Guidelines to be Used to Evaluate Underground Gas Storage

ATTACHMENT B

DEPARTMENT OF ENVIRONMENTAL PROTECTION

BUREAU OF OIL AND GAS MANAGEMENT

DOCUMENT NUMBER: 550-2500-002

TITLE:

Guidelines to be used to Evaluate Underground Gas Storage Operators’

Request to Increase Underground Gas Storage Pressure.

EFFECTIVE DATE:

AUTHORITY:

Effective Upon Final Publication In The Pennsylvania Bulletin

The Oil and Gas Act (P. L. 1140, No. 223) (58 P. S. Section 601.101 et seq.)

Coal and Gas Resource Coordination Act (P. L. 1069, No. 214)

Oil and Gas Conservation Law (P. L. 825, No. 359) (58 P. S. Section 401.1 et seq.)

The Administrative Code (P. L. 177, No. 175) (71 P. S. Section 510-1 et seq.)

POLICY: Department staff will follow this guidance to evaluate requests from underground gas storage operators to increase underground gas storage pressure.

PURPOSE: This document will provide persons and companies operating underground gas storage reservoirs with information on what they need to submit to the

Department in order to request an increase in underground gas storage pressure.

APPLICABILITY: This document provides guidance to the Department staff and the oil and gas industry on how a request for an increase in maximum underground gas storage pressure will be reviewed.

DISCLAIMER: The policies and procedures outlined in this guidance are intended to supplement existing requirements. Nothing in the policies or procedures shall affect regulatory requirements.

The policies and procedures herein are not an adjudication or a regulation.

There is no intent on the part of DEP to give the rules in these policies that weight or deference. This document establishes the framework within which

DEP will exercise its administrative discretion in the future. DEP reserves the discretion to deviate from this policy statement if circumstances warrant.

PAGE LENGTH:

LOCATION:

14

Volume 8, Tab 02

DRAFT / 550-2500-002 / January 29, 2004 / Page i

Guidelines to be Used to Evaluate Underground Gas Storage Operators’

Request to Increase Underground Gas Storage Pressure

Background

Underground gas storage operators have requested guidance from the Department on what information to submit to request an increase in underground gas storage pressure.

Currently the limit for underground gas storage pressure is defined by Chapter 78 (Oil and Gas Wells) of the Pa. Code Section 78.404, Maximum Storage Pressure. This section states:

A gas storage operator, who has not requested approval of a maximum storage pressure for a gas storage reservoir, shall request, by February 15, 1995, Department approval of a maximum gas storage reservoir pressure in accordance with the following:

The maximum shut-in wellhead pressure (psig) may not exceed the highest shut-in wellhead pressure (psig) found to exist during the production history of the reservoir, unless a higher pressure is established through testing of caprock and pool containment. The methods used for determining the higher pressure will be determined in conference with the Department in accordance with Section 501 of the Act.

This guidance provides a framework by which an underground gas storage operator can develop a methodology for determining what information needs to be gathered to request an increase from the

Department of underground gas storage pressure over discovery pressure, or freshwater hydrostatic gradient storage pressure if original discovery shut-in well head pressure, or the highest production shutin well head pressure, is not known.

This guidance also provides the Department with a framework for review of the information submitted by an underground gas storage operator who is requesting an increase in operating pressure of an underground gas storage reservoir.

Procedure

From a review of available literature, discussions with the Federal Energy Regulatory Commission

(FERC), and other states, the Department has determined that the delta pressure method would be a suitable method for an underground gas storage operator to determine if they can safely increase underground gas storage pressure above original shut-in well head discovery pressure, the highest production shut-in well head pressure, or a freshwater hydrostatic gradient storage pressure if the original discovery shut-in well or highest production well head pressure were unknown. Each region has compiled maximum storage pressures for storage fields located within their respective areas that operators are presently using. These are summarized in Appendix I. These maximum pressure would be the starting point for determining, through numerical modeling, pressure testing, and field verification, whether underground gas storage pressure could be increased over original shut-in well head discovery pressure or the highest production shut-in well head pressure.

Delta Pressure Method

The determination of delta pressure is a method an underground gas storage operator can use to determine how much pressure, over original discovery pressure, an underground gas storage field can be

DRAFT / 550-2500-002 / January 29, 2004 / Page 1

safely subjected to. Delta pressure is defined as the pressure at maximum storage minus the initial reservoir pressure. Delta pressure is determined by subjecting cores of the cap rock from the gas storage reservoir to analysis by subjecting it to incremental increases in pressure. This data is then used as an aid to determine the maximum pressure the formation can safely handle without breaking down. A paper by L. K. Thomas, D. L. Katz, and M. R. Tek, “Threshold Pressure Phenomenon in Porous Media,”

Society of Petroleum Engineers Journal, June 1968, discusses how to determine, experimentally, threshold displacement pressures to find out how much overpressure can be used in storing natural gas.

A more recent, and more detailed, report was prepared by Terralog Technologies USA, Inc. for Gas

Research Institute, GRI-98/0198. It is titled “Geo-mechanical Analysis of Pressure Limits For Gas

Storage Reservoirs,” June 1998. It is a field study on the use of delta pressuring to evaluate two underground storage reservoirs. One storage field was in California and the other in the northeastern

United States. The report explains in detail how delta pressure is used to determine if these two underground gas storage fields are suitable candidates to increase their storage pressure over the original discovery pressure.

The Terralog Technologies report provides excellent guidelines on procedures used to determine delta pressure options at an underground gas storage reservoir. These assessment options involve estimating the current rock strength and reservoir stress values with the best available data, calculating induced stress due to pressure cycling, and then comparing the induced stresses to the estimated limiting strength and stress values.

The first step in such an assessment is to characterize the geo-mechanical properties of the reservoir and overburden based on the best available data. The second step in assessing delta pressure potential is to analyze stresses induced by gas storage operations in the caprock and overburden with geo-mechanical models. Figure 2.0 from the Terralog Technologies report shows the step-by-step procedure used to evaluate maximum operation pressures for gas storage reservoirs. This flow-chart is summarized in

Appendix II. The references, and summaries of the references for the flowchart, are listed in

Appendix III.

The Department would expect the underground gas storage operator to follow the following steps in order to provide the information needed by the Department to evaluate whether a request for an increase in underground gas storage pressure over discovery pressure can be accomplished safely.

I. Determining Delta Pressure

A. The underground gas storage operator would determine cap rock and reservoir mechanical properties:

1. From core samples that measure stiffness and strength properties, or

2. From electric log data that technically approximates stiffness and strength properties.

Stiffness and strength properties for the reservoir and cap rock would be derived from direct laboratory measurements on core samples from the cap rock and the storage formation within the underground gas storage reservoir, or from the same formations in an adjacent area.


If core samples from the cap rock and storage formations of the underground gas storage fields are not available, the operator would then have to estimate stiffness and strength properties from available electric log data and lithology correlations from the literature.

Data from available sonic logs are used to estimate stiffness parameters. Values for bulk density (gm/cc), Young’s Modulus (psi), and Poissons Ratio would be determined from these. (Refs. 1, 2, 3)

Estimate a range of shear strength values for the reservoir and cap rock.

Values for shear strength (psi), based on selected values for Young’s Modulus (psi),

% Shale, and % Porosity, could be estimated from Schlumberger (1987) (Ref. 2).

B. Once estimates for stiffness properties have been determined, the operator would then have to:

Determine in-situ stresses and reservoir fracture pressures.

1. From hydraulic fracture data, evaluate minimum and maximum horizontal stress

(Ref. 4), or

2. From quality leak-off data, determine constraining stress tensor (Refs. 5, 6), or

3.

4.

From breakout/image data, determine constraining stress tensor (Refs. 7, 8), or

Estimate data from regional stress data and lithology/depth correlations

(Refs. 9, 10).

C. The underground gas storage operator would evaluate fracture pressure variations with position and reservoir pressure.

This data is obtained through numerical modeling. A program such as Fast Langrangian

Analysis of Continua (FLAC) by Itasca Consulting Group, Inc. was used in the Terralog study.

D. The underground gas storage operator would evaluate cap rock stresses induced by pressure cycling.

This data is obtained through numerical modeling.

II. Field Verification

A. Verification of pressure and stress

Using an abandoned well that passes through the overburden, but is not hydraulically connected to the gas storage reservoir, or has been cemented off, the underground gas storage operator would perform step-rate injection tests and pressure fall-off analyses to confirm fracture gradient and local stress estimates of the cap rock above the underground gas storage reservoir. This would not only give the underground gas storage


the formation. If no data is available, regulations require .433 X specific gravity (.433 is the freshwater hydrostatic gradient).

III. Breakdown Pressure Test

This test is performed on the cap rock above the underground gas storage reservoir. The breakdown pressure test is performed using water. This method is similar to the step-rate pressure test. However, unlike the step-rate pressure test, fractures are actually induced in the formation to determine the pressure at which fracturing occurs. Theoretically, at the conclusion of the test, when the testing fluid is removed, the fractures heal since no proppent was used to hold the fractures open. Additionally, the fractures do not propagate long distances. Some operators then squeeze cement in the area where the fractures were induced to ensure they are sealed.

A. Perform precise mass balances annually to ensure that losses have not been changed disproportionately to the magnitude of delta-pressure.

B.

Use monitoring wells, old abandoned wells, or inactive wells, available for the structure to track the evolution of pressures to ensure excessive pressure propagation is not taking place. operator a risk management dimension to the operation under delta-pressure, but also permit calibration and verification of the numerical models.

B. Step-rate pressure test at the casing shoe

This test is performed on the cap rock above the underground gas storage reservoir. In this procedure, the underground gas storage operator would pump a predetermined volume of fluid and record the pressure. He would then pump another predetermined volume of fluid and again record the pressure. During this pumping, the volume of fluid pumped would be recorded against pressure. The test would be halted at the point where the curve being recorded would begin to “break” or level off. This “break” in the curve would be the maximum allowable pressure the casing shoe, or the borehole, could withstand before formation breakdown occurred. This would translate to the maximum allowable storage pressure an underground gas storage operator could not exceed.

The Environmental Protection Agency looks at pressure limits for permitting purposes.

They want to avoid fracturing of the formation. They examine historical information, stimulation data, and testing data. They also use the step rate test in which fluid is injected into a formation at a certain pressure. The instantaneous shut-in pressure is used to derive a breakdown pressure. The point at which a pressure decrease is seen is the point at which the test is halted. This is the minimum pressure needed to begin to open


IV. Field Monitoring of Surface Deformation Microseismic Emissions

The underground gas storage operator would perform field monitoring of surface deformations and inversions, and micro-seismic emissions.

A. Surface Deformations

The operator would obtain precision surface deformation measurements and inversion by placing stable benchmarks or stable tilt meters in array over the site. Tilt meters are the preferred approach because they are more sensitive and can be measured any time. The down-hole use of tilt meters by the underground gas storage operator can give deformation measurements.

B. Real-time micro-seismic monitoring

Tri-axial geophones are installed in a three-dimensional array in boreholes at depth, or shallow holes which penetrate into the bedrock. If the emissions migrate substantially over time, increase greatly in amplitude and frequency, or are found to become large in area and concentrated on large planar feature, they can be interpreted as potential indicators of instability, either current or impending.

In order for the Department to evaluate a request for an increase in underground gas storage pressure, the underground gas storage operator would have to follow these steps in order to obtain the information they need to determine if an increase in underground gas storage pressure, over discovery pressure, can be accomplished safely.

Upon receipt of this information, the Department will conduct a conference with the underground gas storage operator, in accordance with Section 501 of the Oil and Gas Act, to review the information submitted and make a determination whether to approve or disapprove the request.


Operator

Columbia Gas Transmission

Consolidated Gas Trans.








Nat.l Fuel Gas Supply Corp.





















North Penn Gas Company

North Penn Gas Company

Peoples Natural Gas Co.

T.W. Phillips Gas & Oil



T.W. Phillips

APPENDIX I – 1

DEP MEADVILLE REGIONAL OFFICE


LIST OF GAS STORAGE FIELDS IN NORTHERN PA

Field Name

Maximum

Pressure County

Munderf

Ellisburg

Greenlick

Harrison

Leidy

Sabinsville

Sharon

Tamarack

Tioga

Belmouth

Boone Mt.

Corry

Deerlick

Duhring

East Branch-A

East Branch-B

Galbraith

Hebron

Henderson

1500

600

500

1200

100

225

530

530

860

2200

4250

2150

4200

2200

1000

4300

620

2150

250

Keelor

Markle

Owls Nest/Bear Creek

Owls Nest/Big Run

Owls Nest/Red Run

Queen

St. Marys

Summit

Swede Hill

Wellendorf

Wharton

Meeker

Palmer

Truittsburg

Hughes

Portman

Sprankle

Vardy

800

650

450

3600

1500

1500

900

800

495

375

500

540

750

750

750

590

590

595

Storage

Horizon

Jefferson

Potter

Speechley

Oriskany

Potter & Clinton Oriskany

Potter Oriskany

Potter & Clinton Oriskany

Tioga Oriskany

Potter

Clinton

Oriskany

Oriskany

Tioga

Elk

Oriskany

Cooper

Elk & Clearfield 5th Venango

Erie Medina

Warren

Forest

Warren

McKean

Balltown Tiona

Deemer

Cooper

Cooper

Jefferson

Potter

Mercer &

Venango

McKean

Jefferson

Elk

1st Sheffield

Oriskany

1st Venango

2nd Venango

Cooper

5th Venango

Balltown Tiona

Elk

Elk

Balltown Tiona

Balltown Tiona

Forest & Warren Queen

Elk 5th Venango

Erie

McKean

Oriskany

Balltown Tiona

McKean 5th Venango

Potter & Cameron Oriskany

Tioga Oriskany

Tioga

Clarion

Butler

Butler

Jefferson

Butler

Oriskany

Bayard

5th Venango

4th Venango

Hundred Foot

Sand/Balltown

Tiona

4th Venango

Depth

1930

1930

1200

1330

2350

1810

1160

6000

4200

2870

5160

865

910

1930

1590

1930

4000

1900

1230

4520

1390

950

1960

1960

2300

5100

6800

5000

6400

4500

4800

7000

4100

1550

2024

1690

2634


APPENDIX I – 2

DEP PITTSBURGH REGIONAL OFFICE


LIST OF GAS STORAGE FIELDS IN SOUTHERN PA

Field Name

Maximum

Pressure County Storage Horizon Operator

Columbia Gas Transmission Donegal

Consolidated Gas Trans. Heard

Consolidated Gas Trans. Holbrook

1260

900

900

Washington

Washington

Gordon Stray

Big Injun, Thirty Foot,

Gordon, Fifty Foot

Gantz, Fifty Foot

Consolidated Gas Trans. Majorsville 900

Greene &

Washington

Greene &

Washington






Equitable Gas Company












Blackhawk

Artemas A

Artemas B

Oakford

South Bend

Bunola

Finleyville

Hunters Cave

Pratt

Swarts

Tepe

Swarts West

Colvin

Patton

Webster

Rager Mt.

Alabran

2000

2100

1900

1200

700

890

1000

1000

650

1000

1010

1000

685

600

600

3200

390

Beaver

Bedford

Bedford

Westmoreland

455

Armstrong

Allegheny

Washington &

Allegheny

Greene &

Washington

Greene &

Washington

Greene &

Washington

Allegheny

Greene &

Washington

Washington

Westmoreland

Westmoreland

Cambria

Indiana

Majorsville Deep, Big

Injun, Fifty Foot, Thirty

Foot, Majorsville Shallow,

Salt Sands

Oriskany

Oriskany

Oriskany

Fifth Sands

Murrysville Sand

Hundred Foot Sand

Gantz

Fifth Sand

Big Injun Sand

Fifth Sand and Fifty Foot

Sand

Fifty Foot Sand

Fifty Foot Sand

Fifty Foot Sand








Kinter

Schmidt

Smith-Parke

Clark

Fair & Helm

Gourley Miller

Seanor

360

425

500

800

400

820

1000

Indiana

Indiana

Allegheny

Indiana

Armstrong

Clearfield

Westmoreland

Murrysville Sand

Murrysville Sand

Murrysville Sand

Oriskany Sand

Murrysville,Hundred Foot,

Tiona, First Balltown

Hundred Foot and Second

Bradford

Murrysville, Hundred Foot,

Boulder, Third Tiona, First

Balltown

Boulder Sand

Hundred Foot and Warren

Sand

Hundred Foot, Berea,

Bounder, Speechley

Elizabeth Sand

First Balltown

Depth

2700

5100

6800

5000

6400

4500

4800

7000

4000

1550

2024

1690


APPENDIX II - Step-by-step procedure to evaluate maximum operating pressures for gas storage reservoirs

Determine caprock and reservoir

mechanical properties.

Core available?

Yes

No

Logs available?

Yes

Determine in-situ stresses and reservoir fracture pressures

Measure stiffness and strength properties in lab.

Hyd. Fracture data available?

Estimate stiffness and strength properties

(Ref. 1, 2, 3)

No

Quality leak-off data available?

No

Breakout/image data available?

Yes Yes Yes

No

Evaluate min and max horiz stress (Ref 4)

Constrain stress tensor

(Refs 5, 6)

Constrain stress tensor

(Ref 7, 8)

Estimate from regional stress data and lithology/depth correlations

(Refs 9, 10)

Evaluate fracture pressure variations with position and with reservoir pressure

Evaluate caprock stresses induced by pressure cycling

(Numerical Modeling)

(Numerical Modeling)


1.

2.

3.

APPENDIX III

Summary of References Cited in Guidelines for Approving Requests to Increase

Allowable Underground Gas Storage Pressure

Gatens, J.M. III, Harrison, C.W. III, Lancaster, D.E. and Guidry, F.K. (1990), In-situ stress tests and acoustic logs determine mechanical properties and stress profiles in Devonian Shales, SPE

Form. Eval. Vol. 5 (3), pp 248-254.

The in-situ stress contrast between a reservoir rock and the surrounding formations is important to the design and analysis of hydraulic fracture treatments. The stress contrast between layers controls the fracture’s vertical (height) growth, which in turn affects the fracture length and width. As part of the Gas Research Institution’s (GRI’s) Comprehensive Study Well (CSW) program in the Devonian shales of the Appalachian basin, we measured in-situ stresses directly and used those values to calibrate acoustic log measurements to develop stress profiles across the

Devonian shales. This paper discusses the measurement and interpretation of in-situ stresses, the use of acoustic logs to determine mechanical properties and a more complete stress profile, and the practical use of the stress profile in fracture-treatment design and analysis.

In-situ stresses were measured directly throughout the Devonian shale interval with both open hole and cased-hole stress tests, conducted with nitrogen, a specially designed down hole shut-in tool, and a down hole quartz pressure gauge with surface readout. The paper describes the procedure used and presents interpreted stress-test results from two CSW’s. Full-wave form acoustic tools were run to define elastic properties of the Devonian shales. These properties also were determined under both static and dynamic conditions from whole-core plugs taken in the shales. Logs were calibrated to core-measured values, and then elastic properties determined from the logs were used to compute an in-situ stress profile, which was calibrated against field measurements of in-situ stresses. Finally, we discuss how this data is used to design and analyze hydraulic fracture treatments in CSW’s.

Schlumberger, (1987), Log Interpretation Principles/Applications, 2 nd

edn. Houston,

Schlumberger Educational Services, October.

Schlumberger’s "Log Interpretation Principles/Applications—1989,” describes the principles of measurements used by their open hole logging tools, the basic principles for interpreting those measurements, and the various applications for the services. "Cased Hole Log

Principles/Applications—1989," provides similar information for cased hole services.

A companion volume, Schlumberger Log Interpretation Charts book, contains the charts, monograms, and tables necessary for quantitative interpretation of data from their various logging tools. Several new charts are included for new services and some of the previous charts have been replotted as a result of additional lab measurements and advanced computer modeling.

A brief description of how to use each chart or series of charts is included.

Tixier, M. P., Loveless, G.W., and Anderson, R.A., (1973), Estimate of formation strength from mechanical property logs, SPE 4532.


4.

5.

Provides empirical correlations to estimate compressive or shear strength from rock stiffness values.

Hamison, Bazalel C., (1993), The hydraulic fracturing method of stress measurement: theory and practice, Comprehensive Rock Engineering, ISRM – Pergamon Press, pp. 395 – 412.

Hydraulic fracturing, or hydrofracturing, is the best-known method of assessing the state of insitu stress at great depths. In the last two decades, it has become an indispensable tool in the preexcavation design of large underground projects such as hydroelectric powerhouses, tunnels, mines, waste disposal galleries, energy storage caverns, etc. It has been increasingly used in the planning of oil and gas fields and the design of wellbore simulation. It has also become a requisite field measurement in tectonophysics research, and in earthquake prediction, mechanism and control studies.

The method consists of sealing off a short segment (typically 0.5 – 2 m) of a wellbore or borehole at the desired depth, injecting a fluid (usually water) into it at a rate sufficient to raise the hydraulic pressure quite rapidly (typically 0.1 – 1 Mpa s

-1

), and bringing about hydraulic fracturing. The later is achieved when the borehole fluid pressure reaches a critical level called

“breakdown.” At breakdown the rock fractures in tension causing borehole fluid loss and hence a drop in pressure. When pumping is stopped, the hydraulic line to the teat interval is kept shut in. The pressure will immediately decay, first very quickly as the fluid chases the still extending fracture tip, and then much slower as the fracture closes and the only fluid loss is due to permeation into the rock through the borehole wall. The “shut-in” pressure P

S is the transition level between fast and slow pressure decay and signifies the closure of the fracture. Several minutes into the shut-in phase of the test, the pressure is bled off and the first pressurization cycle is thus completed. Several additional cycles are conducted. From these cycles, supplementary shut-in values are obtained, as well as the fracture opening pressures P

R

. During testing, the pressure and injection fluid flow rate are continuously recorded. The far-field stresses are calculated from the pivotal pressures (P

C

, P

S

and P

R

) recorded during the test using one or more of the available models. The directions of the in-situ stresses are determined from the attitude of the induced hydraulic fracture trace on the borehole wall. Typically, several to more than a dozen tests are carried out in one borehole within the depth range of interest to the project for which knowledge of the in-situ stresses is required.

Aadnoy, B.S., (1990), Inversion technique to determine the in-situ stress field from fracturing data, J. Pet. Sci. and Engineering Vol. 4, pp. 127-141.

Typically, one assumes that the two horizontal in-situ stresses are equal in borehole stability studies. This simplification has been necessary due to lack of information. The new method presented here distinguishes between the in-situ stresses and estimates the magnitude and direction of each of the two horizontal in-situ stresses. The input data used is the leak-off fracturing information.

The new method uses stress transformation equations to take advantage of the directional characteristics of offshore boreholes. By including the hole inclination and the azimuth, one can solve the two unequal horizontal in-situ stresses. The model results in finding the inverse of an over determined system of equations. A field study demonstrates the method.


6.

7.

8.

Kunz, K.R., and Steiger, R.P., (1992), Accurate in-situ stress measurements during drilling operations, SPE 24593, Proc. 67 th

Ann. SPE Tech. Conf., pp. 491-499.

This paper describes easily implemented field procedures for obtaining in-situ horizontal earth stresses during drilling operations. The procedures were developed to obtain stress data that is necessary for well bore stability modeling and for predicting and avoiding fracturing lost returns.

Conventional leak off tests are performed routinely to test the integrity of casing cement jobs, not to accurately measure earth stresses. The most important consideration was to develop methods that were easy to implement and would minimize disturbance to drilling operations, thereby promoting acceptance among operations personnel. The procedures are called Extended Leakoff

Tests (XLOT).

Peska, P. and Zoback, M.D. (1995), Observations of borehole breakouts and tensile wallfractures in deviated boreholes: A technique to constrain in-situ stress and rock strength, Proc.

35 th

U. S. Symp. Rock Mech., Balkema, pp. 319-325.

In this study we demonstrate the relationship between compressive and tensile failures of inclined well bores and the tectonic stress field. We present illustrative polar diagrams from which one can determine the orientation and tendency for borehole failure as a function of the borehole orientation and the stress field. In the case of borehole breakouts, we propose a technique to constrain the magnitude and orientation of S

Hmax

(as well as to estimate the effective in-situ rock strength) from the orientation of breakouts in deviated boreholes. The method is based on the assumption that an estimate of the least principle stress is available from leak-off tests or hydrofracs, and the overburden stress is obtained from the integration of density logs and pore pressure and is either known or can be estimated. Application of this technique in the

GBRN/DOE “Pathfinder” well, Gulf of Mexico, shows that the azimuth of S

Hmin

is ~N42 0 E, perpendicular to a major growth fault penetrated by the well, the magnitude of S

Hmax

is relatively close to the vertical stress and the effective in-situ compressive rock strength is about 22 –32

Mpa. We also illustrate how drilling-induced tensile wall-fractures (detected from FMS/FMI logs) in deviated holes (or vertical holes in which on principle stress is not vertical) can be used to constrain the in-situ stress orientation and magnitude. In the case of the KTB borehole,

Germany, this relationship is used at a depth of 3213 m to estimate the magnitude of S

Hmax

(correlates closely with a value determined from hydraulic fracturing) as well as the deviation S

V from vertical (~10 – 12

0

).

Zoback, M.D., Moos, D., Mastin, L., and Anderson, R.N., (1985), Well bore breakouts and insitu stress, Journal of Geophysical Research, V. 90, NO. B7, pp. 5523-5530.

Data from commercially available four-arm caliper logs have enabled several workers to show that there are spalled sections of well bores termed “breakouts” in the petroleum industry, in which the average azimuth of the long (or spalled) dimension is very consistent within a given well or oil field. Other workers have suggested that the consistent azimuth of the long dimension of the hole was parallel to the azimuth of the least horizontal principle stress.

In this paper, we present detailed measurements of the cross-sectional shape of breakouts in several wells using specially processed data from an ultrasonic borehole televiewer and extend the theoretical analysis of the mechanism of breakout formation proposed by Bell and Gough

(1979, 1982) and Gough and Bell (1981, 1982) in order to explain better the observed breakout


9. shapes. One of the case histories examined in this paper, a well located at Auburn, New York, is discussed at length by Hickman et al.

Bell, J.S., (1996), In-situ stresses in sedimentary rocks, Part 1, Geoscience Canada, Vol. 23,

No. 2.

This paper is the first of two that will review recent research involving in-situ stresses in sedimentary rocks and the geological and petroleum engineering applications of this data. Part I describes and discusses the most commonly used methods for measuring today’s rock stresses in sedimentary rocks, in terms of S

V

(vertical principle stress), S

Hmax

(larger horizontal principle stress) and S

Hmin

(smaller horizontal principle stress). Stress magnitudes may be obtained from density logs (S

V

), from hydraulic fracture tests and leak-off tests (S

Hmin

), as well as from core monitoring techniques (S

Hmin

, S

Hmax

). Borehole slotting holds promise for use in deep wells

(S

Hmin

, S

Hmax

), but is not yet operational. Near-surface stress orientations (S

Hmin

, S

Hmax

) can be inferred from a variety of geological indicators, provided precautions are taken in selecting locations. Subsurface stress orientation data are provided by breakouts (S

Hmin

, S

Hmax

), specific types of core fractures (S

Hmin

, S

Hmax

), core discing (S

Hmax

), as well as by core expansion (S

Hmin

,

S

Hmax

), hydraulic fractures (S

Hmax

), drilling-induced fractures (S

Hmax

), and earthquakes (S

Hmax

).

Acoustic anisotrophy and shear wave splitting will indicate microfracture orientation, which may or may not coincide with contemporary stress axes. All these methods are in common use today, especially within the oil industry.

10. Zoback, M.L., and Zoback, M.D., (1989), Tectonic Stress Field of the Continental United States, in Pakiser, L.C. and Mooney, W.D., Geophysical Framework of the Continental United States:

Boulder, Colorado, Geological Society of America, Memoir 172, pp. 523-539.

The orientation and relative magnitude of in-situ stress in the continental United States have been inferred from a variety of indicators, including earthquake focal mechanisms, stress-induced elliptical borehole enlargement (“breakouts”), hydraulic fracturing stress measurements, and young fault slip and volcanic alignments. The data comes from a wide range of depths (0.1 to 20 km) and has been assigned a quality ranking according to their reliability as tectonic stress indicators. The data shows that regionally consistent orientations persist throughout the seismic

“brittle” upper crust. Stress provinces are defined on the basis of uniform stress orientations and relative stress magnitude (style of faulting).

The sources of stress for all the major stress provinces are believed to be linked either directly or indirectly to plate-tectonic processes. Most of the central and eastern United States is part of a broad “midplate” stress province (which includes most of Canada and possibly the western

Atlantic basin) characterized by NE - to ENE – oriented maximum horizontal compression. This orientation range coincides with both absolute plate motion and ridge push directions for North

America. With the exception of the San Andreas region and most of the Pacific Northwest area, the remainder of the western United States (generally, the thermally elevated region from the high Great Plains to the west and including the Basin and Range province) is characterized by extensional tectonism. Within areas of “classic” basin-range structure, both those currently active and those largely quiescent, the least horizontal stress is orientated approximately E – W

(between WNW and ENE). In the Colorado Plateau interior and the southern Great Plains, the least horizontal stress is NNE, roughly perpendicular to that in surrounding areas. The state of stress in these two regions may be related to pronounced lateral variations in lithosphere thickness beneath them.


New focal-mechanism data in western Washington and northern Oregon define a region of NE compression apparently associated with subduction of the Juan de Fuca plate. In the coastal region of central California, there appears to be a zone approximately 100 to 125 km wide on both sides of the San Andreas fault in which the maximum horizontal stress is oriented NE, nearly perpendicular to the fault itself. While compression orthogonal to the San Andreas fault explains late Tertiary – Quaternary folding and reverse faulting sub-parallel to the San Andreas, this NE compression seems incompatible with the right-lateral slip in the N40W-trending San

Andreas fault. The observed stress field, however, is consistent with current estimates of the direction of relative plate motions, provided that the shear strength of the San Andreas is appreciably lower than the level of far-field stress in the crust.


Guidelines to be Used to Evaluate Underground Gas Storage

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