05 - Shale Assessment

7/27/2019 05 - Shale Assessment

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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

What Are Unconventional Resources?

CBM

Shales

Piceance basin

Deep WCSB

Black Warrior basin

dirty coals

Bossier

MancosLewis

Baxter

Typically self-sourced w sorbed gas

Primarily a sorbed gas reservoir

Fruitland CoalsHorseshoe River

Vaca Muerta Posidonia Utica

Los Molles Barnett Muskwa

Haynesville Alum

Marcellus Lias

Woodford Monterey

Fayetteville Niobrara

Eagle Ford Mowry

Hybrid systems

Shattering to create

the fracture

and thus permeability

Silica rich mineral suite

Carbonate rich mineral suit e

Tight

Sands / Carb

Rose & Associates, LLP 1 Ch 5 - Shale AssessmentAAPG Cartagena 2D course, Sept. 2013


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33 66 slickloamygritty

Siltstone

Shale

mudstone claystone> 1cm

< 1cm

bedded

laminated

beds

laminae

What Are Unconventional Resources?A simple classification scheme for shales

Maximum grain size 0.062 mm

AfterLevine,modifiedfromBlattandothers(1972)

Shales as Source Rock Factories

BarsRepresentGeologicTimeofGlobalAnoxicEvents

100MMYr

Miocene

Monterrey

Cretaceous

LaLuna

EagleFord

Niobrara

Mowry

Jurassic

Kimmeridge

Haynesville

Lias

VacaMuerta

LosMolles

Posidonia

PennShalesPhosphoria

Meade

Gothic

Silurian

Poland

Devonian

Woodford

Marcellus

Muskwa

Ordovician

Alum

Utica

Mississipian

Bakken

Barnett

Fayetteville

%ofH

Cgenerated

30

20

10

Kreyen

hagen

Eocene

Klemme andUlmishek (1991)



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transgressivesed

sequence

Blackshales

Anoxicportionof

watercolumn

Dilutionfromdeltabuildingvs organicbuildup

fromdeltaic

retreat

Pycnocline

Mechanisms of Formation

Classical paradigm

for sediment

transport

AfterMacquaker (2011)

transgressivesed

sequence

Blackshales

Dilutionfromdeltabuildingvs

organicbuildupfromdeltaicretreat

Pycnocline


Classical paradigm

for sediment

transport has

evolved to includeobservations of

bioturbation and in

situ fauna

AfterMacquaker (2011)



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Mechanisms of FormationWhat needs to be tracked is the conversion of Organic Matter (Kerogen) to HC

Kerogen TypeI

II

II

II

III

IV

MaceralAlginite

Exinite

Cutinite/resinite

Liptinite

Vitrinite

Inertinite

Original OMFresh water algae

Pollen, spores

Land plant cuticles/resins

All land plant lipids; marine algae

Woody material from land plants

Oxidized and reworked matter


Note how Type III dominantsource rocks require higher

Ro for gas level maturities

What needs to be tracked is the conversion of Organic Matter (Kerogen) to HC

very rare

very rare

Ro = Reflectance of vitrinite (% Ro or %VRo) = is a measurement of the

percentage of light reflected off the vitrinite maceral at 600x magnification

in oil immersion. The reflectance increases with increasing maturity.

AdaptedfromJarvie (2009)



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AdaptedfromJarvie (2009)


Ro = 0.4 pre generation Ro = 0.85 peak oil generation

Ro = 1.4

gas window

Ro = 2.0 gas window

Ro = Reflectance of vitrinite (% Ro or %VRo) = is a measurement of the

percentage of light reflected off the vitrinite maceral at 600x magnification

in oil immersion. The reflectance increases with increasing maturity.


S1: free oil that volatizes at 300 deg C, the distillable peak

S2: organic matter that pyrolyzes between 300 600 deg C, pyrolyzable peak

aka remaining HC potential

S3: organic CO2 released from Kerogen

Tmax: temp at max evolution of S2 peak

Production Index = S1/(S1+S2), measures kerogen conversion

Transformation Ratio = (HI orig HI now)/HI orig, measures kerogen conversion

Wt organic content = TOC/0.83 (83% C in HC)

S2 * 131.34 = remaining generation potential in MCF/AF

S1 S2 S3time

temp

yield

Tracking is modeled in the lab with programmed pyrolysis measurements


HI = 100 * S2/(TOC), mg HC/g TOC

OI = 100 * S3/(TOC), mg CO2/g TOC

S2/S3 = HI/OI



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HI

OI

lookslikeaVanKrevelen

diagramand

can

be

used

to

determinekerogen type

HI = 100 * S2/(TOC), mg HC/g TOC

OI = 100 * S3/(TOC), mg CO2/g TOC

S2/S3 = HI/OI

Peters(1986)


After

4 days

OBrienandothers(2002)



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S1 / TOC

1 3

50 ft

Remember that kerogen acts like

a sponge, so organic rich rocks

will retain upwards of 50-80 mg

HC/g TOC

Thus when S1 exceeds TOC,

(saturation exceeds adsorption)

that indicates migrated oil which

can be producible

Crossover, aka Hydrogen Content Jarvie (2010)


S1 S2S2

Ro=0.6:

Traceof

S1

and

mostly

S2

as

kerogen

is

juststartingtobeconvertedtoliquid

hydrocarbons.

Ro=0.7:

IncreasingS1

indicating

oil

generation

anddecreasingS2askerogen is

convertedtooil.



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Ro=1.0:

IncreasingS1indicatingoilgeneration

anddecreasingS2askerogen is

convertedto

oil

and

gas.

Ro=1.6:

DecreasingS1asoiliscracked togas

anddecreasingS2.

Ro=2.0:

Trace tonoS1andverylowS2dueto

kerogen conversion.


S1 S2 S1 S2


very rare very rare

Woodford Shale

production,

Arkoma Basin,

with Ro contours

N

Whathappensat

higher%Rovalues?

Late in the process

when Ro exceeds about 3.0,

the kerogen is burnt out which

affects porosity

Andrews(2010)



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Metagenicconversionleadstoporositydestruction

Whathappensathigher%Ro

values?

Laughrey andothers(2011)

0.01

0.1

1

0 1 2 3

%Ro

Porosity


Metagenicconversionleadstoporositydestruction

Whathappensat

higher%Rovalues?

Laughrey andothers(2011)



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By William Hart

Fredonia NY

First Exploited: Dev. Dunkirk Shale, 1821

Beginning in the 1860s

these wells were

stimulated in stagesas nitroglycerin was

detonated via steel balls

dropped at the wells site

www.dec.ny.gov/docs/materials_minerals_pdf/nyserda2.pdf Curtis(2002)

First Exploited: Dev. Dunkirk Shale, 1821

http://www.alleganycountynylocalhistory.com/

Beginning in the 1860sthese wells were

stimulated in stages

as nitroglycerin was

detonated via steel balls

dropped at the wells site



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Next Exploited: Dev. Ohio Shale, 1880

SPE 14446 AdaptedfromVanorsdale (1987)byJenkins

Now: Miss. Barnett Shale, Fort Worth Basin

325 MYA

www.jan.ucc.nau.edu



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1992

First Production Date

First 12 months Production, BCF

0.5

1.0

1.5

1982 2002

The 17 year overnight success story

1997: First water frac

Vertical wells

Horizontal wells

Steward(2009)

400

200 isopach

30 miles

Inside the thicker part of the gas window

is referred to as the Core area.

Whats the problem outside of the

Core area (i.e. in the oil window)?


Ro = 1.1

largecomplexring(3nm)

smallcomplexring(1nm)

methane (0.4nm)



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400

200 isopach

Ro = 1.1

30 miles

Inside the thicker part of the gas window

is referred to as the Core area.

Whats the problem outside of the

Core area (i.e. in the oil window)?


The pores, about the size of 10 gas

molecules, get occluded by the larger oilmolecules and the associated clumping from

electrostatic charge

When the pores are > 50 nm, darcy flow

When the pores are < 50 nm, diffusive flow

Loucks andothers(2008)

L.Penn

Ellenburger

Barnett

East

Darker tones have

more TOC

~ 1 micrometer


and may provide hidden

pathways to enhance production

(Wang, 2009)

ViolaLimestone

Loucks andothers(2008)



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Clays

Qtz + F + PyCarbonates

Barnett core

Siliceous is delicious


400

200 isopach

Ro = 1.1

30 miles


A traffic light, or common risk segment

mapping approach

should include mapping of the

target isopach thicks (with cutoffs, like GR;

excess resistivity delta LogR),

Ro and

higher qtz content

pyrite related to kerogen

using a Barnett analog



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Now: Marcellus Shale, Appalachians

385 MYA

http://www2.nau.edu/rcb7/namD385.jpg


http://eeducation.mediasite.com



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Ro = 1

Ro = 2

Ro = 3

Over pressure present (largely in PA thought to be related to conversion of

oil to gas in fixed pore space)

50 ft

Isopach Thermal maturity

Milici andSwezey (2006),USGSOFR1237


Barnett

Comparison of intra kerogenic porosity

InWV,quartz

concentrationsare

remarkablyuniform

and

theclaycontentis

uniformlylow. Inreality

theMarcellusisnota

shale

1 micrometer

Marcellus

1 micrometer

BoyceandCarr(2009)



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In WV, quartz concentrations are

remarkably uniformly and the clay content is

uniformly low. In reality the Marcellus is not a shale

-- Matt Boyce

150 ft

100 ft

50 ft

What else is needed to high grade this play?

70 ft

Total Marcellus isopach, ft

from Milici and Swezey (2006)

BoyceandCarr(2009)


In WV, quartz concentrations are

remarkably uniform and the clay content is

uniformly low. In reality the Marcellus is not a shale

-- Matt Boyce

150 ft

100 ft

50 ft

What else is needed to high grade this play?

70 ft

Total Marcellus isopach, ft

from Milici and Swezey (2006)

BoyceandCarr(2009)



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Now: Marcellus Play Ingredients: Pressure

Maps rectified via Priemere PowerTools for Arc GIS

Zagorski andothers(2010)

Now: Marcellus Play Ingredients: Isopach





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Now: Marcellus Play Ingredients: Vclay



Thisrelativewell

production

performance (through

endJune2011)

legendisindexedtoa

4.2BCF (=1)typecurve

Ro>10.45psi/ft

Grossthickness>160ft

Vclay


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Now: Marcellus Play Ingredients

Zagorski (2013)

Months

MCF / D

Now: Marcellus Production, 4.2 BCF Type

Curve

Thisrelativewell

production

performance(through

endJune2011)

legendisindexedtoa




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Productionrecordedwascomparedtotype

curveandaratioofactualversustypewas

plotted

Months

e.g.

20months~600days

Actualcumprod=0.5MM

Typecurvecum=1.0MM

Rel performance=0.5

MCF

Now: Marcellus Production, 4.2 BCF TypeCurve

Thisrelativewell

production

performance(through

endJune2011)

legendisindexedtoa


MarcellusHoriz wells

from

Pennsylvania

(West,CentralandEast)

ThroughJune30,2011(n=1078)

Productionnormalizedto4.2BCF(=1)

EURtypecurve

Now: Marcellus Production: W, C, & East



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Fullrangeofdata

MarcellusHoriz wells

from

Northern

Pennsylvania(Northof40.84lat)

ThroughJune30,2011(470outof696)


EURtypecurve

Now: Marcellus Production: North Operators

Fullrangeofdata

Now: Marcellus Production: South Operator

MarcellusHoriz wellsfrom Southern

Pennsylvania(Southof40.84lat)

ThroughJune30,2011(286outof382)


EURtypecurve



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Now: Neuquen Basin

www.eia.gov

ClosingTethys

Subtropicalenvironment

WarmestperiodinCretaceous

8999MYA

Anoxictime

Sluggishsalinewaters

Highcarbonateproduction

Now: Eagle Ford Shale, S. Texas

Bohacs andothers(2011)



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The importance of an early

understanding of mapping

HC Pore Volume

Fanandothers(2011)


Highstand

SENW

LowstandTransgressive

However, there are very good performing wells in the lower Eagle

Ford. So you always have to do your regional homework tying

correlations to rock property data

J. May, personal communications Bohacs andothers(2011)

Upper Eagle Ford tends to be more carbonate rich

Lower Eagle Ford tends to have higher TOC



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Oil molecule diam

~ 0.5 nm to 3 nm

Methane molecule diam

0.4 nm

Three types of porosity

intergranular

intragranular (CO3 disolution)

intrakerogenic

60 75% carbonate

Barnett

Now: Eagle Ford Shale, S. TexasOil molecule diam

~ 0.5 nm to 3 nm

Methane molecule diam

0.4 nm

Marcellus



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Clays


Barnett

Haynesville

Marcellus

Eagle Ford

Niobrara Marl


Now: Permian Basin(s)

Fairhurst andWallace(2013)



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ConchoResourcesMay2013InvestorPresentation

Midland Basin

Leonard

Leonard Lime

Leonard

Upper Spraberry

Lower Spraberry

Dean

Wolfcamp

Upper Wolfcamp

Middle Wolfcamp

Lower Wolfcamp

(Deadwood)

P

ennsyl-

vanian

Cline Shale

Strawn

AtokaMiss. Barnett

WoodfordDevonian

DevonianSilurian

Fusselman

OrdovicianSylvan

Ellenburger


ApacheCorporationJanuary2013InvestorPresentation

Thermalmaturity

map

for

Wolfcamp shales



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Clays


Barnett

Haynesville

Marcellus

Eagle Ford

Niobrara Marl

Scott-Sugg #1HNow: Permian Basin(s)Wolfcamp

Volumetric Calculations For Shale

In Place Resources

from geochemistry: rock pyrolysis data

In Place Resources

from volumetric approaches,

aka tank volume

Analogs of EUR per well



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Conversionfactorsneededare

Volumetric Calculations For ShaleOOIP,BOfromS1rockpyrolysis

Steps

in

evaluation

Generated from geochem data

AdaptedfromDowneyandothers(2011)

OOIP,BO

from

S1

rock

pyrolysis

Stepsinevaluation

Leadstothegeneralformula

Volumetric Calculations For ShaleGenerated from geochem data



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N por

dens por

100

S1, mg / g

Exercise:DeterminethemeanOOIP,BOforyour640ac

Given:

10%chancepaythicknesscouldexceed200

10%chancepaythicknesscouldbelessthan100

S1valuesfromcoreareindeedrepresentativeacrossyouracre

NocorrelationbetweenS1,thickness

Avg Ro~0.8;oildens~0.780from50APIgrav condensate

Seenextslide

fordistribution

viewofS1

Downeyandothers(2011)



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S1,mg/

OOIP,MMBOExercise:DeterminethemeanOOIP,BOforyou

Generated

Rose & Associates, LLP 33


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Exercise:DeterminethemeanOOIP,BOforyour640ac

Generated from geochem data

Lets get a quick look at the availabletank volume in place resource base

for a targeted portion of the play


40,000

ac

P99 P90 P50 Mean P10 P1

Thickness, ft

Por. , %

HC sat, %

1 / Bg

BCF

scf / ton

BCF

Dens, g/cc

Sorbed

Total

BCF

Free

In Place from vol. approach



36/88

Storage space comes from pores, fractures

and adsorption sites

Volumetric Calculations For ShaleIn Place from vol. approach

EagleFordexamplesfromBohacs andothers(2011)


Volumetric contributions from fractures are very

difficult to ascertain, hence the reliance on other

methods.

Storage space comes from pores, fracturesand adsorption sites

Interpreted fractures in Wolfcamp

In Place from vol. approach

ApproachResourcesApril2011investorspresentation



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gas content,

scf / ton


Lewis shale

CellPressure,psia

Volumesorbed,

scf/t

Varies with

temperature

TOC

Sorbed gas for shales = (vol sorbed at reservoir press) (vol sorbed at aband. press)

Jenningsandothers(1997)


data from HPDI

All operators

EUR/well,MMCF

INTEGRAL

Analogs of EUR per well

CourtesyJ.TanigawaandD.Detring



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Chance factor adequacy matrix

0.0 0.2 0.8 1.0

0.2 0.4 0.4 0.6 0.6 0.8

0.3 0.45 0.45 0.55 0.55 0.7

Bad News Good News

Coin Toss

Quality

Quantity

Confidencelevel

Control

Poor Limited

Good Lots

Low

High

For any chance factor

D a t a

So each chance factor is multiplied

such that the product of the chance factors

referred to as the play chance,

represents your confidence of?

Key Chance Elements For Shale



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Month

Suchthattheproductofthechancefactorsalso

calledPlaychance,representsyourconfidenceof

achievingthe

low

end

of

the

initial

production

ratedistributioninthefirststageofdrilling,

somewhereinyourdefinedplaysegment


Hackley (2012)



43/88


Rem

ainingHCpotential,mgHC/grock

TOC, wt %

2 40 8 106

0

10

20

30

Type II

oil prone

marine

lean

S2

mixed Type II/III

oil / gas prone

Type III

gas prone

dry gas prone

Type I

oil prone

lacustrine

Jarvie andothers(2007)


RemainingHCpotential,mgHC/grock

TOC, wt %

20 8 1060

10

20

30

4

Barnett: core and non core

S2

mixed Type II/III

oil / gas prone

Type III

gas prone

dry gas prone

Type I

oil prone

lacustrine

Jarvie andothers(2007)



44/88


If you are concerned

that, from Ro, CAI

Tmax information or

kinetic models that

your area is not within

the needed thermal

maturity window (such

that the wells would

fail), you would lower

your confidence

accordingly

Ro, %

Clays


Barnett

Haynesville

Marcellus

Eagle Ford

Niobrara Marl

MBakken

Polishsh (BNK)

Muskwa (avg of20)

Wolfcamp avg

Consider the fracabilitybased on mineral

ingredients


Barth#2Utica

Pt.Pleasant

Utica, Quebec



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YoungsModulus

Key Chance Elements For ShaleBrittleness index

redefined from

mineralogy relative toelastic moduli

0

2

4

6

8

100.1 0.22 0.400.28 0.340.16

Poissons Ratio

ModifiedfromWang(2009)SIPESpresentation

Key Chance Elements For ShaleBrittleness indexredefined from

mineralogy relative to

elastic moduli

0.1 0.22 0.400.28 0.340.16Poissons Ratio

Vp / Vs

4

3

2

PlasticshaleDolostone toLsSilicarich

1

AfterVonLunen(2009)



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Key Chance Elements For ShaleConsider the impact of

natural fractures and

faults

Faults are not conducive to

productive wells in the Barnett if

they cut deeper into the water

bearing zones

Fracture systems help provide more

permeability but can also prevent

the development of a complex frac

job

Healed fractures like the picture are

easier to reactivate with fraccing

than inducing fresh fracturesthrough shale

Frac energy preferentially drawn

toward the zones of weakness

Fault related folding

Red = ridges

Blue = depressions

Lunardi (2008)

Tenn Va WV Penn NYWV

0

2,000

ChattanoogaMillboro

Marcellus

GeneseoBurkett

Mostly LS, SS and Chert

Mostly Silts and Shales

Key Chance Elements For ShaleConsider the impact ofnatural fractures and

faults

Appalachian Basin Devonian

Black Shales

Milici andSwezey (2006)



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The higher TOC portions of the Appalachian black shales

have the densest joint sets

Strike joint (J1) are betterdeveloped in the shales and dip

joints (J2) in the sandy beds

J1

J2

J1 related to HC-overpressureJ2 related to uplift

Key Chance Elements For ShaleConsider the impact of

natural fractures and

faults

Appalachian Basin Devonian

Black Shales

Sheldon(1912)

Key Chance Elements For ShaleConsider the impact ofnatural fractures and

faults



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First gas well

50 100 150

In addition to mineralogy, also consider fractures in the reservoir.

Marcellus Shale

isopach maps

can be complimented

with available fracture

density and orientation

(relative to present max

princ. stress) maps as well

as with TOC and % qtz +

dolomite

Photo by G. Lash

ShalePoreDiameter,nm

ShalePorosity,%

5

5

10

15

10 15

largecomplexring(3nm)

smallcomplexring(1nm)

methane (0.4nm)

When dealing with liquids,the pore space available

compounds the challenge


AfterJarvie (2008)



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Key Chance Elements For ShaleBe on guard for elements

that could hinder the

basal seal effectiveness

PinnacleTechnologies

L.Penn

Ellenburger

Barnett

East

Viola

Key Chance Elements For ShaleBe on guard for elementsthat could hinder the


Nissen andothers(2007)



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diapirs andkarsting asthemaintechnicalrisks for ParadoxBasinshalePlays

Akah Salt

Key Chance Elements For ShaleBe on guard for elements

that could hinder the


BillBarrettCorpOctober2008InvestorPresentation

Month

Suchthattheproductofthechancefactorsalso

calledPlaychance,representsyourconfidenceof

achievingthelowendoftheinitialproduction

ratedistributioninthefirststageofdrilling,

somewhereinyourdefinedplaysegment

Chance Assessment in Perspective



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PlayChance(atthesegmentlevel):Theproductofthechancefactors,which

representsyourconfidenceofachievingthe

lowendoftheinitialproductionrate

distributioninthefirststageofdrilling,

anywhereinyourdefinedplaysegment

Independentchance(atthewelllevel):Weestimate,giventheplaysegmentcan

yieldminimal production,whatpercentage

ofsubsequentwellswillsucceed when

considering geologicalvariability(usingthe

samechecklistasabove)andalsothe

percentageofwellsthatwillsucceedwhen

considering mechanicalconcerns.

Whenwemodela play

Wedeterminefirstthe

playchance,

thentheindependent

chancetodeterminea

drillingsuccessrate

Thisineffectdeterminesthepercentageofthesimulationtrialsthat haveaccess

toproduction

Chance Assessment in Perspective

Thischanceofsuccessisthenusedtocalculate,withestimatesofproduction,timing,

productpriceandcosts,thechanceofmakingaprofit(aswellastheamountofprofit).

then

Possible Analogs for your Shale Gas PlayPossible Analogs for your Shale Play

Byline: Shales gonewild!



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Midinterval

Largely

dolomitic to

east,

sandyor

limeyshales

towestand

north

Therearetwoconcessions,A&B,availableforlicensinginthisoilplay.

Acompilationofregionaldatahasbeenmapped

Inrecentyears,thetargetintervaljustbecameproductive,hencethesale.

TherearerelativelyshortEWlineamentsinthevicinityofA,and

SEtrendinglineamentscrossingBassociatedwithfaultswarmsonpoorqualityseismicdata

Whichconcessionismorepreferred,andwhy?

ConcessionPreferenceExercise

great great

Foreachparameter,gradeeachconcession

onascaleof5(best)to1



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Estimatedfacies

50km

largely

dolomite

Limey

dolomite

shaley

limestone

B

ConcessionPreferenceExerc



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TopStructure

Vertical

extentof

fractures

-8750

-7500

-6250

B

50km




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Isopach

Isopach

50

150

100

100

B

50km




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63/88

Note,Tempsbelow420

degCareconsidered

immature

S2Tmax,LShale

Tmax

440

420

4

B

50km




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65/88

Recentoilproductionfromhorizontalwells

BetweenconcessionsAandB

EURforBE:270

50

CumProduction,MBO

BOE

/D

200

400

600




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1) Examinethemapsofdepth,thickness,TOCandRoanddeterminethevaluea

cellblock. Eachcellblockrepresents9sqmiles.

2) Foreachnode,enterthedepth,thickness,TOCandRovaluedeterminedfrom

entrytabofthespreadsheetprovided. Therewillbe100entries,4entriesf

3) Notethatcolumnslabeledisothermandporosityhavetheirvaluesprogram

TOCandRo,respectively.

If

the

present

day

thermal

maturity

is

less

than

0.6%

Ro,

the

free

(and

ato0ontheassumptionthatnosignificantthermalgashasbeengenera

Thefreegasvolumeiscalculatedfromthethickness,pressure,tempera

depth),area,andgassaturation. Porosityisacalculatedasafunctiono

StandardreservoirengineeringmethodologyisusedandthegasZfac

4) WereallycantsaythenodalRovalueisrepresentativeoftheentireblock,so

we

have

also

calculated

cases

where

the

porosity

is

uniformly

2%,

3%,

7%

and

5) Whentheporosityis2%or3%,thegassaturationissetto70%. Whenthepo

saturationissetto85%.

Instructions(whenallelsefails,readhere)

Exercise: Determinetheblocksyouwanttolease,basedoninplacegas(OGIP)ina9sqmiblock&inthewetgas(Ro=



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6) So,onthetabsummarylinkyouwillhavethemapderivedvalues,andvalue

otherscenarios. Wehaveprovidedthemeanofthosefivescenarios.

7) Post(atthenodesoftheprovidedblankbasemap)andcontourthemeanofillustratewhereyoushouldcontinuethenextstageofexploration. Rememthe250BCFcontourtraversingitqualifiesforthefirstcriterion.

8) Forthoseblocksthatdomeetthecriteria,buildadistributionofthevariabilwhich

the

mean

was

calculated),

via

the

mid

point

plotting

method

to

commassociatedwiththemeancase.

9) Toaccomplishthedistribution,takethevaluesfromcolumnsBtoFforyourp

(soundsdetentionlike,doesntit)andtypeorpastethemintothe datacolu

thetablabeledlogprobit (2cycle). Inorderforthevaluestoplotproperlyy

themfromhightolow. Ifplottingbyhandtheformulatodeterminepercent

valuesispercentile=(rank 0.5)*(100/n)

Instructions(continued)

Exercise: Determinetheblocksyouwanttolease,basedoninplacegas(OGIP)ina9sqmiblock&inthewetgas(Ro=



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A B C D E

MeanfreeOGI



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A B C D E



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A B C D E



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A B C D E



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A B C D E



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freeOGI



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freeOGI



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freeOGI



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Commoncompositemethods

Whygothroughtheprocessofcompositingwhichthenhelpsusdeterminethesegments?

Why do we go through the effort to segment?

www.priemere.com/GIS

120 km

A

B

D

E

F

C

Here, the geometric mean of the three parameters

Different rock Ingredients will likely result in different production profiles.

It behooves us to standardize how we composite.

1 2 3 4

1) Determine what constitutes favorable and unfavorable conditions2) Color code those values

3) Overlap and integrate a composited color to a value

Different segments need different type curvesWhy:

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Steffen(2012)

20yearsMMCF/

D

PVperwell

EURperwellEURpersegment,TCF,linearscale

P90

P10

0

$5/MCF


05 - Shale Assessment

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Transcript of 05 - Shale Assessment