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Evaluation of Tight Gas ReservoirsEvaluation of Tight Gas Reservoirs
Victor Hein, P.E.Victor Hein, P.E.
Ryder Scott CompanyRyder Scott Company
June 2009June 2009
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Resource PyramidResource Pyramid
Small Volumes
Large Volumes
Increas e
dDemand
BetterT
echnologyHigh
Quality
Medium
Quality
Low
Quality
Coalbed
Methane
Gas
Shales
Tight
Gas
1000 md
100 md
1 md
0.1 md
0.001 md
0.0001 md Contin
uedDri
llingan
dDevelopme n
t
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Gas Consumption North AmericaGas Consumption North America
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Gas Consumption WorldGas Consumption World
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OECD CountriesOECD Countries
AustraliaAustriaBelgiumCanada
Czech RepublicDenmarkFinlandFrance
GermanyGreeceHungaryIcelandIreland
ItalyJapanKoreaLuxembourgMexico
NetherlandsNew ZealandNorwayPolandPortugalSlovak RepublicSpainSweden
SwitzerlandTurkeyUnited Kingdom
United States
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World Gas ReservesWorld Gas Reserves
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Excludes Russia
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Overview of World Gas ReservesOverview of World Gas Reserves
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Significant Gas FactsSignificant Gas Facts
Tight Gas 20% of US Production
Unconventional Gas 44% of 2005 US Production
Unconventional Gas 49% of 2030 US Production
2005 OECD 38 % Worlds Gas Production 2005 OECD 50 % Worlds Gas Consumption
2030 OECD 27 % Worlds Gas Production
2030 OECD 42 % Worlds Gas Consumption
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Tight Gas Resource TriangleTight Gas Resource Triangle
58 TCF produced through 2000 34 TCF Proven Reserves in 2001
Technically Recoverable volume 185 TCF
Undiscovered 350 TCF Additional GIP 5000 TCF
Source GTI 2001
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Tight Gas CharacteristicsTight Gas Characteristics
Low Permeability (
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Evaluation MethodsEvaluation Methods
Volumetrics Material Balance
Decline Curves
Production History Matching
Advanced Production Analysis
Simulation
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VolumetricsVolumetrics
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Archie EquationsArchie EquationsClean SandClean Sand
For low porosity sandstones:
a is typically 1.0m initially thought to be 2.0, later used values of 1.8-2.0
for tight gas
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Shaley SandShaley Sand
Fertl and Hammack reduction of Simandoux
Original Simandoux (widely used) based on very limited
samples
Vsh is effective shale volume, fraction
F is from shale corrected porosity
Rsh is the resistivity of the shale in sand recommends0.4R of shale beds
Hilchie 1982
Advanced Well Log Interpretation
D it P itD it P it
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Density PorosityDensity PorosityCorrections for InvasionCorrections for Invasion
Clean SandClean Sand
Density gets most of response from 3-4 from wellbore
Solve equations by trial and error
Initial guess for b is from mf= 1 + 0.73P where P is
Salinity in ppm divided by 1,000,000
Calculate gas density or estimate from following figure
When numbers converge you have answerHilchie 1982
Advanced Well Log Interpretation
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Density Neutron PorosityDensity Neutron Porosity
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Density Neutron PorosityDensity Neutron PorosityType I Invasion ProfileType I Invasion Profile
Hilchie 1982
Advanced Well Log Interpretation
Very deep or very shallow invasion - logs read same fluid
Quick approach below, best simultaneous eq using Rxo
Density Neutron PorosityDensity Neutron Porosity
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Density Neutron PorosityDensity Neutron PorosityType II Invasion ProfileType II Invasion Profile
Hilchie 1982
Advanced Well Log Interpretation
Invasion on order of 3-4 but not beyond neutron
Simultaneous equations for density with Rxo device best
Use density porosity only will be somewhat high
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Combined Archie EquationCombined Archie EquationClean SandClean Sand
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Pi k tt Pl t E l
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Pickett Plot Example
Th i N P d
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Their New ProcedureTheir New Procedure
R1(T1+6.77) = R2(T2+6.77)
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ConclusionsConclusions
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ConclusionsConclusions
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Net pay 18ft
Net pay added using highresolution is 50 feet!
High Resolution in Layered SandsHigh Resolution in Layered Sands
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Net PayNet Pay
Low Permeability Zones Often Have ExtensiveTransition Zones
Calibrate Cutoffs with Cores
Archie Equation Breaks Down at Very Low Porosities
for m = 2
Watch Out for Laminated Sands Below Vertical
Resolution of Logs
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Data IntegrationData Integration
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General Observations Log AnalysisGeneral Observations Log Analysis
Tight gas systems often contain layered and/or
dispersed clay (analysis methods different) Core data and FMI often critical to understanding
type system and existence of fractures
Must depth shift logs particularly in layered system
Calibrate logs and k estimates to cores Consider special core analysis in new plays
Full logging suite required for shaley sands
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What Is Effective Drainage Area?What Is Effective Drainage Area?
1 Year
0.1 md
0.0001 md0.001 md
0.01 md
10 Years
0.1 md
0.0001 md0.001 md
0.01 md
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Effective Drainage AreaEffective Drainage Area
Drainage Area f(k, Xf, Porosity, Geometry)
Have Dependent Relationship Between
Effective Drainage Area and Recovery Factor
Should Define Effective Drainage Area Relative
to Time and Recovery Factor
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Core AnalysisCore Analysis
CER, Holditch & Assoc 1991
Analysis critical to understanding of layered or
complex reservoir
Must measure rock properties under NOB(Jones andOwens, Soeder and Randolf)
Can have ten fold or more reduction in permeability
due to NOB at 0.01 md and below
Lower permeability rocks - smaller pore throats
Reduction of k with net overburdenReduction of k with net overburden
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Reduction of k with net overburdenReduction of k with net overburden
CER, Holditch & Assoc 1991
Reduction of k with net overburdenReduction of k with net overburden
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Reduction of k with net overburdenReduction of k with net overburden
Mesaverde FormationMesaverde Formation
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Estimation of Permeability From LogsEstimation of Permeability From LogsExample Timurs Equation
c
wi
ma
S
Kk
=
c = 2 since k inversely proportional to surface area
squared and Swi proportional to surface area
Plot vs2)( wiSk straight line with slope m on log log
and y axis intercept at Ka
m related to tortuosity of the rockKukal, Simons SPE 13880
Estimation of k in very tight rocksEstimation of k in very tight rocks
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Estimation of k in very tight rocksEstimation of k in very tight rocks Timurs: little data < 1 md, also unstressed k
Predicted k two orders of magnitude high for 0.1d < k < 0.1md
Clay increases tortuosity, surface area
Better method: plot k(Swi**2) vs. ((1-Vcl) on log log plot
where: Swi and Vcl in fractions
K includes effect of overburden at 1.0 psi/ft
Swi must be at irreducible
must correct k to Kg
Derived from Mesaverde core date in Western Colorado
Kukal, Simons SPE 13880
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Estimating k where SEstimating k where Swiwi unknownunknown
86.3))1((4.171 clVk =
Porosity and Vcl in fractions
Only slightly less accurate that equation with Swi
Derived from Mesaverde also works in Travis Peak in
East Texas
Other examples of slot pore geometry are Albertas
deep Spirit River, East Texas Cotton Valley,Piceance Cozzette, Wyoming
Should be useful in many low k sandstones
Kukal, Simons SPE 13880
Plot k vs. ((1-Vcl)) on log log plot
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Material Balance P/ZMaterial Balance P/Z
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P/Z Based on Tank ModelP/Z Based on Tank Model
Constant Volume
No Efflux or Influx
Pressure Gradients Small
Measured Pressures Representative of Average
Pressure
Tight Gas P/Z PlotTight Gas P/Z Plot
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Tight Gas P/Z PlotTight Gas P/Z Plot
R di f D i R di l FlR di f D i R di l Fl
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Radius of Drainage Radial FlowRadius of Drainage Radial Flow
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Transient vs. Boundary FlowTransient vs. Boundary Flow
Constant Rate Example
Cross Section
Plan View
3500
2500
4000
3000
2000
Boundary Dominated
Well Performance
f(Volume, PI) Transient Well P
f(k, skin, ti
Fekete RTA
Documentation
T i t B d FlT i t B d Fl
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Transient vs. Boundary FlowTransient vs. Boundary Flow
Transient Flow
Early time or lowpermeability.
Flow that occurs when the
pressure pulse is
moving into an infinite orsemi infinite acting
reservoir.
The fingerprint of the
reservoir. Contains
information about
reservoir properties ie k
Boundary Flow
Late time flow behavior. Typically dominates long
term production data.
Reservoir is in a state of
pseudo-equilibrium massbalance.
Contains information
about reservoir pore
volume (OGIP).
Fekete RTA
Documentation
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Time to Pseudo Radial FlowTime to Pseudo Radial Flow
3
006328.02 =
ft
fXDxc
kt
t
Lee, Wattenbarger SPE Textbook 5
D ti f Fl P i d HF W llD ti f Fl P i d HF W ll
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Duration of Flow Periods HF WellDuration of Flow Periods HF Well
Lf (ft) k(md) telf tsprf
100 1 0.3 hrs 51.2 hrs100 0.01 27.3 hrs 213 days
1,000 0.01 114 days 58 years
100 0.001 11.4 days 5.8 years
1,000 0.001 3.1 years No way!!
= 0.15, CrD = 100, = 0.03 cp, ct = 0.0001 1/psi
Ti h G P B ild T
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Tight Gas Pressure Buildup TestsTight Gas Pressure Buildup Tests
very important to run prefrac BU for k and Pwsi
prefrac results can insure on proper straight line after
production period of significant length for pseudo radial
common problem in PT tests is that shut in period is too
short
too short of flow period can also be a problem i.e
wellbore unloading is incomplete (mass rate at surface
exceeds mass rate out perforations)
consider bottom hole shut-in (tubing plug) if afterflow
exceeds maximum practical test time
P B ild T t D i
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Pressure Buildup Test DesignPressure Buildup Test Design
make estimates of kgfrom guess then test data
estimate end of WBS
estimate beginning of pseudo radial flow
estimate onset of BDF
post frac estimates for time use type curves
SPE 17088, Dr. W. J. Lee
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Static Material Balance ProblemsStatic Material Balance Problems
Difficult to Analyze Due to Required SI Time,
Heterogeneity, Large Pressure Gradients
Common Curved Behavior
Can Result in Large Errors for GIP which are Generally
Low for Early Cum Values Increased SI Times Help but GIP Generally Low
Scatter = f(Pressure Gradients, Heterogeneity)
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Static Material Balance SummaryStatic Material Balance Summary
Get Pre Frac Initial Pressure Use Longer SI Times if Possible
Existence of Straight Line Does Not Insure Tank
Behavior
If Curved or Two Slopes Look at Later Straight Line
If Possible, QC Shut-in Times
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Flowing Material BalanceFlowing Material Balance
FTP converted to FBHP
Pseudo Pressure and Pseudo Time to Correct for
Viscosity and Compressibility Changes
Uses BDF flow equation for Gas simplified to
pssp
pa
i
pssp bp
GG
bp
q 11+
=
Iterative Process Dependent on guess for OGIP Plot Normalized Rate and Cum Prod
Fl i M t i l B lFlo ing Material Balance
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Flowing Material BalanceFlowing Material Balance
ppq
p
pa
p
G
Flowing Material BalanceFlowing Material Balance
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Flowing Material BalanceFlowing Material Balance
Curve is concave up until PSS - generally yielding
minimum OGIP Model is well in Center of Circle
Liquid Loading, Condensate Ring, Scale, etc. can
Affect Results
Dont use where Water Drive or Abnormal Pressure Use with Caution for High Perm Variations
Can be Useful but be Careful
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Decline CurvesDecline Curves
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D li C E ti ADecline Curve Equations Arps
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Decline Curve Equations - ArpsDecline Curve Equations - Arps
Exponential
Hyperbolic
A T diti l A l iA T diti l A l i
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Arps Traditional AnalysisArps Traditional Analysis
Based on Empirical Observations Exponential (D is constant)
Hyperbolic (D changes with time, 0
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Types of Decline Curves - ArpsTypes of Decline Curves - Arps
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Criteria for Arps AnalysisCriteria for Arps Analysis
Well Produced at or near Capacity Constant Flowing Bottom Hole Pressure
Drainage Area Remains Constant (BDF has been
Achieved)
Same Completion
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What About b > 1 ?What About b > 1 ?
Wrong Interpretation
Transient Flow instead of Boundary Dominated
Effects of b FactorEffects of b Factor
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Effects of b FactorEffects of b Factor
Cox, et alSPE 78695
Deep Tight Gas ExampleDeep Tight Gas Example
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Deep Tight Gas ExampleDeep Tight Gas Example
0.0009 < k < 0.07 md
Spacing 80 acresPwsi = 16,200 psia
BHT 400 deg F
Porosity = 6.6%Sw = 36%
Kv/Kh = 0.001
Thickness = 200
Rushing, et al SPE 109625
Xf= 300 (unless specified)
Fracture k = 100md
Effects of Layers on b ExponentsEffects of Layers on b Exponents
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Effects of Layers on b ExponentsEffects of Layers on b Exponents
Years b
1 Lay
b
4 Lay
b
8 Lay
b
16Lay
Error
(%)
1Layer
Error
(%)
4Layer
Error
(%)
8Layer
Error
(%)
16Layer
1 3.62 2.78 2.89 2.97 132 110 117 128
5 2.95 1.35 1.30 1.39 58 22 11 20
10 1.48 1.04 1.18 1.26 19 8 9 11
20 0.58 1.01 1.04 0.96 0.1 7 7 3
Effects of Xf on b ExponentsEffects of Xf on b Exponents
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Effects of Xf on b ExponentsEffects of Xf on b Exponents
Years b
Xf=50
b
Xf=100
b
Xf=300
b
Xf=500
Error
(%)
Xf=50
Error
(%)
Xf=100
Error
(%)
Xf=300
Error
(%)
Xf=500
1 4.01 3.60 2.78 1.91 145 139 110 78
5 1.53 1.44 1.35 1.20 34 25 22 12
10 1.10 1.08 1.04 1.03 14 10 8 7
20 1.07 1.06 1.01 0.96 0.11 9 7 6
Synthetic Single ReservoirSynthetic Single Reservoir
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80 acres80 acres
Cheng, Lee, McVay
SPE 108176
Synthetic Single ReservoirSynthetic Single Reservoir
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80 acres80 acres
Cheng, Lee, McVay
SPE 108176
Synthetic Single ReservoirSynthetic Single Reservoir
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80 acres80 acres
Cheng, Lee, McVay
SPE 108176
Synthetic Single ReservoirSynthetic Single Reservoir
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80 acres80 acresall data includedall data included
Cheng, Lee, McVay
SPE 108176
All predictions from regression are too high
All values of b >1.0
b is proportional to Di
Percent error increases as b increases
Correct values for b cannot be directly obtained
from transient data
Synthetic Single ReservoirSynthetic Single Reservoir
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80 acres80 acres
Cheng, Lee, McVay
SPE 108176
Stabilization time was 4.4 years
Discarded all data prior to 5.0 years
b generally decreases with time and all b values < 1.0
Results indicate that using only stabilized data sufficiently accurate
Decline Curve EstimateDecline Curve Estimate
Si l L b i d 1 0Si l L b t i d t 1 0
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Single Layer, b constrained to 1.0Single Layer, b constrained to 1.0
Cheng, Lee, McVay
SPE 108176
Decline Curve EstimateDecline Curve Estimate
Si l L b t i d t 1 0Si l L b t i d t 1 0
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Single Layer, b constrained to 1.0Single Layer, b constrained to 1.0
Cheng, Lee, McVay
SPE 108176
Decline Curve EstimateDecline Curve Estimate
Si l L b t i d t 1 0Si l L b t i d t 1 0
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Single Layer, b constrained to 1.0Single Layer, b constrained to 1.0
Cheng, Lee, McVay
SPE 108176
b= 1.0 results in either underestimates oroverestimates
At early times production generally
underestimated
Forecasts tend to be more stable as more
late time data are included in the analysis
Additional ObservationsAdditional Observations
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Additional Observationsdd o a Obse a o s
Cheng, Lee, McVay
SPE 108176
b for stabilized flow related to reservoir drivemechanism, fluid properties and reservoir conditionsFetkovich et al 1996, Chen and Teufel 2002
b decreases as reservoir depletes
Average b during entire depletion phase will be < 1Chen and Teufel 2002
Improved Analysis TechniqueImproved Analysis Technique
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Improved Analysis Techniquep y q
Chen 2002
Calculate bE Pi = initial reservoir pressure
Pp,n = is normalized pseudo pressure
Cgi is isothermal compressibility @ Pi Zi evaluated at Pp, Zwfevaluated at Pwf
Improved Analysis TechniqueImproved Analysis Technique
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p o ed a ys s ec quep y q
Cheng, Lee, McVay
SPE 108176
Improved Analysis TechniqueImproved Analysis Technique
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p y qp y q
Cheng, Lee, McVay
SPE 108176
Back extrapolate to get qi at zero delta time
Improved Analysis TechniqueImproved Analysis Technique
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p y qp y q
Cheng, Lee, McVay
SPE 108176
Back extrapolate to get Di at zero delta time
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Improved Analysis TechniqueImproved Analysis Technique
Multi LayerMulti Layer
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Multi LayerMulti Layer
Cheng, Lee, McVay
SPE 108176
Estimate b at 0.6
No theoretical basis, based on observed results from a
few field and synthetic cases
Other procedures are the same
Decline Curve Analysis CBMDecline Curve Analysis CBM
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Rushing, Perego, Blasingame studied CBM behavior
using simulation (SPE 114514)
Long term b exponents ranged from 0.20 to 0.80 Early decline behavior for many wells was
exponential becoming more hyperbolic with time
None of the simulated cases exhibited long term
exponential behavior due to non linearrelationships between key coal properties and
either pressure or saturation
Wells with higher Pwf(all other factors being equal)
exhibited higher b values for long term production
Improved Decline Curve AnalysisImproved Decline Curve Analysis
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Additional method proposed by Ilk, Rushing, Perego,
and Blasingame (SPE116731)
Presents power law lost ratio method Presents diagnostic curves to aid in decline type
- hyperbolic, exponential
Method has merit, however, industry probably
slow to replace traditional decline curve methods
Summary Conventional AnalysisSummary Conventional Analysis
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Fit Hyperbolic when in BDF
Research Terminal Declines! Research Time in Transient Flow!
See if can Fit with b 1.0
Use Improved or advanced methods
Analogies Should Have Similar Completions
Similar Reservoir Parameters
Similar Spacing
Sufficient Production History for Reliable Analysis
Type Curve Changes With SpacingType Curve Changes With Spacing
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yp g p gyp g p g
1,000
10,000
100,000
0 20 40 60 80 100 120
Gas[M
cf]
Months
1,000
10,000
100,000
0 20 40 60 80 100 120
Gas[M
cf]
Months
1,000
10,000
100,000
0 20 40 60 80 100 120
Gas[M
cf]
Months
160
acre80 acre
40 acre
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Production History MatchingProduction History Matching
Production History MatchingProduction History Matching
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y gy g
Example PROMAT Single-Phase, Single-Layer Analytical Model
combined with Regression Analysis
Fast + Can Provide Accurate k, S (Xf) and sometimes
Drainage Area Accuracy Good where k Variation not big (Sergio Vera, MS
Thesis, Texas A&M 12/2006)
Production History Match ExampleProduction History Match Example
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Production History Matching - ProblemsProduction History Matching - Problems
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Non-Unique Solutions without Good Reservoir
Description
Pre-frac k can Over Estimate Reserves
Inaccurate in Layered Systems with Large
Permeability Variations
Accuracy Increases with Production Data
Multi-Layer Models often Require Detailed Data such
as Production Logs, etc.
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Advanced Production AnalysisAdvanced Production Analysis
Flow Periods for Fractured WellFlow Periods for Fractured Well
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Most of flow due to expansion in fracture
Generally too early to be of practical use
Often masked by WBS
Cinco et al 1981
Flow Periods for Fractured WellFlow Periods for Fractured Well
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Two types of linear flow simultaneously occur
Most of flow comes from formation
Cannot determine frac length just from bilinear flow Plot of Pwfvs t**1/4 is straight line, plot of P or m(p)
vs time is slope on log log plot Cinco et al 1981
Flow Periods for Fractured WellFlow Periods for Fractured Well
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Cinco et al 1981
Occurs only where high conductivity fracture, CrD 100
Continues approxtLfD = 0.016
Plot of Pwfvs. t**1/2 is straight line, plot of P or m(p)vs time is slope on log log plot
Flow Periods for Fractured WellFlow Periods for Fractured Well
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Transition period between linear flow and radial flow
Badazhkov et al (SPE 117023) contains method and
references
Cinco et al 1981
Flow Periods for Fractured WellFlow Periods for Fractured Well
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Fracture functions as extended wellbore consistent witheffective wellbore radius concept
Large Lf compared to drainage area can mask due to
BDF
Begins at tLfD ofapprox 3 for CrD 100, less for lower CrD
Pwfvs log t is straight lineCinco et al 1981
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Tight Gas FlowTight Gas Flow
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General Behavior
Small Xf compared to ROI Linear to Pseudo Radial less common
Large Xf compared to ROI
Long Term Linear Flow followed by BDF
Infinite Acting Linear Systems
Parallel Reservoir or No Flow Boundaries
Analysis of Linear FlowAnalysis of Linear Flow
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Plot of (m(pi)-m(pwf))/qg vs t**1/2 yields straight lines of
different slopes
Slope departs from analytical value as flow rates or
degree of drawdown become higher
Dont see the same degree of departure from analytical
solutions for pseudo radial flow
Analysis of Linear FlowAnalysis of Linear Flow
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Ibrahim and Wattenbarger SPE 100836
Analysis of Linear FlowAnalysis of Linear Flow
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Ibrahim and Wattenbarger SPE 100836
Analysis of Linear FlowAnalysis of Linear Flow
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Ibrahim and Wattenbarger SPE 100836
Analysis of Linear FlowAnalysis of Linear Flow
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Ibrahim and Wattenbarger SPE 100836
Analysis of Linear FlowAnalysis of Linear Flow
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Ibrahim and Wattenbarger SPE 100836
Analysis of Linear FlowAnalysis of Linear Flow
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Ibrahim and Wattenbarger SPE 100836
Analysis of Linear FlowAnalysis of Linear FlowCorrections to Constant PCorrections to Constant Pwfwfcase for Drawdowncase for Drawdown
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Ibrahim and Wattenbarger SPE 100836
Define Dimensionless Drawdown as:
Define correction factor as:
Solutions become
Analysis of Linear FlowAnalysis of Linear FlowCorrections to Constant PCorrections to Constant Pwfwfcase for Drawdowncase for Drawdown
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Ibrahim and Wattenbarger SPE 100836
Analysis of Linear FlowAnalysis of Linear FlowS iSynopsis
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SynopsisSynopsis
Ibrahim and WattenbargerSPE 100836
cAk from slope of (m(pi)m(pwf))/qg vs sqrt(t) plot
Determine pore volume from slope and time to end of
linear flow, OGIP by including rock and fluid properties
Cannot determine k independently without Ac
Slope ofsqrt(t) plot affected by drawdown for constant
pwfcase
Without correction factor can be in error by up to 22%
at maximum drawdown No correction factors yet available for constant rate
case
Advanced Production AnalysisAdvanced Production Analysis
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Combines Concepts from Pressure Transient Analysiswith Production Data
Allows for Determination of k and S or Xf in Transient
Region, OGIP from BDF
Newer Methods (Post Fetkovich) Allow Changes inOperating Conditions
Can also use for Diagnostic Analysis (Transient, BDF,
Interference)
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FetkovitchFetkovitch
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Combination of Analytical Transient Model and
Traditional Arps
Vertical Well, Center of Closed Circle, Single Phase
Fluid
Requires Constant Flowing Bottom Hole Pressure - less
useful for gas wells
Type Curve Match of Qd and Td against actual rate
versus time
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Blasingame, et alBlasingame, et al
S l t M d l
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Select Model
Radial
Infinite Conductivity Fracture
Finite Conductivity Fractures
Elliptical FlowHorizontal Well
Obtain match, multiple functions should fit same TC
Possible to obtain k and S or Xf
Can obtain OGIP if in BDF
Blasingame, et al
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Advanced Production AnalysisAdvanced Production Analysis
Blasingame and othersBlasingame and others
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Tight gas reservoirs can suffer from non unique
solutions
Must have good idea of OGIP to reduce the non-
uniqueness problem
Even prefrac buildup for k and a post-frac buildupfor Xfdoes not guarantee a unique solution
Can use decline curves or FMB to estimate OGIP
Important Type Curve TechniquesImportant Type Curve Techniques
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Palacio and Blasingame (SPE 18799, Fekete RTA documentation) Agarwal, Gardner, et al (SPE 57916, Fekete RTA documentation)
Important Other MethodsImportant Other Methods
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Crafton, Reciprocal Productivity Index (SPE 37409, 49223)
Ozkan,et al
Transient RPI for Horizontal Wells (SPE 77690, 110848)
Reservoir SimulationReservoir Simulation
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Reservoir SimulationReservoir Simulation
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Gold Standard for Evaluation
Expensive, Time and Data Intensive Danger is Experience Level of Hands On Workers
or Weakest Link
Simulation Requires Knowledge of General
Reservoir Engineering and Production Engineering
Must have People in you Organization to
Understand Work Process, Results and Integrate
with Common Sense
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Cox et al SPE 98035
re Generally Proportional to Lf, k
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Cox et al SPE 98035
re Generally Proportional to Lf, k
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Cox et al SPE 98035
Practical Limit Exists for Geometry and low k
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Cox et al SPE 98035
Synopsis for Accurate EvaluationSynopsis for Accurate Evaluation
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Industry Acceptance and Time Constraints RequireMostly Traditional Decline Analysis
Volumetrics Must be Augmented with Core Data,Analogy, Information from More AdvancedMethods or Insights from Performance particularlyat Lower Permeability
Advanced Methods are useful for ObtainingK, S, or Xf for Transient Flow
OGIP for Boundary Dominated Flow andsometimes Linear Flow
For OGIP, Confirm from Several Methods or withReservoir Simulation or Analytical Model
Your Most Powerful ToolsYour Most Powerful Tools
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Peer Reviews!
Integrated Methodology
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