A Better Modeling Approach for Hydraulic Fractures in ...
Transcript of A Better Modeling Approach for Hydraulic Fractures in ...
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A Better Modeling Approach for Hydraulic
Fractures in Unconventional
Reservoirs
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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
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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)
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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
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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
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Conventional modeling approachConventional modeling approach
Estimate reservoir matrix and natural fracture properties
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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
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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
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NEW modeling approachNEW modeling approach
Estimate reservoir matrix and natural fracture properties
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NEW modeling approachNEW modeling approach
Estimate reservoir matrix and natural fracture properties
Generate SRV geometry and properties as part of the calibration process
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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)
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Conventional\NEW approachConventional\NEW approach
Conventional NEW
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Conventional\NEW approachConventional\NEW approach
Difference in EURDifference in Drainage Area
Example~10 yrs
5740 ft2500 ft
NEW
Conventional
Conventional NIEW
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SRV Generation – What We Used to ThinkSRV Generation – What We Used to Think
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SRV Generation – What We Used to ThinkSRV Generation – What We Used to Think
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SRV Generation – What We Used to ThinkSRV Generation – What We Used to Think
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SRV Generation – What We Used to ThinkSRV Generation – What We Used to Think
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SRV Generation – What We Used to ThinkSRV Generation – What We Used to Think
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SRV Generation – What We Used to ThinkSRV Generation – What We Used to Think
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SRV Generation – What It Really Looks LikeSRV Generation – What It Really Looks Like
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SRV Generation – What It Really Looks LikeSRV Generation – What It Really Looks Like
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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.
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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
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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
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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
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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
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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 )'(
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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
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σ᾿n
τ
σT
σ᾿1
σ᾿3
Mohr-Coulomb Failure CriteriaMohr-Coulomb Failure Criteria
Initial pressure
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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
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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 )'(
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σ᾿n
τ
σT σ᾿1
σ᾿3
Increase of Pore Pressure
Shear Failure
Mohr-Coulomb Failure CriteriaMohr-Coulomb Failure Criteria
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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
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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
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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
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• 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
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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
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Study #1Study #1
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Study #1Study #1
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Study #1Study #1
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Study #1Study #1
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Study #1Study #1
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Study #1Study #1
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Study #1Study #1
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Study #1Study #1
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Study #1Study #1
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Study #1Study #1
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Study #1Study #1
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Study #1Study #1
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Study #1Study #1
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Study #1Study #1
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Calibration to the Frac StagesCalibration to the Frac Stages
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SRV Aspect RatioSRV Aspect Ratio
750 ft Width
300 ft Height
View from heel to the toe
TEX Value
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SRV Aspect RatioSRV Aspect Ratio
300 ft Height
Side view. Heel is on right.
TEX Value
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SRV Aspect RatioSRV Aspect Ratio
750 ft Width 450 ft Width
View from top. Heel is on Right
TEX Value
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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
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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
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Fracture ClosureFracture Closure
Pore Pressure
Log(T-multiplier)
Pinit Pfrac
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Pore Pressure
Log(T-multiplier)
Tip of the fracture:
Stem of the fracture:
Fracture ClosureFracture Closure
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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
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Pore Pressure
Log(T-multiplier)
Tip of the fracture closes during flow-back period
Stem of the fracture
Fracture ClosureFracture Closure
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Pore Pressure
Log(T-multiplier)The propped portion of the hydraulic fracture stays open well below the initial reservoir pressure
Fracture ClosureFracture Closure
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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
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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
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AHMAHM
Worse Case (Obj Func = ~900)
Best Case(Obj Func = ~75)
Approximately 200 runs
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AHM ResultsAHM Results
THP
Water Rate
Gas Rate
Oil Rate
Worse Case - Blue Best Case - Black
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MatchingProMatchingPro
Simulating fracture treatments results in a large number of unknown parameters
Parameter spaceUp to 18 parameters during investigation phase
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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
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SRV Simple or SRV ComplexSRV Simple or SRV Complex
SRV with Simple Fractures
SRV with Complex Fractures
MatchingPro®
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Project ResultsProject Results
4 Projects: Project #1: Bakken Project #2: Bakken(same field as #1) Project #3: Wolfcamp Project #4: Eagleford
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Project #1Project #1
Solid lines represent simulated data.Colored points indicate measured data
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Project #1Project #1
Solid lines represent simulated data.Shaded areas indicate measured data
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Project #2Project #2
Solid lines represent simulated data.Colored points indicate measured data
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Project #2Project #2
Solid lines represent simulated data.Shaded areas indicate measured data
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Project #3Project #3
Solid lines represent simulated data.Colored points indicate measured data
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Project #3Project #3
Solid lines represent simulated data.Shaded areas indicate measured data
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Project #4 – Well 1Project #4 – Well 1
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Project #4 – Well 2Project #4 – Well 2
Frac volume ± 5 %Length ± 10 %
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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
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Investigate Well CompletionsInvestigate Well Completions
Accelerated Performance
18 stages, X volume, X min21 stages, X volume, X min
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Optimize Fracture Treatment VolumeOptimize Fracture Treatment Volume
Doubling of Frac Injection Rate Base
2 x Frac vol.
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Optimize Well OrientationOptimize Well Orientation
Orientation 1
Orientation 2
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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
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Multiple WellsMultiple Wells
2008
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Multiple WellsMultiple Wells
2011
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Multiple WellsMultiple Wells
2013
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How Are The Forecasts Holding Up?How Are The Forecasts Holding Up?
HM~ 8 months
Here is how we compare ~22 months later
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How Are The Forecasts Holding Up?How Are The Forecasts Holding Up?
HM~ 5 months
Here is how we compare ~20 months later
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How Are The Forecasts Holding Up?How Are The Forecasts Holding Up?
HM~ 12 months
Here is how we compare ~13 months later
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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
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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
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Questions?
Thank You!