bluuebunny/crossref_metadata_2025 huggingface dataset:
Partially Penetrating Fractures: Pressure Transient Analysis of an Infinite Conductivity Fracture
Authors: Rodriguez Fernando , Horne R. N. , Cinco-Ley Heber
Published: December 2007

The effect of the partial penetration of an infinite conductivity fracture on the transient pressure behavior of a vertically fractured well is investigated.

Analysis of results shows that the pressure behavior of a well intersected by a partially-penetrating infinite conductivity vertical fracture can be divided into three flow periods: 1) the early time flow period which is characterized by a formation linear flow as in the case of a fully-penetrating infinite-conductivity vertical fracture, 2) the infinite-acting flow period and 3) the pseudoradial flow period which develops after the effects of the vertical boundaries of the reservoir are felt in the pressure behavior of the well.

A log-log graph of log(hf/h)pwD versus log tDxf shows a slope of one half during tine early time How period of a well with an infinite-conductivity partially penetrating fracture. The time for the end of the early time flow period is directly related to the square of the dimensionless height of the fracture, hfD, which is defined as the ratio between the height of the fracture and its half length. This time becomes so small for small values of hfD that the linear formation flow period will not show up for practical purposes.

The solutions during the infinite-acting flow period are, for the different values of penetration ratio and a given value of hfD, characterized by a single envelope curve in the log-log graph previously mentioned.

The time for the start of the pseudoradial flow period shows no dependence on the penetration ratio and on the dimensionless fracture height except for fractures with dimensionless heights larger than about 1 and penetration ratios smaller tha 1/5.

Even though solutions were mainly obtained for the case of a fracture located at the middle of the formation, the effect of offsetting the fracture was investigated for some particular cases. As expected, the solutions are the same up to the end of the infinite acting flow period which slightly varies as a function of the fracture location.

The solutions are presented in the form of type curves suitable for transient pressure analysis procedures.
Prevention of Calcium Carbonate Precipitation From Calcium Chloride Kill Fluid in CO2-Laden Formations
Authors: Kapelke M. S. , Caballero E. P.
Published: December 2007

Water containing high concentrations of calcium chloride can now be efficiently used as a kill fluid in production wells having heavily laden carbon dioxide formations. This investigation has determined that the amount of calcium carbonate scale normally produced under these conditions can be reduced by increasing the carbon dioxide partial pressure and increasing the tubing pressure leading from the casing annulus.
An Evaluation of Analysis Methods Used To Estimate Well Damage From Pressure Buildup Tests in the Prudhoe Bay Reservoir
Authors: Jones K. D.
Published: December 2007

This work shows that effective well damage determination from pressure buildup tests in complex, developed reservoirs may be best achieved through early time data analysis. Extensive analysis was done using field data from the Prudhoe Bay reservoir in Alaska· Conventional Horner analysis is largely ineffective in this reservoir because of distortion of the late time data by boundary effects. The early time data are affected by partial completion of a large net pay zone. Five different analysis techniques were used to analyze the pressure buildup data. Results from these methods were correlated with production histories and scale damage removal treatments on thirty-two Prudhoe Bay wells. A radial implicit simulator was also used to history match the pressure behavior in several buildup tests to verify the analytic results.

It was found that the McKinley Early Time Analysis Method, modified for partial completion, provided the most reliable estimate of well damage at Prudhoe Bay. The method can provide a qualitative indication of well damage in the presence of a constant-pressure boundary (the gas cap at Prudhoe Bay). The more reliable estimates of well damage allowed us to plan a more effective well stimulation treatment program.
NOX Reduction Methods for California Steam Generators by Applied Technology
Authors: Anderson D. F. , Szytel Thomas
Published: December 2007

In recent years heavy oil operators in California have been required to meet increasingly stringent Air Pollution Control District Regulations, especially regarding NOx emissions associated with Thermal Enhanced Oil Recovery (TEOR) projects. This has resulted in the employment of state-of-the-art NOx control techniques. Of the currently known NOx reduction techniques investigated by TEOR operators, low NOx burners have been most frequently utilized to date. Generally, low NOx burner manufacturers design and construct their burners for a specific set of assumed operating conditions. However, in actual field applications these conditions are not always met, resulting in performance inconsistencies. Field testing has demonstrated that the overall NOx performance of a system is quite sensitive to operational changes. Through applied technology, optimum emission performance can be achieved.
Drain Hole Drilling-An Old Idea Whose Time is Now
Authors: Hyland Craig R.
Published: December 2007

The drilling of horizontal laterals from vertical bores for the production of crude oil has been the subject of recurrent interest for more than a century. Often touted as a cure-all for declining or marginal wells, the use of drainholes has shown some notable successes in spite of deficiencies in technology and the lack of strong economic incentives. Modern engineering's knowledge of reservoir behavior can greatly increase the success of drainhole completions for diverse applications. Today's energy environment offers substantial economic incentives which, together with technological expertise, dictate the wider application of drainhole drilling and production technicques in todays oil and gas industry.
The Technology of Drilling in 7,500 Ft of Water
Authors: Johnson A. S. , Smith G. D.
Published: December 2007

Deep water drilling technology has progressed rapidly since 1965 when the first wells were drilled in Water depths greater than 600 feet (183 m). Since the advent of dynamically positioned drilling vessels in the early 1970's, the move toward deeper waters has seen continuous progress. The state of the art of present day technology in deep water has been demonstrated by Shell Offshore, Inc., utilizing the Discoverer Seven Seas drillship which is currently rated for operations in 7500 feet (2286 m) of water.

Some of the major factors addressed by Shell Offshore, Inc., and Sonat Offshore Drilling Inc., in order to successfully explore for hydrocarbons in 7500 feet (2286 m) of water are the subject of this paper. These include marine riser, BOP controls and station keeping systems. The topics of riser tension required in deep water, riser hangoff requirements and riser recoil systems are discussed. Blowout preventer stack strength, the integration of two different types of positioning systems and reentry techniques are also important and to some extent not previously addressed.

The significance of this technology is that it is specialized to the extent that only one Operator, with its partners, is actively drilling in ultra-deep waters and only one rig is fully capable of completing a 7500 feet (2286 m) water depth drilling program. A tremoundous commitment of resources from Shell Offshore Inc., has resulted in this ability which is clearly on the leading edge of drilling technology.
The Cascade Method for Accelerated Convergence in Implicit Simulators
Authors: Appleyard John R. , Cheshire Ian M.
Published: December 2007

Several iterations may be required when Newton's method is used to solve the fully-implicit reservoir simulation equations. This paper presents a new technique, called "Cascade", to complement the standard Newton method and minimise the number of Newton iterations required at each timestep. The method exploits the use of upstream relative permeabilities to compute saturations one cell at a time, starting with the cell of highest potential and proceeding down the potential sequence to the cell of lowest potential. The power of the technique is demonstrated for highly non-linear problems containing strong counterflow and with saturation fronts advancing through many cells in a single timestep.
Hydrologic Applications Of Lithofacies Clastic-Ratio Maps
Authors: Pettyjohn Wayne A. , Randich P.G.
Published: December 2007

A sequence of lithofacies clastic-ratio maps will reveal the stratigraphy of an aquifer. The use of these maps in conjunction with a study of the water-level fluctuations of wells and streams will aid in determining the relationship of surface water and ground water. In addition, these maps should indicate boundaries and water-table or artesian conditions of aquifers. They may also provide information concerning changes in quality of ground water.

Introduction

Lithofacies maps in combination with several types of ratio maps have been used in stratigraphic studies for many years. The value of these maps for the interpretation and reconstruction of paleogeography is unquestioned. Until the present, however, this concept of map making has not been utilized to a great extent for geohydrologic purposes. Hydrologists have the benefit of numerous complex formulas to be used in the determination of aquifer characteristics but the concept of an aquifer "constant in thickness, infinite in areal extent, homogeneous and isotropic" is one that normal does not exist in nature. Obviously, if aquifer characteristics are dependent on the structure, composition, and lateral and vertical changes in lithology of any water-bearing zone, then one must first determine as accurately as possible the, geology and then select the hydrologic formula that best conforms to the total picture. The collection of hydrologic data by means of pumping or aquifer tests is an expensive and time-consuming process.
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

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

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

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

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

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

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

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

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

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

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

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

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

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.
Effect of Temperature on Drilling Mud Resistivities
Authors: Lynn Ralph D.
Published: December 2007

A cell is described for measuring drilling mud resistivities at temperatures up to 350°F. Rm, Rmf and Rmc were measured at temperatures from 75 to 225°F with 100 psi pressure maintained on the mud system. Hence, Rmc is measured on the undisturbed mud cake under differential pressure. Fifteen synthetic mud samples and 25 field samples were measured. Some of the more important results areThe effect of elevated temperature on Rmf and Rmc is not the same as for NaCl solutions having corresponding resistivities at 75°F.The resistivity ratios, Rmf/Rm and Rmc/ Rm, vary with temperature in a different manner for different muds.Resistivity ratios may be widely different for different muds.Rmc may be different for undisturbed mud cake under differential pressure than when it is disturbed for measurement.Some chemical additives greatly affect the resistivity values as well as resistivity ratios.Mud resistivities may vary widely while drilling.

Introduction

Quantitative interpretation of electric logs requires reliable values for the mud resistivity, Rm, the mud filtrate resistivity, Rmf, and the mud cake resistivity, Rmc, under borehole conditions. For example, the resistivity of the formation water, Rw, is often calculated from the self-potential curve by the equation:

In this equation, K has a value which is relatively constant for certain conditions of lithology and borehole temperature within a specified area. Thus, in the use of this equation to find Rw, it is evident that an error in the determination of Rmf will result in an error of like magnitude in the calculation of Rw.

Rm is sometimes measured in the borehole with the collapsed microsonde but it is more difficult to make routine measurements of Rmf and Rmc under borehole conditions. When these resistivities are determined by sample measurements at the surface the correction to borehole conditions is of major importance. Temperature, pressure and differential pressure are some physical fact is that may affect resistivity values but temperature is by far the most important. Loan found no measureable effect of pressure on Rm up to 1,000 psi, but he found that Rmf and Rmc are affected by differential pressure. For differential pressures of 100 psi and 1,000 psi, Rmf was as much as 20 per cent greater for the higher pressure but Rmc was as much as 10 per cent smaller for the higher pressure.
The Phenomenon of Free Fall During Primary Cementing
Authors: Beirute R. M.
Published: December 2007

For many years the oil industry has been performing primary cementing jobs perhaps without a complete understanding of the actual flow behavior of the fluids in the well during the cementing operation. It is well known that in many jobs the well "goes on a vacuum", "U tubes" or "free-falls" while the heavy fluids (cement slurries, spacers) are being pumped down the casing. When this occurs, one loses control of the job rates since the column of fluids in the casing free-falls at rates different than the pump rates at the surface. During the first stages of free-fall, the free-falling column of fluids accelerates and the free-fall rate is larger than the surface pump rate. This early acceleration causes a "partially empty" or "discontinuous" zone or gap to form between the free-falling column of fluids and the wellhead. It is possible that this initial acceleration is not detrimental to the cement-mud displacement process, unless the job was designed to be pumped under plug flow and the accelerated rates take it out of the plug flow regime. On the other hand, toward the end of free-fall, the free-falling column of fluids decelerates and the free-fall rate can fall below a minimum desired pump rate for turbulent flow displacement. This again can be detrimental to the job success. It is obvious, therefore, that a better understanding of the phenomenon of free-fall and the design of ways to handle it are a must if the industry is going to fully control the mud displacement process.

To gain this additional understanding, a mathematical model simulating the phenomenon of free-fall that often occurs during primary cementing has been developed. The model has been programmed as an integral part of a cementing computer simulator. This paper discusses the free-fall model and reviews information obtained using the simulator that explains and helps in the understanding of the hitherto obscure phenomenon of free-fall. Using the model, it is now possible to obtain a prediction of the expected rate of returns during free-fall, as well as the surface and bottomhole pressures during the job.

Predictions made with the simulator have been checked versus several field cases. The simulator results compare extremely well with the field measurements. Some of these comparisons are included in this paper.
An Integrated Approach to the Modeling of Permeability Barrier Distribution in a Sedimentologically Complex Reservoir
Authors: Martin J. H. , Cooper J. A.
Published: December 2007

In a complex clastic reservoir of glaciodeltaic origin - the target for a steam-drive pilot project - low permeability ‘baffles’ seen in cores are difficult to correlate between wells. Their distribution is estimated probabilistically incorporating analogue outcrop data. The resulting model was used to calculate effective vertical permeability to oil, water and steam and to construct a 2-D reservoir simulation model used to determine optimum injection intervals.
Single-Well Pressure Testing Solutions for Naturally Fractured Reservoirs With Arbitrary Fracture Connectivity
Authors: Wijesinghe Aanda M. , Culham Wilmer E.
Published: December 2007

Traditional pressure testing models for naturally fractured reservoirs assume that the rock formation is heavily fractured to an extent that the matrix blocks are completely surrounded by fracture surfaces. Thus, the matrix blocks are unconnected and fluid transport over macroscopic distances can take place only in the fracture network. The model presented here overcomes this deficiency by allowing for matrix and fracture network permeabilities over macroscopic distances; it is thus able to represent moderately fractured formations as well as the limiting cases of unfractured and heavily fractured formations. Also, a new unsteady interporosity fluid flow formulation, which accounts for independent variation of the matrix and fracture system pressures is employed in this model. This feature has not been included in previous interporosity flow formulations.

Analytical solutions and type curves for single-well pressure tests in one, two and three dimensional fluid flow configurations in unbounded domains are presented. Interporosity fluid transfer is modelled using the standard unsteady flow models and the new unsteady interporosity flow formulation. The effects of well bore storage and of the matrix and fracture system skin factors on constant rate drawdown well tests are illustrated through numerical examples. The significance of the special features of this model, namely, that of modelling the macroscopic permeability of the matrix system in addition to that of the fracture system and of using the new unsteady interporosity flow model is demonstrated. The numerical results show that, for moderately fractured formations, significant errors are incurred in the predicted formation properties when matrix block connectivity and the resulting direct fluid transport between matrix blocks are neglected. Also, the results show that the dependence of interporosity flow on the independently varying matrix and fracture system pressures must be accounted for in the interporosity flow model.
Relationship Between Foam Stability Measured in Static Tests and Flow Behavior of Foams in Porous Media
Authors: Maini B. B. , Ma V.
Published: December 2007

Selection of a suitable foaming agent for mobility control in steam floods requires screening a large number of available surfactants. Many different screening strategies have been reported in the literature for this purpose. Almost all of them rely on some type of foam stability measurement for initial screening. However, the relationship between such foam stability measurements and the flow behavior of foams in porous media under steam flood conditions has not been thoroughly investigated. The objective of this study was to determine whether or not a correlation exists between the foam stability index measured in static tests and the mobility reduction characteristics measured in a porous medium.

Foam stability tests were performed under ambient conditions and under conditions of high temperature (200°C) and pressure (6.9 MPa). Foams were generated by injecting nitrogen gas through a gas sparger submerged under the test solution in pressure vessels equipped with glass windows. Subsequent drainage of liquid from the foam as well as rate of decay of the foam volume were then monitored. The mobility control characteristics were measured at 200°C and 6.9 MPa by monitoring the pressure drop across a 30 cm long and 5.7 cm diameter core composed of unconsolidated sand during steady-state flow of foam through the core. Various foams were compared in terms of their mobility reduction factor which represents the ratio of pressure drop across the core at given flow rates of the foaming liquid and gas to the pressure drop obtained at identical flow rates with pure water and gas.

The results show that foam stability measurements made under ambient conditions do not provide an indication of how the foam will perform at high temperature. However, foam stability measurements performed at high temperature and pressure are generally a good indicator of the mobility reduction factor. When comparing different concentrations of the same surfactant, the concentration which provided the maximum foam stability also gave the highest value of mobility reduction factor. When comparing different surfactants, a fairly good correlation was found between the foam stability index and the mobility reduction factor.
Replacement Costs of Domestic Crude Oil
Authors: Kuuskraa V. A. , Morra F.
Published: December 2007

The United States has a rich base of petroleum resources, but replacing domestic oil reserves will be costly and will require advances in technology. In the mature onshore and offshore regions, the bulk of the future oil will be found in small fields. The promise of large discoveries lies in the costly and challenging deep offshore waters and the hostile Arctic. With significant investment in R&D, advanced tertiary recovery methods could also make a major contribution to lower-cost domestic supplies.

The study of the replacement costs of domestic crude oil shows that adequate supplies of lower cost oil could be available through the middle of the 1990s. However, as these lower-cost sources are depleted, replacement costs will begin to escalate rapidly, reaching very high levels after the turn of the century.
Controlling Incompatibilities of Formation and Kill-Weight Fluids during Workover
Authors: Riley S. M. , Potter G. F. , Holmes J. M. , Reeves H. C.
Published: December 2007

Previous attempts to kill water injection wells with calcium-base fluids for workover operations have been unsuccessful due to incompatibilities between the kill fluid and the formation water. Special engineering procedures, supported by comprehensive laboratory screenings, make these operations possible without the formation of damaging precipitates. Laboratory results have demonstrated that scale precipitation can be prevented for at least 10 days with no formation damage. Field data support these results.
Stability Fronts of Permanent Form in Immiscible Displacement
Authors: Jerauld G. R. , Davis H. T. , Scriven L. E.
Published: December 2007

The theory of stability of plane saturation fronts of permanent form in mathematical models of immiscible displacement that was presented in SPE 12691 is developed further. Stability of the saturation profile to normal modes of smal1-amplitude perturbations in pressures and saturation is found by solving the generalized eigenproblem to which linear stability analysis leads. Adaptive discretization into subdomains, simple finite element basis functions, and the Galerkin method are used to compute the growth or decay rate of incipient fingers of small and moderate width across the front. An expansion for large wavelengths is used to derive an analytical formula for the growth or decay rate of very wide fingers.

A generalized mobility ratio, the sum of the mobilities of the two phases far behind the front divided by the sum far ahead, proves to be the first determinant of front stability: ratios larger than unity indicate instability and less than unity, stability. Gravity acting on the density difference between the phases is the second determinant. Incipient narrow fingers are always damped by capillary pressure gradient-driven flow. When the front is unstable there is a fastest growing wavelength, or width of incipient finger — a most dangerous mode. The growth rate of a given wavelength disturbance depends on its length in the flow direction. The greater that length, the faster growing a disturbance of given wavelength. Thus the results indicate that (1) stability depends on the dimensions of the reservoir or core being modeled, and (2) rate of development of fingering depends on the lengths of heterogeneities that disturb the flow.
Sweep Improvement Scoping Studies
Authors: Fussell L. T.
Published: December 2007

Results of a series of reservoir performance predictions investigating simulated effects of sweep improvement methods on oil recovery and economic benefit are presented. In all predictions, the simulated recovery method was an alternate gas-water injection process with operation under parting pressure assumed. Both reservoir modification and process modification techniques are considered as well as variations in treatment interval, reservoir description, gas-water injection ratio, and operating costs.

These studies indicate selective placement of sweep improvement agent is the most important requirement of the variables considered in effecting a successful sweep improvement treatment. Improved oil recovery was predicted for applications with selective placement in reservoirs described with noncommunicating zones, with significant economic improvement dependent on increased gas-water injection ratio and/or high operating costs. Most simulations of sweep improvement applications in reservoirs described without flow barriers between zones resulted in reduced oil recovery and poor economic performance.
A New Fracture Gradient Prediction Technique that Shows Good Results in Gulf of Mexico Abnormal Pressure
Authors: Brennan R. M. , Annis M. R.
Published: December 2007

Accurate formation fracture gradient prediction in abnormally pressured wells is one of the most critical considerations involved in planning a successful drilling operation. Shallow abnormal pressure, coupled with deep geologic objectives, requires an accurate fracture gradient prediction to insure casing setting depths are correctly determined in order to carry sufficient mud weights to successfully reach the deep objectives. In an effort to better meet these requirements, a study of formation fracture gradients was made for the Western and Central Gulf of Mexico. As a result of this study, a new technique was developed which accurately predicts fracture gradients in the abnormally pressured formations. This technique is based on an empirical correlation of Effective Horizontal Stress Gradient to Effective Vertical Stress Gradient.