DEVONIAN GAS TECHNOLOGY-2 CORE ANALYSIS AND CT IMAGING IMPROVE SHALE COMPLETIONS

M.E. Blauch, J.J. Venditto
Halliburton Services
Duncan, Okla.

E. Rothman, P. Hyde
Columbia Natural Resources Inc.
Charleston, W.Va.

To improve hydraulic fracturing efficiency in Devonian shales, core analysis and computerized tomography (CT) can provide data for orienting perforations, determining fracture direction, and selecting deviated well trajectories.

This article is the second of a five-part series on technology tested in a West Virginia well for improving the economics of developing Devonian shale and other low permeability gas reservoirs.

With slight production increase per well, Columbia Natural Resources Inc. (CNR) has determined that marginal gas well payout time can be shortened enough to encourage additional drilling.

For eight wells completed by CNR in 1992, the absolute open flow (AOF) averaged 116 Mcfd before stimulation.

After stimulation using long-standing fracture stimulation procedures, the AOF averaged 500 Mcfd.

The test well in this study came in with only a show of gas but increased to 780 Mcfd AOF after fracture stimulation.

For 1993, CNR plans a 40-well drilling program in which techniques discussed in this series will be used to stimulate gas production.

EFFECTIVE FRACTURING

To a great degree, fracture geometry is influenced by the location of perforation relative to formation stresses that determine induced fracture direction. Therefore, successful shale fracture stimulation depends, in large measure, on placing perforations and understanding the types of fractures created. Correct perforation orientation can:

Reduce treating pressure, thereby reducing screenouts
Improve well bore communication with the reservoir
Extend fracture geometry
Reduce the tendency for complex or multiple fractures.

Core pressure tests show that siltstone-laminated intervals are more conducive to gas recovery because free gas is within the siltstones. These laminated intervals furnish a conduit for gas to communicate through dark, or organic-rich shale packages.

With this information, perforations can be placed to increase the completion's profitability.

Proper on site core handling, on site core pressure measurements, core/log integration, and integration of downhole measurements with data obtained from oriented whole core analysis are critical to a successful analysis.

In this study, induced fracture orientation data obtained through CT imaging were verified by comparison to:

Data from experimental downhole extensometer
Data from an anelastic strain relaxation (ASR) method
Images from acoustic borehole imaging.

CORING

Six objectives for coring the Devonian shale test well were to:

Retrieve hydraulically microfractured sections. These sections help establish fracture and stress orientation.
Use core orientation data to validate an experimental downhole extensometer, a circumferential acoustic scanning tool, and the anelastic strain relaxation (ASR) method of determining fracture orientation.
Characterize lithologic parameters to improve log interpretation and correlation.
Use CT imaging to help understand heterogeneity, fractures, and potential controls on gas production.
Obtain preserved-core samples for testing shale surfactant additives and stimulation fluids.
Recover quality core samples for on site testing for core pressure.

The intervals selected for obtaining an oriented whole core were determined by characteristic gamma ray response. To maximize return on coring investment and obtain individual fracture information, cores were taken immediately below microfractured intervals.

Core depths were 3,386 to 3,433 ft for the lower Huron shale member and 4,787 to 4,845 ft for the Rhinestreet shale member.

The box gives a summary of coring practices.

ORIENTATION

Cores were oriented with a film-based magnetic multi shot survey technique that required stopping bit rotation to photograph the downhole compass.

Data, obtained every 3 ft, showed orientation grooves that were asymmetric. The acute angle between the secondary scribes was approximately 80. The obtuse angles were 130 and 150 between the principal scribe and the nearest secondary scribe.

When viewed from the surface to downhole, the larger obtuse angle was clockwise from the principal scribe.

Because of skipping and disruption within the inner core barrel, a straight, continuous orientation scribe was difficult to obtain in the shale. Therefore, frequent core orientation was critical for accurately measuring the planar core features.

Only orientations that could be extrapolated back to the nearest orientation shot were used in the fracture orientation analysis and the ASR test.

Future coring operations will feature continuous electronic orientation surveys to provide more core orientation coverage.

RETRIEVAL

Initially, a nondiamond coring bit designed for soft formations was used. But after experiencing extreme bit wear and operational difficulties, the bit was changed to a more conventional, less aggressive diamond core bit.

To minimize fluid contact, the well was cored with an air-mist core fluid.

The retrieved 4-in. diameter core was encased in a rigid aluminum core liner, marked for depth on the outside.

Nearly 100% of the core was recovered in all core runs. Once marked, the core tubes and the encased cores were cut into 4-ft sections. The ends were capped with elastomer end caps and sealed after stabilizing the cores within the inner liners.

STABILIZATION

Devonian shale cores tend to be fissile, separating extensively along parting planes in the rock and along planes of weakness.

To obtain a quality intact core of this friable-like rock, a heavy-walled, aluminum inner core barrel was used.

The special core-handling techniques led to less core jamming, less flexing of the core when laying down the core from the rig, and better depth control.

For additional quality improvement and to reduce the chance of jamming, core sections were kept to 30-ft lengths. Therefore, two core runs were made for each cored interval.

An exterior core support brace is recommended if longer core sections are desired or if a less rigid liner material is used.

The annular region between the core and outer barrel allows for physical disturbance and breakage of the core following retrieval and transport. To eliminate or reduce this problem, the on site core stabilization procedure involved filling the annular space with a low CT number (CTN) material.

The material did not affect native core properties such as wettability, saturation, and core gamma ray response. The material also eases core removal from the inner liner.

One major requirement for stabilizing the core was to reduce the beam-hardening artifact in CT imaging through the aluminum inner liner.

By filling the annular space with a low CTN, particulate solid, the beam-hardening artifact was significantly reduced. This resulted in improved CT imaging response over a nonstabilized core barrel.

Other benefits included observing intact induced fractures without separation and with minimal rolling. Core centralization within the inner liner was also improved.

ON SITE SAMPLING

The ASR test and core chamber experiments required on site sampling.

ASR samples were selected based on the premise of obtaining a competent, non-fractured, cylindrical core sample from the lower portion of the core tube sections. The core's laminated nature made sample selection difficult because both techniques required intact core sections.

To account for the volume of the missing core, intervals represented by the ASR method and core pressure-chamber samples were marked and replaced by foam spacers within the core tubes.

PRESSURE CHAMBER

An experimental core pressure-chamber test was conducted to evaluate gas storage, permeability, and gas flow behavior in the tight Devonian shale. The core used was a 4-ft section from 3,415 to 3,419-ft vertical depth.

The portable data acquisition system (Fig. 1) included attached pressure monitors, a thermocouple, and electronic cables.

The test determined diffused gas volume, porosity, and permeability in a section of shale core. From raw pressure vs.-time data an analytical method determined gas volume at original conditions and permeability.

The thermally insulated chamber was placed in a thermostatically controlled room. Because the gas volume released from the shale is much smaller than the volume released in coal samples, a different technique was developed for estimating gas storage through degassing.

Chamber pressure and temperature were monitored and recorded for a period of 12 days (Fig. 2). These data were analytically processed for permeability and diffusivity. Gas storage volume also was obtained.

The calculated permeability data from the whole core section using a diffusivity-permeability relationship were compared with values from build-up tests and core plug measurements.

Test results confirmed that matrix permeability in the Devonian shale core was a diffusion-dominated mechanism. Therefore, more surface exposure is needed for effective gas production.

To obtain this additional exposure, fracturing should consist of a number of smaller fractures, targeted on siltstone areas.

TOMOGRAPHY

Computerized tomography, commonly known in the medical field as CAT scanning (computerized axial tomography or computer assisted tomography), is a nondestructive technology that provides an image of an object's internal structure and composition.

CT applications in the petroleum industry include examining and evaluating:

Core structures
Plug sample selections
Encased unconsolidated cores
Pressurized cores
Natural fractures
Mineral distribution
Multiphase core-flow displacement
Acidizing effects
Porosity distribution
Formation damage.

The basic CT system consists of an X-ray tube, single or multiple detectors, and a special computer system that controls scanner functions, image reconstructions, and postprocessing hardware and software.

Additional equipment includes a precision (core drive) repositioning table, hard-copy image output and recording devices, and an X-ray transparent core holder or encasement materials.

Images obtained by CT represent cross-sectional axial or longitudinal slices through the object. The image is from a reconstruction of the matrix of X-ray attenuation coefficients by a special computer system that controls the scanner.

The images and quantitative data reflect volume by volume (voxel) variations displayed as gradational levels of contrasting CTN. The CTN is a function of density and the atomic number of the material.

The X-ray CT study of the aluminum liner-encased Devonian shale core was conducted to nondestructively characterize the core material with emphasis on gas production mechanisms, core heterogeneity, depositional features, fractures, and statistical quantification of CTN distribution for log correlation.

Capabilities of the CT analysis in this study include:

Natural fracture detection
Interpretation of in situ stress
Location of subsequent core sampling points
Accurate record of core and quality control of test samples
Reservoir description and quantification of heterogeneity
Correlation of CTN with log data
Evaluation of gas production (adsorption/desorption) mechanisms.

IMAGES

A total of 98 ft was scanned with the CT-41 ft from the upper core section of the lower Huron and 57 ft from the lower core section representing the upper Rhinestreet shale.

The CT slice spacing was 2 in. across the entire 98 ft of core. The spacing allows for detailed statistical analysis of the data.

In scanning the 25 sections of aluminum tubes containing the shale core, individual lead markers were placed on the tubes to indicate the location of the foot markers. The occurrence of some rotation of the core during coring was evident because the scribe marks were not all uniformly aligned within the tubes.

The amount of rotation varied from slice to slice. Because of variations, each image was rotated to align the orientation marks using a special software routine.

Partings and fracturing in the core presented some difficulty in the log format output of the calculation. Slices having low CTN's and high standard deviations are indicative of the presence of large induced fractures.

The log-generated format generated an excellent method for correlating the small-scale, laminated features with the open hole log features.

This work led to using smaller-scale, higher resolution logging techniques to identify subtle gas-producing zones.

With conventional logging, such bed resolution is not possible because these logs average over small features. The presence of small gas-producing intervals can be lost in the averaging process.

INTERPRETATION

Devonian shale intervals contain distinct small-scale heterogeneity (centimeter scale) as determined by the overview images and reflected in the quantitative statistical analysis. Occasional lower density areas and frequent high atomic number/high-density areas were detected along bedding features.

High atomic number/high-density materials, such as siderite, pyrite, or other iron-bearing minerals, were frequently present. This created a laminated appearance in the overview scans.

The distribution of these laminae varied between core intervals. The lower CTN sections containing higher porosity were interpreted to be reflecting siltstone lithology, and the brighter bands were interpreted as shale laminae containing the pyrite and/or siderite.

Identification of these features aided in interpretation of log/core correlations. The siltstone stringers within the pyritic shales form the major gas-producing lithology.

FRACTURE ANALYSIS

A method was developed for determining fracture orientation data derived from azimuthal measurements from CT images of whole core. Caused by the high CTN contrast between an open, gas-filled, induced fracture and the surrounding rock matrix, fractures could be observed directly in the images even though narrow hairline fractures may not be visible on the exterior of the core surface.

Fracture analysis verified and compared data derived from the fracture extensometer, circumferential acoustic logs, and rotational directional gamma ray logs.

These data can aid in selecting perforation orientation and making decisions as to the direction of deviated wells.

Precision of the angle measurements from CT are estimated at 4. This error range could be less except for ambiguity in precision of the core orientation scribe marks.

INDUCED FRACTURES

Circumferential traces of core perimeters showed little displacement of the sections separated by the open fractures. This supports the interpretation that the fractures were open before being cut by the core bit. This indicates that the fractures had hydraulically induced origin.

Induced fractures contained no evidence of secondary mineralization along the fracture faces as would be observed by a bright CT response within the fracture or along the fracture face.

In addition, the fractures are characteristically straight and transect the core boundaries with no apparent deviation or curvature as would occur if the fracture was generated following coring.

Little evidence was available from the CT analysis to show the presence of identifiable, steeply dipping natural fractures.

Regarding tectonic fracturing, it is significant to note that some horizontal depositional parting planes containing high CTN mineralization are interpreted as tectonically related to slippage and mineralization along horizontal slickensides caused by compressional low-angle thrust faulting.

This may confirm previous studies that have interpreted stratigraphic thickening in the eastern Devonian shale to be the result of displacement along imbricate thrust blocks that dissipated within the shale.

As a result, identification of this type of tectonic features may prove to be an important exploration tool in the Devonian and similar shales.

MULTIPLE FRACTURES

A series of multiple, closely spaced, parallel induced fractures with higher intensity were observed immediately below the hydraulically induced microfracture zone.

Fracturing was obvious in the upper core interval from 3,388 to 3,392 ft. All fractures in the region have essentially the same orientation. Greater depths in this core interval did not contain discernable fractures.

It can be inferred that complex fracturing of the formation may be characteristic of the Devonian shale. Multiple fractures may also have resulted from the three injections during the nitrogen treatment and liquid microfracs performed immediately above the core.

The same intensity of multiple fractures was not observed in the lower core section that did not experience multiple nitrogen injections.

FRACTURE ORIENTATION

A method was developed to convert the CT-measured fracture trace angle to fracture strike azimuth orientation.

In the test well, which was vertical, the slice images were taken in a plane perpendicular to the well's axis. As a result, the strike orientation was determined directly in relation to the principal scribe orientation that in turn was recalculated with respect to compass direction or azimuth.

In a deviated well, the apparent strike must be corrected for the deviation.

The polar plot's orientation data selected from the CT fracture orientation images statistically agreed with postmicrofrac data obtained independently from the fracture extensometer. The N60E orientation from the extensometer nearly aligning with the highest orientation data density derived from the CT scan images of about N57E.

This data agreement allowed researchers to place a high degree of confidence in the inferred hydraulic fracture orientation.

This direction also corresponds with the induced fracture orientation observed with the acoustic log across the microfrac intervals. The resolution of the acoustic log orientation was less accurate because of borehole breakouts and erosion around the induced fracture zone. Systematic correspondence to the distinct borehole breakouts was also observed with the acoustic log (Fig. 3).

Output of circumferential acoustic log during open hole testing shows a tendency of the shale breakouts and well bore ellipticity to be oriented in a northeast-southwest direction.

The dotted line overlay is the inferred fracture direction as determined by CT imaging and downhole extensometer work. Note the excellent agreement of the three methods for determining fracture orientation. This information can be used to orient perforations in the optimum direction.

Fig. 4 illustrates the benefit of knowing the inferred fracture direction when planning to orient the perforation.

Based on findings shown in Fig. 3, the direction of the natural-fracture tendency is established. However, if perforations are out of phase with this direction, a tortuous path is taken by fracture fluid to promote fractures in the natural direction. When pumping ceases, near well bore communication can be blocked by closure.

If the perforations are made in the direction of the formation's tendency to fracture, communication is maintained from the well bore to the extent of the induced fracture.

Because of excessive linear expansion and mechanical anisotropy of the rock, the data from the ASR method were not suitable for obtaining induced hydraulic fracture orientation in the shale.

XENON CT

To understand gas desorption and adsorption in the shale and the significance of free porosity, dynamic CT imaging experiments on xenon gas invasion into a whole core sample confirmed results and analytical solution of core pressure test data collected on site.

Quantification of porosity and gas adsorption were performed using the CT method similar to that used in the study of coalbed methane and other fractured shale reservoirs.

The whole core sample was selected from the interval at about 3,396 ft. In the original overview CT images, a single fracture was identified, and the sample was selected based on its overall character. The primary goals of the xenon experiment were to quantify fracture/matrix gas invaded porosity and gas adsorption effects, and to detect any microfractures and/or micro heterogeneities that were not visible in the overview scan images.

The core, in its preserved state, was removed from the original core tube and placed into an aluminum pressure vessel. After evacuating the sample to a micron level vacuum, a set of baseline CT scans of the entire evacuated core was made to select the location of the dynamic experiment.

Xenon gas, which has a similar molecular diameter and adsorption behavior to methane gas, was introduced into the evacuated core. During the xenon gas injection, dynamic scans were performed at various time intervals at a single scan location. This technique essentially provides a time lapse image of gas as it invades the rock matrix. To show only the gas, the rock image is subtracted from the total image.

At the conclusion of the dynamic gas invasion series, a whole core scan series was performed on the gas-saturated core.

Porosity values were calculated by computer subtraction of the evacuated images from the corresponding xenon gas saturated images and normalized to the CTN of the xenon in the annular space of the chamber.5

CT RESULTS

A surprise was that CT and core pressure results indicated that gas adsorption may be a lesser component in gas production from Devonian shale than had been previously believed. Free gas storage and small-scale heterogeneity appear to be the dominant controlling factors for gas productive shale.

Identification of such features therefore is important to gas production. Design parameters influenced by the features are:

Perforation location (depth)
Perforation orientation (around the casing)
Number and size of induced fractures
Type of lithology to penetrate, i.e., laminated shales vs.-homogeneous, organic-rich shales

Specific test results include:

Mean porosity-2.2%, fracture porosity-4.3%
Little or no gas adsorption observed after 40 hr of gas invasion
Invaded porosity reached maximum in 1 hr.

ACKNOWLEDGMENTS

The authors thank the management of Columbia Natural Resources and Halliburton Co. for permission to publish results of this work.

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