06 - Reservoir Flow

7/27/2019 06 - Reservoir Flow

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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

Rose & Associates, LLP 1 Ch 6 - Reservoir FlowAAPG Cartagena 2D course, Sept. 2013


2/15

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.



6/15

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



7/15

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



8/15

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?



9/15

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)



10/15

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



11/15

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.



12/15

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



13/15

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



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.





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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.



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



15/15

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

06 - Reservoir Flow

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