bluuebunny/crossref_metadata_2025 huggingface dataset:
Coal Gas Resource and Production Potential of Subbituminous Coal in the Powder River Basin
Authors: Pratt Timothy J. , Mavor Matthew J. , DeBruyn Roland P.
Published: December 2007

This paper presents interim data for an ongoing project funded by the Gas Research Institute (GRI). The project objective is to obtain quantitative estimates of reservoir properties for a subbituminous Powder River Basin coal gas reservoir. The study is important since coal gas reservoir data are scarce in the Powder River Basin and for subbituminous coal in general.

Introduction

The subbituminous Powder River Basin (PRB) coal possesses characteristics that are dramatically different from the commercially developed areas in the San Juan, Warrior, and other basins. In particular, water content is very high, gas content is low, ash content is low, and absolute permeability is much greater, ranging from tens of millidarcies to more than a Darcy. Early in this decade, conventional wisdom concluded that large-scale commercial production of natural gas from Powder River coal seams was not possible. The coals were recognized as high permeability aquifers that could not be sufficiently “dewatered” to produce sorbed natural gas. Conventional wisdom was wrong, as has so often been the case when dealing with coal seams. Gas can be released from the coal matrix in commercial quantities even when gas content is low and permeability is high. This fact has been proven by numerous PRB operators over the past six years who have concentrated development along the basin's margins in thick coals typically 250 to 1,000 feet deep.

Redstone Resources, Inc. allowed GRI access to the Triton Federal #21C-2623 well located in Section 26, Township 52 North, Range 73 West, Campbell Co., WY. This well was cored and logged and is currently being tested. Redstone has also graciously allowed us to present data from the Twenty Mile #21C-3523 well located roughly 1 mile south of the Triton well in Section 21. Both wells are located on the eastern margin of the basin as illustrated in Figure 1, just west of large strip mines located near the outcrop. The specific coal target was the Canyon coal seam that belongs to the Tongue River Member (late Paleocene) of the Fort Union Formation. The depth of the Canyon coal seam is shallow in both these wells, 557 to 621 feet at the Triton location and 530 to 594 feet at the Twenty Mile location.
Selective Production of Horizontal Openhole Completions Using ECP and Sliding Sleeve Technology
Authors: Constantine Jesse J.
Published: December 2007

Openhole horizontal completions using external casing packers (ECPs) for zonal isolation are a growing trend in the oil industry. This style of completion is installed with slotted pipe or screen across production intervals that are isolated by ECPs. This method, integrated with standard liner hanger equipment set in one trip, allows for production at a lower completion cost, but it also minimizes the options for water shutoff or shutoff of a naturally depleting interval.

As companies continue to implement openhole horizontal completions, they look for alternatives that will provide precise zonal isolation while reducing installation time. This paper addresses an alternative isolation method wherein nonelastomeric sliding sleeves replace the slotted pipe between the ECPs. This method enables the operator to increase production while shutting off undesired intervals, thus fully optimizing the production program. With the use of coiled tubing and hydraulically actuated tools, sliding sleeve manipulation can be accomplished in long-reaching horizontal wellbores. The manipulation of these sleeves can increase production while shutting off undesired intervals.

These sliding sleeve isolation systems have been installed and successfully operated in numerous horizontal wellbores in the Rocky Mountain Region and worldwide. Sliding sleeve systems have been successfully manipulated using coiled tubing methods, even when placed at 90° angles, true horizontal. The capability of shifting sliding sleeves in the horizontal position by utilizing coiled tubing hydraulically actuated shifting tools will be demonstrated in the paper. This allows for the selective opening or closing of multiple sleeves in a single trip. Utilizing sliding sleeves to control well inflow can improve well economics by shutting off unwanted water or gas production.
Successful Completion Practices-An Experience Sharing Effort
Authors: Wang-Allen Yimei , Hill David G. , Fielding Robert Crane , Tesar Dennis
Published: December 2007

A study of Successful Completion Practices has been conducted in the J Sandstone of the Wattenberg Field of the Denver Julesberg (DJ) Basin. The data gathered from six operators suggests that reservoir quality plays an important role in well production performance. However, for the similar geologic, reservoir, and production conditions, the optimal fracture treatment design can result in significant addition in two-year recovery (TYR) and estimated ultimate reserve (EUR). Based on this study, the optimal treatment design parameters include an average proppant concentration of 3.25 ± 0.25 pounds per gallon (lb/gal) of proppant-laden fluid, pounds of proppant weight per foot of gross pay of 5460 ± 500 (lb/ft), and a pad fluid percentage of 20% ± 2%. Results also indicate that post fracturing performance of a well is more sensitive to the type of gel breakers utilized and post-frac shut in duration than to the type of gel used. By using "successful" instead of "average" completion practices, a 27% improvement in the average TYR benchmark and up to 70% improvement in cumulative cash flow can be achieved.
Mechanism for Gel Propagation Through Fractures
Authors: Seright R. S.
Published: December 2007

Many conformance control treatments rely on the ability of gels to extrude through fractures during the placement process. This paper describes an experimental investigation of the mechanism for propagation of a Cr(III)-acetate-HPAM gel through fractures. When large volumes of this gel were extruded through a fracture, progressive plugging (i.e., continuously increasing pressure gradients) was not observed. Effluent from the fracture had the same appearance and a similar composition as those for the injected gel, even though a concentrated, immobile gel formed in the fracture. The concentrated gel formed when water leaked off from the gel along the length of the fracture. The driving force for gel dehydration (and water leakoff) was the pressure difference between the fracture and the adjacent porous rock. During gel extrusion through a fracture of a given width, the pressure gradients along the fracture and the dehydration factors were the same for fractures in 650-md sandstone as in 50-md sandstone and 1.5-md limestone. A simple model was developed that accounted for many of the experimental results.
Production Well Water Shut Off Polymer Treatment in the Weber Sandstone – Ashley Valley Field, Uintah County, UT
Authors: Larson J. B. , Marchant B. P. , Cotton G. D.
Published: December 2007

The Ashley Valley field, located in the Uintah basin of northeastern Utah, produces oil from the Pennsylvanian Weber Sandstone in conjunction with a prolific natural water drive. Permeability heterogeneity is extreme. Matrix permeability in the reservoir rock ranges from 1 to 700 md. In addition, a substantial fracture network contributed to premature water breakthrough and the co-production of thousands of barrels of water per day from the underlying acquifer. This paper describes the application of a chromium (III) polyacrylamide gel system (MARCITSM) as a water shut off treatment in the Ashley Valley #2. In addition to conformance control from the reduction of excessive water production, the field exhibited potential for improved oil recovery from the polymer treatment.

A stratified reservoir model quantified a potential incremental target of 500,000 STB or 3.0% of original oil in place (OOIP) from uniform depletion of the lower permeability reservoir matrix by maximum pressure drawdown at the production wells. Production logging with a downhole video camera in the open hole completion interval confirmed that the highest permeability zones were not contributing any oil production.

Following placement of 2,200 barrels of the MARCIT SM polymer system in the Ashley Valley #2, oil production increased 6 BOPD (32%), water production decreased 2,950 BWPD (40%) and relative permeability to water decreased 70%.
Economics of In-Depth Polymer Gel Processes
Authors: Norman C. A. , Smith J. E. , Thompson R. S.
Published: December 2007

Traditionally, polymers have been used in waterfloods to address an adverse mobility ratio. However, polymer gel processes can also reduce permeability variation in heterogeneous reservoirs, resulting in a more uniform flood front and improved recovery efficiency. Forecasting the economics of a polymer process and selection of the appropriate polymer technology are fundamental to project success. This report offers a methodology for assessing the economic risk of two variables critical to waterflood performance: injection efficiency and permeability variation. Also, an economic model that compares a conventional waterflood, a polymer enhanced waterflood and a waterflood utilizing colloidal dispersion gels (CDG's) demonstrates an objective approach to project selection.
Alkaline-Surfactant-Polymer Flooding of the Cambridge Minnelusa Field
Authors: Vargo Jay , Turner Jim , Vergnani Bob , Pitts Malcolm J. , Wyatt Kon , Surkalo Harry , Patterson David
Published: December 2007

This paper was prepared for presentation at the 1999 SPE Rocky Mountain Regional Meeting held in Gillette, Wyoming, 15–18 May 1999.
Case History of Miscible Gas Flooding in the Powder River Basin North Buck Draw Unit
Authors: Fulco G. J.
Published: December 2007

The North Buck Draw Unit (NBDU) produces volatile oil from the Dakota sandstone in the Powder River Basin. This high-pressure, miscible gas injection project is in its eleventh year of operation. The field has been under partial pressure maintenance since November 1997. Blowdown is scheduled in 1999.

Based on the performance and operating experience at NBDU, it is concluded that the Dakota Sand formation and its fluid properties in the deep Powder River Basin are favorable for miscible gas flooding. Horizontal drilling met with mixed results. WAG operations initiated in the latter part of the project life was successful in extending the life although the effect of injected water on ultimate recovery is still unknown. In addition to process understanding and reservoir and fluid characterization, continuous surveillance of performance is very important to the success of a project such as NBDU.

The project has outperformed original projections and has been very successful, technically and economically. The cumulative production of 22 MMB represents over 62% of the original oil-inplace (OOIP). Ultimate recovery will exceed 65% OOIP.

This paper documents all aspects of the field development, flood operations and performance.
A New Study Of Domestic Petroleum Profitability
Authors: Hubbell Robert O. , Derouen Gordon A. , Yee Raymond S.
Published: December 2007

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

Three case studies representing domestic petroleum investment situations currently of interest were examined for economic relationships. Multiple cash flow analyses were performed by a sophisticated computer program utilizing sensitivity analysis and user-directed algorithm modification via data input. Tax rules specified by the 1975 Tax Law were programmed and are included in this study. The results are presented as a series of figures demonstrating the dependence of profitability indicators on project variables. Cases investigated project variables. Cases investigated were: I, Domestic Onshore Dry Gas Development Case; II, Domestic Offshore (Federal Waters) Gas Prospect Bidding Case; and III, Domestic Onshore Oil Development Case.

Introduction

Currently the most unsettled functional area of the petroleum industry is economics. The period commencing several years ago and continuing today is one of nonpareil change, worldwide and nationally, in the economic constraints under which the American capitalistic petroleum industry exists. The interrelated factors of rapid inflation, ascending but unstable petroleum prices, increasing governmental tax and prices, increasing governmental tax and acquisition tendencies, and more difficult and expensive drilling operations have combined to require frequently hard investment decisions from managers or owners. The decision maker, in turn, demands from his staff or consultant the most reliable economic analysis possible under time and budget limitations. Such an assignment normally dictates utilization of the computer tool to perform swiftly and cheaply period-by-period perform swiftly and cheaply period-by-period cash flow analysis.
A New Technology in Potable Water Disinfection for Offshore Rigs
Authors: Nathan P. Regu
Published: December 2007

Disinfection of potable water aboard ships and oil rigs is presently accomplished through chlorination by feeding calcium hypochlorite solutions. This method has several drawbacks in terms of equipment operation, maintenance, reliability and safety. Recently developed equipment utilizes disposable filter cartridges containing bromine impregnated resin to feed predetermined amounts of bromine into the water system for disinfection. These bromination systems have been field tested and have been found to be safer, more reliable, and easier to maintain, and they provide a greater health safeguard aboard ships and rigs.

Introduction

While recognized as necessary for sustaining life, water has long been suspect as a vehicle for the transmission of many diseases to man. Yet it was not until just over 100 years ago that this pernicious role of water was confirmed. With definite evidence on hand, emergency treatment with hypochlorites became quite common during periods of epidemics and in 1904 the first attempt of continuous chlorination of a public water supply was initiated. With the development of facilities for feeding gaseous chlorine in 1912, chlorination of public water supplies has grown rapidly and has become routine in this country. The result has been dramatically low epidemic incidences during the last few decades.

Chlorination is practiced to disinfect a water supply, i.e., to kill pathogenic (disease causing) organisms, and thus prevent the spreading of pathogenic (disease causing) organisms, and thus prevent the spreading of water-borne diseases. However, besides killing organisms, chlorine also reacts and oxidizes a wide variety of other impurities in the water; particularly ammonia, iron, hydrogen sulfide, manganese, nitrites, and particularly ammonia, iron, hydrogen sulfide, manganese, nitrites, and organic compounds. Many such reactions are rapid and their demand for chlorine must be satisfied before chlorine becomes available to accomplish disinfection. Thus, the level of chlorine addition has to be in excess of the actual demand, allowing for a measurable chlorine residual to accomplish and indicate completion of the disinfection process.

Gaseous chlorine is toxic to man and is dangerous to handle, but adequate materials and methods have been developed for its use in public water supplies, where the process can be supervised by attending personnel. In small or private water systems where constant attention cannot be provided, gaseous chlorine is not used for disinfection.
Effect of Cyclic and In Situ Heating on the Absolute Permeabilities, Elastic Constants, and Electrical Resistivities of Rocks
Authors: Aktan T. , Ali S.M. Farouq
Published: December 2007

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

An experimental study was conducted to determine the effects of cyclic and in situ heating on the Young's moduli, bulk moduli, Poisson's ratios, resistivities and Poisson's ratios, resistivities and permeabilities of Berea, Boise, California and Tennessee permeabilities of Berea, Boise, California and Tennessee sandstones.

Elastic moduli were calculated by measuring the longitudinal and shear wave transit times of the cores subjected to triaxial pressure. Samples were loaded to 5000 psi overburden pressure at 1000 psi increments, and the pressure at 1000 psi increments, and the confining pressure was kept at 60% of the overburden pressure.

Cyclic heating and cooling runs were carried out by placing the cores in steel core holders and heating them at 550 deg. F and 2000 psig pressure in a convection oven. Afterwards, pressure in a convection oven. Afterwards, the cores were placed into the triaxial cell to measure the longitudinal and shear wave transit times. In situ heating experiments were conducted by simultaneously heating the core to 300 deg. F in the triaxial cell and measuring the elastic wave transit times.

Permeabilities of dry and saturated cores were measured using the Ruska permeameter. Resistivities were calculated by determining the resistance of the 2% brine saturated sandstones by the aid of a Wheatstone bridge.

Longitudinal and shear wave velocities for the sandstones tested decreased as a result of microcracks formed during heating-cooling cycles to 550 F, and in turn, being dependent on the wave velocities, the Young's modulus, bulk moduli, and Poisson's ratios showed significant reductions. In the in situ heating experiments, the decreasing trend of the dynamic elastic constants was less pronounced than that observed in the cyclic heating experiments. Absolute permeabilities of the Berea and Boise sandstones showed progressive increases upon heating to 300 deg. and 500 deg. F, respectively, while the electrical resistivities of all four sandstones exhibited considerable reductions when heated to the same temperatures.

Introduction

A comprehensive study of a reservoir under thermal treatment warrants a knowledge of the temperature and pressure dependence of the petrophysical properties of the constituent petrophysical properties of the constituent reservoir rocks. In particular, the temperature dependence of the rock elastic moduli plays an important role in the analysis of the thermal stresses induced by the flow of hot fluids in porous rocks. porous rocks.
Effect of a Wetting Immobile Phase on Diffusion and Macroscopic Dispersion in Unconsolidated Porous Media
Authors: Verlaan M. L. , Dijkgraaf H. F. , van Kruijsdijk C.P.J. W.
Published: December 2007

The objective of this paper is to determine the effect of a wetting immobile phase (e.g. connate water) on the diffusion and macroscopic dispersion in homogeneous unconsolidated packs. We measured the effective dispersion coefficients of gases as a function of water saturation, pressure, and velocity in a laboratory set-up. The dispersion coefficients were 2 to 3 times higher than in the dry porous medium. This effect is also studied using a pore network model where the immobile phase blocks a fraction of the pores for fluid flow. A random walk through the network and counting cluster sizes both gave approximately the same results, which were in good agreement with the experimental data.
Interference Testing to Verify Drainage Strategy for a Large Offshore Development
Authors: Jensen Bjorn , Hjelleset Ellen Angelina , Larsen Leif
Published: December 2007

The paper presents plans, execution and results from a multirate interference test to verify drainage strategy for the large HPHT Smorbukk reservoir in the Aasgard field offshore Norway. The critical question being communication between oil producers and a planned updip line of gas injectors. A fractured oil well undergoing an extended well test to determine the long-time production behavior of fractured wells in a reservoir with a fluid system near critical conditions was the source of the interference data.

The interference test was planned with surface read-out (SRO) through accoustic signal transmission from the wellhead of the observation well to the active well platform. The SRO part of the test failed, but memory gauges for later retrieval were also installed in the well. The test ran from Nov. 96 to Jan. 97, with both pre and post fracturing production periods, but the gauges were left in the hole until the well was re-entered Sept. 98. During this period the gauges were exposed to temperatures near 160°C for nearly two years, but two of six gauges were still found to contain data consistent with their sampling scheme, with one gauge sampling data long enough to pick up the response from the post fracturing extended well test.
Use of NMR Logging for Formation Damage Prevention: Water-Flooding Case Study in Cañadón Seco, San Jorge Basin
Authors: Diaz Delia C. , Breda Eduardo , Minetto Carlos , Atlas Baker , Chen Songhua
Published: December 2007

Water flooding is a well-established secondary oil recovery technique used in many reservoirs around the world. A key issue involved in water flooding is the prevention of the invasion of solids, which may cause formation damage and, consequently, inhibit injection and cease production. To remove fine particles cost-effectively from the flooding fluid, it is necessary to determine the maximum size of the particles that can flow with the fluid without plugging the formation. Determination of the threshold particle size, however, is often very challenging.

In this paper, we report a successful water flood case study for San Jorge Basin reservoirs. Nuclear magnetic resonance log (MRIL [R]*) data were used to obtain the pore size distribution. Core NMR measurements were conducted to validate the T2 distributions derived from the MRIL logs. In addition, the same core samples were analyzed with conventional methods, including capillary pressure, SEM, thin section, and mineralogical analyses. Based on the MRIL log and core data, we were able to establish the correlation between the T2 distributions in the formation and the threshold solid particle size allowed in the injection water, which is important to prevent formation damage.

A critical step in the process is the accurate determination of T2 distribution. Different inversion techniques were used for data processing from which we found that the inversion with gamma-density functions is the most suitable for matching the NMR-based pore size distributions with core-based pore body and throat size distributions.

The approach was applied to the water-flood projects for Mina el Carmen formation reservoirs, San Jorge Basin, Argentina, in a pilot project involving multiple wells. The initial estimate of lifetime cumulative oil production was estimated with conventional-analysis prediction. Based on MRIL and core data analysis of a pilot well, the water-flood filtration program was changed, and successful water injection has continued for over two years. The cumulative oil production exceeds the initial estimate by more than a factor of 2. The particle-size correlation derived from the key well was found applicable to other wells in the same formation and water injection was applied to four oil-bearing zones. NMR logs were acquired for five of the seven wells in the project. The pore-size distributions derived from these logs are used to adjust the threshold particle size in the filtration program of the individual wells. To date, all of these wells have been producing successfully.
Reservoir Optimization in Full-Field Development Using Geosteering Techniques to Avoid Existing Production Completions
Authors: Edwards John , Hillock Peter , Pogson Mark , Nichol Gordon
Published: December 2007

To maximise drainage, the full field development phase of the Wandoo oil field required three new horizontal wells to make a total of five crossings with two existing horizontal wells. The low relief structure and potential coning from nearby fluid contacts required three of these crossings to be within a vertical separation of 2 m. Because this clearance is much smaller than the closest safe approach possible using geometric collision avoidance, geosteering was used as the collision avoidance technique. This required a detailed resistivity and gamma ray model of the stratigraphic sequence, which was used to establish the relative position of the existing and new wellbores. The well-crossings were made by geosteering in the formation layer either over or under that of the existing well. Three crossings requiring the closest approach had separations computed to be 2.6, 2.4 and 1.7 m. These separations are much closer than the minimum allowable 5.2 to 7.1 m for geometric collision avoidance, but are far enough apart to avoid fracturing between the wells.

As the horizontal drainholes dropped down the updipping sequence they were geosteered within two reservoir units. One unit has a 0.6-m sweet spot, and each unit has its own upper and lower coning boundaries. This reservoir geosteering also required a resistivity and gamma ray model, in order to build a real-time geological cross-section. This cross-section was used to intersect and follow the sweet spot, and design sidetracks if faults or rapid dip changes caused the well to enter a reservoir unit outside its coning boundary.

The well crossings allowed approximately 7 million barrels of reserves to be successfully exploited without putting the existing wells at risk. Production from the field was above budget estimates, which was due primarily to the high efficiency in placing the well bore in good quality rock and the contribution from the crossed wells.
A Case History Study - Evaluation of San Andres Stimulation Results
Authors: Black Harold N. , Stubbs Bruce A.
Published: December 2007

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

Frequently, it is asked: "What is the best stimulation method for the San Andres formation? Under what conditions is it better to fracture, acidize or to fracture-acidize?" An objective of this study is to help in the designing of future treatments and evaluating previous treatments in similar type reservoirs.

This case history study is an evaluation of hydraulic fracturing, acidizing and fracture-acidizing treatments in approximately 25 wells in 5 fields producing from the San Andres formation in producing from the San Andres formation in the Permian Basin (Fig. 1). Most of these fields are now being waterflooded. Actual and theoretical productivity index ratios calculated by three methods were compared by plotting these ratios versus both actual and dimensionless times. Oil, water and total production rates were cross-plotted versus time production rates were cross-plotted versus time to help explain deviations of actual from the theoretical productivity index ratio curves.

Introduction

A lithogical study has indicate that three basic San Andres rock types, lagoon, backreef and reef, resulted from variations in the depositional environment during the Permian Period of the Paleozoic Era. When the seas covered the Paleozoic Era. When the seas covered the present Permian Basin area, the larger present Permian Basin area, the larger particles of corals and fossil fragments particles of corals and fossil fragments settled and formed reef-banks in the high energy zone away from the shoreline. These reef-banks later formed high porosity, high permeability formations porosity, high permeability formations classified as reef type rock. Shelfward from these banks, the quiet water envirollment allowed finer particles to deposit which later resulted in the lower porosity backreef type rock. In the porosity backreef type rock. In the shallow water near the shoreline, even finer grained sedimentation eventually caused the formation of lagoon type rock. The lagoon type rock, at the present time, due to its low porosity, is generally not considered commercially productive of hydrocarbons unless it contains productive of hydrocarbons unless it contains natural fractures.
Associated Gas Management In The Gulf Of Suez: Maximizing Profitability And Conserve The Environmental Quality
Authors: Shaheen S.E. , Nour M.H
Published: December 2007

This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.
Development of a Single-Trip Method for Shallow-Set Casing Shoe Testing and Openhole Drilling
Authors: Coronado Martin P. , Frisby Ray A.
Published: December 2007

This paper describes the development of a new method for drilling out a shallow-set casing shoe, testing pressure integrity at the shoe, and drilling open hole below in a single drill pipe trip in a deepwater drilling environment. This methodology should reduce the cost of drilling operations, particularly in locations with shallow-water-flow potential.

The development and operation of a new drillstring-integral shoe test packer system will be described that allows isolation of the bottom of a shallow-set casing string for purposes of pressure testing the shoe. This provides the operator with a method to verify shoe integrity prior to drilling into high-pressure sands, which have potential for water flow1, with fewer drill pipe trips.

The paper will also present a detailed case history of how this method was applied for a major offshore operator from a floating vessel in 4,000 ft of water in the Gulf of Mexico. For this application, shoe-testing of the 30-in. casing string was critical to check for resistance to potential shallow-water-flow reaching the surface. This test operation was also performed riserless, without a means to perform the shoe pressure test other than the drill pipe string. If the shoe test proved successful, the operator could continue drilling the next wellbore section without pulling the workstring, thus streamlining the operation and saving time.

Performance criteria required by the operator, the design methodology used to meet those criteria, qualification testing and field performance in initial operations, including time savings from the one-trip system will also be discussed.
Evaluating Hydraulic Fracturing in Cased Holes Using Cross-dipole Acoustic Technology
Authors: Tang X. M. , Patterson D. , Hinds M. , Cheng N. Y.
Published: December 2007

A cross-dipole technology was used to evaluate a carbonate formation in Southeastern New Mexico to determine fracture trends in a water-flooded environment. The measurements were first made in openhole, then in casedhole before and after fracture stimulation. The cross-dipole data were processed to find the amount of anisotropy and the associated azimuth. The results demonstrate that stimulated fractures create a substantial anisotropy and well-defined azimuth behind casing. More important, by evaluating the anisotropy value and the azimuth from the casedhole data, we can determine the fracture extent along the borehole and its azimuth in the formation. The fracture extent is also consistent with that from a radioactive tracer measurement. The results of this study suggest that cross-dipole acoustic logging is an effective technology for casedhole fracture stimulation evaluation.
New Cementing Technology Cures 40-Year-Old Squeeze Problems
Authors: Farkas R. F. , England K. W. , Roy M. L. , Dickinson M. , Samuel M. , Robert E. Hart
Published: December 2007

Remedial cementing using recently developed engineered micro-cement slurries allows small channels to be efficiently filled with cementitious materials, developing a permanent, high quality seal with high compressive strength and low permeability. Deeper penetration is achieved over conventional micro-cement slurries by improving axial fluid loss control through particle size distribution adjustments, and not from using small particles alone. This new technology has been extremely effective in remedial cement squeeze treatments, where synthetic and conventional cement systems have failed over the past 40 years.

The packing volume concept separates engineered slurries from conventional slurries. Engineered micro-cement slurries incorporate a particle size distribution that allows deeper penetration without bridging, premature viscosification or dehydration. The slurry has extremely low fluid loss, low plastic viscosity, lower yield points and better slurry stability with respect to free water and sedimentation. This slurry has superior injectivity over previous oil field cements, however, placement procedures do not follow conventional cement squeezing wisdom. When this material is placed into the channel, crack or perforation, the typical increase in pressure response that is seen during conventional squeeze treatments may not be observed.

This technology has been proven to be successful in more than forty wells to-date. In the New Hope field of East Texas, and in particular the Bacon and Hill Sand formations, up to nine squeeze attempts were performed on individual wells, without establishing a permanent hydraulic seal using various conventional cement systems and techniques. Conversely, in the same field, seven barrels of the engineered micro-cement slurry were placed on the first attempt, achieving the isolation required for re-completion. The application of this technology has also experienced good success in the Canadian shallow gas, and heavy oil markets. The shallow gas fields are located in Southeastern Alberta, near Medicine Hat, and the heavy oil fields are located in Northeastern Alberta in the Wainwright area.
Interpretation Of Chemical And Physical Measurements From An In Situ Coal Gasification Experiment
Authors: Brandenburg Charles F. , Reed Ray P. , Boyd Michael R. , Northrop David A.
Published: December 2007

Brandenburg, Charles F., Laramie Energy Research Center, U.S. ERDA, Reed, Ray P., Sandia Laboratories, Albuquerque, Boyd, Michael R., Laramie Energy Research Center, U.S. ERDA, Northrop, David A., Sandia Laboratories, Albuquerque and Jennings, James W., University of Wyoming and Laramie Energy Research Center, U.S. ERDA.

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

A second underground coal gasification experiment is being conducted at the Laramie Energy Research Center's field site near Hanna, Wyoming. This paper presents the results from the first phase of this Hanna II experiment in which coal seam permeability was evaluated, pneumatic linking and linking via reverse combustion were studied, and a sustained gasification process was maintained between the two linked vertical wells. Extensive in situ and surface process instrumentation have provided considerable information on the chemical and physical mechanisms involved in underground coal gasification. Air injection alone did not increase permeability to levels which would allow sustained gasification. Reverse combustion linking was determined to be a local, relatively low temperature process which advanced at a 5 ft/day rate and produced a high permeability carbonized path, Subsequent gasification was completed over a 38 day period. Overall, injection of 1.9 MM scf/day of air yielded 2.7 MMscf/day of gas with a heating value of 152 Btu/scf. Material balance calculations indicate that 1688 tons of coal in place were utilized. Specific discussion of reaction front configurations and interpretation of in situ thermometry are included.

Introduction

Underground coal gasification (UCG) has been the subject of investigations for more than 100 years. The process has been shown to be technically feasible in several experiments, but previously has been economically unattractive in competition with petroleum resources. The recent development of shortages of inexpensive petroleum fuels has resulted in rekindled petroleum fuels has resulted in rekindled interest in research on efficient in situ gasification of coals in the United States using modern techniques which were not available to earlier investigators.

Russian activities in underground gasification of coal have been the most sustained. Electricity has been generated from low Btu gas at several large scale plants in the Soviet Union from plants in the Soviet Union from subbituminous coals and lignites since 1960. Recently, diminished Soviet utilization of UCG for energy production is believed due to the discovery of adequate local petroleum fuel sources.
Foamy Oil Flow in Primary Production of Heavy Oil under Solution Gas Drive
Authors: Maini Brij B.
Published: December 2007

Foamy oil flow has received considerable attention in the literature in last several years. It is believed to be a key factor in producing the higher than expected well rates and the high recovery factors observed in several Canadian and Venezuelan reservoirs. However, beyond the recognition that it may involve dispersed flow of gas, there is little agreement as to what the underlying mechanisms are.

This paper presents a new mechanistic model of foamy solution gas drive and experimental evidence in support of the model. The main hypothesis in this model is that foamy oil flow is simply two-phase gas-oil flow at high capillary numbers. It occurs when the viscous forces become strong enough to mobilize gas ganglia growing from bubble nucleation sites.

The evidence in support of the existence of dispersed flow in solution gas drive in viscous oil systems comes from the effect of depletion rate on the performance of laboratory scale solution gas drive tests. These tests show that the high rate of pressure depletion at the production port results in: (1) a much higher oil recovery factor and (2) a high pressure-gradient within the sand-pack. Relatively high pressure-gradient persists throughout the duration of the high rate test and declines very slowly even after the flow has virtually stopped. It implies that the mobility of the free gas is exceedingly small, which strongly suggests that the gas is not continuous. By contrast, a high pressure-gradient never develops in slow depletion tests.

The evidence in support of the suggested form of dispersed flow comes from visual observations in etched glass micromodels. These tests show that the dispersion is not a result of nucleation of a very large number of bubbles but forms by break-up of a much smaller number of nucleated bubbles which become mobilized in the presence of high pressure gradient.

Finally the conditions under which this type of dispersed flow is likely to occur in the field are discussed.
Experimental Modelling of the SAGD Process – Enhancing SAGD Performance with Periodic Stimulation of the Horizontal Producer
Authors: Sasaki K. , Akibayashi S. , Yazawa N. , Doan Q. , Farouq Ali S. M.
Published: December 2007

Experiments on initial stages of the steam-assisted gravity drainage (SAGD) process were carried out, using 2-D scaled reservoir models, to investigate production process and performance. Expansion of the initial steam chamber, its shape and area, and temperature distributions were visualized using video and thermal-video pictures. The relationship between isotherms and steam chamber interface was investigated to study the drainage mechanism. The temperature at the interface where the steam chamber was expanding was observed to remain nearly constant at 80°C. Effect of vertical spacing between the two horizontal wells on oil recovery was also investigated. For the case of conventional SAGD, oil production rate increased with increasing vertical spacing; however, the lead time for the gravity drainage to initiate oil production became longer. The results suggest that L can be used as a governing factor to evaluate production rate and lead time in the initial stage of the SAGD process. Based on these experimental results, the SAGD process was modified: the lower production well was intermittently stimulated by steam injection, in conjunction with continuous steam injection in the upper horizontal injector. Using the modified process (named SAGD-ISSLW), the time to generate near breakthrough condition between two wells was shortened, and oil production was enhanced at the rising chamber stage compared with that of the conventional SAGD process.
Heterogeneity Effects on the Storage and Production of Gas from Coal Seams
Authors: Özgen Karacan C. , Okandan Ender
Published: December 2007

This paper presents the results of the experiments conducted on two structurally different coals from Turkey to investigate the effect of different heterogeneities on gas flow and storage in coal beds. Gas flow experiments were conducted on 3.8 cm diameter core plugs of these coals using xenon as the gas phase. Dual energy CT imaging technique was used to visualize the flow and storage of gas along the coal core to get qualitative and quantitative data from the images. After storage experiments end, nitrogen injection was performed to recover the stored gas from coal to represent an enhanced gas recovery operation. An analytical solution to this phase of one specific experiment was proposed to be able to calculate the diffusion coefficients from the gas recovery data calculated from CT images. The results of the experiments were analyzed to show the storage capacities of these two coals. The effect of different coal structures on the gas transport and storage and the matrix/fracture interactions were discussed by making a pixel based analysis and coupling it with the microstructure of coal investigated with scanning electron microscopy (SEM).

Results show that, if the coal is structurally heterogeneous in the sense that there will be different layers of mineral and organic matrix, there will be different zones that affect the storage and transport of gas. Due to these heterogeneities, gas recovery by nitrogen injection is not efficient at some regions. On the other hand, the coal that is more homogeneous has a higher storage capacity due to its microporous structure. In this coal, even if there are mineral fillings in the micropores, such mineral inclusions do not have an adverse effect on gas storage and transport as evidenced from CT images.
Scaling Up Matrix-Fracture Transfers in Dual-Porosity Models: Theory and Application
Authors: Bourbiaux B. , Granet S. , Landereau P. , Noetinger B. , Sarda S. , Sabathier J. C.
Published: December 2007

The dual-porosity model concept has been introduced to simulate flows through naturally-fractured reservoirs because of the specificity of those media: fluids are mainly stored in the matrix and flow to the wells through the fracture system. A simplified formulation of matrix-fracture fluid transfers at the scale of a simulator cell uses a pseudo-steady-state (PSS) transfer equation involving a constant exchange coefficient also called shape factor. The shape factor has long remained controversial because a theoretical framework was missing and evidence was given of its dependence on the mechanism of flow.

This paper presents different approaches to determine the matrix-fracture transfer behavior and derive the best approximate expression of the shape factor. These methods make use of the joint element technique for discretizing the actual fractured medium and are based on either (a) direct simulation of flow exchanges at local scale, (b) the application of upscaling theory, or (c) the implementation of a novel random walk method.

A resolution example is given for a realistic image of a fractured medium in 2D single-phase flow conditions. The whole process of matrix-fracture transfer, including the initial transient states, has been determined from local-scale simulation. All upscaling methods lead to the same approximate expression of the shape factor to be used in the PSS equation describing matrix-fracture transfer. This shape factor is expressed versus equivalent block dimensions, which are in practice determined with a recently-developed methodology involving geological image processing.

Then, an extension to multiphase flow conditions is presented. The local-scale simulation approach is used to compute the exact transient water-oil capillary transfers at dual-porosity cell scale. These transfers are quite well reproduced with a PSS formulation incorporating the shape factor expression defined for single-phase transfers. A transient shape factor, formulated versus simulator unknowns, has also been tested. It turns out that capillary transfers can be reproduced with a dual-porosity simulator without resorting to any parameter tuning.

To conclude, reliable simulation tool and upscaling methods are now available to compute matrix-fracture transfers on actual fractured media and derive the optimal PSS formulation to be used in dual-porosity simulators.
Achieving Technical Excellence and Improved Results through a Strategic Business Alliance
Authors: Chmilowski Walt , Dole Stephen A.
Published: December 2007

PanCanadian Petroleum Limited and Dowell, Division of Schlumberger Canada Limited formed a strategic alliance for well stimulation services in 1993. The difficulty of initiating the relationship and then growing the alliance over time has resulted in many challenges and provided many rewards. The working arrangement was built on a win/win philosophy of openness and mutual trust. A shared risk/reward relationship was developed to provide incentive to both companies to continuously improve the process and reduce costs. Objectives of the alliance were to reduce cost per unit of hydrocarbon recovered, improve productivity, and improve the profitability of both companies while maintaining the present outstanding safety and environmental record. Immediate benefits from the relationship were a more efficient usage of resources, reduction in redundancy of efforts between the corporations, better treatment design that resulted in improved well productivity in spite of limited well information. There have been a number of occasions where the relationship has grown and times where the relationship has experienced major challenges. Through the efforts of key team members, issues were resolved with the relationship now stronger than ever and new initiatives for mutual benefit are ongoing.

This paper discusses the real-life issues and positive as well as negative experiences encountered in this business relationship and how its chances of success have been improved by both parties.
Liquid Carry-over in Gas-Liquid Cylindrical Cyclone Compact Separators
Authors: Chirinos W. A. , Gomez L. E. , Wang S. , Mohan R. , Shoham O. , Kouba G.
Published: December 2007

The liquid carry-over phenomenon in Gas-Liquid Cylindrical Cyclone (GLCC©1) compact separators has been studied experimentally and theoretically.

Experimental data have been acquired including the operational envelope for liquid carry-over and percent liquid carry-over beyond the operational envelope. The data show that at low gas and high liquid flow rates, under churn flow conditions in the upper part of the GLCC©, large amount of liquid can be carried over relatively easily. On the other hand, at high gas and low liquid flow rates, under annular flow conditions, one should exceed the operational envelope significantly in order to have large amount of liquid carryover.

A mechanistic model has been developed for the prediction of the percent liquid carry-over beyond the operational envelope, for churn flow conditions. An existing model for the prediction of the operational envelope for liquid carry-over has been extended to high-pressure conditions, including improved models for zero-net liquid flow holdup, droplet region and blowout and critical velocities.

Comparisons between the new mechanistic model predictions for percent liquid carry-over with the experimental data, under churn flow conditions, show a good agreement. Also, in the lack of experimental data, the predictions of the operational envelope for liquid carry-over at high-pressure conditions show reasonable trends.