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Geochemical Assessment of Unconventional Shale Resource Plays, North America*

( * submitted for publication in AAPG Bull. Special Issue on Shale Resource Plays due out 2nd quarter 2010)

Daniel M. Jarvie1, R. Paul Philp2, Brian M, Jarvie3, and James D. Jarvie3 1 Worldwide Geochemistry, PO Box 789, Humble, Texas 77347 USA ([email protected]) Current address: Institut Francais du Petrole, 1 et 4, avenue de Bois-Preau, 92852 Rueil-Malmaison, France ([email protected]) 2 University of Oklahoma, 100 East Boyd Street, Suite 810, Norman, OK 73019 USA ([email protected]) 3 Geomark Research, 218 Higgins Street, Humble, Texas 77338 USA ([email protected];[email protected])

Introduction

Unconventional shale resource plays have grown dramatically in the last 10 years in North America. The low porosity (~4-5%), nanodarcy permeability Mississippian Barnett Shale in the Newark East Field, Fort Worth Basin, Texas, is now the largest gas field in the USA. Interestingly it will possibly be exceeded by several other shalegas plays including the Haynesville/Bossier, Marcellus, and Muskwa shale systems of North America. There are many factors that affect the producibility of hydrocarbons from shale source/reservoir rocks. Basic geochemical data goes a long way toward characterizing these plays and their likelihood of high-graded commercial success: · Gas type · TOC · Thermal maturity · K Kerogen type t · Residual oil saturation · Gas-in-place (GIP) · Mineralogy including clay speciation · Rock mechanical properties · Porosity/permeability The bulk of gaseous hydrocarbons are generated from secondary decomposition of resins (NSOs) (Behar et al., 2007). Thus, it is important to understand gas generation, but also gas storage and preservation at higher thermal maturities. While these plays are often characterized as engineering or stimulation plays, they are not until the right areas are identified; otherwise the engineers would be stimulating any and all shales, most of which would not be productive. Shale-gas and shale-oil plays are not necessarily strictly "shale" plays as hybrid system ­ those systems with mixed lithofacies present ­ appear to be the most productive. Strictly speaking shale is defined by particle size, but in shale-gas plays it is i more i important t know mineralogy as well as h i clay speciation. t t to k i l ll having l i ti Hybrid Shale System: mixed lithofacies at variable scales Mudstone Bioturbated siltstone and sandstone Laminated sandstone and mudstone

North American Shale Resource Plays y

22 30 U U

24 23 6 1 21 21 20

7 25 19 U U 2

3a

18 17 27 26 16 15 10 X1 4 28 12

1 13 31 X1 U

3b

9 8 X2 11 31

Biogenic shale-gas Thermogenic shale-gas Shale-oil (not oil shale!) Failed for shale-gas Untested shale

No. 1 2 3a-b 4 5 6 7 8 9 10 11 12 13 14 15

U

14 5 13 29

Age, Shale, Basin Devonian Antrim Shale, Michigan Basin Cretaceous Niobrara Shale, Central Nebraska area Devonian New Albany Shale, Illinois Basin Devonian Woodford Shale, Ardomore Basin U. Jurassic Bossier Shale/Sand, East Texas Salt Basin Ordovician Utica Shale, Devonian Marcellus Shale, Appalachian Basin Cambrian Conasauga Shale, Mississippian Fayetteville Shale, Arkoma Basin Devonian Woodford Shale, Arkoma Basin U. Jurassic Haynesville/Bossier Shales, ETNL Salt Basin Mississippian Barnett Shale, Fort Worth Basin Cretaceous Pearsall Shale, Maverick Basin Penn-Miss-Devonian Shales, Delaware Basin Devonian Woodford Shale, Anadarko Basin

Type bg bg bgtg tg tgh tg tg tg tg tg tgh tg tg tg tg

No. 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31

Age, Shale, Basin Penn Shale, Panhandle Area, Anadarko Basin Cretaceous Pierre Shale, Raton Basin Pennsylvanian Gothic Shale, Paradox Basin Cretaceous Baxter Shale, Greater Green River Basin Cretaceous Mowry Shale, Big Horn Basin Paleocene Waltman Shale, Wind River Basin Devonian Muskwa Shale, Big Horn Basin, BC Devonian Bakken Formation, Williston Basin Pennsylvanian Heath/Tyler Shales, Central Montana Trough Miocene Antelope Shale, San Joaquin Basin Miocene Monterey Shale, Santa Maria Basin Cretaceous Mancos Shale, San Juan Basin Mississippian Barnett Shale, Fort Worth Basin Cretaceous Eagle Ford Shale, South Texas Basin Triassic Montney Shale, West Canada Basin Cretaceous Tuscaloosa Shale, Mississippi Salt Basin

Type tgh tgh tg tg tg tm tg oh oh of of of ot tgh tgh ot

Type codes: T d bg = biogenic shale gas tg = thermogenic shale gas tgh = thermogenic shale gas, hyrbid non-shale lithofacies tgm = thermogenic shale gas, migrated

of = shale oil, fractured oh = shale oil, hybrid non-shale lithofacies ot = shale oil, tight shale

Comparison of Five Different Shale-Gas Systems

REM MAINING HYDROCARBON POTENTIAL (mg HC/g Rock)

60

50

40

Barnett Shale New Albany Shale Antrim Shale Bossier Formation Waltman Shale

Type I Oil Prone usu. lacustrine

TYPE II Oil Prone (usu. marine)

ETHANE, PROPANE, and BUTANES (vol.% )

-75 Bacterial Gas Barnett Antrim Shale Shale New Albany Shale New AlbanyWaltman ShaleKY Shale, Barnett Shale Bossier Shale Waltman Shale

Mixed Type II / III Oil / Gas Prone

-65

30

Mixed BacterialThermogenic Gas

20

Organic Lean

Type III Gas Prone

ETHANE (ppt C ME

-55

10

Dry Gas Prone

-45

Oil Associated Gas

0

Risking Shale-Gas Systems

One of the principal issues in evaluating shale-gas systems is making an accurate determination of thermal maturity, or more appropriately, the type of products that will be found. Thus, some calibration to a given system is required. We use a polar plot to assess geochemical risk as well as other variables as shown below.

Some Geochemical Risk Factors

Decreasing Risk

0

2

4

6

8

10

12

14

16

Post Mature Dry Gas Condensate Associated Gas

TOTAL ORGANIC CARBON (TOC, wt.%)

Gas-in-Place Risk

Decreasing Risk

-35 Above - These data show yields (S2) versus TOC indicative of high remaining potential for those source rocks having greater than 10 mg/g S2 for five different shale gas systems. -25 Organic-rich rocks with TOC > 2% are prime targets from an 0.0 10.0 20.0 30.0 40.0 50.0 60.0 organic richness viewpoint. Right ­ Carbon isotopic values versus gas wetness show differences in type, thermal maturity, or origin among these five systems. The importance of these differences lies in what ultimately will be recovered from these shales in terms of bcf or m3/m3. They may be IP rated as follows:

Biogenic and low thermal maturity shales < gas window maturity shales < gas window shale hybrids

Increasing Risk

Increasing Risk

Some Petrophysical Risk Factors

Some Geological and Economic Risk Factors

Barnett Shale porosity is almost entirely derived from organic matter decomposition decomposition. On the other hand, Haynesville Shale porosity exceeds its organic porosity development by a factor of 2. This means that more gas is stored as free gas rather than adsorbed gas resulted in very high initial production (IP) rates. This is due to Haynesville having additional matrix porosity derived from secondary porosity in carbonate­a hybrid system.

Organic Porosity Created from Kerogen Decomposition

Organic Porosity Development Potential

18.00%

2.5% TOCo

16.00% 14.00% 12.00% 10.00% 8.00% 6.00% 4.00% 2.00% 0.00%

5.0% TOCo 7.5% TOCo 10.0% TOCo 12.5% TOCo 15.0% TOCo 17.5% TOCo 20.0% TOCo

If high thermal maturity is good, then excessively high thermal maturity must be even better? This appears to be incorrect, although not understood. Data is contradictory but there is evidence of possible gas destruction in hot reservoirs. The data on the right is derived from Barker and Takach (1991) showing a 50% volumetric loss of methane at high thermal maturity (>3.5%Ro).

Research Questions

25%TR 50%TR 75%TR 100%TR

Porosity can be developed by decomposition of organic matter (e.g., Tissot & Welte, 1984). 1984) The graphic above shows the total potential porosity that could be derived from organic matter decomposition for shales of varying organic richness and at very levels of conversion of organic matter. After much investigation by the Bureau of Economic Geology, University of Texas, no open fractures or matrix porosity have been revealed. However, Reed et al. (submitted) identified nanopores in the Barnett Shale utilizing an argon ion milling technique derived from the semiconductor industry. They identified "nanopores" that range in size from 1-2 nanometers to 400 nanometers. This appears to be the main means for storage of gas in the Barnett Shale. At PVT conditions 5% porosity can store over 700 mcf/af (16.9 m3/m3).

Many questions remain poorly understood in shale-gas and shale-oil systems: · What are the best indicators of high flow rate wells? · Is commercial gas producible above 3.0%Ro? · Wh t are the best landing zones f h i What th b t l di for horizontal wells? hi h t gas contents; most b ittl t l ll ? highest t t t brittle rock? · How important is carbonate content in shale or associated lithofacies? · Why do some wells produce fair amounts of liquid hydrocarbons with gas whereas other wells are choked by the present of liquid hydrocarbons? · Why are wells next to each other sometimes so variable in performance? · When and how often are generated products expelled and how much is retained? Can this be used as a proxy for GIP? · Do organic acids including CO2 play a role in creation of migration conduits or secondary porosity? · What are the controls on porosity in addition to organic matter decomposition? · How important is depositional setting on the likelihood of success for shale gas or oil? · How can oil be produced more effectively from tight shales?

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