RSC 2012 Reserves Conference_8Shale_Michaelides

0RSC Reserves Conference September 2011©Ryder Scott Company, L.P.

0

C a l g a r y • H o u s t o n • D e n v e r

Estimating in-place volumes in shale plays, an example from

the Eagle Ford

Michael MichaelidesRyder Scott Company

RSC Reserves Conference September 2012


1

Geological Aspects of Evaluating Unconventional Reservoirs

• Geologists use core data, log analysis, and geophysical techniquesto determine hydrocarbon volume.

• Geological and engineering teams work together to develop evaluation methods in conventional reservoirs.

2

• Typically large areas.• Relatively thin (± 15m) to quite thick (300m+)• Hydrocarbons are self-generated, self-contained.• Low porosity, low permeability, requires fracking.• Vertically and laterally complex.• May or may not be naturally fractured.• Some shales may be partially depleted, others untapped.

Unconventional “Shale Gas” Plays


Our goal is:

1. To identify organic rich shales with good fracking potential

2. Determine the reservoir limits

3. Estimate the resource volumes in-place

A Geologic Approach to Evaluating Shale-Gas Resources


• Start at well level, evolve to regional level.

• must have core data• use core data to correlate to log data• use log-core combination to correlate to un-cored

wells

• Develop trends with wells, then tie to seismic attributes.

• Correlate attributes beyond local to regional areas.

• This is an “up-scaling” process, local to regional.

A Geologic Approach to Evaluating Shale-Gas Resources


Start with Core Data

• Preferable to have whole-core data.• determine mineralogy (chemical composition, ratios)• determine porosity, permeability (kv/kh), grain density• TOC, kerogen content, fluid content, vitrinite

reflectance (oil or gas)• texture (grain sorting, orientation, lamination

thickness)• geomechanical properties (compressive strength,

fracture toughness)• fractures (frequency, width, orientation)

• Most of this information cannot generally be detected directly from open hole logs alone.


Tie Core Data to Logs

• Important to tie log and core depths.• Run full suite of conventional logs.

• GR, Resistivity, Neutron, Density, Sonic• Also consider running other more specialized logs.

• Spectral GR, Photo-electric, CMR, etc.• Use algorithms to tie core defined characteristics to the

log data.• Passey method TOC correlation (GR-Res-sonic)• CNL-FDC, GR, PEF (lithologic data)


Tie the Log-Core Relationships to Non-Cored Wells

• Use the established correlations (core-to-log) in nearby wells.

• Determine local trends.

• Determine if there are any seismic attributes that can be extracted at the local level out to the regional level.


Be Aware That Core-Log Algorithms May Be Locally Specific

• May not be able to use core-log correlations as an “analogy” beyond a local level.

• All the shale rock properties are highly dependent on its source area and that can vary significantly around the basin perimeter.

9

The Eagle Ford Shale


Eagle Ford Shale

• Composed of Cretaceous aged sediments filling basins formed during the Laramide Orogeny.

• Depositional environment was low energy with a stable water column. High organic content of 3-5% was preserved due to anoxic conditions.

• Thermal degradation of the organics into hydrocarbon chains forced water out of the shale. These hydrocarbons eventually saturated the shale and seeped out, forming accumulations in overlying formations such as the Austin Chalk.

• The low permeability of the shale has allowed significant amounts of hydrocarbons to remain trapped in-situ.


Eagle Ford Shale Log Character

• Compared to surrounding rock, the organic rich strata within the Eagle Ford shale tend to have….

• Low density (organics and HC’s take up rock volume)• High resistivity (formation water forced out by HC’s)• Higher neutron porosity than limestone (bound water,

hydrogen in organics and HC’s)• Lower neutron porosity than barren shale (less formation

water)• High sonic porosity (longer transit times through organics)


Eagle Ford Shale Log Character

• Crossplots can be used to determine the character of the various lithologies in the shale in order to establish pertinent cutoffs for core-log correlations.

• These cutoffs can then be applied to algorithms and methods such as the Passey method to constrain the results.


Passey Method

• Relies on higher resistivity and longer acoustic transit times resulting from the presence of organics and hydrocarbons in shale.

• Separation of the acoustic and resistivity curves is measured in ‘decades’. The separation is referred to as Deltalog R, or DlogR.

• Generally used to estimate Total Organic Carbon (TOC) in shale.

• Most useful to locate potential intervals of interest.

• Can be attempted without core data to achieve qualitative results, however calibrating to core may provide quantitative results.


• Can result in false positive indications of TOC.

• Needs to be calibrated using barren shale.

• Cutoffs need to be used appropriately.

Passey Method Limitations


Modified Passey Method

• With core data, the Passey method can be used to derive Total Hydrocarbon filled porosity.

• Generally useful in later stages of development.

• Needs to be calibrated using barren shale.

• Also relies on higher resistivity and longer acoustic transit times resulting from the presence of organics and hydrocarbons in shale.

• Can NOT be attempted without core data.

• Can result in false positive indications of hydrocarbon accumulation.


Appropriate Analyses

• For the Passey and modified Passey methods to work as intended, certain steps need to be taken.

• Cutoffs must be established to avoid false positives.

• Core data in different wells should be analyzed by the same core lab.

• Some core data is more useful than other core data.

• Need Oil, Gas and Water saturations, wt% TOC and porosity.


RSC Petrophysical analysis of the Eagle Ford Shale


Necessary Data

• Minimum.

• Gr, ResD, Neutron, Rhob.

• Good.

• Gr, ResD, Neutron, Rhob, Sonic.

• Best.

• Gr, ResD, Neutron, Rhob, Sonic, Core.


Data Calibration

• Curve calibrations.

• Consistent, all LS matrix or all SS matrix.

• Same kind of resistivity, (induction).

• Log calibrations.

• Establish baselines on well known lithology.

• Barren shales work best.


Establish Zone of Interest

• Regional studies, well correlations, seismic.

• Identify typical non-organic shale in well bore.

• Use non-organic shale as a baseline for DlogR.

• Review areas with significant DlogR separation.


Tie Log to Core

• Use cross plots to correlate log to core samples. Experimentation may be appropriate.

• The following simple cross plots have worked well in the Eagle Ford.

• DlogR / HC filled porosity.• Density Log porosity / Core porosity.


• Use core to definitively determine pay.

• Use cross-plots to determine log characteristics of pay.• Neutron / Density / GR• Density / Sonic / Resistivity

• Use same cross-plots to identify character of non-pay.

Characteristics of Pay

• Use core to definitively determine pay.

• Use cross-plots to determine log characteristics of pay.

• Neutron / Density / GR• Density / Sonic / Resistivity

• Use same cross-plots to identify character of non-pay.


Application

• Detailed Steps

• Determine cuttoffs

• Set up DlogR

• Tie log to core


Cutoffs

• In Texas, Eagle Ford cutoffs were determined using crossplots.

• GR > 50• PHIN > 12%• PHIN < 30%• RHOB < 2.5

• Cut-offs may vary across the field. Additional core data is needed to verify or modify cut-offs.


PHIN / RHOB / GR Crossplot


RESD / DT / GR Crossplot


Setting up Passey Separation (DlogR)

• Translate DT to DTequivalent (log scale)

• Scales should be 50 μs/ft per decade • 200 μs/ft – 1000 ohm (4 decades)• 150 μs/ft – 100 ohm (3 decades)

• Calculate the separation (DlogR)• DLogR[] = log(ResD[]/DTequiv[])


• Align DTequivalent with ResD in barren shale.

• Shift DT equivalent until DlogR = 0 in barren shale.

Calibrating DlogR


• Relate DlogR to Total HC filled porosity.• Relate core porosity to log porosity.

Core-Tie


Apply Correlations and Cutoffs

• The Pay track shows where cutoffs have been applied.

• The Porosity track shows modified log porosity and core porosity (purple dots and line).

• The Calculated HC track shows the calculated HC filled porosity (black line) and HC filled porosity measured in core (red dots).


• Phi*H Maps show the variation of in-place volumes across the field.

• The magnitude of Phi*H in an area generally correlates to average well production.

Mapping the Log Results


Limitations

• At present the hydrocarbon filled porosities have not been successfully separated into liquids and volatiles from log analysis.

• The analysis is very sensitive to the type of resistivity curve available in the well log.

• Some operators only log the ZOI, resulting in a poor calibration to barren shale.

• Without basic curves (Density, Neutron) to verify cutoff compliance, in-place volumes can be grossly overestimated.


Results

• If done correctly, and with enough supporting evidence, such as comparable production, geologic investigation can provide a measure of quantitative comparison.

• As more information becomes available, qualitative geologic comparisons may be possible in the future as it is done in conventional reservoirs today.

34

Questions

Michael MichaelidesRyder Scott Company

Documents

RSC 2012 Reserves Conference_8Shale_Michaelides