bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analyzing Gas Well Buildup Tests With Changing Wellbore Storage in Tight Gas
Authors: Lee W. J. , Retna T. , Holditch S. A. , Whitehead W. S. 
Published: December 2007

ABSTRACT
Pre-fracture pressure buildup tests in tight gas formations can be extremely difficult to analyze correctly, particularly when large pressure drawdowns precede the shut-in period. A major source of difficulty is the wellbore storage coefficient, which changes continuously throughout the test and which can change by one to two orders of magnitude from beginning to end of the test. This change causes particular problems in type-curve analysis; in turn, this can cause serious difficulties in recognizing when, if ever, the semi-log straight line with slope related to formation permeability appears. As a result, buildup test analysis results can be the subject of great controversy and uncertainty.
This paper summarizes research which shows conditions under which changing storage coefficient causes interpretation problems and which also shows how the use of Agarwal's pseudo-time function can resolve the difficulties. Simulated buildup test analyses are used to show the problem and its solution. Several actual tests from tight gas formations also illustrate the difficult-to-analyze shapes suggested by theory, and the correct analysis of these tests is presented.
An Automated Method of Matching Production Performance Using Dimensionless Solutions
Authors: Holditch S. A. , Gatens J. M. , McVay D. A. , Lancaster D. E. 
Published: December 2007

Abstract
It is widely recognized that U.S. gas reserves can be substantially increased if gas from tight reservoirs can be more economically developed1,2. One of the main problems hindering the development of tight reservoirs is the general lack of adequate reservoir description. One of the best techniques for reservoir analysis is pressure buildup testing. In tight gas reservoirs, a buildup test which will adequately describe a large portion of the reservoir requires that a well be shut in for several weeks or months. Many operators run these long pressure buildup tests both before and after a well has been fracture treated. If such tests are run, an acceptable description of the reservoir and fracture can be obtained using reservoir simulation history-matching techniques3.
Even when the pressure buildup tests are correctly run and interpreted, it is difficult to determine the areal extent of reservoir drainage. To determine drainage area, several years of production data are normally required. Therefore, to completely define a tight gas reservoir, the information obtained from the analysis of pre-fracture pressure buildup data, post-fracture pressure buildup data, and long-term production data must be combined4.
The most important problem to be solved in the development of a tight gas reservoir is determination of the optimum fracture length. The optimum fracture length is a function of reservoir permeability, gas in place, and future net revenues and can best be quantified as a fraction of the drainage radius. To determine the optimum fracture length, it is necessary to predict future well performance as a function of effective propped fracture length. The effective areal extent of a reservoir must be known or estimated in order to accurately predict future well performance. Thus, knowledge of drainage area is critical in the determination of the optimum fracture length.
Stress Ratio and Stress Trajectory Simulations for Devonian Gas Shales
Authors: Advani S. H. , Andrews Anthony , Lee J. K. , Komar C. A. 
Published: December 2007

ABSTRACT
A brief review of selected in situ stress studies is presented. Pertinent geomechanical factors and rationale for stress trajectory characterizations are discussed in the context of natural fracturing in geological formations. Examples with structural cross sections incorporating the influence of the Rome Trough are identified and potential mechanisms for in situ stress reorientation and tectonic relief across selected regions in the Appalachian Plateau Province in West Virginia are given. Detailed finite element stress simulations and stress ratios associated with cross sections through Southeastern Kanawha County extending from the Warfield anticline to the Cabin Creek syncline are also reported. A discussion of these results and their correlation with available data and salient structural features is also given. In addition, the role of stress ratios, using a compressive-shear failure criterion, is emphasized in relation to the natural fracture systems in the Devonian shales.
Current Status of the Multiwell Experiment
Authors: Northrop D. A. , Sattler A. R. , Mann R. L. , Frohne K. H. 
Published: December 2007

ABSTRACT
The Multi-Well Experiment (MWX) is a research-oriented field laboratory whose objective is to develop the understanding and technology to allow economic production of the several years supply of natural gas estimated to be within the low permeability, lenticular gas sands of the Western United States. Features of MWX include: (1) three closely-spaced wells (115–215 ft, 35–66 m) for reservoir characterization, interference testing, well-to-well geophysical profiling, and placement of diagnostic instrumentation adjacent to the fracture treatment; (2) complete core taken through the formations of interest; (3) a comprehensive core analysis program; (4) an extensive logging program with conventional and experimental logs; (5) determination of in situ stresses in sands and bounding shales; (6) use of various seismic surveys and sedimentological analyses to determine lens morphology and extent; (7) use of seismic, electrical potential, and tilt diagnostic techniques for hydraulic fracture characterization; and (8) a series of stimulation experiments to address key questions. This paper presents the current MWX accomplishments resulting from the 1983 field season which featured the drilling of a third well and the first stimulation experiment.
Interference Testing of the Naturally Fractured Cozzette Sandstone: A Case Study at the DOE MWX Site
Authors: Branagan Paul , Cotner Gene , Lee S. J. 
Published: December 2007

Abstract
The DOE Multi-Well Experiment (MWX) is a research oriented field laboratory whose objective is to improve the technology and provide additional insight into the processes required to develop low permeability lenticular gas sandstone reservoirs.1 The site of the MWX is located in the Rulison Field in the Piceance Basin of Colorado, as shown in Figure 1.
The MWX consists of three closely spaced wells drilled through the Marine Mesaverde Formation to depths of about 8,000 ft.
A detailed geological and geophysical assessment is a continuous effort being conducted throughout the Piceance Basin and other areas as a means to characterize the salient features of this site. Very extensive core and logging programs were carried out in all three MWX wells with emphasis on the zones of interest. Seismic surveys and sedimentological investigations were conducted to provide an assessment of morphology, areal extent of lenses and others. As a prelude to the intensive reservoir investigations that were scheduled for the lenticular sandstones, several well tests were performed in the blanket Cozzette sandstone. Some of the experiments conducted within the Cozzette included in situ stress testing, several short drawdown and buildup tests as well as a more sustained interference and pulse test that utilized two of the available MWX wells.
The marine blanket Cozzette sandstone characteristically exhibits gas permeabilities on the order of 10 microdarcies or less. However, the production and test data from the MWX site along with subsequent analytic methods require an average reservoir permeability on the order of 100'sof microdarcies. Data obtained from the observation well during the interference test suggests that the pressure distribution from the production well was not radially symmetric and thus the reservoir was modeled as an anisotropic naturally fractured reservoir. Numerical modeling techniques including a dual porosity reservoir model were used to simulate this naturally fractured tight reservoir. Included in our analysis was a parametric sensitivity study for a number of salient well and reservoir parameters, such as wellbore damage and the effects of boundaries.
Several months of sustained winter pipeline production that followed well testing attests to the fact that the natural fracture system within the Cozzette extends over a large area.
This paper details some of the studies carried out in the Cozzette sandstone and includes core analysis, and the results of the MWX well testing.
A Practical Hydraulic Fracturing Model Simulating Necessary Fracture Geometry, Fluid Flow and Leakoff, and Proppant Transport
Authors: Ahmed Usman 
Published: December 2007

ABSTRACT
Hydraulic fracturing model using various sets of fracture flow/geometry equations are available in the industry. The majority of these models assume a constant fracture height selected at the start of the design, and simulate two-dimensional fracture geometry (width and length) and one dimensional fluid flow in both the fracture and the formation. The two-dimensional fracture geometry simulation can lead to optimistic estimates of fracture lengths and the one-dimensional flow may not allow adequate representation of proppant transport and fluid loss. Highly sophisticated hydraulic fracturing models are available that simulate three-dimensional fracture height and two-dimensional fluid flow throughout the entire fracture process. These models are versatile and are recommended for highly complex, layered reservoirs where rock material properties, in-situ stress distribution, and flow properties are variable at the wellbore and also throughout the reservoir. For everyday use by the completion/production engineer, hydraulic fracturing models need to be generated that are more advanced than the "conventional" two-dimensional models but simpler in approach and less costlier than the fully three dimensional models.
The hydraulic fracturing model presented in this paper can be classified as a pseudo three-dimensional fracture geometry accounting for simple two-dimensional fluid flow. Fracture height at the wellbore, width, and length are computed simultaneously. These calculated parameters are then compensated for two-dimensional fluid flow which accounts for friction pressure drop and gravity. An iteration process is set-up until a satisfactory convergence is attained. Knowledge of appropriate fracture geometry and two-dimensional fluid flow enhances the accuracy in fluid loss calculations and proppant transport. Special data required as input to this model include the in-situ stress and mechanical properties distribution in and around the pay zone. The paper presents hydraulic fracturing theory and the basis of the model under discussion. A detailed explanation of the model is also presented where field examples are used to illustrate its use and importance.
Numerical and Physical Studies of Fluid-Driven Fracture Propagation in Jointed Rock
Authors: Shaffer R. J. , Thorpe R. K. , Ingraffea A. R. , Heuze F. E. 
Published: December 2007

ABSTRACT
Hydraulic fracturing in rock masses involves complex and coupled processes of fractures propagating in discontinuous media and of fluid flow in discrete channels. The Unconventional Gas Program at Lawrence Livermore National Laboratory is actively developing numerical models to gain insight in the physics of these coupled processes. However powerful and versatile these models are, they must be verified against analytical solutions and/or physical experiments. This paper describes the current status of the FEFFLAP code, which models fluid-driven discrete fracture propagation in jointed media. We also discuss the results of a preliminary series of physical tests in which hydrofractures were driven across slanted interfaces between dissimilar materials, in blocks loaded in biaxial compression.
Laboratory and Field Evaluation of Fluid-Loss Additive Systems Used in the Williston Basin
Authors: Woo G. T. , Cramer D. D. 
Published: December 2007

ABSTRACT
Many formations in the Williston Basin are naturally fractured limestones and dolomites. Naturally fractured reservoirs are typically the most difficult to maintain control of fracturing fluid leakoff. Treatments in the Mission Canyon, Midale and Ratcliffe formations of the Madison Group have had high fracturing fluid leakoffs. Polymer/inert solids mixtures, 100 mesh sand, silica flour and oil-soluble resins have been used in an attempt to control fluid loss. These additives have not consistently solved the problem of excessive fluid loss, and frequent screenouts, gel-outs or pressure-outs have resulted.
A laboratory simulation of naturally fractured reservoir leakoff was employed to evaluate the efficiency of ten fluid loss additive systems. Tapered-slot fluid loss tests and proppant pack damage tests were performed using each additive system. Five fluid loss additive systems were identified which performed well in both tests.
This paper also summarizes the results of a field evaluation of nine of the original ten fluid loss additive systems used in 70 wells in the Madison Group. Two fluid loss additive systems, a mixture of silica flour and 100 mesh sand, and a mixture of oil-soluble resin (nominal 250 mesh) and 100 mesh sand, performed well in the laboratory tests and had a high success rate in the field.
Controlling Cement Circulation Loss to Both High-Permeability and Fractured Formations
Authors: Nayberg T. M. , Linafelter R. L. 
Published: December 2007

ABSTRACT
A polymeric material is described which has been developed for controlling lost circulation during cementing. The morphology of the material permits sufficient particle deformation to optimize plugging of high permeability matrices, while the particle size of the material is precisely sized so as to optimize sealing of fractures. This optimization of morphology and particle size distribution enables the material to effectively control cement circulation loss to both high permeability and fractured formations.
Laboratory data are presented comparing the relative effectiveness of the new material, gilsonite, gilsonite plus cellophane flakes, crushed coal and a graded plastic material in controlling cement slurry loss to simulated high permeability and fractured formations. In simulated high permeability formations the new material outperforms gilsonite and gilsonite plus cellophane flakes, and is slightly better than crushed coal. In simulated fractured formations this material outperforms a graded plastic material.
It is shown that the new material does not appreciably affect thickening time or compressive strength of the cement slurries. Free water data for the cement systems tested with this material are satisfactory, but gel should be added to some systems to optimize this slurry property.
Wyoming Overthrust, Williston Basin and Powder River Basin case histories are presented which demonstrate the effectiveness of this new material in areas where severe lost circulation problems have been encountered. It has been used to control cement circulation loss in wells with both high permeability and fractured formations, in wells with high bottomhole static temperatures and in applications requiring flow through downhole tools.
Reservoir Characterization by Analysis of Light Hydrocarbon Shows
Authors: Haworth J. H. , Sellens M. P. , Gurvis R. L. 
Published: December 2007

ABSTRACT
The use of mathematical treatments of light hydrocarbon gas shows in the qualitative analysis of reservoir characteristics has been attempted by many authors over the years. Most of the techniques were originally designed for steam-stilled mud samples or drillstem test analysis and then adapted for mudlog shows. They have, however, been limited by the number of samples it is possible to plot on the specialized grids without losing interpretational value.
A study using a large number of mudlogs from many different geological environments, including the Overthrust Belt and Williston Basin, was conducted using computer-generated plots of the various mathematical treatments of mudlog gas shows. The aim of the study was to produce a method of reservoir chracterization using hydrocarbon gas shows that was relatively simple to calculate, plot and interpret. The method should also be capable of integration with other data such as wireline logs and mudlogs; hence it should be able to be plotted on a depth log without losing any interpretational value.
From this study a new method was evolved which employs mathematical treatment of mudlog chromatograph data which can be performed at the wellsite during drilling; by study of the signature produced, initial evaluation of reservoir characteristics is possible.
An Investigation of Three-Phase Relative Permeability
Authors: Manjnath A. , Honarpour M. M. 
Published: December 2007

ABSTRACT
A critical review of all known experimental and mathematical methods to predict three-phase oil relative permeability is presented, and factors affecting laboratory relative permeability determination are discussed. Imbibition three-phase oil relative permeability have been generated for water-wet systems from Owen's and Archer's two-phase data using Nolen's and Naar and Wygal's models; and a comparison of these two models has been presented. Corey's correlation has been used to generate three-phase oil isoperms in a system where gas displaces oil and water using Donaldson and Dean's three-phase data. Predicted data from Corey's correlation has been compared with Donaldson and Dean's experimental three-phase oil isoperms. Large discrepancies are noticed, expecially at low oil saturations.
This paper also gives a preliminary result of steady-state three-phase experimental work in progress. Studies have been conducted using refined non-polar oil, brine, and nitrogen gas. A modified Penn State method and Berea sandstone have been used. Apparatus has been assembled for such studies involving the flooding of the core with nitrogen while varying the saturations of oil and brine. Brine saturation is determined by electrical resistivity measurement, oil saturation is obtained gravimetrically, and the gas saturation is the difference of the pore volume and the total liquid saturation. The core holder allows simultaneous measurement of (1) resistivity by the four electrode method, and (2) pressure differential across the core while the fluids are flowing.
Improved Drainage of Sand Pack Enhances Fracturing Fluid Recovery and Increases Production
Authors: Phillips A. M. , Wilson W. J. 
Published: December 2007

ABSTRACT
A technique for improving stimulation fluid recovery has been developed in the laboratory arid has proven effective in field applications. The method involves improving proppant pack drainage and minimizing capillary pressure in the formation through the judicious application of surface active agents.
The technique is particularly applicable in low pressure oil wells and tight gas reservoirs, and may be used in all aqueous fracturing treatments. These include slick and gelled water, as well as foamed and crosslinked systems. The technique involves the use of a solvent in the pad fluids and a surfactant system throughout the entire fracturing treatment. This combination improves sand pack drainage and minimizes capillary water blocks in the invaded formation, while maintaining the water-wet condition of both the proppant pack and formation.
The results of field applications using this technique have shown great improvement in the recovery of aqueous stimulation fluids in both sand and limestone formations. Increases in initial hydrocarbon production have also resulted. Case histories are presented from both oil and gas wells in a variety of formations.
The Influence of Geometry Upon Acoustic Logging Signals
Authors: Vogel C.B. , Hubbard W.M. 
Published: December 2007

Abstract
The effects produced on velocity logs by acoustic signal variations as they are related to the geometry of the borehole and sonde are discussed in this paper. All presently used velocity logging devices measure the time required for an acoustic wave traveling in a borehole to assume successively at two closely spaced depths a certain arbitrarily chosen amplitude. The indicated specific acoustic delay, or reciprocal velocity, is a function not only of the velocity of the formation, but also of the character of the acoustic wave at the two depths. Shell Development Co. has developed a device which records both a log of acoustic delay vs depth and an oscillogram record of the acoustic signals produced within the borehole. The oscillogram records provide a continuous calibration of the logs and afford an opportunity for evaluating basic data. The logs and oscillogram records are described and illustrated.
Oscillogram records and laboratory experiments indicate that acoustic signal variations related to geometrical factors can have a significant effect on the accuracy of velocity logs. Borehole signals can be classified as early arrivals if they represent waves having the velocity and travel path of first-arriving compressional waves. Signals not satisfying these conditions can be termed late arrivals. It appears that the amplitude of early arrivals may be greatly reduced by interference effects where the borehole is enlarged, where there is a deep disturbed zone in shale, or where there is an abrupt diameter variation. These interference effects may cause erroneous readings on the velocity log. The best method of avoiding these errors is to measure travel-time between early phases of the received signals. The use of later phases is not likely to produce substantial errors in sands and carbonates but may do so under unfavorable conditions. The use of centralizers reduces these interference effects.
Late-arrival signals generally have large amplitudes and are observed only on oscillogram records made with reduced amplification. In presently used instruments, these signals represent waves which travel with the velocity of first-arrival waves but with different travel paths; or they represent waves which travel with a velocity slightly lower than that of drilling fluid. Interference between these signals and early arrivals will produce phase shifts which may result in erroneous indications on the velocity log if the late arrivals are used to measure travel-time. Again, the method of avoiding these errors is to measure travel-time between early phases of received signals.