A Better Modeling Approach for Hydraulic Fractures in

A Better Modeling Approach for Hydraulic

Fractures in Unconventional

Reservoirs

OUTLINEOUTLINE

Numerical Simulation:

Comparison of Conventional and

NEW Approaches

NEW Approach as a Modeling Tool (understanding what has occurred)

Field Examples

Predictive Tool (investigating what might occur) Field Examples

What Is Our Goal? What Is Our Goal?

To quantify the impact of different strategies Well placement Well spacing Well orientation Number of stages Fracture treatment rates Fracture treatment volumes Cluster spacing (if applicable) Perforation density (if applicable)

How Do We Achieve The Goal?How Do We Achieve The Goal?

Unlike the early days, we have thousands of wells and performance data

Post-mortem analysis is the key to understand the controlling parameters

This can only be achieved by sophisticated approaches that can account for the interaction among controlling parameters

Must be able to predict outcomes for different well placement/completion strategies

Must be able to predict outcomes for multi-well applications where interference is important

How Do We Achieve The Goal?How Do We Achieve The Goal?

We need very sophisticated, integrated (geomechanics/flow) simulation models that can be quickly calibrated for: Fracking operation for all stages

Flow-back period for frack fluid

Production period for oil/gas/water

Use the calibrated models to study alternatives: Well placement, orientation, spacing

Completion design

Frack operation

Conventional modeling approachConventional modeling approach

Estimate reservoir matrix and natural fracture properties

Conventional modeling approachConventional modeling approach

Estimate reservoir matrix and natural fracture properties

Assume SRV geometry Estimate fracture height Estimate fracture half length Estimate fracture frequency Estimate distribution

Conventional modeling approachConventional modeling approach

Estimate reservoir matrix and natural fracture properties

Assume SRV geometry Estimate fracture height Estimate fracture half length Estimate fracture frequency Estimate distribution

Calibrate to post-fracturing production performance only Has limited predictive capability

NEW modeling approachNEW modeling approach

Estimate reservoir matrix and natural fracture properties

NEW modeling approachNEW modeling approach

Estimate reservoir matrix and natural fracture properties

Generate SRV geometry and properties as part of the calibration process

NEW modeling approachNEW modeling approach

Estimate reservoir matrix and natural fracture properties

Generate SRV geometry and properties as part of the calibration process

Calibrate to the fracture treatment, flow back and production periods

Calibration through tuning of the geomechanical properties which define the SRV parameters

fracture height fracture half length fracture frequency distribution (complexity,

location of complexity)

Conventional\NEW approachConventional\NEW approach

Conventional NEW

Conventional\NEW approachConventional\NEW approach

Difference in EURDifference in Drainage Area

Example~10 yrs

5740 ft2500 ft

NEW

Conventional

Conventional NIEW

SRV Generation – What We Used to ThinkSRV Generation – What We Used to Think

SRV Generation – What We Used to ThinkSRV Generation – What We Used to Think

SRV Generation – What We Used to ThinkSRV Generation – What We Used to Think

SRV Generation – What We Used to ThinkSRV Generation – What We Used to Think

SRV Generation – What We Used to ThinkSRV Generation – What We Used to Think

SRV Generation – What We Used to ThinkSRV Generation – What We Used to Think

SRV Generation – What It Really Looks LikeSRV Generation – What It Really Looks Like

SRV Generation – What It Really Looks LikeSRV Generation – What It Really Looks Like

NEW Approach as a Modeling ToolNEW Approach as a Modeling Tool

Use a finite difference simulator

with geomechanical capabilities,

in dual porosity mode,

to simulate the life of a hydraulically fractured well from the first stage of fracturing to the end of its productive life.

SENSOR® is a finite difference simulator with pseudo geomechanical capabilities Generates fractures by simulating the growth

of the SRV during the frac treatment MatchingPro® is an assisted history matching

program Introduction of geomechanical properties

multiplies the complexity of the history matching process

NEW Approach as a Modeling ToolNEW Approach as a Modeling Tool

Accounts for net pore pressure (stress) changes from initial conditions throughout the frac treatment (stage by stage) and during subsequent depletion

NEW Approach as a Modeling ToolNEW Approach as a Modeling Tool

Accounts for net pore pressure (stress) changes from initial conditions throughout the frac treatment (stage by stage) and during subsequent depletion

Process allows for tensile and shear rock failures

NEW Approach as a Modeling ToolNEW Approach as a Modeling Tool

Accounts for net pore pressure (stress) changes from initial conditions throughout the frac treatment (stage by stage) and during subsequent depletion

Process allows for tensile and shear rock failures

Accordingly the net pore pressure impacts fracture pore volume and transmissibility and the matrix-fracture communication (TEX)

change

NEW Approach as a Modeling ToolNEW Approach as a Modeling Tool

Basic Concepts – Pore PressureBasic Concepts – Pore Pressure

Increase in pore pressure results in decrease of net effective stress

After initiation, fractures propagate perpendicular to minimum horizontal stress

Extent of fracture depends on rock properties

Direction and magnitude depend on principal stresses

poreeff P )'(

Mohr-Coulomb Failure CriteriaMohr-Coulomb Failure Criteria

σ᾿nσT

This is the rock in its natural state

Cohesive strength - S0

Cohesive strength and Coefficient of Internal friction different for different rocks

σ᾿3

σ᾿1

σ᾿n

τ

σT

σ᾿1

σ᾿3

Mohr-Coulomb Failure CriteriaMohr-Coulomb Failure Criteria

Initial pressure

σ᾿n

τ

σT

σ᾿1

σ᾿3

This is the rock in its natural state

Mohr-Coulomb Failure CriteriaMohr-Coulomb Failure Criteria

Initial pressure

Stronger shear strength

Less anisotropy

σ᾿n

τ

σT σ᾿1

σ᾿3

Increase of Pore Pressure

Shear Failure

Mohr-Coulomb Failure CriteriaMohr-Coulomb Failure Criteria

When we increase the pore pressure, we reduce the net effective stress

poreeff P )'(

σ᾿n

τ

σT σ᾿1

σ᾿3

Increase of Pore Pressure

Shear Failure

Mohr-Coulomb Failure CriteriaMohr-Coulomb Failure Criteria

σ᾿n

τ

σT

σ᾿1

σ᾿3

Increase of Pore Pressure

Tensile Failure

Mohr-Coulomb Failure CriteriaMohr-Coulomb Failure Criteria

Finally, tensile failure is triggered causing dilation of the pore space and propagation of the hydraulic fracture.

Direction of the fracture depends on stress directionsExtent of the fracture depends on rock propertiesComplexity of the fracture depends on stress anisotropy, rock properties and injection rates

Frac fluid

Injecting fluid into the reservoir increases pore pressure

Increasing the pore pressure decreases the effective stress

At low effective stresses the rock undergoes shear and tensile failures

Those failures generate flow pathways

Basic Concepts – Hydraulic FracturingBasic Concepts – Hydraulic Fracturing

Source: http://www2.epa.gov/hydraulicfracturing

Basic Concepts – Hydraulic FracturingBasic Concepts – Hydraulic Fracturing

Simple fractures Complex fractures

Source: Hydraulic Fracture complexity and treatment design in Horizontal wells, Craig Cipolla

Source: Warpinski, N.R. ; Mayerhofer, M.J. ; Vincent, M.C. ; Cipolla, C.L. ; Lolon, Stimulating Unconventional Reservoirs: Maximizing Network Growth While Optimizing Fracture Conductivity, Unconventional reservoir modeling conference, 2008. SPE 114173

• Flow in dual porosity systems

• More complex fractures result in more fluid transfer between matrix and fracture media

MATRIX

FRACTURE

MATRIX MATRIX

Bi-Wing FractureSimple Geometry

Bi-Wing FractureComplex Geometry

Increasing TEX –Increasing fracture complexity

‐ Increasing fracture density within the matrix adjacent to the bi‐wing frac.

TEX determines the flow between matrix and the fracture

Fracture Complexity and Distribution

Stage by Stage SRV growth

The next slides show the stage by stage SRV generation (14 stages)

Color indicates TEX Higher TEX values indicate greater

communication between the fracture and matrix systems

Example SRV GenerationExample SRV Generation

Study #1Study #1

Study #1Study #1

Study #1Study #1

Study #1Study #1

Study #1Study #1

Study #1Study #1

Study #1Study #1

Study #1Study #1

Study #1Study #1

Study #1Study #1

Study #1Study #1

Study #1Study #1

Study #1Study #1

Study #1Study #1

Calibration to the Frac StagesCalibration to the Frac Stages

SRV Aspect RatioSRV Aspect Ratio

750 ft Width

300 ft Height

View from heel to the toe

TEX Value

SRV Aspect RatioSRV Aspect Ratio

300 ft Height

Side view. Heel is on right.

TEX Value

SRV Aspect RatioSRV Aspect Ratio

750 ft Width 450 ft Width

View from top. Heel is on Right

TEX Value

After the Frac TreatmentAfter the Frac Treatment

Hydraulic fractures start closing once the treatment is completed

Persistent leak-off decreases the pressure – initiates closure

Leak-off is loss/imbibition of the fluid into the matrix!

Production - decreases the pore pressure – closure continues

Matrix porosity/permeability reduces also

Tensile failures - close most rapidly

Proppant is used to keep tensile fractures open

Shear failures - close more slowly or stay open

Rock dislodging and fragments act as proppant

SRV “Closure”SRV “Closure”

After the SRV is generated during the hydraulic fracture treatment, the connectivity reduces as the result of depletion

Simulation data table determines the transmissibility reduction as a function of pore pressure

Fracture ClosureFracture Closure

Pore Pressure

Log(T-multiplier)

Pinit Pfrac

Pore Pressure

Log(T-multiplier)

Tip of the fracture:

Stem of the fracture:

Fracture ClosureFracture Closure

Pore Pressure

Log(T-multiplier)

Tip of the fracture: where the proppant cannot get to and is ineffective

Stem of the fracture: where proppant is accumulated and is effective

Fracture ClosureFracture Closure

Pore Pressure

Log(T-multiplier)

Tip of the fracture closes during flow-back period

Stem of the fracture

Fracture ClosureFracture Closure

Pore Pressure

Log(T-multiplier)The propped portion of the hydraulic fracture stays open well below the initial reservoir pressure

Fracture ClosureFracture Closure

Assisted History Matching (AHM)Assisted History Matching (AHM)

Large number of parameters means that history matching by hand is difficult

MatchingPro is an assisted history match (AHM) program that uses an objective function to assess and generate new solutions

User specifies which parameter values to vary and by how much

AHMAHM

Objective function based on the following data Hydraulic Fracturing Period

Inject measured volumes of fluid Constrained by maximum injection BHP

Flow back and Production Period Produce correct quantities of fluid

Oil Gas Water

Match the pressure of the natural flow period Match the monthly volumes of produced fluids

AHMAHM

Worse Case (Obj Func = ~900)

Best Case(Obj Func = ~75)

Approximately 200 runs

AHM ResultsAHM Results

THP

Water Rate

Gas Rate

Oil Rate

Worse Case - Blue Best Case - Black

MatchingProMatchingPro

Simulating fracture treatments results in a large number of unknown parameters

Parameter spaceUp to 18 parameters during investigation phase

MatchingProMatchingPro

These eight variables proved to be the most important for one of our projects

CTEX: TEX compressibilityCX: TX compressibilityOWC: Oil Water ContactSORW: Residual oil saturation to

waterSRV: SRV Growth FactorTEXS: TEXMOD from shear

failureTEXT: TEXMOD from tensile

failureTX: X direction transmissibility

modifier

Number of parameters reduced in later phase of calibration

SRV Simple or SRV ComplexSRV Simple or SRV Complex

SRV with Simple Fractures

SRV with Complex Fractures

MatchingPro®

Project ResultsProject Results

4 Projects: Project #1: Bakken Project #2: Bakken(same field as #1) Project #3: Wolfcamp Project #4: Eagleford

Project #1Project #1

Solid lines represent simulated data.Colored points indicate measured data

Project #1Project #1

Solid lines represent simulated data.Shaded areas indicate measured data

Project #2Project #2

Solid lines represent simulated data.Colored points indicate measured data

Project #2Project #2

Solid lines represent simulated data.Shaded areas indicate measured data

Project #3Project #3

Solid lines represent simulated data.Colored points indicate measured data

Project #3Project #3

Solid lines represent simulated data.Shaded areas indicate measured data

Project #4 – Well 1Project #4 – Well 1

Project #4 – Well 2Project #4 – Well 2

Frac volume ± 5 %Length ± 10 %

NEW Approach as a Predictive toolNEW Approach as a Predictive tool

Conventional approach has limited predictive capability if completion practices change

Once calibrated, NEW approach has predictive capabilities

Alternative scenarios can be run to quantify the impact of different strategies Well placement/spacing Well orientation Fracture treatment volumes Fracture treatment rates Number of stages Placement of stages

Investigate Well CompletionsInvestigate Well Completions

Accelerated Performance

18 stages, X volume, X min21 stages, X volume, X min

Optimize Fracture Treatment VolumeOptimize Fracture Treatment Volume

Doubling of Frac Injection Rate Base

2 x Frac vol.

Optimize Well OrientationOptimize Well Orientation

Orientation 1

Orientation 2

Multiple WellsMultiple Wells

Project Description: All wells use the same drilling and completion

strategy First well drilled in 2008 and produces Second well drilled in 2011 and produces Third well to be drilled in 2013

Automatically accounts for affect of stress level changes from one well fracture area to another over time

Multiple WellsMultiple Wells

2008

Multiple WellsMultiple Wells

2011

Multiple WellsMultiple Wells

2013

How Are The Forecasts Holding Up?How Are The Forecasts Holding Up?

HM~ 8 months

Here is how we compare ~22 months later

How Are The Forecasts Holding Up?How Are The Forecasts Holding Up?

HM~ 5 months

Here is how we compare ~20 months later

How Are The Forecasts Holding Up?How Are The Forecasts Holding Up?

HM~ 12 months

Here is how we compare ~13 months later

How Are The Forecasts Holding Up?How Are The Forecasts Holding Up?

HM~ 6 months

Here is how we compare ~14 months later

Known change from Gas lift to SP during this period

Summary

Analyze multiple wells in the same field Different hydraulic fracture treatments

Understand the performance differences based onReservoir qualityCompletion typeTreatment volumesTreatment stages

Optimize treatment practices and well spacing

Supplemental recovery mechanisms

Questions?

Thank You!