ADVANCED TECHNOLOGY IMPROVES NATURAL FRACTURE PREDICTION

Based on a workshop sponsored by PTTC’s Appalachian and Texas Regions, on November 19, 1998, in Pittsburgh, PA.

BOTTOM LINE

Small-scale microfracture analysis techniques have been used to predict large fracture distribution and conductivity, as well as improving the characterization of natural fractures of natural gas reservoirs in the Appalachian Basin.

PROBLEM ADDRESSED

A new, inexpensive microfracture analysis technique using sidewall core has been proven effective in the Appalachian Basin. Microfracture analysis was used to determine large-fracture orientation and relative timing, and predict fracture quality and distribution. The distribution of cements filling fractures is related to fracture conductivity and can now be mapped accurately. Thus, scaled microfracture analysis can be used to predict quality of fractured reservoirs in areas of seismic anomalies and may prove useful in locating additional reserves. A newly available shaped-charge source can create S waves for fracture identification. P-to-S wave mode conversion was demonstrated to be as effective as the S-wave approach was in illuminating fractures.

KEY WORDS:

Microfracture Analysis, Natural Fractures, Fracture Characterization, S-Wave Technologies, Appalachian Basin, Vertical Seismic Profile, Sidewall Core Orientation

SPEAKERS

Project Overview:
Doug Patchen, Appalachian Oil & Natural Gas Research
Consortium & PTTC Appalachian Region

Secondary Gas Recovery Program Overview
Rob Finley, Bureau of Economic Geology
University of Texas at Austin

Technical Problems Identified
Bob Heim, Atlas America

Microfracture Study of Sidewall Cores and Outcrops
Steve Laubach, Bureau of Economic Geology
University of Texas at Austin

Running a VSP Survey with Shaped Explosives
Bob Hardage, Bureau of Economic Geology
University of Texas at Austin

TECHNOLOGY OVERVIEW

The Lower Silurian Cataract/Medina Group sandstone is one of the largest and most significant natural gas plays in the Appalachian Basin, with proven gas reserves of 9.1 Tcf from more than 76,000 wells. Estimates of additional undiscovered resources range from 3.9 to 4.3 Tcf. In this project, advanced technology, including identifying fracture attributes in cores and geophysical methods, was used to investigate how to avoid drilling sub-economical fractured natural gas wells in the Henderson Dome area.

As a result of this study, a low-cost procedure now exists that will allow Appalachian Basin operators to use scanning electron microscope (SEM) images from sidewall cores to infer the spatial orientation, relative timing, and density of large-scale fracture systems in reservoir sandstones.

An innovative method was developed for obtaining stratigraphic and geographic tops of sidewall cores. The method involves the analysis of surface morphology of the broken end of the core as a top indicator. The study determined that microresistivity logs (or other image logs) can be used to obtain sidewall core azimuths and to determine precise depths of sidewall cores.

Two seismic shear (S-) wave technologies were developed. The first was a special explosive package that produces more robust S-wave seismic data than standard seismic explosives. This new technology allows S-wave seismic data to be generated across the Appalachian Basin. Previously, operators had not been able to use S-wave seismic technology to detect fractured reservoirs because the industry-standard Swave source was not practical in the heavy timber that extends across most of the basin.

The second technology was vertical seismic profile (VSP) data confirming that robust S-waves are generated by the P-to-S mode. Appalachian Basin operators can, therefore, use converted-mode seismic technology to create S-wave images throughout the region.

New Microfracture Analysis Approach
Microfractures (micron-to millimeter-fracture lengths) serve as a proxy for larger natural fractures that influence reservoir behavior. They are far more abundant than large fractures and can, therefore, be used when no large fractures intersect the wellbore. Microfracture analysis is also useful where large fracture attributes are inadequately determined by geophysical well logging methods.

The innovative technique characterizes fractures through analysis of sidewall cores and borehole-image logs using scanning electron microscopy, cathodoluminescence, and conventional petrographic analysis of thin sections, and predictive scaling of fracture populations.

The method has proven capable of providing three types of information:

1. Microfracture orientation can be used to infer the strike of large fractures.
2. Timing relations of fracture opening and cement precipitation can be used to assess the degree of mineral fill in fractures and, therefore, conductivity.
3. Microfracture size distributions can be used to predict the characteristics of large fractures.

Sidewall Core Orientation
Determining the sidewall core stratigraphic and physical top is key to successful core orientation. Azimuth of the sidewall core is then determined by examining the traces of the sidewall-core hole visible on an image log run after the coring tool.

During the field tests, a Schlumberger Sidewall CoreDrill ® tool was used. The sonde is pressed against the borehole wall by a hydraulically powered shoe and the bit advances 5 cm, at which time the device is abruptly rotated 7° downward to snap off the core. The exact direction, and amount of rotation used for breakoff, must be known for the analysis to be successful. Fracture surface features, such as arrest lines and plume structures, are used to identify the direction of snapoff fracture propagation. Together with tool rotation direction, this information can be used to infer core tops.

Because the sidewall coring device is a wireline tool, bouncing can affect vertical placement. Thus, sidewall coring must be followed by microresistivity logging or other image logging to precisely determine depths of azimuth of the core.

Identifying Microfractures
It has proven difficult to discriminate natural from drilling-induced subvertical fractures using only a borehole image. In the oriented, thin sections, most microfractures are at least partially filled with quartz cement, which cannot be seen using standard petrographic methods. However, authigenic and detrital quartz tend to exhibit different brightness in luminescence. SEM-based cathodoluminescence (CL) is more rapid, clear, and accurate than conventional CL and is the only practical method for imaging relatively large sample areas, which is required for orientation and scaling analysis.

The first step in interpreting scanned CL images to measure fracture orientation trends is to categorize the microfractures. The most useful were formed in a regional stress field and a relatively mechanically homogeneous rock. Scanned CL photomosaics composed of 30-40 individual photos were assembled. Each microfracture was then classified and its attributes measured.

FIELD RESULTS

Physical and diagenetic attributes of natural microfractures were determined from three wells in the Cataract/Medina Group in the Henderson Dome area. Two types of experimental tests were conducted: low-cost microfracture analysis of sidewall cores and evaluation of S-wave methods to detect and map fractured reservoir facies. This study was the first test of these methods in the Appalachian Basin.

Microfracture analysis provided information on the strike of large fractures, degree of mineral fill in fractures, conductivity, and size distribution of large fractures. In the Henderson Dome area, it was determined that large quartz-lined regional fractures have strikes of N20E and a subsidiary set has strikes at N70W. Some fractures have degraded quality because of infilling by ferroan dolomite and anhydrite. However, the location of zones of high fracture quality (intense fracturing with minimal mineral filling) can be assessed from sidewall cores. Future mapping in the Henderson Dome area has an excellent chance to identify fracture-controlled highly-productive zones.

The quality and scaling data from sidewall cores in the Henderson Dome area demonstrated that fracture evaluation can be carried out without collecting whole cores from all intervals. The use of scaling methods developed in this project could permit quantitative fracture characterization at depths where seismic anomalies are present.

Fracture Orientation
The cored Medina intervals indicate the most prominent microfracture set strikes N85W, the next most dominant set strikes N20E, and the third distinct set strikes N30W. Results are based on a total of 2,225 microfractures from sidewall cores in two wells. These results are compatible with orientation of macrofractures visible on image logs in these same wells. In addition, where orientations of microfractures and large fractures on image logs are congruent, there is increased confidence that the large fractures on the image logs are natural.

Microfracture lengths range from 5µ to hundreds of microns, and apertures from 0.5µ to 40 µ. The lower aperture size represents a limit of SEM image resolution, not an absolute size limit. Crosscutting relations indicate that the N20E fracture set is older than the N85E set.

Petrographic Analysis of Fracture Quality
Fracture quality relates to whether fractures are likely to be open or mineral filled, and their resultant conductivity. It was found that there are at least two episodes of fracture formation in the Cataract/Medina Group in the Henderson Dome area. The timing of fracture opening with respect to cement precipitation was used to assess the degree of mineral fill in fractures and therefore fracture conductivity. Regional fractures are present in the Henderson Dome and are lined (only partly blocked) with quartz.

Postkinematic (post fracture formation) cements consisting of ferroan dolomite, calcite, anhydrite, and clay minerals are mainly responsible for closed fractures. The distribution of these cements is variable within the tested wells, but can be accurately mapped. Therefore, a major factor controlling reservoir quality (conductivity) can now be mapped and used to target additional wellsites.

Microfractures Calibrate Fracture Detection Methods
Data from the field study suggest that the microfracture population shows power-law scaling. This means that microfracture size distributions can be used to predict the size distribution of large fractures, which is required for predicting permeability by seismic studies. In addition, distribution of postkinematic cement halos around small but through-going faults in the vicinity of Henderson Dome could account for observed fault-related variation in production. It also could be important in predicting seismic response in these fault zones.

Seismic Detection of Fractured Rock
Based on field testing in the Henderson Dome area, it was found that Appalachian Basin operators should use seismic S-waves to detect and evaluate fractured reservoirs. Field testing indicates that two approaches can be taken to create appropriate S-wave seismic data for identifying fractures in the Appalachian Basin rocks. The first approach is use of a shaped charge explosive package where conventional sources (specifically horizontal vibrators) cannot be used. This explosive charge developed jointly the Bureau of Economic Geology and Austin Powder Company was predicted to be commercially available during the first quarter of 1999. The second approach is to use a standard seismic source and rely on P-to-S mode conversion to generate downgoing S-waves to detect fractured reservoirs. Field tests over Henderson Dome indicate that the mode-conversion technique will be successful in the Appalachian Basin and can be considered as effective for fracture illumination as the S-wave approach.

CONNECTIONS:

Bob Heim, Atlas America, Inc.
311 Rouser Road, Moon Township, Pennsylvania 15108
Phone 412-262-2830, Fax 412-262-2820, E-mail general@atlasamerica.com

Bob Hardage, Bureau of Economic Geology
University of Texas at Austin
University Station, Box X Austin, TX 78713-2924
Phone 512-471-0300, Fax 512-471-0140, E-mail bob. hardage@beg.utexas.edu

Steve Laubach, Bureau of Economic Geology
University of Texas at Austin
University Station, Box X Austin, TX 78713-2924
Phone 512-471-6303, Fax 512-471-0140, E-mail steve. laubach@beg.utexas.edu

For information on PTTC’s Appalachian Region and its activities contact:
Doug Patchen, Program Director, Appalachian Oil & Natural Gas Research Consortium
West Virginia University NRCCE-Evansdale Dr., PO Box 6064
Morgantown, WV 26506-6064
Phone 304-293-2867 x 5443, Fax 304-293-7822, E-mail dpatch@wvunrcce.nrcce.wvu.edu

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