RESOURCE ASSESSMENT Michael Hohn, Susan Pool, and Jessica Moore West Virginia Geological & Economic...

RESOURCE ASSESSMENT

Michael Hohn, Susan Pool, and Jessica Moore

West Virginia Geological & Economic Survey

Background

Approaches to estimating hydrocarbon volumes for continuous unconventional reservoirs:• Use production data to estimate

recoverable resources directly

• Use geologic data to estimate original hydrocarbons-in-place from which recoverable resources can be determined

Background• All hydrocarbon that

could be produced (varies):– Technically recoverable (TRR)--

function of geology and technology

– Economically recoverable (ERR)--function of geology, technology, and economics

• All the hydrocarbon that exists (fixed):– Original hydrocarbon-in-place

(OHIP)--function of geology

Modified from Boswell

REMAINING RESOURCES

Assessment of Utica Shale Play Remaining Resources

Methodology

• Probability-based U.S. Geological Survey method

• Uses distributions for total assessment unit area, areas of sweet spots, EUR, and success rates

• Excludes wells already producing• Monte Carlo sampling of distributions for

mean, median, 5%, 95% values for total resource

Steps

• Definition of total assessment units• Delineation of minimum, median,

maximum area of sweet spots• Decline curve analysis for determining

estimated ultimate recoveries• Success ratios• Drainage areas

Assessment Units

Producing Oil Wells

Condensate/NGL Production

Producing Gas Wells

Definition of Assessment Units: Thermal Maturity

Gas Prone

Wet Gas

Oil ProneOvermature

Definition of Assessment Units: Oil Sweet Spot

Definition of Assessment Units: Wet Gas Sweet Spot

Assessment Units and Sweet Spots

Oil

Sw

eet

Spo

t M

inim

um

Oil Sweet Spot

Minimum

Oil Sweet Spot

Maximum

Wet Gas Sweet Spot

Maximum

Wet Gas Sweet Spot

Minimum

Dry Gas Sweet Spot

Maximum

Dry Gas Sweet Spot

Minimum

Estimated Ultimate Recovery


0 5 10 15 20 25 30 35 40 450

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

Months

Ba

rre

ls O

il


0 5 10 15 20 25 30 35 40 450

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

Median 1 year

Median 2 years

Median 3 years

Median 4 years

Median

Months

Ba

rre

ls O

il

EUR Model

0 20 40 60 80 100 1200

50,000

100,000

150,000

200,000

250,000

300,000

350,000

Median 1 year

Median 2 years

Median 3 years

Median 4 years

Median

Minimum EUR model

Median EUR Model

Maximum EUR Model

Months

Ba

rre

ls O

il

EUR Distributions

Oil AU (MMbo) Min Med Max

Sweet Spot 0.022 0.199 0.628

Non Sweet Spot 0.002 0.022 0.049

Wet Gas AU (Bcf) Min Med Max

Sweet Spot 0.64 5.76 18.84

Non Sweet Spot 0.20 0.64 1.19

Gas AU (Bcf) Min Med Max

Sweet Spot 0.19 7.09 30.37

Non Sweet Spot 0.039 0.19 0.32

Success Rates

Oil AU (%) Min Med Max

Sweet Spot 90 95 99

Non Sweet Spot 1 3 5

Wet Gas AU (%) Min Med Max

Sweet Spot 90 95 99


Gas AU (%) Min Med Max

Sweet Spot 90 95 99


Results

Oil Assessment Unit

OIL MMbo Gas Bcf

F95 F50 F5 Mean F95 F50 F5 Mean

Sweet Spot 733 1,677 3,744 1,908 2,231 6,636 17,722 7,949

NonSweet Spot 23 49 91 52 69 191 446 216

Total 791 1,728 3,788 1,960 2,370 6,858 17,960 8,165

Wet Gas Assessment Unit

OIL MMbo Gas Bcf


Sweet Spot 23,840 49,601 106,550 55,980

NonSweet Spot 99 379 1,023 447

Total 24,484 50,037 106,852 56,427

Gas Assessment Unit

OIL MMbo Gas Bcf


Sweet Spot 220,473 590,680 1,542,873 710,341

NonSweet Spot 2,862 6,584 13,835 7,238

Total 228,478 598,026 1,549,586 717,579

ORIGINAL IN-PLACE RESOURCES

Assessment of Utica Shale Play In-Place Resources using

Volumetric Approach

Purpose

• Estimate original hydrocarbon-in-place volumes for selected stratigraphic units

• Determine general overall hydrocarbon distribution

• Examine key parameters that may impact hydrocarbon distribution

Methodology and Data

Use geologic data and volumetric approach to estimate total original hydrocarbon-in-place (OHIP):

OHIP = Free + Adsorbed


Use geologic data and volumetric approach to estimate total original hydrocarbon-in-place (OHIP):

OHIP = Free + Adsorbed

Free Hydrocarbon-in-PlaceOGIPfree = (feff * (1-Sw) * (1-Qnc) * Hfm * Ar * 4.346*10-5 ) / FVFg

OOIPfree = (feff * (1-Sw) * Hfm * Ar * 7758) / FVFo

Adsorbed Hydrocarbon-in-PlaceOGIPadsorb = Gc * rfm * Hfm * Ar * 1.3597*10-6

?OOIPadsorb= S2 * 0.001 * rfm * Hfm * Ar * 7758

Hfm , rfm , f, and Sw

are derived from Utica Project well logs

with f and Sw adjusted for Vsh and Vker

TOC

is from Utica Project sample/well log data

Gc

is from publicly-available isotherms

given TOC and pressure

FVF

is derived from Utica Project well logs and other publicly-available data

given temperature, pressure, and gas compressibility



1. Identify and select wells meeting approach criteria

2. Examine stratigraphic picks and well log data

3. Select and extract well log data

4. Compile and derive additional required data

5. Process data and estimate volumes

6. Correct and refine data


Searching for:• Utica, Point Pleasant, Logana penetrations

• Top depth no less than 2,500 feet (initial); ~3,000 feet (final)

• Digital well logs with, at minimum, gamma ray, bulk density/porosity, resistivity traces

• Vertical non-faulted wells

• Even geographic distribution

Step 1—Identify and Select Wells

Methodology and DataStep 1—Identify and Select Wells

Digital logs for wells with Utica, Point Pleasant, and/or Logana identified plus top depth greater than 2500 feet


Full suite digital logs for wells with Utica, Point Pleasant, and/or Logana identified plus top depth greater than 2500 feet


Full suite digital logs for wells with Utica, Point Pleasant, and/or Logana identified plus top depth greater than 2500 feet

Note: Limited digital well log data

Thermal maturity as determined from equivalent %Ro

• Determined level of maturity for selected wells based on equivalent %Ro map

• Divided in-place assessment into gas and oil regions

• Assumed single phase in each hydrocarbon region


Methodology and DataStep 2—Examine Stratigraphic Picks and Logs

Example digital well log data with stratigraphic units identified;used to review log availability through units plus assess log quality

Methodology and DataStep 3—Select and Extract Log Data

Example digital well log data with stratigraphic units identified;used to review log availability through units plus assess log quality

Log data:• Gamma ray• Density and porosity• Resistivity• Temperature• TOC

Notes:• Normalized• Sample interval=0.5 feet


Including:• Total Organic Carbon

• Pressure

• Volume of Shale

• Temperature

• Gas Content

Step 4—Compile and Derive Additional Data

Methodology and DataStep 4—Compile and Derive Additional Data

Mean total organic carbon (%) for Utica Shaleas derived from Consortium analytical data

TOC


Mean total organic carbon (%) for Point Pleasant Formationas derived from Consortium analytical data

TOC


Mean total organic carbon (%) for Logana Member of Trenton Limestoneas derived from Consortium analytical data

TOC


Had limited reservoir pressure data. From formation-specific well data for WV and OH, Consortium partner input, and publicly-available data; assumed pressure gradients (psi/ft) of:• 0.433 for NY and 0.6 for remaining area except...

• 0.5 in very small portion of southern NY

• 0.7 in small portion of north central PA

• 0.7-0.9 in small area including southwestern PA, northern WV panhandle, and east central OH


Pressure


Corrected for volume of shale as extracted from: • X-ray diffraction (XRD) data

• Maps from XRD data

• Gamma ray well logs plus XRD data


Volume of Shale


Temperature gradientas derived from the National Geothermal Project data

Temperature


Gas content determined from publicly-available isothermsgiven total organic carbon (TOC) and pressure

Advanced Resources International, Inc.

• CH4 isotherm for NY

• Isotherm used for NY, majority of PA, and WV given TOC and pressure

• CH4 isotherm for various states

• Isotherm used for OH given TOC and pressure

• Isotherm values from NY and OH averaged for northwestern corner of PA given TOC and pressure

Gas Content

Methodology and DataStep 5—Process Data and Estimate Volumes

a. Estimate effective porosity

b. Estimate water saturation

c. Estimate formation volume factor

d. Estimate free hydrocarbon volumes

e. Estimate adsorbed hydrocarbon volumes


Porosity Notes:

• Determined density porosity from bulk density or used density porosity

• Used both density and neutron porosity if available

• Corrected for Vsh as extracted from XRD data, maps from XRD data, and gamma ray well logs+XRD data

• Corrected for Vker as extracted from maps assuming linear relationship between TOC and Vker


Water Saturation Notes:

• Used Simandoux equation

• Used A=1, M=1.7, and N=1.7

• Corrected for Vsh as extracted from XRD data, maps from XRD data, and gamma ray well logs+XRD data

• Corrected for Vker as extracted from maps assuming linear relationship between TOC and Vker


Additional Notes:

• Used TOC from Utica Project analytical data and maps rather than using TOC from Passey method

Stratigraphic Unit

Original In-Place Resources,Average Volumes Per Unit Area

Oil (MMbo/mi2)* Gas (Bcf/mi2)*

Utica Shale 20.8 53.5

Point Pleasant Formation 15.8 85.1

Logana Member of Trenton Limestone 3.0 17.0

Preliminary summary results

* = average volume per square mile in the sweet spot area; sweet spot area is as defined to estimate remaining recoverable resources using the probabilistic (USGS-style) approach

Step 5—Process Data and Estimate VolumesMethodology and Data

Utica Shale original in-place volumes per unit area,preliminary summary results

average volume per square mile in the sweet spot area; sweet spot area is as defined to estimate remaining recoverable resources using the probabilistic (USGS-style) approach


Supplemental Slide 1

DISCLAIMER: This map is a preliminary draft which reflects data and analyses current as of July 14, 2015.The volumetric calculations and derivative maps will likely change as additional data become available and techniques are refined. Users are cautioned that this map represents only a best estimate of trends given limited available data and should not be used as a stand-alone product.


Methodology and DataPoint Pleasant Formation original in-place volumes per unit area,

preliminary summary results

Step 5—Process Data and Estimate Volumes




Methodology and DataLogana Member of Trenton Limestone original in-place volumes per unit area,

preliminary summary results

Step 5—Process Data and Estimate Volumes



Stratigraphic Unit

Original In-Place Resources,Total Volumes

Oil (MMbo)* Gas (Bcf)*

Utica Shale 43,508 1,098,119

Point Pleasant Formation 33,050 1,745,803

Logana Member of Trenton Limestone 6,345 348,476

Preliminary summary results

* = estimated volume in the sweet spot area; sweet spot area is as defined to estimate remaining recoverable resources using the probabilistic (USGS-style) approach

Step 5—Process Data and Estimate VolumesMethodology and Data

Resources Oil (MMbo)* Gas (Bcf)*

Recoverable Resources

2,611 889,972

Original In-Place Resources

82,903 3,192,398

Current Recovery Factors

3% 28%

* = estimated volume in the sweet spot area; sweet spot area is as defined to estimate remaining recoverable resources using the probabilistic (USGS-style) approach

Comparison of Results

Issues

• Limited amount of full-suite well log data especially for Pennsylvania and West Virginia

• Limited formation pressure data

• Limited core data for log-to-core calibration


Potential Future Work

• Incorporate additional data from supplemental sources (e.g. IHS)

• Incorporate additional data from wells with less than full suites of log data

• Investigate additional data processing techniques

• Conduct sensitivity analysis

• Update EUR’s and sweet spots as play develops


RESOURCE ASSESSMENT Michael Hohn, Susan Pool, and Jessica Moore West Virginia Geological & Economic...

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