Documented field results of vertical hydraulic fracturing suggest that quite often the created fracture migrates vertically away from the formation of interest (the hydrocarbon-bearing zone), thereby producing undesirable results. The single set of information needed to help answer questions concerning fracture migration consists primarily of in-situ stress, tensile strength, and primarily of in-situ stress, tensile strength, and elastic constants of the rock material in and around the formation of interest.
This paper describes the use of full waveform data from a sonic wireline tool to determine the relative stress distribution and the resultant induced hydraulic fracture height. Compressional and shear wave slowness, derived from the sonic waveforms, are used to calculate the dynamic elastic rock properties. A transversely isotropic model is used to compute the in-situ stress from the elastic properties. Advantages of the use of wireline measured data are discussed, as are the limitations of the technique. Final evaluation of the technique is shown through the comparison of predicted and poststimulation measured vertical predicted and poststimulation measured vertical fracture height. Two field cases are presented to illustrate the technique.
With the recent advent of uncertain prices for oil and gas, the importance of efficiently developing hydrocarbon resources has increased significantly. Many costs are relatively fixed and cannot be greatly impacted by improved technology. However, new technology can make significant contributions in hydraulic fracturing operations. Often, a hydraulic fracturing treatment not only represents a large fraction of initial well costs, but also determines the economic viability of a particular well or field. Too large a fracture treatment can be an unnecessary waste of completion funds, while too small a treatment may result in such inefficient drainage of the reservoir as to make a well unprofitable. Because of this economic double-edged sword, a hydraulic fracturing treatment must be designed which best exploits the reservoir.
Much research, both theoretical and applied, has been conducted in recent years toward greater understanding and control of fracturing treatments. Although several general three-dimensional computer-based models have been developed, their application has often been limited because of poor input data. Consequently, many rule-of-thumb schemes are often employed for local areas. When the proper input data are available, most of the more sophisticated models can predict the size and shape of a created fracture. Therefore, powerful tools exist in the industry for efficient fracture treatment design but have been underutilized for lack of sufficient field data. The consensus among investigators is that the information most needed for making realistic fracture geometry design decisions consists of the elastic parameters of the rock, the in-situ stress conditions, and the created fracture height.
In general, this information has been unavailable except on a relatively few research type operations. Therefore, data from a few wells are being extrapolated for use over large regions so that predictions from even the most sophisticated models often have a large degree of uncertainty. Usually, the greatest uncertainty about the created fracture geometry arises from the estimation of the vertical migration or height of the fracture with changes in treatment pressure and pumping conditions. A majority of hydraulic pumping conditions. A majority of hydraulic fracturing models require a realistic fracture height as an input.
Tailored pulse loading is a descriptor for intermediate strain rate rock fracturing processes. These processes are capable of generating multiple fractures in the reservoir rock when the proper energy- time profile is applied to the wellbore. Such multiple fracture networks have a high probability of intersecting natural probability of intersecting natural fractures; hence initial applications have focused on low permeability, naturally fractured formations.
Tailored Pulse Fracturing, a tailored pulse loading process, has undergone pulse loading process, has undergone developmental testing in the San Andres formation in the Permian Basin. These tests have provided insights into the fracture characteristics and the production effects of multiple fracture networks. Concurrently, mathematical models have been developed to predict the performance of Tailored Pulse predict the performance of Tailored Pulse Fracturing.
Discussed in the context of explosive and hydraulic fracturing, predicted fracture lengths and widths are presented as a function of applied energy and formation properties. Productivity indices are proposed properties. Productivity indices are proposed based on multiple fractures affecting changes either in effective reservoir permeability or effective wellbore radius. permeability or effective wellbore radius. Enhanced production results indicate either natural fracture intersection or a synergistic blend of production mechanisms.
Field tests in the San Andres are discussed and production data are analyzed. The data is interpreted as indicating long fractures (greater than 100 feet) can be created and that long term conductivity is maintained.
Increasing interest is being directed at tailored pulse loading processes for the stimulation of oil and gas wells, with emphasis on the Devonian shale formation of Appalachia. The basis for this interest is the potential of these technologies to create a network of multiple fractures. In naturally fractured reservoirs, such a fracture network should, it is hypothesized, have a higher probability of intersecting the far-field natural fractures than the networks created by explosive or hydraulic fracturing processes.
Current state-of-the-art fracturing processes have serious limitations with processes have serious limitations with respect to their application to naturally fractured formations.
Explosive fracturing, through stress waves, creates a highly fractured region around the wellbore, less than 10 wellbore radii in extent. Subsequently, the gas pressure extends a few of these fractures farther into the reservoir, perhaps 50 to 100 wellbore radii. perhaps 50 to 100 wellbore radii. Because of the high pressures created by the detonation of an explosive >1,000,000 psi), this process is restricted to uncased psi), this process is restricted to uncased wells. More importantly, these extremely high pressures exceed the dynamic compressive yield strength of the wellbore rock. The resultant permanent rock compaction produces a very low permeability barrier at the wellbore. If no sloughing off of this barrier occurs, a net reduction in flow from the reservoir to the wellbore will result, regardless of the fracture network established. Even without this permeability barrier, effective explosive permeability barrier, effective explosive fracturing would be restricted to those formations with a high natural fracture density because of the relatively short fractures created.
Roodhart, L.P., Koninklijke/Shell E and P Laboratorium SPE Member
Experimental results of the settling of spherical particles in flowing non-Newtonian fracturing fluids show that Stokes Law based on "Power Law" viscosities is insufficient to predict particle fall rates in both flowing and quiescent fluids.
In a stagnant fluid the experimental settling velocities are more than an order of magnitude higher than those calculated, while in a flowing fluid, settling is lower than that calculated. These phenomena can be explained by extending the "Power Law" model with a zero shear viscosity and by assuming an anisotropic viscosity in a flowing fluid.
Anisotropy in the viscosity only becomes important above shear rates of, say, 25 s-1, and so will not play a role in the majority of fracturing treatments where average shear rates in the fracture will be below this value.
In a hydraulic fracturing treatment, a fracture is created from the wellbore by rupturing the formation at high pressure by means of a fracturing fluid. A propping material, carried by the fracturing fluid, is placed in the induced fracture channel to prevent the fracture from closing placed in the induced fracture channel to prevent the fracture from closing after the fluid pressure has been released. The productivity improvement is mainly determined by the propped dimensions of the fracture, which in turn are largely controlled by the settling velocity of the proppant in the frac fluid. A high settling velocity will result in the formation of a proppant bank at the bottom of the fracture. A very low settling velocity proppant bank at the bottom of the fracture. A very low settling velocity will permit the proppant to remain in suspension distributed over the total fracture height.
On account of their highly non-Newtonian fluid characteristics, the common fracturing fluid possess completely different properties under shear and under stagnant conditions. In the calculation of proppant settling velocities, two distinct shear regimes must therefore be distinguished:
1. During the hydraulic fracturing treatment, when the fluid is being pumped.
2. During closure of the fracture following the treatment, when the fluid is essentially stagnant.
In both cases knowledge of the setting velocity of a single sphere is the first step in understanding of the complex transport process leading to the final proppant distribution in the fracture.
There are few published experimental results of the settling of proppant in a quiescent or a flowing fluid. The build-up of a proppant bank from a non-Newtonian fluid in a vertical slot flow model was studied by Schols and Visser and Babcock. Several others studied the settling of single particles under shear in concentric cylinder devices, a moving belt particles under shear in concentric cylinder devices, a moving belt parallel plate model, or in vertical slot flow model. parallel plate model, or in vertical slot flow model. Each of the authors report findings which deviate from Stokes' Law settling velocities in sheared fluids ad well as stagnant fluids, but no good explanation was found for this anomalous behaviour.
This paper provides an explanation for such behaviour by using a description of the rheological behaviour which accounts for the zero shear viscosity of the fluid, and by introducing the concept that the resistance to motion across the flow is different from the resistance to motion in the direction of flow. For conceptual ease, this is best described by the term "anisotropic apparent viscosity". However, one must realise that the term viscosity can not be uniquely defined for a non-Newtonian fluid.
This paper presents geologic and reservoir parameters of the Niobrara Formation In Weld County, Colorado. With the use of computer generated contour maps, It is possible to predict favorable areas of profitable possible to predict favorable areas of profitable Niobrara pay. This predictability Is further enhanced when combined with Scanning Electron Microscopy (SEM) analysis and historical production analysis.
The SEM results show that the Niobrara In this region is a micrite and not a true chalk. The porosity Is, therefore, lower than would be expected in a chalk.
The thickness of the second bench and the pore volume appear to have a better relationship to known faults In the Niobrara than present day structure. These parameters were analyzed in order to predict areas of parameters were analyzed in order to predict areas of faulting and fracturing, since these areas are known to have the best potential for Niobrara production. Use of these techniques Indicates that the northern portion of the study area has the highest potential portion of the study area has the highest potential for successful Niobrara wells.
Based on the limited amount of production history available in this region and current market oil and gas prices, the average Niobrara well in this region appears to be uneconomic unless supported by additional production from other horizons. However, computer mapping suggests that current production Is not located in the most promising areas. Greater Niobrara production potential may be found In local areas characterized by greater porosity, thicker benches, and proximity to faults.
The development of cost effective predictive techniques for petroleum exploration has been a continuing quest in the petroleum geology industry. This paper presents one such technique found useful in the Weld County, Colorado, Niobrara Formation of the Denver-Julesburg Basin. More specifically, the data were derived from the Second Chalk Bench of the Niobrara. This bench was selected as It constitutes the most continuous bench across the study area and has the highest potential for commercial hydrocarbon development. The geographical study area consists of 56 townships located in Weld County, Colorado, T1-7N, R61-68W (Figure 1).
The purpose of this paper Is to Identify favorable areas for Niobrara hydrocarbon exploration. Seven critical variables from publicly available well logs were input Into a computer and used to generate a series of contour maps showing present day structure, paleostructure, porosity, thickness, and pore-volume. paleostructure, porosity, thickness, and pore-volume. Two further techniques, Scanning Electron Miscroscopy (SEM) analysis of sidewall coresand historical production analysis, were employed to assist In production analysis, were employed to assist In interpreting and predicting potential reserves. Evaluation of the computer maps, SEM data, and historical production data provided the basis for predicting favorable areas for hydrocarbon exploration predicting favorable areas for hydrocarbon exploration in the Niobrara Formation.
The Niobrara Formation was deposited during the Late Cretaceous Period in the Western Interior Seaway. The Niobrara is divided Into two members: the Smoky Hill Chalk and the Fort Hays Limestone. The upper member, the Smoky Hill Chalk, consists of gray to white chalky shale with three locally massive chalk benches, referred to as benches 1, 2, and 3 (from top to bottom). The Fort Hays Limestone, the lower member, is composed of 25 to 85 feet of chalk and shaly chalk interbedded with thin beds of chalky shale (see Figures 2 and 3),
The Niobrara produces gas from low-relief structures on the east flank of the Denver-Julesburg Basin and the north flank of the Las Animas Arch in Colorado, Kansas, and Nebraska (Smagala, 1981). In Yuma County, Colorado, and portions of the Las Animas Arch, Bench 1 is a high porosity, low permeability reservoir. This differs from the correlative chalk bench in the Weld County Denver-Julesburg Basin which is of lower porosity. This reduced porosity is thought to be due porosity. This reduced porosity is thought to be due to greater depth of burial.
The Niobrara produces biogenic gas In low volumes ranging from 20 to 300 thousand cubic feet of gas per day (MCFGPD) (Lockridge, 1978). Niobrara wells are commonly stimulated with a foam fracture treatment.
The rheological properties of hydraulic fracturing fluids, commonly used in low permeability reservoirs, has been discussed extensively in recent years because of their importance in stimulation treatment design. Rheology of these systems is primarily determined in a coaxial cylinder viscometer primarily determined in a coaxial cylinder viscometer and reported as apparent viscosity. However, many problems have been encountered in obtaining accurate problems have been encountered in obtaining accurate measurements of crosslinked gels due to the fluid slipping at the solid boundaries of the bob and cup. This slip creates an unknown velocity profile across the flow field; in other words, the fluid experiences an unknown shear. Since viscosity, as well as job design parameters n' and K' are the direct result of shear rate and shear stress, determination of the actual shear rate experienced by the fluid is critical. Many instances have been observed where the steady shear measurements indicate that the fluid has little or no viscosity. Yet, accounting for slip at the walls, the fluid is still a viscous crosslinked gel. Only by deter-mining the existence and extent of wall slip of fracturing systems and how to correct for it, can the steady shear data that are utilized in treatment design models be meaningful.
This paper presents the application of a theory to determine 1). wall slip velocities in a coaxial cylinder viscometer 2). corrected shear rate not based on power law parameters and 3). true viscosity of crosslinked fracturing fluids. Data have been taken over a wide shear rate range to distinquish if wall slip is more prevalent at low or high shear rates. Data also show, that for certain mixing conditions of the polymer and crosslinking reagent, wall slip is very significant and the shear experienced by the fluid is less than expected, resulting in higher viscosity values. Methods of gel testing and preparation have been examined and those methods that minimize wall slip will be discussed. In addition, oscillatory shear measurements, which describe gel structure, are shown to further explain rheological behavior in steady shear. Viscosity values corrected for slip will be compared with viscosity values obtained on a closed loop pipe viscometer.
Many efforts have been made to describe the rheology of hydraulic fracturing fluids, with each having the common goal of predicting fluid performance in the field. But because of the varied results that have been reported and the existing non-unifor-mity in test methods, the need for realistic and consistent viscosity values of crosslinked fluids has not been satisfied. Accurate rheological characterization is desirable primarily for treatment design, but also for comparison of competitive fluid systems, or their components, in order to evaluate or improve performance. Although new and variations on-old test procedures have been proposed, many researchers still lack confidence in the accuracy of viscosity data that is reported and used in treatment design. Frustration with these problems has ultimately led to API funded research on rheological characterization of these materials in hope of better understanding their complex rheology.
The typical means for rheological evaluation of fracturing fluids have been rotational viscometers and pipe viscometers. Under most circumstances, these two methods give very different viscosity values for the same fluid. Rotational viscometers generally give higher viscosity values and historically have had a problem with reproducibility. Since water-based crosslinked gels are viscoelastic, some of the reproducibility problem has been attributed to their "rod-climbing" tendency. These fluids may also form a watery layer on the surface if the crosslink density is very high. This surface phenomena creates the possibility of the fluid not adhering to the bob or cup of the viscometer, that is, slipping at the wall of the bob or cup. For these reasons, viscosity results using a rotational viscometer have been discounted to a certain extent.
An improved technique for determination of the Swanson Petrophysical parameter, (S /P )A for correlating permeability with capillary pressure data has been developed. (P /S ) as a function of S , yields a well defined minimum which corresponds to the values of P and S from the Swanson graphical method. The P and S from the Swanson graphical method. The improved technique leads to ease of computer determination of the parameter. The relationships developed by Swanson for correlating permeability with capillary pressure work well for samples with permeabilities pressure work well for samples with permeabilities greater than 10 microdarcies. A new relationship between the Swanson parameter and permeability has been developed for tight gas sands which leads to a more accurate permeability prediction below 10 microdarcies.
Mercury capillary pressure data at wetting phase saturations higher than 50% are approximately a factor of 10 greater than centrifuge air-brine capillary pressure for tight gas sands. This contrasts with the pressure for tight gas sands. This contrasts with the more commonly assumed value of 5. Consequently gaswater relative permeabilities computed from mercury injection capillary pressure data will result in predictions of higher water-gas ratios than the predictions of higher water-gas ratios than the airbrine data. Optimistic cleanup times for tight gas wells completed in water-base fluids would, therefore, be deduced from the mercury injection data.
Tight gas sands are characterized by small pore throats and crack-like interconnections between pores. These microscopic features result in some characteristic macroscopic features such as high capillary pressures, low porosity, high irreducible wetting phase pressures, low porosity, high irreducible wetting phase saturation, and low permeability. The intent of this paper is to examine the effects of these paper is to examine the effects of these microstructural features on air-brine capillary pressure, mercury capillary pressure, absolute permeability, and calculated relative permeability.
A relationship between capillary pressure and absolute permeability was developed by Purcell in his paper which introduced the mercury injection method to paper which introduced the mercury injection method to the petroleum industry. In a response to this paper, Rose pointed out some possible problems in equating mercury capillary pressure curves to air-brine or oil-brine data. Almost concurrently with Purcell's paper, Rose and Bruce presented a derivation of both absolute and relative permeability from capillary pressure curves. Burdine also presented relationships between relative permeability and capillary pressure.
Most recently, correlations between absolute permeability and capillary pressure behavior have been permeability and capillary pressure behavior have been presented by Thomeer and Swanson for sandstones and presented by Thomeer and Swanson for sandstones and carbonates from conventional oil and gas reservoirs. Also, refinements to the earlier capillary pressure-relative permeability equations have been presented pressure-relative permeability equations have been presented by Brooks and Corey. These techniques are very attractive because of their ease of use and because capillary pressure curves, particularly from mercury injection, are relatively easy to obtain.
However, all of the above correlations and equations were developed and/or tested using sandstone samples with permeabilities generally greater than 10 mD. We have extended the Swanson relationship for clean sands to include samples less than 1 microdarcy. In so doing we will present an improved method for calculating the Swanson parameter, (S /P )A ,Hg.
We have measured the air-brine ana mercury injection capillary curves for several samples and will show how the two differ in some typical cases. A new relationship is given for permeability versus (S /P )A from air-brine capillary pressure. As a final exercise we will show how the relative permeability curves, as calculated from the Brooks-Corey equations, are affected by using mercury data instead of air-brine data.
Of the 35 tight gas sand samples examined here, numbers 1 through 18 are Cretaceous Falber sandstone of Western Alberta and 19 through 35 are from the Lower Cretaceous Travis Peak sandstone of East Texas. Sample depths range from 6,000 ft to 8,000 ft. Even though the mineralogical compositions of these two formations are quite different, they are fairly similar in porosity and permeability. porosity and permeability. P. 293
Two stimulation operations have been conducted to date in the paludal zone of the Mesaverde formation in one well, MWX-1, at the DOE's Multiwell Experiment test site in the Piceance Basin near Rifle, Colorado. Problems were encountered in the second stimulation: MWX-1 would not sustain production for several months and post-frac production production for several months and post-frac production was less than pre-frac rates. The laboratory program was expanded to examine these problems and program was expanded to examine these problems and these laboratory studies were integrated with well testing and other data to help explain MWK-1 production behavior. A unique explanation cannot be found production behavior. A unique explanation cannot be found for the failure of MWX-1 to produce; a combination of factors was responsible. Water probably inhibited matrix rock production. A system of naturally occurring microfractures is important in production from the paludal zone and it probably sustained damage by water and fracture fluids. The basic gel degraded slowly because only a small amount of breaker was used. The fracture closure (viscosity break) observed from the volte analysis of the stimulation was not the same as the breakdown of the basic gel. The remedial treatment conducted after the second stimulation was probably too reactive. A list of items has been developed from experience gained both inside and outside the laboratory that shows what work and which procedures should be emphasized or avoided in tight sand stimulations.
Two stimulation operations have been conducted in Well MWX-1 of the Department of Energy's Multiwell Experiment (MWK) in the Piceance Basin near Rifle, Colorado. Zones 3 and 4 of the paludal section of the Mesaverde Formation, shown in Figure 1, were the zones of interest. The first stimulation operation (Phase I, December 1983) consisted of a series of small, unpropped step-rate/flow-back tests and minifracs whose primary goals were fracture diagnostics and containment prediction. The second (Phase II, May 1984) was a larger sandpropped hydraulic fracture treatment with the additional goal of production enhancement.
Production rates of 250 MCFD (3080 m /d) were measured from the two zones together during prePhase I testing. No difficulty was encountered in prePhase I testing. No difficulty was encountered in getting the well to flow after periodic cleanup during the winter after the Phase I operations. However maximum flows of only 200 MCFD (5660 m /d) could be sustained just prior to Phase II operations. Clean-up after the Phase II Phase II operations. Clean-up after the Phase II stimulation was difficult and the well was not capable of sustained flow. A remedial breaker treatment was performed a month later (June 1984) without notable improvement. Sustained gas flow was not realized until mid-July when a revised packer assembly was installed. Nevertheless, rates in excess of 170 MCFD (4810 m /d) could not be sustained during the ensuing post-frac testing period. period. Extensive laboratory investigations were initiated to examine the production problems. These studies involved many aspects of the core program and the analyses which had been performed prior to both stimulation operations.
The purpose of this report is to examine (a) early core analysis data, (b) laboratory core studies supporting stimulation design, and (c) post-frac laboratory investigations and analyses, post-frac laboratory investigations and analyses, and then to integrate these results with field data to clarify and interpret the results of both the Phase I and II stimulation operations. Phase I and II stimulation operations. BACKGROUND CORE DATA
The objectives of the MWX core program are to provide a physical description of the reservoir and provide a physical description of the reservoir and to support well testing and-stimulation. Prior to MWX, there was very little specialized core data (e.g., restored state permeabilities as a function of water saturation, capillary pressures, etc.) available from tight sandstone formations such as the Mesaverde. In fact, many of the first such measurements were made on WWX core.
This laboratory study, using formation cores, addressed problems associated with restoration of gas permeability in problems associated with restoration of gas permeability in core from tight gas sand formations after massive hydraulic fracturing (MHF) treatments. Parametric studies affecting the flow of both brine and gas in these formation cores included the effects of the pressure differential across the fluid invaded zone, permeability, temperature, and gel damage to the fracture surface. Formation damage after exposure to fracturing fluids is primarily a problem of fluid recovery and water-saturation reduction.
Polymer damage to the fracture or fracture surface using Western tight gas sand cores caused significant brine permeability reduction and increased the fluid recovery time permeability reduction and increased the fluid recovery time of the invaded zone. Increased fluid recovery time was magnified for very low permeability formations (less than 0.03 md) and low gas pressure differentials. Capillary end effects are postulated to be responsible for these results. However, after fluid saturations were reduced by displacement and evaporation, polymer damage to gas flow was less than 20 percent.
Results of this study indicate that as reservoir quality decreased there were greater capillary effects and extended time periods were required for invasion fluid recovery to attain maximum gas flow. By using cleanup time and regained gas permeability curves of saturated cores, these capillary effects were observable in the laboratory at reservoir conditions.
The low-permeability gas sands of the Western United States have long been a target for economical natural gas production. (1) Massive hydraulic fracturing (MHF) appears production. (1) Massive hydraulic fracturing (MHF) appears to be the most viable technique for stimulating gas production from wells in these reservoirs. (2) However, MHF production from wells in these reservoirs. (2) However, MHF has had only limited success in commercially exploiting these low-permeability gas sands.
The detrimental effect on well productivity of fracturing fluids has been the subject of a number of studies. Vein Poollen (3) and Tannich (4) indicate that the damage by the fracturing fluid is of minor importance as long as the induced fracture is highly conductive. These studies assume there is sufficient reservoir pressure to recover liquids from the invaded formation, liquid-filled fracture, and wellbore. Formation gas pressure must be sufficient to displace partially the fracturing fluids before natural gas production con occur. Studies by Holditch (5) suggest that production con occur. Studies by Holditch (5) suggest that gas-production con be completely blocked in the reservoir pressure is not sufficient to overcome the capillary forces pressure is not sufficient to overcome the capillary forces which retain liquids in rock pores next to the fracture. In some reservoirs, extended time periods are needed before cleanup of liquid is complete and gas production is realized. Even after gas flow is established, partial liquid retention con depress well productivity.
The problem of permeability damage to the liquid-invaded formation and fracture faces is addressed in this paper. Laboratory studies were performed by the National paper. Laboratory studies were performed by the National Institute for Petroleum and Energy Research to determine the following:
1. The extent of permeability damage of cores caused by various types of fracturing fluid polymers and gels on gas and brine permeability.
2. The effect of reservoir permeability, temperature and pressure on fluid cleanup rates.
3. The role of liquid-filled, induced fractures and how they affect liquid recovery from the invaded formation rock.
CORE DESCRIPTION AND PREPARATION
The low permeability sandstone cores used in this research come mainly from the Department of Energy Multiwell Experiment (MWX), Garfield County, Colorado. Mesaverde cores from other wells were also used to provide a wider range of core permeabilities. Well locations are shown in table 1. In general, these cores have pore structures, cementation, and diagenetic history similar to those of the MWX core.
Core plugs 3.8 cm in diameter and 1.5 to 3.0 cm in length were used. Since some of the core samples were contaminated with drilling fluids (diesel fuel), solvent extraction was used to clean the test specimens.
The Wilcox formation is a primary target for exploration and development of relatively low permeability tight gas reservoirs. Many operators permeability tight gas reservoirs. Many operators have and will continue to drill for the Wilcox in South and South Central Texas. This formation continues to make a major economic contribution to the area's oil and gas industries. This paper will present background information on the geology of the present background information on the geology of the Wilcox formation. The data presented will include lithology data derived from x-ray diffraction, and Scanning Electron Micrograph (S.E.M.) studies of whole core and/or sidewall core samples. The formation rock characteristics, such as permeability, porosity, youngs modulus, and formation water porosity, youngs modulus, and formation water analysis are also discussed. Some of the latest completion techniques, including cementing, casing and perforating programs, are discussed in detail. Bottom hole pressure, thermal and fracture gradients are reviewed due to their important influence on completion practices.
A variety of stimulation procedures have been used very successfully on the Wilcox formations. Stimulation fluid selections, volumes and even injection rates have their influences on completion practices and resultant production. Finally, the practices and resultant production. Finally, the types and size proppant selected and the volumes used are presented to maximize the production and to provide an optimum completion program. provide an optimum completion program
The Wilcox sand of the Eocene era were deposited along the South Texas Gulf Coast, primarily in a 10 county area (See Figure 1) The most prolific zones were discovered in: Webb, Zapata, Duval and Live Oak counties. Reserves for the area are estimated in excess of 600 billion cu. ft. (18 billion cubic meters)/yr. with some additional associated condensate.
Early Wilcox exploration was sporadic due to lack of pipeline availability as well as unattractive gas pricing. A second obstacle, abnormally high pressured zones between 9,000 and 13,000 ft (2743 and 3962m), also slowed development of the area. Drilling in the Wilcox trend increased dramatically after gas prices rose under the Natural Gas Policy Act of 1978.
Since 1978, drilling activity has been steady throughout the trend. In general, the Wilcox is a tight, poorly consolidated, fine grained sand that is somewhat sensitive to contact by foreign fluids. A wide variety of drilling and completion practices have been attempted in an effort to obtain commercially productive zones.
Most wells drilled require some stimulation to yield commercial production rates. A wellbore clean-up with a weak (less than 7.5%) acid or 2% KCl based fluid may dramatically improve production, however, hydraulic fracturing is usually production, however, hydraulic fracturing is usually required. In some instances where the Wilcox contains 150 - 500 ft (45.7 - 152.4m) of zone, Massive Hydraulic Fracturing (MHF) is required. This paper's discussion will focus on the fracturing and MHF treatment applications, specifically applicable to the Wilcox formation.
FORMATION DEPOSITIONAL AND ROCK CHARACTERISTICS
The Wilcox and Midway groups of the lower Eocene series constitutes the oldest of the thick sandstone/shale sequences within the Gulf Coast system (See Figure 2). Sediments within the updip section were deposited primarily by fluvial processes. Downdip sediments were transported across processes. Downdip sediments were transported across the Wilcox fluvial plain and were deposited in huge deltaic systems. Some deltaic sediments were reworked and transported along the shore by marine processes and then redeposited on barrier bars and processes and then redeposited on barrier bars and strand plains . Growth faults developed near the shorelines of several of the larger deltaic lobes where thick layers of sand were redeposited on previous sediments.
The growth of a hydraulic fracture increases the period of free oscillations in a well. Simultaneously, the period of free oscillations in a well. Simultaneously, the decay rate of free oscillations decreases. The properties of forced oscillations in a well also change during fracture growth. All of these effects result from the changing impedance of the hydraulic fracture that intersects the well. Fracture impedance can be determined directly by measuring the ratio of downhole pressure and flow oscillations, or determined indirectly from wellhead measurements using impedance transfer functions. Because impedance is a function of fracture dimensions and the elasticity of the surrounding rock, impedance analysis offers a promising new approach for evaluating fracture geometry- Because oscillatory flow conditions occur continuously a hydraulic-fracturing treatment, data collection is simple and economical, adding to the attractiveness of this technique.
This paper introduces impedance analysis as a tool for fracture diagnostics. Impedance analysis is based on the dynamics of wave propagation in a well and the effect the hydraulic fracture has on oscillatory pressures and flows. Impedance analysis is a logical extension of the two pressure analysis techniques currently used for evaluation pressure analysis techniques currently used for evaluation of hydraulic fractures. The first, pressure transient analysis, is based on the solution of a diffusion equation derived from Darcy's law and the principle of conservation of mass., In this method gradual pressure changes resulting from fluid flow, through the pores of the fracture and formation are measured and used for estimating fracture size and permeability. The second pressure analysis method is also derived from the pressure analysis method is also derived from the principle of mass conservation and considers gradual principle of mass conservation and considers gradual pressure, changes associated with the elasticity of an pressure, changes associated with the elasticity of an inflating fracture. Neither of these approaches considers the inertial component of fluid flow, an effect important in the study of wave propagation and reflection. Inertial forces are accounted for by invoking the principle of conservation or momentum. This principle, alone, with that of conservation of mass, forms the basis of the study of oscillatory pressure and flow in wells and other conduits.
This paper begins with a definition of impedance and then presents several field examples of oscillatory pressure changes resulting from the changing impedances of hydraulic fractures. Reasons for these changes are subsequently derived using impedance analysis techniques. To illustrate the relationship between fracture impedance and fracture dimensions, we then construct a hydraulic model of a fracture intersecting the bottom of a well. The properties of the fracture are combined in two lumped parameters, a flow resistance and a capacitance, which determine the impedance at the well-fracture interface. These parameters can be expressed in terms of fracture dimensions and the elastic properties of the surrounding rock. properties of the surrounding rock. It is not our purpose in this paper to provide a definitive recipe for measurement of fracture dimensions based on impedance analysis. We hope instead to illustrate the potential of the method and provide a framework for its further development.
CONCEPT OF HYDRAULIC IMPEDANCE
Imagine that a specialized tool is placed at the bottom of a well beside a low-permeability zone about to be fractured. This tool is able to precisely measure very small changes of both pressure and flow as injection rates are increased. In addition, the tool can measure oscillatory pressures and flows resulting from the reciprocating action of the pistons in the fracturing pumps. When injection begins, the pumps force fluid pumps. When injection begins, the pumps force fluid into the well, although flow into the formation is not, possible since breakdown has not occurred. possible since breakdown has not occurred. P. 411