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Introduction
Probability, Distributions and Correlation
Estimating Under Uncertainty
Tight Clastics / Carbonate Assessment
Shale Assessment
Reservoir Flow
Valuation Techniques
Risk, Uncertainty & Economic Analysis
for Resource Assessment and Production
Forecasting in Shale and Tight Reservoirs
Darcys Law: Flow Through Porous Media
= flow rate
= permeability
kA
A
Q
k
A
= viscosity
= cross sectional area
= pressure gradient
Reservoir Flow Process in Tight Sands
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Uncertainty in Recoverable Gas Calculations
Tight Gas Recoverable Gas Volumes =
Area * Avg Net Pay * Avg. Porosity * (Sg) * 1/Bg * RE
What determines production rates?
How do we determine net pay cut-offs?
How do we determine Average Porosity?
Volumetric Considerations:
How is the Average h Determined?
Very difficult to assess individual zone volumes,
so alternative approaches have evolved
BCF per section
Analogs of EUR per well
Darcy flow:
Low k
Lots of h
Cumella (2005)
Piceance Basin
Pinedale Arch
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Pinedale Arch
Volumetric Considerations:How is the Average h Determined?
Porosity Example
Twenty wells have multiple estimates of
carbonate porosity based on log analyses
Wells Samples Average
1 12.2% 45.4% 25.8% 42.7% 27.0% 42.6% 32.5% 39.6% 41.8% 34.4%
2 19.8% 44.5% 39.8% 9.5% 29.0% 6.5% 24.0% 37.3% 49.7% 28.9%
3 34.1% 39.4% 40.7% 9.8% 13.9% 10.1% 23.2% 44.3% 15.1% 25.6%
4 15.5% 19.4% 48.1% 16.5% 23.5% 44.1% 31.7% 43.3% 13.1% 28.4%
5 31.5% 28.0% 26.7% 14.2% 22.2% 37.3% 49.6% 38.0% 7.9% 28.4%
6 39.7% 21.6% 5.0% 10.6% 34.3% 23.7% 31.9% 39.4% 4.5% 23.4%
7 47.3% 18.3% 13.9% 23.4% 30.4% 20.7% 44.3% 44.8% 18.9% 29.1%
8 5.0% 12.9% 41.8% 23.0% 36.3% 11.4% 13.4% 44.3% 16.5% 22.7%
9 48.4% 39.5% 23.3% 19.9% 44.8% 47.9% 25.8% 46.7% 15.0% 34.6%
10 37.3% 44.8% 43.9% 44.8% 32.0% 18.4% 14.9% 33.0% 16.2% 31.7%
11 8.2% 32.3% 6.2% 41.8% 35.2% 42.6% 12.8% 8.4% 25.1% 23.6%
12 36.7% 7.6% 21.6% 40.9% 33.6% 22.8% 48.2% 34.6% 16.9% 29.2%
13 45.6% 9.3% 27.5% 15.6% 23.5% 29.3% 17.5% 34.1% 45.7% 27.6%
14 28.1% 5.5% 16.5% 19.3% 47.9% 43.0% 44.3% 47.4% 13.9% 29.5%
15 5.7% 6.4% 5.1% 37.3% 8.3% 41.7% 46.0% 45.9% 5.3% 22.4%
16 34.4% 48.7% 44.8% 29.2% 21.2% 23.0% 42.7% 16.6% 19.1% 31.1%
17 43.9% 3.7% 11.6% 38.0% 31.7% 28.5% 14.0% 49.2% 21.6% 26.9%18 36.0% 10.4% 32.6% 44.2% 21.5% 38.7% 18.8% 26.0% 22.5% 27.9%
19 29.9% 42.5% 45.2% 29.9% 46.3% 37.5% 20.2% 47.3% 46.2% 38.3%
20 34.4% 5.7% 4.5% 28.5% 38.8% 10.3% 20.2% 49.8% 32.3% 25.0%
28.4%
Samples range from about 5% to 48%
Wells averages range from
about 23% to about 38%
Field average estimate
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P99 P01P98 P02
P95 P05
P90 P10
P10 P20
P70 P30
P60 P40
P50 P50P40 P60
P30 P70
P20 P80
P10 P90
P05 P95
P02 P98
P01 P99
1% 10% 100%Porosity
Porosity and Average Poros ity
Distributions of Porosity Samples and
Average Porosity
Porosity
Samples
Average
Porosity
This is the
distribution that
you want to use
Porosity, Saturation, FVF
Distributions for these parameters
should be for the average value over
the field
Average parameters tend to have a
smaller uncertainty than the
distributions of samples
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Jonah Field
At w hat K do we no
longer get
contribution to
flow?
Does proximity to
better rock affect
the cut-off?
Jonah Field
Porosity, %
Distribution of routine
core porosity values for
Lance Fm
Frequency
Distribution of avg
porosity by well, Lance
Fm.
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LogofDistanceFromtheWellbore
What is the Impact of Reducing Permeability?
Permeability
P i
P wf
Psia
Rw Re
Log of Distance (feet) From the Wellbore
DistanceFromtheWellbore
Drainage Radii After 25 Years in nD Rock
P i
P wf
Psia
Rw Re
1 10 1000.10.01
Log of Distance (feet) From the Wellbore
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Time to Stabilization Linear Flow
0.01
0.10
1.00
10.00
100.00
1000.00
0 160 320 480 640
Tight Gas - 0.1 md
Shale Gas - 0.0005 mdUltratight Gas - 0.01 md
Area, acres
StabilzationTime,years
Recognize The Impact of Permeability
10 YearsNo Boundary
tDFq
SPE138987BrentHale,W.Cobb&Associates
BarnettVerticalWells
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JenkinsandIlk(2010)
the impact of fracs
Recognize The Impact of Permeability
Volumetric Calculations For Shale GasAs with tight sands and coal, the RF in Shale Gas is sensitive to the drilling program
Inplaceresourceover640ac:75,000MMCF
Inthisdeterministicexample:
Impact of Inter-well interference.
How can this be mitigated?
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What is the Optimal Spacing?
It is a function of your firms discount rate and futureprice expectations. At a 10% discount rate 85% ofthe value is realized in the first 10 years.
There is always incremental recovery which has trueeconomic value when our R/P ratios exceed 15
SPE 160002 modeled Tight Oil and Tight Gas playsto provide directional guidance
Reservoir Flow Process in Shales
Rockcompositionandtexturetendtocontrolmechanicalpropertiesandhenceinfluencereservoirflow.RockcompositionandtexturecanvarywithstratigraphicsequencepositionHence,theearlieryoucancalibratecorestologs,thesooneryouimproveforecastsofreservoirflow.Thisisthegrowingfieldofmechanicalstratigraphy
ModifiedfromMayandAnderson(2010)
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In Conventional tight gas sands we expect discrete transverse
planar bi-wing fractures e.g. the Montney.
In tight mudstone/shale with perms less than ~ 0.03 millidarcy,
complex fractures may be initiated by brittle fracturing or
reactivation of healed natural fractures.
Fracture gradients in excess of 1 have resulted in horizontal
pancake fracture.
Typically the drainage area is greater than the stimulated area.
This is dependent on the matrix permeability.
In Shale, the drainage area is dependent on the StimulatedRock Volume (SRV).
Multi-stage, high rate, high volume fracture stimulations are
used to develop the largest possible fracture network.
Fracturing in Tight Sands vs Shale
Brinell Hardness Number
AfterSPE148781B.W.McDanielandMullenetal(2010)Generalized Brinell Hardness Comparison o f Unconventional Resource Plays in the USA
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SPE137413 S.Khalidandothers
Brittleness is a property of the rock that refers to post failure behaviour.
A rock is brittle if it cannot support load after failure It is ductile if it can. Ductile materials exhibit significant plastic
deformation before fracturing.
Youngs Modulus and Poissons ratio describe a rock elasticity or
plasticity, which is different from brittleness and ductility.
Elasticity describes the build-up of strain during hydraulic fracturing,
but is not an indicator of failure after fracturing, which is what
brittleness denotes.
A rock is elastic if it returns its initial state after a load/unload cycle and
plasticity means that it does not.
Youngs modulus and Poissons ratio do not necessarily predict
brittleness or ductility as these moduli deal with the material before
failure.
Which Factors Impact the Brittleness of Shale
SPE137413 S.Khalidandothers
Which Factors Impact the Brittleness of Shale
Gas shales are anisotropic. When measured vertically relative to
horizontally a difference exceeding 200% has been observed.
Shattering of the rock occurs when the rock cannot dissipate the
impact energy fast enough in any way other than to create surface
area by distributing the energy to multiple fractures.
In the absence of pre-existing texture, the hydraulic fractures are
planar, as is the case in the Canadian Montney reservoir.
The existence of a pre-existing natural fracture network (healed or
not) is why the Barnett and Horn River shale exhibits a complex
fracture network.
Brittleness aids in facilitating the development of a desired texture,
due to tectonic deformation or other strains but it does not play a role
in facilitating fracture complexity.
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TerryEngelder DepartmentofGeosciencesPennStateUniversity
The Role of The Organic Layers in Shale
These hydrophobic, high gas content pores have relatively highpermeability and can be the hidden pathways for flow of the
desorbed gas volumes when they become or are connected to
natural or induced fractures. Reservoir issues around organics:
The geometry/size of the layers
The stacking pattern & distribution
Most importantly, their connectivity
F.P.Wang,SIPESTalkDallasMay19,2009
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Volume Impact @ 5% TOC by weight %:
Given: Total porosity of Shale 6%Assumed: Fracture porosity of < 0.5%
Given: Weight percent of Organic matter (OM) 5%
The grain density of OM is half that of the rock minerals,
therefore the volume % of the TOC is 2 times the weight %.
The Volume % of the OM is therefore ~ 10%
* Porosity increases due to organic Carbon decomposition
The Role of The Organic Layers in Shale
F.P.Wang,SIPESTalkDallasMay19,2009
Volume Impact @ 5% TOC by weight %:Given: Total porosity of Shale 6%
Assumed: Fracture porosity of < 0.5%
Given: Weight percent of Organics 5%
The Volume % of the OM is ~ 10%
Assumed: ~ 50% of the OM are now pores, such that the volume
impacted by the 10% Volume of OM is 20% of the Rock volume
Average porosity of OM in Shale is ~ 20%
The contribution to total porosity:
OM - 10% Volume * 20% average porosity = 2%Inorganics 3.5%
Fractures 0.5%
OM porosity is 4+ times greater than the fracture porosity.
The Role of The Organic Layers in Shale
F.P.Wang,SIPESTalkDallasMay19,2009
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The organic matter is hydrocarbon
wet. The hydrocarbons are imbeddedas porous films which act as selective
nano level membranes which allow
the passage of oil and gas but block
the passage of water.
Pores in the Organics range from
5 to 800 nm (Reed et al, 2008). The CH4 molecule diameter is
about 0.4 nm and an Oil molecules diameter varies from ~0.5
nm to 3 nm
Porosity of Organic matter can be 2 to 5 times higher than the
total porosity of the Shale. Organics can absorb, store and
transfer CH4 molecules and can represent ~20 to 40% of the
free gas.
The Role of The Organic Layers in Shale
F.P.Wang,SIPESTalkDallasMay19,2009
Intra-Organic Porosity Found to date in all successful gas shale
Very low Sw (hydrophobic)
Contains both free and adsorbed gas
Inter Crystalline Between clay particles or detrital crystals
Higher Sw (Hydrophilic)
Carbonate dissolution
Carboxylic acid associated with kerogen maturation important in high carbonate rich rocks.
W.A.Zagorski,RangeResources(2010)AAPGHedbergShaleGasConference
Factors Impacting Shale Gas Production
Pore Types
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Flow Regimes Within Shale
SPE139097MarkMilleretalLucidReservoirTechnologies
Internal Linear Transient
After wellbore storage and fracture transient effects,
characterized by infinite acting linear flow into the
induced and natural fractures. Within the SRV.
Internal Depletion
Characterized by quasi-Boundary Dominated Flow (BDF) from
the Stimulated Rock Volume (SRV) into the natural or
induced fracture network.
External Linear Transient
Characterized by transient linear flow into the peripheral fracture
faces of the SRV.
Drainage Volume Depletion
Characterized by the quasi steady state flow from the drainage
volume once a well has been affected by drainage boundaries. Desorption of the Organics Pressure dependent
Characterized by the Langmuir isotherm and interconnectivity of
the OM.
(1:2)
(1:4)
(1:1)
(1:1 Slope Fracture interference/Depletion)
(1:2 Slope Linear flow/High fracture
conductivity)
(1:4 Slope Lowfracture conductivity)
1
2
3
Ilk(2012)
Flow Regimes Within Shale
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