Petrophysics in shale gas

8/9/2019 Petrophysics in shale gas

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Petrophysics

Appraising and DevelopingShale Oil and Gas Reservoirs

Shale Composition: Petrophysical Perspective

From Randy Miller, Integrated Reservoir Solutions, Core Lab


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Shale OGIP Equation

Where:OGIP = Original gas in place (cubic meters)

A = Area (square meters)

h = Shale thickness (meters) m = Matrix porosity (fraction)

Sg = Gas saturation (fraction)

Eg = Initial gas expansion factor (scm/rcm)

Gs = Gas storage capacity, as-received basis (m^3/ton) = Shale density, as-received basis (ton/m^3)

]*}**[{* S m GSg Egh AOGIP

PetrophysicalMeasurements

from Core


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Sampling Methodology

From Core Laboratories

CoreLabs Analysis Procedure

From Core Laboratories


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GRI Reasoning for Using Crushed Samples fo rPorosity Measurements

From Ted Braun, SPWLA short course, 2011

Helium was unable to contact all the pore space within an uncrushed sample

Uncontacted pores are interpreted as grains with zero density

Result was low porosity and low grain density

Crushing dramatically increases the surface area to volume ratio resulting in greateraccess to pore space and more representative measurements

Core porosity needs to be decreased by 0.5-1 porosity unit to correct values to in-situ conditions

GRI Measurement of Matrix Permeability

Change in pressurewith time is used tocalculate perm.

Core chips are assumed to be unfractured (crushing would have broken the corealong fractures) and the measurement is made at surface conditions



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GRI Measurement o f Phi , So, Sw, Grain Den.


Water volume is calculated by assuming a water density (salinity)

Oil volume = (oil weight / assumed oil density) where oil weight = weight loss ofcrushed rock in excess of the water collected in the Dean Stark receiver

Pore volume = bulk volume grain volume; Porosity = pore volume / bulk volume

Sw = water volume / pore volume; So = oil volume / pore volume

Result ing Petrography and Core Data

EpifluorescencePetrography



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Matrix K vs. Total Porosity by Play


Matrix K vs . Water Saturation by Play



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Distribution of Water and Gas in the Pore Space

From SPE 131350

TerraTeks Analysis Procedure

From SPE 147456

Retort method

Differentiates between free and bound fluid volumes basedupon temperature

Temperature is increased through a series of programmedsteps

250 degrees F for mobile water

600 degrees F for mobile oil

1300 degrees F for clay-bound water and boundhydrocarbons

Allows reporting of total and effective porosities


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Table of Shale Core Measurements

From Terratek

Reported Porosi ties from Three Different Labs

From Quinn Passey et al, AAPG Search and Discovery Article 80231


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Repor ted Permeabiliti es from Three Different Labs

100 nD

Service laboratories have developed their own proprietarytechniques and it is difficult to know if the differences in reportedvalues are due to the differences in the data or interpretations

From Quinn Passey et al, SPE 131350

Exxons New Approach For

Measuring Kon shale cores

(SPE 152257)

Steady-state app aratusfor measuring permson very tight samples

Comparison between steady-stateperms from plu gs and pressure decayperms fro m vendors A & B measuredon crush ed samples


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Mineralogy Comparison by Play

From Randy Mil ler, Integrated Reservoir Solutions, Core Lab

Shale Petrophysical Properties by Play



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Comparison of Shale Characteristics

MONTNEY BARNETT HAYNESVILLE MARCELLUS MUSKWA/OOTLA

Basin Western Canadian Fort Worth Gulf Coast Appalachian Horn River

Age Triass ic Miss iss ipp ian Jur assi c Devon ian Devon ian

Depth, meters 1,500 to 2,400 2,000 to 2,700 3,000 to 4,000 1,500 to 2,400 2,700 to 4,000Reservoir Temperature, C 60 to 80 70 to 90 150 to 175 40 to 65 60 to 80

Thickness, meters 100 to 300 100 to 150 50 to 100 15 to 75 100 to 180

Total Porosity, % 4 to 9 3 to 7 6 to 10 5 to 8 3 to 5

Water Saturation, % 10 to 60 20 to 50 15 to 30 10 to 40 20 to 40

Sorbed Gas, m 3/mt 0.14 to 0.71 2.0 to 2.8 1.4 to 2.8 1.4 to 4.2 0.85 to 1.70

Sorbed Gas, % total 5 to 30 40 to 45 25 45 to 55 20 to 40

TOC, weight % 0.5 to 2.5 3 to 8 3 to 5 5 to 8 2 to 5

Kerogen Type Type II Type II Type II Type II Type IIVitrinite Reflectance, % Ro 0.3 to 2.5 1.2 to 2.2 1.2 to 2.5 0.9 to 3.5 1.6 to 3.0

Pressure Gradient, kg/cm 2/m 0.09 to 0.15 0.10 to 0.13 0.18 to 0.21 0.09 to 0.16 0.12 to 0.14

IP, 10 3m 3/d 50 to 150 30 to 170 140 to 550+ 55 to 170 140 to 280

OGIP, 109

m3

/km2

0.1 to 3.0 0.5 to 2.2 1.6 to 2.7 0.3 to 1.6 2.0 to 3.5Well Spacing, km 2 0.32 0.1 to 0.4 0.32 to 0.65 0.32 to 0.65 0.16 to 0.65

Recovery Factor, % 20 to 30 20 to 50 30 20 to 40 20 to 30

EUR, 10 6m 3 per well 150 to 270 60 to 140 130 to 240 100 to 150 110 to 170

DeterminingTotal OrganicCarbon from

Logs


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How Organic Matter and Uranium are Related

OxidizingZone

As t he ano xic zon e expands , organicmatter settles through the oxidizing zonemore rapidly, and therefore more organic

matter accumulates

Organic matter is oxidized resulting inproducts (C, N, P) that are recycled bylive organisms

OxidizingZone

U+6 (soluble) is reduced to U +4

(insoluble) when it comes in contactwith organic matter

U +6U+6

U+6

U +4 U+4

U +6U+6

More U +4 precipitates as the anoxic zoneexpands and more organic matter is

preserved

U +4 U +4U +6

U +4 U +4

U +6

U +4

Modified from Nick Harris, Source Rocks 101 Short Course

Relationship between Uranium and TOC

From Luning and Kolonic, 2003


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Relationship Between TOC and GR Logs

Higher TOCvalues equate tohigh GR valuesdue to the affectsof uranium

However, not allorganic mattercontains uraniumand a spectral GRmay be needed if

Th or K arepresent

>15%TOC

> 600 API

Modified from Nick Harris, Source Rocks 101 Short Course

Identifying Organic-rich Shales from GR and RHOB

Bulk Density

G R

Organic-richShales

Nuttal et al, AAPGSearch and Discovery

Art icl e 40171


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Delta Log R Technique

Organic-poor shales = rock matrix + water Immature organic-rich shales = rock matrix + water +

solid organic matter

Mature organic-rich shales = rock matrix + water + solidorganic matter + hydrocarbons

As a result, compared to organic-poor shales Immature organic-rich shales have higher apparent porosity (due

to low-density, low-velocity kerogen)

Mature organic-rich shales have higher apparent porosity andhigher resistivity (as water is displaced by generatedhydrocarbons)


Set the scale so that 50microseconds/foot = 1 resistivitycycle

Adjust the scales so that in ashale, the sonic and resistivitylogs overlap

Elsewhere, the sonic log will plotto the left of the resistivity log

The gap between the two curvesis proportional to the TOC

The resistivity and sonic valueshere are the baseline values

From Passey et al, 1990


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Delta Log R TechniqueThe follow ing expressio n (after Passey et. al.) describes the separationof baselined resistivity and porosity lo g curves;

Where is curve separation

R is the measured formation resistivityRns is the resistivity of organic-poor shalesP is the porosity log readingPns is the porosity log reading in organic-poor shalesK is a scale factor dependent on porosity log measurement units

K = -0.02 for sonic, 2.5 for density, and -0.04 for neutron logs

TOC is calculated using

Where TOC is total organic carbon in weight percent

LOM is the level of organic maturityThe equation above predicts zero TOC where there is no curve separation (baselinecondit ions). In practice, however, all shales have some organic carbon content, so it isnecessary to add 0.2 to 1.6 percent to p redicted TOC. The baseline TOC content of shalesis usually determined from laboratory measurements or using local knowledge.

From Henderson Petrophysics (www.hendersonpetrophysics.com)


Also need to estimate the Level of Organic Metamorphism (LOM) Approximately equal to Ro * 10 at lower LOM values For higher LOM values: If Ro = 1.1, LOM = 11; If Ro = 1.5, LOM = 12; If Ro =

1.8, LOM = 13; If Ro = 2.1, LOM = 14; If Ro = 2.3, LOM = 15; If Ro = 2.5, LOM= 16; If Ro = 2.8, LOM = 17; If Ro = 3.3, LOM = 18; If Ro = 3.9, LOM = 19

From Passey et al, 1990


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Comparison to TOC and S2 dataFrom Passey et al, 1990

ResolvingFractures with

Logs


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Fracture Variations by Layer, Outcrop

Photo From the Austin Chalk, San Antonio

From WL Taylor and JV Grant, From Carbonate Deformation: Outcrop Analogs for FracturedReservoirs, 2004, Field trip associated with AAPG Annual Conv.

Fracture Variations by Layer, FMI Log

Image from a vertical well inthe Barnett Shale illustratesthe relationship betweenmechanical bed thickness andfracture height and length

The joints terminate at bedboundaries (blue arrows)which separate strata ofdifferent rock mechanicalproperties

Fracture height and length is,therefore, a function of bedthickness and fracture attitude

From C. Stamm et al, Barnett Shale, NewLWD sensor technology, SPWLA, 2007


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Petrophysical AnalysisExample

Visual Log Assessment GR log

Higher values indicate higher TOC (hot shales >150 API units)

Resistivity log Higher resistivity values indicate greater hydrocarbon presence

Density log Lower values ( 8 pu (limestone matrix)

Neutron log

High neutron response (>35 pu) indicative of clays or coals

Geochemical log Presence of pyrite (associated with higher TOC) Low clay content is a good indicator of brittleness

From R. Salter and R. Lewis, Schlumberger


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Recommended Logging Suite

Spectral GR Induction or Laterolog

Density with PE curve

Neutron

Acoustic scanning tool

Image log

Geochemical logging tool Such as the Elemental

Capture Spectroscopy tool(ECS) for mineralogy,kerogen, matrix density

From Erik Rylander, Schlumberger

Generic Petrophys ical Approach for Shale Gas

Computational process Determine the mineralogy (including kerogen)

Compute TOC from kerogen (function of kerogen type andmaturity)

Compute sorbed gas using Langmuir isotherms for samples withvariable TOC values

Determine effective porosity and Sw; compute free gas

Convert free gas into scf/ton and add to adsorbed gas to obtaintotal gas

Key outputs Gas saturation, porosity, hydrocarbons in place per unit

Can apply reservoir and pay cutoffs if desired

From Erik Rylander, Schlumberger


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Mineralogy and TOC

Need to combine thegeochemical log outputwith knowledge of whichcomponents are present inthe shale (from X-raydiffraction and petrography)

Typically these are calcite,quartz, pyrite, illite,kaolinite, kerogen, andporosity

Kerogen is then convertedto TOC

From Keith Bartenhagen, Schlumberger

Conversion of Kerogen to TOC

Kerogen contains carbonand other elements

As kerogen matures,carbon content increases

Need to assume a value forK based on thermalmaturity

Type I II IIIDiagnesis 1.25 1.34 1.48End of Catagenesis 1.20 1.19 1.18

Maturity Constants


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Free Gas Calculation

Need to calculateporosity and Sw valuesfrom the logs thatmatch core-derivedvalues

May have to changeparameters along thewell to get a match

Need to know claycontent, matrix density,

Rw, and electricalproperties

From Keith Bartenhagen, Schlumberger

Void Space Correction

Accounts for the volume of measuredfree space occupied by the sorbed gas

Shale A shows a decrease of 14.2% offree gas and 11.6% of total gas

Shale B shows a decrease of 30.2% offree gas and 17.1% of total gas

From Ray Ambrose et al, SPE 131772


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Convers ion of Free Gas to SCF/ton


Total Gas Log

K. Bartenhagen,Schlumberger

80

200


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Net Reservoir and Pay Flags

Net Reservoir >2% Gas-filled porosity

Pay>4 pu effective porosity2% TOC>100 nanodarcies permeability


Technique will likely underestimate the total moveablegas, but can be used to identify wells with the highest productivity/EUR and help explain why they are so good

A Rigorous Petrophysical Workflow

1. Load, quality assure, and edit log and core data2. Shift the cores to the log depths3. Apply environmental corrections, if necessary4. Determine if there are sufficient core samples5. Set parameter values based on available logs & cores6. Compute TOC from logs and cores7. Compute fluid density8. Compute average inorganic matrix density and TOC density9. Compute total porosity corrected for the volume of kerogen10. Convert TOC (weight percent) to bulk volu me of kerogen

11. Recalculate apparent matrix values for the presence of kerogen12. Compute Sw and bulk volume gas (gas-filled porosi ty)13. Compute free, sorbed and total gas14. Compute gas-in-place15. Compute lithologic volumes

From Log-Core Calibrated Shale Gas Evaluation Procedures, a Weatherford document


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Summary

Petrophysics is critical for Estimating production potential

Selecting completion intervals and designs

Identifying poor performers

Quantifying non-shale reservoirs, stimulation barriers, and water-bearing intervals

Keys to successful evaluation include Gathering sufficient, high-quality data

Calibrating the logs to other data

Innovations that will allow us to better quantify gas storage andflow capacity

Documents

Petrophysics in shale gas