bluuebunny/crossref_metadata_2025 huggingface dataset:
Internal Corrosion in Submarine Pipelines – Methods of Detection, Mapping of Attacks and Procedures to Predict the Lifetime and Allowable Operating Pressure
Authors: Kristoffersen K. , Taberner D.
Published: December 2007

The paper mentions various factors which influence internal corrosion and how they might be controlled and monitored in submarine pipelines carrying hydro-carbon products. There is a description of factors influencing the choice of inspection areas and of inspection methods. Finally, procedures to estimate the corrosion rate/lifetime and the establishment of the allowable operating pressure are given.
A New Approach for a C-100 Performance Sour Gas Grade
Authors: Greer J. B. , Schneider W. P. , Roberts C. D. , Fisher L. D.
Published: December 2007

Unsuccessful exposure to hydrogen sulfide containing production fluids occurred in API N-80 and P-110 grades in the early 1950's and prompted the development of metallurgically improved and strength restricted C-75, L-80 and C-90 grade tubulars for sour service. As deeper, higher pressure wells were drilled, the need for higher performance grades escalated. For wells deeper than about 17,500 feet, economics justified higher performing quality tubulars, yet C-100 or higher performing tubulars remained unavailable.

Following similar developments in other industries facing a need for higher performing, fracture resistant materials, Lone Star Steel Company has combined advanced metallurgical and processing techniques with ID and OD imperfection removal and cold forming steps to upgrade both dimensional control and steel quality of tubulars. The result is a more conservative approach which conveys C-100 performance for the LSS-95 SSGS grade. A method for statistical analysis of dimensional properties is derived and its relationship to manufacturing process design and product dimensional compliance is presented for plain-end OCTG casing.
A Proposed Completion Method for Deep, High-Pressure, Corrosive Wells
Authors: Glaser M. C. , Roy K. W. , Dunn G. T.
Published: December 2007

This paper describes the development of a completion method for a well in Offshore, Louisiana. This completion was designed and built to handle a corrosive gas up to 20,000 psi at 400 degrees F from depths below 20,000 ft.

Though this well was never completed, all of the equipment was manufactured and the testing completed prior to the well being temporarily plugged and prior to the well being temporarily plugged and abandoned. This completion method resulted in new tools and techniques which will be necessary for similar wells in the future.
Stability Analysis of Miscible Displacement Processes
Authors: Lee Sheng-Tai , Gary Li K.-M. , Culham W. E.
Published: December 2007

This paper presents a linear perturbation analysis of viscosity- and gravity-induced instability in miscible displacement processes. The analysis takes into account the time-dependent behavior of the basic flow solution. It also considers the velocity dependence in the hydrodynamic dispersion expressions. By solving analytically the perturbation equations, the necessary and sufficient conditions for instability in miscible displacement processes are derived. These criteria are related to the well-known Dumore's velocity and to a critical wavelength for finger growth. Furthermore, they are calculated at the most unstable location in the solvent-oil mixing zone. The equations derived then relate quantitatively major process variables to the onset of instability in a miscible displacement process.

Examples are presented to illustrate the applications of the criteria derived. It is shown that as the displacement process proceeds, the injection rate can be gradually increased. Furthermore, for dipping and stratified reservoirs, and for laboratory core experiments, a threshold time can be reached, after which the process is said to be in a state of unconditional stability.

The transverse interlayer mixing is an important variable in smearing the fingers. From a qualitative analysis on the stability of horizontal displacement processes, it is revealed that transverse dispersion is more effective in smearing the fingers than longitudinal dispersion. However, the existence of a dispersed longitudinal mixing zone is necessary for the stabilizing effect of the transverse dispersion to be operative.

Oscillatory instability can occur in a miscible displacement process. It is attributable solely to the existence of a longitudinal wave. The existence of a longitudinal perturbation can further stabilize the displacement process.

For horizontal displacement processes with an adverse mobility ratio and in the absence of a gravitational stabilizing force, transverse dispersion alone is incapable of smearing the fingers for typical reservoir length scales. On the other hand, in the case of laboratory core experiments, the small transverse dimension of the core allows the dispersion mechanism to effectively damp the growth of the fingers, resulting in a stable displacement.
Role of Immobile Phase Saturations in Tertiary Oil Recovery
Authors: Kasraie Mahnaz , Farouq Ali S. M.
Published: December 2007

The presence of an immobile phase – oil, water, or gas – can influence the performance of an oil recovery process, adversely under most conditions. Furthermore, the flood velocity exerts an additional effect on the role of the immobile phase.

The paper discusses the effect of an immobile phase on dispersion in porous media. Specifically, solvent flooding is examined in the context of immobile oil, water, and gas phases. The phase saturations were reduced below the critical values to study an extended saturation range. Also tested was the effect of entrained polymer on dispersive mixing.

Although the studies were primarily conducted in a miscible displacement framework, the results are examined in the context of other recovery methods as well, such as micellar and alkaline flooding. Solvent flooding of very viscous oils is also considered, wherein the dispersion behavior is controlled by the dissolution of an initially immobile oleic phase.

The results obtained show that dispersion in a porous medium tends to decrease in the case of wetting immobile phase. The behavior is opposite if the immobile phase is nonwetting (oil or gas). For wetting phase saturations below the critical, the mixing coefficient first decreases then increases with an increase in saturation. The opposite behavior is observed in the case of nonwetting phase. In all cases the mixing coefficient is rate-dependent, the direction of change being governed by the type and magnitude of the immobile saturation.

The practical implications of the above observations from the point of view of tertiary oil recovery processes are discussed.
Factors Affecting Solvent Slug Size Requirements in Hydrocarbon Miscible Flooding
Authors: Chen Shing-Ming , Allard D. R. , Anli Jun
Published: December 2007

Selecting an optimum solvent slug size is critical in the proper design of a hydrocarbon miscible flood. It has been common practice in the industry to calculate slug size requirements using a dispersion model. However, this method often yields slug sizes that are much smaller than the minimum requirements suggested by many field test results. This paper reviews the assumptions and limitations of the dispersion models and proposes many other important factors which must be taken into account when designing solvent slugs.

More specifically, the paper suggests possible modifications to the dispersion-capacitance model, as it is applied to carbonate reservoirs exhibiting dual porosity. As well, the influence of the following factors on slug requirements is examined: (1) water blocking of solvent at high water saturations, (2) residual solvent within and behind the solvent bank, and (3) the multiple-contact miscible displacement process.
A Predictive Model for Water and Polymer Flooding
Authors: Jones R. S. , Pope G. A. , Ford H. J. , Lake L. W.
Published: December 2007

A predictive model (PM) has been developed for water and polymer flooding for use in screening studies and feasibility analysis. The PM requires only a fraction of the computing time of numerical simulators, but includes most of the phenomena which affect flood performance. This is accomplished by combining a two-dimensional crosssectional model (using vertical equilibrium), with areal sweep correlations, and injectivity functions which gives results (oil rate versus time) which are suitable for economic analysis.

The paper presents validations of the PM against simulator, analytical, and field results. A brief sensitivity analysis concludes the paper.
Evaluation of CO2 Flood Performance, Springer "A" Sand, NE Purdy Unit, Garvin County, OK
Authors: Fox M. J. , Simlote V. N. , Beaty W. G.
Published: December 2007

This paper describes and presents results of an overall program of monitoring and evaluation of a carbon dioxide flood being conducted in the Northeast Purdy Springer "A" Sand Unit in Garvin County, Oklahoma. The response of one specific five-spot pattern is described through detailed reservoir simulation utilizing data from observation well logging, pressure transient analysis, carbon dioxide injection profiling, sampling of produced fluids, and monitoring of production rates. A reservoir description satisfying primary, secondary and tertiary performance is also described in detail.

History matching of the carbon dioxide flood performance is being utilized to define the effects on reservoir performance of waterblocking, viscous fingering and residual oil saturation to carbon dioxide flooding. These parameters are not laboratory defined. Sensitivity work was conducted to design the best process.

In-situ saturation changes obtained from an observation well logging program are presented and correlated with model calculated saturation changes and indicate that oil is being mobilized as predicted by the simulator. A comparison of carbon dioxide injection profiles to water injection profiles and the results of observation well logging indicates that the carbon dioxide is flooding certain reservoir layers that were not waterflooded. The model reservoir description was modified to include these layers. Results of compositional analyses of produced fluids are presented.
Chateaurenard Field Test Recovery Mechanisms and Interpretation
Authors: Bourdarot Gilles , Sardin Michel , Putz Antide
Published: December 2007

The CHATEAURENARD micellar/polymer field test was conducted between 1976 and 1980 in the south part of the PARIS Bassin. Pilot design, operations and oil production results have already been presented. We present a detailled analysis of the effluents. It appears that surfactant, most of wich remained trapped in the reservoir, is associated with calcium in the oil when produced, as a result of sodium exchange with the calcium associated with the clay in the reservoir sand. Supporting phase studies and floods through sandpacks are presented to quantify this cation exchange and investigate its influence on oil recovery and phase trapping.
The Relative Permeability Function for Two-Phase Flow in Porous Media: Effect of Capillary Number
Authors: Ramakrishnan T. S. , Wasan D. T.
Published: December 2007

Expressions for both drainage and imbibition relative permeabilities for wetting and nonwetting phases have been derived using the cut and random rejoin approach. The pore structure is modeled by using information about the pore size distribution that determines capillary pressure. The nonwetting phase is considered to be present as both connected and disconnected fluid. The appropriate permeability equations are then obtained by considering laminar flow equations for the randomly formed pore throat constrictions. Based on the classical percolation theory for mobilization of disconnected nonwetting phase and data on entrapment of connected nonwetting phase, the relative permeability equations are presented for varying capillary numbers.

The theoretical results of relative permeability for both natural and synthetic porous media agree with the available experimental data for drainage as well as imbitition. Moreover, the limited experimental data for high capillary numbers corroborate the basic considerations of the model.

The injection or in situ generation of surface active agents alters the fractional flow of oil in a reservoir due to an increase in the (local) capillary number. This change in the fractional flow is also dependent upon the initial connected and disconnected nonwetting phase saturations. The present approach takes both of these factors into account and therefore can be put to direct use in modeling surfactant and caustic flooding processes.
Concepts Pertaining to Reservoir Pretreatment for Chemical Flooding
Authors: Meyers K. O. , Salter S. J.
Published: December 2007

In this paper, a model is proposed which details how preflush chemicals in the aqueous phase are transported through an oil-containing porous media. The example preflush process chosen is monovalent/divalent, cation-exchange. Initially, the chemistry of ion exchange is summarized. This is followed by a careful system of core characterization designed to determine as many of the ion-exchange characteristics of the chosen porous media as possible, independent from specific preflush experiments. A series of preflush experiments, run with zero and waterflood residual oil saturations are then described. Finally, a mathematical model is proposed to describe the preflush process. This model is solved numerically and compared with the experimental results. The model is shown to be successful in both a matching and predicting mode over a wide variety of conditions. This success verifies many of the ion-exchange and flow concepts used in formulating the model.
Enhanced Oil Recovery by Nitrogen Injection: The Effect of Increased Temperature and the Amount of Gas in Solution
Authors: Alcocer C. F. , Menzie D. E.
Published: December 2007

The results of laboratory research conducted to study displacement of crude oil by high-pressure nitrogen injection are presented in this paper. The objectives of this research were to study the effect of temperature and original gas-oil ratio in solution on crude oil recovery and the miscibility process in high-pressure (H-P) nitrogen injection. Also in addition, the effectiveness of nitrogen injection after waterflooding and the effect of nitrogen-driven propane slugs was examined. Nine experimental tests were performed using crude oil of 42.3° API recombined with natural gas. The experimental tests were made using two temperatures (70°F and 120°F) and three gas-oil ratios in solution (575 SCF/STB, 400 SCF/STB and 200 SCF/STB). The reservoir model used was a stainless steel tube 125 feet long and 0.435 inches in diameter, packed with sand consolidated to give an average permeability of 910 md. The model was provided with five sampling valves to collect vapor samples. The vapor samples were analyzed by using a gas chromatograph. A temperature control system was built based on the results obtained from a heat transfer mathematical model specifically prepared for this research. The results obtained in this study suggest very strongly that crude oil recovery and miscibility in this kind of oil depend on temperature and oil-gas ratio in solution. Multiple-regression equations to predict crude oil recovery using temperature and gas-oil ration in solution were developed based on the experimental data.
Diagnostic Tools for Mapping EOR Processes
Authors: Wayland J. R. , Leighton A. J.
Published: December 2007

Success of an EOR process is often dependent upon determining the extent of oil desaturation in an area and early discovery of detrimental flow paths by injected fluids. Early detection of these, and alteration of production and injection schedules (and other measures) can reduce costly bypassing and production of excess displacing fluids and can maximize oil recovery and project economics. The criteria given for selection of the best diagnostic tool at project inception can reduce costly and ineffective trials and produce more useful information at lower cost. This paper presents the essential principles and significant parameters for the principal techniques for determining fluid distributions, flow patterns, and fronts for oil recovery methods which are displacement mechanisms. Several new geophysical methods are included. Microseismic measurements are being tested in Canadian thermal recovery projects. New electromagnetic techniques for monitoring subsurface movement of thermal fronts and injected fluids are considered. Single well and interwell tracer tests are finding increased application in water floods, chemical floods, and chemically aided steam floods. Pressure transient tests are used to define reservoir continuity and provide directional permeability for preferred fluid movements. Physical description of each system as well as information obtained and required analysis are provided along with the advantages and disadvantages of each system and cost. Tables are formulated to indicate which diagnostic methods work best in different sets of reservoir-recovery system combinations. The engineer is then able to select one or more candidate techniques for further evaluation and possible use. Numerous references are provided. Field applications of most of the methods covered showing the use and significance of the data are described. In the emerging techniques, results from comparable subsurface applications are mentioned. Where possible, laboratory studies are described which aid in identifying the phenomena to provide validity of interpretation of field results.
Testing and Development of the Beowawe Geothermal Field
Authors: Epperson I. J.
Published: December 2007

Since the initial drilling in 1959 within the Beowawe Geothermal field in north-central Nevada, USA, a total of 16 wells have been drilled. The source of the hot low salinity fluid is believed to be in Lower Paleozoic carbonates at depths approaching 20,000 to 30,000 feet (6100-9100 m). The geothermal fluid flows upward from the carbonates by way of a complicated series of faults, charges permeable horizons along the way and finally discharges at the surface. Numerous flow tests, buildups, interference tests, and injectivity tests have been conducted on eight of these wells. All data indicates that the geologically complicated 3eowawe system is very prolific and fed by a very large reservoir.
Impact of Perforation Variables on Well Productivity at Prudhoe Bay
Authors: Twyford L. R. , Tyler T. N.
Published: December 2007

Numerical models and laboratory studies have been performed by other investigators to define the impact of various perforation parameters on well productivity. Field verification of these findings is difficult due to uncontrolled factors such as charge performance, drilling invasion, and reservoir quality.

Using information from Prudhoe Bay, a study of perforation parameters affecting well productivity was undertaken in an effort to identify the most significant perforation variables in terms of initial and long term well performance. Findings from the study of field data verifies that perforation penetration is the most significant factor affecting well performance. Wells perforated with deep penetrating casing guns have lower drawdowns and significantly lower decline rates than wells perforated with through tubing guns. The high decline rates at Prudhoe Bay are a result of calcium carbonate scale buildup, which is exacerbated by perforations of poor quality. The data also suggests that 0° gun phasing is comparable to other phasing when perforating in deviated, large diameter well bores.
An Evaluation of Options for Prudhoe Bay Natural Gas
Authors: Corley D. I. , Marsden S. S.
Published: December 2007

This study investigates some of the reasons why the natural gas which is produced along with the oil at Prudhoe Bay is not being delivered to a market and three of the possible methods of delivering this gas energy to a market. These three alternatives include a proposal to build a natural gas pipeline through Canada, a liquefied natural gas (LNG) proposal and a proposal to manufacture fuel grade methanol from the natural gas at Prudhoe Bay which would be shipped through the existing Trans Alaska Pipeline System. A brief review of the engineering, economic, environmental, supply/demand and market aspects, and most importantly the political considerations affecting the selection of any of these three alternatives is presented.

The concern over marketability of gas delivered through the proposed pipeline through Canada is responsible for this proposal being held in abeyance, even though it was politically selected as the Alaskan Natural Gas Transportation System in 1977. If an alternative System is to be selected, action should be taken before there is a political decision to force the construction of the pipeline through Canada.

From virtually every viewpoint the methanol proposal is the most reasonable method of delivering the Prudhoe Bay gas energy to a market. It is shown that either of the other alternatives would result in the cost of the Prudhoe Bay gas energy being higher than the cost of energy from imported oil or natural gas.
Prediction of Fracture Extension During Waterflood Operations
Authors: Kuo M. C. T. , Hanson H. G. , DesBrisay C. L.
Published: December 2007

A fracture extension mechanism was proposed to explain daily surface injection pressure behavior observed in a waterflood project located in the Somatito Field A fault block in the Talara Area of Northwest Peru. Daily surface injection pressure data indicated a repeating phenomenon, i.e., formation pressure increasing slowly along a general trend as the flood continued (called normal formation recharge). Surface injection pressure occasionally built up above this trend value because of fracture plugging. Then the injection pressure dropped back sharply to the general trend (called fracture extension). The mechanism repeats again and again in the same sequence until water breaks through at a producer. Fracture propagation theory (Geertsma and de Klerk1) was applied to calculate incremental fracture length, or, the time interval during the fracture extension period. Combining the information of fracture extension frequency and incremental fracture length, expected breakthrough dates can be predicted at producers along the fracture azimuth. Water breakthrough sensitivity analysis is a useful technique to identify fracture azimuths or preferential permeability trends.

Given daily surface injection pressure data, a simple method was developed to allow engineers to predict premature injection water breakthrough in tight reservoirs. This simple procedure is especially useful to reservoir and field engineers involved in secondary and tertiary recovery projects.
The Transport of Bacteria in Porous Media and Its Significance in Microbial Enhanced Oil Recovery
Authors: Jang Long-Kuan , Sharma M. M. , Yen T. F.
Published: December 2007

MEOR is a tertiary recovery process which has only recently been accepted as a technically feasible alternative to other EOR processes in certain shallow, highly permeable reservoirs. The transport of injected bacteria in the porous media is among the problems which need to be resolved before a MEOR process can be successfully applied in a candidate reservoir. In order to contact trapped oil with active metabolites generated in situ, potential strains of bacteria must be transported deep into the reservoir. The problem of transport of bacteria is linked closely with the success or failure of an MEOR process.

This paper presents a bench-scale investigation of bacterial transport in sandpack columns and sandstone cores and its relationship with oil recovery efficiency. Various oil recovery processes utilizing Bacillus subtilis (a bio-surfactant producer) have been attempted: (a) Continuous flooding with bacterial culture, (b) inoculation of bacteria followed by injection of nutrient, (c) inoculation followed by repeated cycles of static incubation, pressure release and nutrient (or water) drive. Experiments revealed that the above processes recovered 30%-40% of the heavy oil (Ranger Zone, Long Beach, CA) in the sandpack column remaining after secondary water-flooding. It was found that bacteria are able to migrate 1 ft/day through the sandpack column saturated with nutrient broth.

The transport of bacteria (or spores) in process (c), which is tentatively thought to be the most feasible among the three processes, is achieved through injection with nutrient followed by a period of static incubation during which cells mutiply and migrate. Separate experiments simulating the two stages of bacterial transport revealed that bacterial spores of B. subtilis and C. acetobutylicum are most easily pushed through the sandstone core while B. subtilis cells migrate through the core faster than Pseudomonas putida during static incubation. This suggests that the procedure developed in this work provides a criterion of selecting bacterial cells with favorable transport properties in porous media.
Unconventional Pilot Steam Drive, Tar V Sand, Long Beach Unit, Wilmington Field, CA
Authors: Jung K. D.
Published: December 2007

This paper reviews the design, implementation and history of the unconventional pilot steam drive (greater than 2,500 ft measured depth) that has been underway since December 24, 1980 in the Tar V reservoir in the Long Beach Unit, Wilmington Field, Los Angeles County, California. This paper describes the project through November 30, 1983.

The Tar V reservoir is a series of interbedded sands, siltstones and shales in the Middle Repetto formation of lower Pliocene age. The Tar V reservoir in the Long Beach Unit is approximately 200 acres in areal extent, has a vertical gross thickness of 185 ft and a maximum vertical net oil sand thickness of 90 ft comprised of 8 to 10 separate sand units. Oil in place is estimated at 27 MMbbl of stock tank oil.

The study area is 9.2 acres in areal extent with an average net oil sand thickness of 81.7 ft. The pilot steam drive was originally installed as an isolated 5.6 acre inverted 5-spot pattern. The 9.2 acre study area includes two off-pattern wells that have been affected by the steam drive process.

Injection started December 24, 1980 in A-662I. The injector and all wells in the study area are directionally drilled from Island Grissom or the Pier J site. Inzone hole angle averages 50°. Well measured depths average 3,256 ft. The top of the Tar V reservoir is approximately 2,100 ft vertical subsea.

Tank oil-in-place in the 9.2 acre study area at the start of injection is estimated at 1,171 Mbbl. Oil recovery from the study area from start of injection to November 30, 1983 is 210.8 Mbbl or 18.0% of the oil originally-in-place. Oil recovery from the study area prior to start of injection is 23.4 Mbbl or 2.0% of the oil originally-in-place.

Production from the six-well study area in November, 1980 was 475 B/D gross, 118 B/D net, 75.2% cut. Peak oil rate was in June, 1982 at 1,969 B/D gross, 413 B/D net, 79.0% cut. The November 1983 rate was 710 B/D gross, 87 B/D net, 87.7% cut. Cumulative injection of steam and/or hot water is 572 Mbbl into A-662I the pattern injector, and 172 Mbbl into the six producing wells for thermal stimulation. Total injection is 744 Mbbl for a cumulative oil-steam ratio of 0.28 and 0.40 pore volumes injected.
Slug Test Data Analysis in Reservoirs With Double Porosity Behavior
Authors: Mateen Khalid , Ramey H. J.
Published: December 2007

Pressure analysis for a slug test which corresponds to the flow period of a Drill Stem test is extended to wells in reservoirs with double porosity behavior.

The modelling of fluid flow within the reservoir is achieved by considering reservoirs having homogeneously distributed regions of primary (matrix) and secondary (fissure) porosity. The matrix acts as a source and fissures connect with the well. The well conditions include wellbore storage and skin effect.

Solutions were obtained for either pseudostate, or transient interporosity flow. The distinctive features of both solutions are identified. Results presented are applicable to both naturally fractured and layered reservoirs as long as only the high permeability layer conducts to the wellbore.

An interpretation method based on type-curve matching is proposed. Type curves based on pseudosteady or transient interporosity flow are presented. These type curves are similar to existing single layer type curves with the addition of interporosity flow lines indicating double porosity behavior. Application of the type-curve matching technique can provide the interporosity flow parameter λ, the storativity ratio, ω, in addition to transmissivity kh/μ, and skin effect S.

Ramey et al. presented type curves for a single homogeneous layer which required empirical correlation in terms of CDe2s and tD/CD. A formal solution showing wellbore pressure as a function of CDe2s and tD/CD for a homogeneous reservoir is presented. This permits discussion of the approximation involved in Ramey et al. study.
Exploration/Production Studies of the Devonian Gas Shales
Authors: McBane R. A. , Thompson T. W.
Published: December 2007

Producers currently develop Devonian shale gas fields by drilling wells which offset a high productivity well. Remote sensing as well as various geophysical and geochemical techniques are sometimes used to site wells. Yet, productivity of the development wells can be highly variable. In an attempt to improve the production potential of these wells, the Gas Research Institute has undertaken a research program aimed at developing a better understanding of the geological features which control production in the shale, and which a wellbore must intersect or communicate with in order to result in higher productivity. A better understanding of these geological production controls is necessary to develop an exploration or stimulation methodology which will enable the producer to better locate and stimulate wells, and thus improve overall productivity of the field.
Porosity and Permeability of Tight Sands
Authors: Randolph P. L. , Soeder D. J. , Chowdiah Prasan
Published: December 2007

Detailed analyses of more than 50 core samples of western tight sands have resulted in several unanticipated observations that are set forth in this paper. Core analyses performed under stress representative of producing conditions provided data on porosity, pore volume compressibility, stress dependence of permeability to gas, and slope of the Klinkenberg plot (permeability at constant net stress vs· the inverse of pore pressure). Scanning electron microscope (SEM) and petrographic microscope analyses were performed on samples cut from the ends of core plugs tested. The microscopic studies were explicitly directed toward observing the <0.1 micron flow path openings deduced from permeability data.

The Computer Operated Rock Analysis Laboratory (C.O.R.A.L.) used for these measurements has been previously described.(1) Permeabilities are measured with a maximum pressure drop of 20 psi, much less than the pore pressure of 100 to 1500 psia. At the one microdarcy level, the standard deviation of a sequence of permeability measurements under constant conditions is typically 2% of the measured value. Resolution is a few naaodarcies· The accuracy of porosity measurement is about ± 2% of the reported value, but the sensitivity to pore volume change due to an incremental step in confining pressure is better than 0·1% of the pore volume. Thus, pore volume compressibility is measured to an accuracy of a few percent for a 1000 psi step in confining pressure.

The selection of tight sandstone samples for analysis involved an intentional bias. Namely, all samples were from depths that were either known to be gas producers or judged likely to be producers on the basis of wireline log analysis.
Perforation Placement Optimization: A Modified Hydraulic Fracturing Technique
Authors: Ahmed Usman , Thompson T. W. , Kelkar S. M. , Veghte Richard , Hathaway Scott
Published: December 2007

The success of a hydraulic fracture treatment is greatly enhanced by control of the created fracture geometry. This problem is most serious if the boundary lithologies are not highly stressed as compared to the pay zone and do not form an effective barrier to upward migration. Reservoirs with this nature are common in many areas, including the Douglas Creek Arch, Green River Basin, Uintah Basin, San Juan Basin, and Central Alberta.

The Perforation Placement Optimization technique involves the determination of perforation locations such that the hydraulic fracture contact area within the pay zone is optimized. Where the upper boundary lithologies are not highly stressed as compared to the pay zone, the fracture will migrate predominantly upward into weak boundary lithologies. Where weak boundaries exist, the extent of the exposed fracture area that can be contained within the pay zone is strongly dependent on the location of the perforations and the gross height of the pay formation. Initiating the fracture below the pay sand (should lithology at the site be amenable to locating the perforations below the sand) can lead to greater fracture contact area within the pay sand and thus increased production. The work presented in the paper includes laboratory simulations performed on one meter cubic blocks, fracture design efforts, field implementation and transient pressure testing. The results of the laboratory tests helped in developing a model for optimizing perforation placement. This has been used in conjunction with a pseudo three dimensional fracture geometry and a pseudo two dimensional fluid flow hydraulic fracture model to design a field hydraulic fracture treatment. The treatment has been implemented in a well in the Douglas Creek Arch area, Colorado.

In-situ stress measurements in the well and special core testing on retrieved core material were performed to evaluate this well and the reservoir properties. In-situ stress distribution indicated the absence of stress barriers as expected. Reservoir engineering studies indicated that a significant increase in post-stimulation production can be expected by the use of perforation placement optimized hydraulic fracture treatment. The well was stimulated through perforations placed fifty feet below the pay zone and the created fracture was allowed to migrate upward into the pay zone. Post-stimulation transient pressure testing, fracturing fluid clean-up, and gas flow data indicate that the technique has been successfully applied.

This paper discusses the development, application, and evaluation of the modified hydraulic fracturing technique. This particular technique has been developed as part of a research program sponsored by the Gas Research Institute of Chicago and conducted by Terra Tek, Inc. of Salt Lake City and Chandler and Associates of Denver.
A Case Study for Exploration and Development of the Trenton Reservoir in Northwest Ohio
Authors: Schrider L. A. , Caprarotta D. W. , Natoli M. A. , Sawyer W. K.
Published: December 2007

Independent oil and gas companies such as Beiden and Blake continue to search for new sources of hydrocarbon reserves. In many instances this has resulted in a re-evaluation of reservoirs that were considered depleted or of higher risk. The Trenton Limestone reservoir, located in the northwestern part of Ohio, is a case study of such an occurrence.

Through an extensive three-year evaluation of this area, both geologically and from an active drilling program, it was found that the area still contains vast amounts of hydrocarbons located in various types of geologic traps. While large amounts of oil and gas exist in this reservoir, ultimate production is sensitive to well completion and production practices. More specifically in the case of natural gas, pressure transient tests were conducted to determine whether gas reserves were sufficient to consider pipeline construction. Results of the reservoir tests verified the Trenton formation to be of low permeability in the range of one millidarcy, and porosity between 2 and 4 percent. An economic evaluation was then performed to determine what reservoir flow capacities, well spacing and economic criteria were required for successful engineering and economic development.

Conclusions of the case study showed (1) the need for high grading the well site selection through geological interpretation in order to expand the "sweet spots," (2) a need for stimulation treatments designed to enhance production, (3) a marginal return on investment with current economics, and (4) that gas pipeline construction should be delayed until larger reserves are found or until a more favorable gas marketing climate develops.
Practical Aspects of Devonian Shale Exploration and Development in Western West Virginia: One Operator's Experience
Authors: Murray W. G. , Woodfork L. D. , Wolfe R. T. , Heck W. A. , Fairchild Mark
Published: December 2007

The discovery of new oil production (with associated gas) from the Devonian shales in western West Virginia in 1979 led to a tremendous increase in Devonian shale exploration and development in that area. The records of the West Virginia Geological and Economic Survey indicate that over 40% of drilling permits issued in 1982 were for various zones in the Devonian shales. With the decline in the gas market, the number of Devonian shale gas wells has declined in 1983. Nevertheless, activity in Ritchie, Pleasants, and Wood counties has remained very high. That activity is a source of considerable practical information on Devonian shale exploration and development. In fact, that play has provided an active testing ground for a variety of theories and techniques. The information presented in this paper is derived largely from the experience of one operator, Rendova Oil Company of Midland, Texas. That organization has been active in West Virginia since 1980 and, through the end of 1983, has drilled over 40 Devonian shale wells. That effort has been a continuous learning process in all phases of exploration and development. This paper will attempt to share that experience by describing the methods and techniques that have been tried as well as Rendova's current practices. The discussion will include exploration rationale, drilling methods, and completion and production practices. In addition, we will discuss what we see as the major problems that remain in developing oil and gas reserves in the Devonian shales.
Devonian Shale Production Data Analysis
Authors: Koziar Gregory
Published: December 2007

Analysis of Devonian shale production histories without careful data screening can easily mislead even the most exacting investigator. Trends established from cumulative production data may not accurately represent the true production pattern. The difference between a good well and a poorer producer may be the result of fracture depletion or the length of actual producing time (among other factors) rather than a change in reservoir quality. The use of matrix controlled production information, derived from decline curves, appears to resolve this problem.
Evaluation of Naturally Fractured Gas Shale Production Utilizing Multiwell Transient Tests: A Field Study
Authors: Chen Chih-Cheng , Alam Javaid , Vozniak J. P. , Blanton T. L.
Published: December 2007

A series of multiple well transient tests1 were conducted in a Devonian shale gas field in Meigs County, Ohio. Production parameters were quantified and it was determined that the reservoir is highly anisotropic, which is a significant factor in calculating half-fracture length from pressure transient data. Three stimulation treatments, including conventional explosive shooting, nitrogen foam frac, and high energy gas frac (HEGF)2, were compared on the basis of overall effectiveness and performance. Based on the evaluation of results, the nitrogen foam frac provided the most improved productivity. The study provided new type curves and analytical solutions for the mathematical representation of naturally fractured reservoirs and confirmed that the shale reservoir in Meigs County can be modeled as a dual porosity system using pseudosteady-state gas transfer from the matrix to the fracture system.
Coal as a Conventional Source of Methane: A Review and Analysis of 50 Wells in Two Production Areas in the Black Warrior Basin of Alabama
Authors: Dunn B. W.
Published: December 2007

This paper presents a review of the actual production, sales, and economic data from two production areas with 52 wells developed by a joint coal industry' gas industry effort owned equally by Jim Walter Resources, Inc. (JWR), a subsidiary of Jim Walter Corporation of Tampa, Florida and Enhanced Energy Resources, Inc. (EER), a subsidiary of Kaneb Services, Inc. of Houston, Texas. The unique reservoir characteristics of the coal environment are described in brief, a comparison of actual methane production from coal with computer model predictions is presented, and the capital and operating costs are discussed with specific emphasis on the economic results.

This information differs from similar previous work in that economic vitality is now apparent whereas previous inquiries were essentially restricted to the technical reservoir engineering characteristics and the physical capability of coal to desorb (produce) methane. There are a number of published papers on this important technical aspect several of which are references for this presentation.

Production Area I (31 well production area) has been generating an operating profit for the past 21 months. Profits have increased substantially in the past year as a result of the completion of an 8" transmission line and reduced operating costs. Initial production commenced in late 19/9. A five well pilot project was evaluated for approximately two years before commercial development commenced in late 1981. A total of 31 wells were drilled by mid-1982. First sales commenced in February of 1982. Production Area II drilling commenced in January of 1983 with initial sales in March of 1983.

The economic viability is demonstrated based on actual operating profits over the past twenty-one months and current experience with respect to improvements in operational techniques and costs. These data are applied to the computer forecasts of long term dellverabilities for projections of expected economic performance.
Methane Production Characteristics for a Deeply Buried Coalbed Reservoir in the San Juan Basin
Authors: Jones A. H. , Ahmed Usman , Bush D. D. , Holland M. T. , Kelkar S. M. , Rakop K. C. , Bowman K. C. , Bell G. J.
Published: December 2007

In cooperation with Tiffany Gas Company, Terra Tek cored the Fruitland Formation coal, lying at approximately 3100 feet, in the Glover Well #1 drilled in the southeast quarter of Section 2, T32N, R6W, Archuleta County, Colorado, within the northern portion of the San Juan Basin. The coal was fully water saturated. Laboratory tests were performed on the recovered cores and reservoir engineering tests within the coal before and after underreaming. Production data indicates the need to treat the coal with a deeply penetrating fracture to achieve acceptable gas production. However, coal fines migration is a serious problem to maintaining high production.
A Lumped Numerical Model for the Design of Hydraulic Fractures
Authors: Keck R. G. , Cleary M. P. , Crockett Alan
Published: December 2007

This paper presents some derivations and results of lumped numerical models which describe the growth and final geometry of hydraulic fractures. Using generally averaged resevoir and fracture parameters the model employs simple numerical routines to solve coupled non-linear ordinary differential equations for the pressure and dimensions of the fracture. Results of more complex models are included as a data-base in the spatial lumping process; thus the models represent all the essential features of fully 3-D, physically realistic hydraulic fractures. The present model provides a consistent description of fracture growth and includes the effects of mechanisms such as fluid loss, backstress, heat transfer, proppant and variable fracture geometry. Results are presented for a variety of typical field applications and show the general usefulness of these models for fracture design and on-site interpretation of observed versus predicted downhole pressures.
Offshore Gulf of Mexico Drilling From a Floating Vessel
Authors: Rushing H.H. , Poimboeuf W.W.
Published: December 2007

Zapata Offshore Co.'s Nola No. 1 proved drilling from a floating vessel in the Gulf of Mexico is feasible and economical.

Fishing and completion operations below 10,000 ft presented no significant problems.

The Nola No. 1 and the drilling method used are described.

The advantages and disadvantages of this method of drilling are presented.

The success of the Nola No. 1 should extend drilling operations in the Gulf of Mexico to water depths in excess of 200 ft.

Introduction

This paper describes the Nola No. 1 and the method of drilling into the submerged lands of the Gulf of Mexico from a floating vessel. The results to date and the significance of floating vessel drilling also is included.

Due to the complex geology of piercement-type salt domes in the Gulf of Mexico, the use of a floating drilling vessel reduces the risk and cost involved in proving locations for expensive drilling platforms.

Increasing well costs and sharply declining allowables in Louisiana have affected profits from offshore oil drilling operations. In view of this situation, it is essential that operators find ways and means to decrease offshore drilling costs. Present indications are that drilling from floating drill barges ultimately will help accomplish this objective.

History

The initial drilling from floating drill barges occurred offshore California in 1953. Since that time several floating drill barges have been built and several hundred-thousand ft of hole drilled from floating drill barges. The majority of drilling from floating barges has occurred offshore California, and several holes have been drilled offshore Trinidad, but none have been able to complete above water until the advent of the Nola No. 1.

Several sulphur core holes were drilled offshore Texas with small floating drill barges. The Nola No. 1 drilled the first well in search of oil or gas from a floating drill vessel in the Gulf of Mexico on State Lease 2548, West Delta Block 51, No. 2.
A Review of the Northern North Sea's Beryl Field After Seven Years' Production
Authors: Steele L. E. , Adams G. E.
Published: December 2007

The Beryl oil field is a United Kingdom North Sea giant. Ultimate recovery is estimated to be 800 million barrels of oil and 1.4 billion cubic feet of gas. The field was discovered in 1972 and first production from the Beryl A platform commenced in June 1976, only 44 months from discovery. This paper reviews the geology and performance of the Jurassic Upper Beryl Sandstone which is the principal reservoir in the field. Production from the Upper Beryl through March 1984 amounts to 179 million barrels. Ultimate recovery from this reservoir should be optimal because of gravity segregation and high pressure rich gas injection.
The Interpretation of Interference Tests in a Reservoir With Sealing and Partially Communicating Faults
Authors: Stewart G. , Gupta A. , Westaway P.
Published: December 2007

The interference test has been extensively used in North Sea reservoirs to assess communication between wells and in this paper the effect of fault planes on interference test response is analysed. In the first part simple systems of intersecting and parallel sealing faults are analysed using the method of images. The matching of observed and model response to give the reservoir parameters kh/μ and ϕμct is best carried out using a method based on implicit function theory originally proposed by Cannon and Dogru. In the second part the effect of a partially sealing fault between the active well and the observation well is analysed using a two-dimensional single-phase numerical simulator. A set of log-log type curves giving pD as a function of td for various values of a fault transmissibility parameter is given.