Modeling Complexities

Of Natural Fracturing

Key In Gas Shales

By William Dershowitzand Thomas W. Doe

REDMOND, WA.–Safe, efficient, and profitable development of shale

natural gas resources depends on achieving a clear understanding of the

role of natural fractures in shale gas production.

Natural fracturing is critical to enhancing stimulation treatment design and

optimizing well performance. Although every shale formation is somewhat

different, there can be significant variations in natural fracture systems from

one location to another within a given play area, with equally significant

differences in production rates from one well to another.

Reservoir development is impacted by natural fractures in three ways. First,

natural fractures are planes of weakness that may control hydraulic fracture

propagation. Second, high pressures from the hydraulic frac treatment may

cause slip on natural fractures that increases their conductivity. Third, natural

fractures that were conductive prior to stimulation may affect the shape and

extent of a well’s drainage volume.

The “Better Business” Publication Serving the Exploration / Drilling / Production Industry

AUGUST 2011

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There are three classes of shale gas reservoirs, and the strat-egy for developing each class of reservoir can be dramaticallydifferent. The reservoir classifications are based on the degreeof natural fracturing and how gas is stored within the shale:

• Type A: Hydraulic fracture propagation provides the onlyflow pathway to the well.

• Type B: Hydraulic fracture propagation provides the pri-mary flow pathway to the well, but is supplemented by naturalfractures that are critically stressed by frac fluids (especiallyrough fractures).

• Type C: Frac fluid “leak off” to natural fractures is ex-tensive (Figure 1), and production is through a combined net-work defined by the hydraulic fractures and natural fractures(or perhaps by the natural fractures alone).

While a play may include all three types of reservoirs, it isessential to identify which reservoir type is dominant. For TypeA reservoirs (Figure 2), where the only flow paths are hydrauli-cally induced fractures, gas storage is exclusively within theshale rock matrix. For Type B (Figure 3) and C (Figure 4) reser-voirs, gas can be stored in some combination of shale rock ma-trix and natural fractures. The reservoir type has a profound in-fluence on the reservoir recovery factor, initial production, andthe decline curve of production over time.

This type of fine-tuning of the choice of approaches works

well in shale gas plays, because in many cases, these develop-ments have the advantage that comes from having plentifulhigh-quality data characterizing reservoirs, even in early stagesof development.

Fracture image logs provide insights into the natural frac-ture pattern, production logs and gas returns support under-standing of how gas is delivered to the well bore both beforeand after fracturing, and 3-D seismic provides a clear pictureof stratigraphy and faulting. Microseismic and seismic energymonitoring provides a 3-D visualization of hydraulic fracturesand reactivated natural fractures.

Despite this wealth of information, many operators still de-velop shale gas fields using empirical approaches, ignoring thenatural fracture patterns and spending tens of millions of dol-lars on inefficient or even counterproductive hydraulic fractur-ing strategies. Operators tend to develop shale gas as a “re-source play,” as if the production from each well was equivalent,while in fact, some wells in a reservoir can produce 5, 10 oreven 20 times more gas than average wells.

Fracture network models provide a means of quantifying hy-draulic properties from measured fracture data. Depending onthe scale of fracturing, fracture network models can be used to

FIGURE 1

Leak-Off from Hydraulic Fracture To Natural Fracture Network

FIGURE 2

Type A Gas Shale Reservoir (Flow from Hydraulic Fractures only)

Natural Fracture Network (DFN)

Leak-Off to Natural Fracture Network

Hydraulic Fracture

Well - 9 Frac Stages

Hydraulic Fractures (blue)

Drainage from Shale

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FIGURE 3

Type B Gas Shale Reservoir(Flow from Hydraulic and Natural Fractures)

Drainage Volume Accessed fromHydrofrac andReactivated Natural Fractures (yellow)

Natural Fractures (green)

Hydraulic Fractures (blue)

Well - 2 Stages Shown

FIGURE 4

Type C Gas Shale Reservoir(Reactivated and Connected Natural Fractures

Dominate Production)

Drainage Volume Accessed by Natural Fractures

Natural Fractures (colored by gas flow)

FIGURE 5Impact of Natural Fracture Properties on Stimulated Reservoir Volume

Stubby Narrow Elongate BroadElongate

estimate hydraulic parameters for reservoir simulation and pro-duction performance. Discrete fracture network (DFN) technol-ogy leverages the wealth of available data to understand boththe storage of gas in the shale reservoir, and the delivery of gasthrough fractures–both natural and hydraulically induced.

DFN Analysis

Figure 5 shows the impact of key natural fracture propertieson the stimulated reservoir volume after hydraulic fracturing.The DFN approach for natural and hydraulic fractures providesanalyses and workflows that help leverage the wealth of datacollected for shale gas reservoirs, and uses that information todetermine the type of shale reservoir and the best strategy forits development.

In terms of natural fracture geometry and properties, frac-ture image logs provide information on electrically conductiveand resistive natural fractures and bedding at well control. Im-age log technology is increasingly being used on horizontalwells to provide improved insights into subvertical fracture sets,which can dominate shale gas plays.

New drill bit fracture imaging technologies provide signifi-cant improvements to imaging, particularly for the horizontalwells that are used for shale gas development. The DFN ap-proach utilizes geologic, geophysical and geomechanical in-formation to extrapolate the natural fracture pattern beyondwell control to the entire reservoir.

Where controlling the vertical extent of fractures is a con-cern, it is essential to start fracture image logging substantiallyabove the targeted reservoir horizon. It has been observed thatin some reservoirs, only electrically conductive (“open” and“partially open”) fractures are important, while in other reser-voirs, closed and healed fractures, and bedding planes can pro-vide a significant influence on shale gas production.

Stratigraphic surfaces and faulting can be derived from 2-Dseismic data, but are now routinely supplemented by 3-D seis-mic interpretations. Seismic processing technologies such asamplitude-variation-with-offset have the additional advantageof characterizing liquids, which has been problematic.

While it is widely recognized that in situ stress plays an es-sential role in controlling hydraulic fracturing, the role of localin situ stress variability in fractured rocks also can be very im-portant. Each hydraulic fracture provides a stress shadow–asindeed do many natural fractures. Also, fault blocks can createlocal in situ stress conditions that are significantly differentfrom regional conditions.

The propagation of hydraulic fractures, and their interac-tion with natural fractures, is tightly dependent on in situstress conditions. Consequently, the derivation of in situ stressand its spatial variability is a key portion of the discrete frac-

ture network workflow. In some cases, in situ stress can bederived from drilling-induced tension fractures and bore holebreakouts seen in fracture image logs, while in other cases,it is best back-calculated from frac records and microseis-mic monitoring, or estimated from calibrated geomechanicalsimulations.

Rock mass and fracture geomechanical properties are keysto understanding fracture propagation, and especially, verticalcontrols on propagation beyond reservoir horizons. Rock masselastic modulus and strength properties can be estimated fromwireline and seismic, but are more accurate when supplement-ed by core and sidewall core testing. In particular, fracturetoughness and rock mass modulus (compressibility) are veryimportant controls on the hydraulic fracturing process, andshould be estimated as part of any DFN analysis workflow.

Reservoir pressures are also crucial. Hydraulic fracture prop-agation is controlled by “effective stress,” which is defined bythe total stress minus the reservoir pressure. As a result, accu-rate evaluation of fracture propagation also requires accurateestimates of reservoir pressure. This is particularly importantwhere the reservoir pressure is a significant fraction of the min-imum stress, which can occur frequently, particularly in over-pressured reservoirs.

While hydraulic fractures generally are assumed to propa-gate in tension, the combination of pre-existing natural frac-tures and high reservoir pressures can result in hydraulic frac-tures formed primarily as a coalescence of natural fracturesaffected by frac fluid pressures. This process occurs as a com-bination of tensional and shear propagation.

Geomechanical Simulation

Discrete fracture network geomechanical simulation has theadvantage that it starts from a realistic model of the naturalfractures, so that the natural fracture/hydraulic fracture inter-action can be modeled explicitly. Geomechanical modeling re-quires the ability to model both the deformation of the rockmass (allowing fractures to accept frac fluids and proppant),and the fracture propagation process itself.

Rock mass deformation is a combination of fracture defor-mation and the deformation of the rock matrix to accommo-date frac fluids penetrating natural and induced fractures. It hasbeen demonstrated clearly that rock mass effective deforma-bility is a combination of rock mass deformability (generallycharacterized by shear modulus and Poisson’s ratio) and frac-ture deformability (generally characterized as fracture shearand normal stiffness). Procedures exist for estimating rock massdeformability based on the types of fracture and rock charac-terization activities that are typically carried out for shale reser-voirs, as well as for estimating where detailed characterization

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has not yet been carried out.The derived rock mass deformability parameters then can

be used in geomechanical simulations. When fractures and bed-ding are considered, rock mass deformation in shale is gener-ally anisotropic, which needs to be considered carefully in fracjob design and monitoring.

Two approaches are available for geomechanical simulationof hydraulic fracture propagation and interaction with naturalfractures within a DFN. The fully coupled, flow/geomechani-cal approach requires the use of a finite element code that cansimulate both fracture and rock mass deformation, and alsosimulate frac fluid and proppant flow and fracture propagation.

The distinct element method meets all these requirements,particularly when integrated with a conventional finite elementanalysis approach such as Rockfield Software Ltd.’s ELFEN™code for numerical modeling. The advantage of the code in ful-ly coupled 2-D or 3-D geomechanical simulation is somewhatbalanced by the limitations of computation time, which limitsthe number of natural fractures that can be considered. The sim-pler alternative, a fully 3-D DFN approach, uses a less rigor-ous analysis, constrained by mass balance and simple elasticmodels of fracture growth and inflation (for example, the PKNmodel).

Answering Key Questions

Discrete fracture network analyses synthesize availablereservoir geologic, frac and production data to answer key reser-voir development questions, such as:

• What tributary drainage volume is drained by any givenhydraulic fracture or series of fractures?

• What depth of rock matrix is effectively drained to hy-draulic fractures?

• How are fracture heights controlled both to improve pro-duction efficiency and to minimize environmental risk?

• What is the most effective frac stage spacing and lengthto maximize production?

• What portions of a field are likely to be most productive?• Is water production a risk, and if so, how can it be miti-

gated?This type of analysis can help improve production efficien-

cies and improve environmental safety in shale gas extraction.r

WILLIAM DERSHOWITZ is the technical director of theFracMan Technology Group and a principal of Golder As-sociates Inc. in Redmond, Wa. He has pioneered naturalfracture analysis for oil and gas reservoirs for more than25 years, introducing FracMan, the first commercial dis-crete fracture network modeling software in 1987. Der-showitz received a Ph.D. in rock mechanics from the Mas-sachusetts Institute of Technology in 1985. He serves astreasurer of the American Rock Mechanics Association,and serves on the advisory board of the “Rock Mechanicsand Rock Engineering” journal.

THOMAS W. DOE is an authority on hydraulic fracturing,with more than 30 years of hydraulic fracturing experienceon six continents. He is a principal of Golder Associates inRedmond, Wa., and a member of the FracMan TechnologyGroup. Doe served on the U.S. National Committee for RockMechanics’ Committee on Fracture Characterization and Flu-id Flow, and is the author of “Fractured Bedrock Field Meth-ods and Analytical Tools,” a standard reference for fracturedrock characterization. He holds a B.A. in geology from PomonaCollege, and a Ph.D. in geology and mining engineering fromthe University of Wisconsin-Madison.

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