractures. The availability of logging tools that provide higher data sampling rates has made the study of in-situ, fine-scale formation features possible. Tools such as the Formation MicroScanner* (FMS), Borehole Televiewer (BHTV), and the High-Resolution Dipmeter are able to show images of borehole walls. However, the interpretation of borehole images relies on the quality of the image data presented. Fine-scale formation features such as bedding will not be recognized if the presentation of the images is unclear.

The purpose of this paper is to provide an inexpensive and intuitive way for enhancing and displaying borehole images. The advent of 32-bit microcomputers and windowing software on PC's makes the availability of inexpensive platforms for viewing, analyzing, and interpreting data possible. We have developed a prototype system for image analysis and image processing of FMS and BHTV field data. The software represents the first stage towards a borehole image understanding system.
PLATLOC: A Program for Optimizing Offshore Platform Locations
Authors: Watson W. S. , Mahaffey D. W. , Still J. P. , Taylor R. D.
Published: December 2007

Platform site selection is one of the most important decisions made early in the life of an offshore lease development, impacting not only total cost but also hydrocarbon recovery. We developed a non–statistical computer model which focuses on the critical technical aspects of development optimization.
An Expert System Helps in Formation Recognition
Authors: Mabile C. M. , Hamelin J-P. A. , du Chaffaut B. Amaudric , La Fonta J-G. M.
Published: December 2007

An expert system has been developed to give the driller indications on formation changes by using downhole or surface measurements. In a "user friendly" environment the expert system includes a preprocessor to combine parameters and a 0+ inference engine. Results are displayed with standardized pattern and comments to describe the formation. The many tests performed with this expert system show that the rule base used to describe knowledge stays constant for an oil field.