unconventional oil & gas resource evaluation of the...

Unconventional Oil & Gas Resource Evaluation of

the Woodford Shale in New Mexico

by

Vidya Sagar Bammidi

Submitted in Partial Fulfillment

of the requirements for the degree of

Master of Science in Petroleum Engineering

New Mexico Institute of Mining and Technology (NMT)

Department of Petroleum Engineering

Socorro, New Mexico

July 31, 2011

Unconventional Oil & Gas Resource Evaluation of

the Woodford Shale in New Mexico

by

Vidya Sagar Bammidi

Submitted to New Mexico Tech (NMT)

In partial fulfillment of the requirements

For the degree of

MASTER OF SCIENCE

Approved as to style and content by:

Dr. Robert S. Balch Dr. Thomas W. Engler

_______________ _________________

[Research Advisor] [Academic Advisor]

Ms. Martha Cather Dr. Michael Kelly

_______________ _________________

[Committee Member] [Committee Member]

July 31, 2011

Major Subject: Petroleum Engineering

ABSTRACT

The Upper Devonian Woodford Shale ranges from a thickness of 0 ft to 300 ft and is

found at depths of 7,000 ft to 18,000 ft in the Delaware Basin. The Woodford is ther-

mally mature over its entire extent in New Mexico: In the deeper parts of the Dela-

ware Basin, it is in the thermogenic gas and condensate window; on the Northwest

Shelf and where present on the Central Basin Platform, it is in the oil window (Broad-

head, 2010).

The goal of this work was to identify areas of high potential oil, dry gas and wet gas

production within the Woodford in Southeastern New Mexico. Southeastern New

Mexico was subdivided into Regions I, II and III using updated data from Comer

(2008) and Broadhead (2010) based on the intensity of the fracture networks, thermal

maturity, and Total Organic Carbon (TOC).

The methodologies used for ranking and estimating the potential in these regions are

Miller's gas shale ranking scorecard and Comer's hydrogen mass balance.

Miller’s (2010) gas shale ranking scorecard is used with parameters of total organic

carbon, vitrinite reflectance, shale thickness, gas-filled porosity, clay content, quartz

content, fluid compatibility, natural fracture intensity, tectonic stress and reservoir

pressure gradient. The range of the ranking scale is 0 to 100 points with an equal

weight applied to each of the 10 parameters. Higher rankings improve the prospects

of finding shale gas. For reference, the Barnett Shale has 73 points.

Each of the regions in Southeastern New Mexico (Regions I, II and III) was ranked

for the prospects of shale gas. Regions were assigned a score of 68, 66 and 48 respec-

tively, and results showed that Regions I and II have better reservoir properties for

shale gas. Finally, an assessment was made to quantify the volumes of oil and gas in-

place using Comer’s (2005) Hydrogen mass balance method. The estimated volumes

were 36 billion barrels of original oil in-place and 44.5 trillion cubic feet of original

gas in-place in comparison to 119 billion barrels of original oil in-place and 230 tril-

lion cubic feet of gas in-place in the Woodford Shale for the entire Permian Basin

(Texas & New Mexico) (Comer, 2008).

Uncertainty analysis is performed on the mass balance and volumetric calculations

along with the ranking of the most important parameters for each of the regions. This

helps in the hypothetical resource development in those areas. As a result, this as-

sessment confirms that Woodford Shale is a major unconventional source of both oil

and gas in New Mexico.

A new approach is defined as part of this work, called Shale Potential Interpretation

Network (SPIN) which is a Case-Based Reasoning (CBR) approach to define sweet

spots for hydrocarbon potential in a given region. The key parameters that are used

are average porosity, present day and original Total Organic Carbon (TOC), thick-

ness, Hydrogen Index (HI) and thermal maturity (Tmax).

The CD accompanying the work contains the calculation sheet of the hydrogen mass

balance in-place estimation, uncertainty calculations and an interactive GIS map that

were used in the Woodford play analysis.

iii

ACKNOWLEDGEMENTS

I would like to express my sincere appreciation and gratitude to my research advisors

Dr. Robert S. Balch, Ms. Martha Cather and my Department Chair, Dr. Thomas W.

Engler, for being my mentor throughout my studies.

I would like to thank my committee member Dr. J. Michael Kelly for reviewing my

work.

I would like to express my gratitude to Mr. Ronald F. Broadhead, author of “The

Woodford Shale in Southeastern New Mexico: Distribution and Source Rock Charac-

teristics” and staff member of New Mexico Bureau of Geology, for all his advice and

recommendations.

In particular, I would like to thank Dr. Randy Miller, from Core Labs, who offered the

short course on of Shale Gas Evaluation with the Ranking Scorecard for Shale Gas

reservoirs, and Dr. John Comer, from Indiana Geological Survey, who offered the re-

source estimation method for shales.

I would like to thank Dr. Robert Lee, Director of Petroleum Recovery Research Cen-

ter (PRRC), for motivating me throughout my Masters Program.

And finally, would thank Ms. Karen Balch, Ms. Heidi Guerra, Ms. Shaojie (Jenny)

Ma, and many more for extending their hospitality and kindness throughout my stay.

iv

TABLE OF CONTENTS

ABSTRACT .................................................................................................................... i

ACKNOWLEDGEMENTS ......................................................................................... iii

TABLE OF CONTENTS……………………………………………………………..iv

LIST OF FIGURES………………………………………………………………….vi

LIST OF TABLES……………………………………………………………………x

CHAPTER 1…………………………………………………………………………..1

INTRODUCTION AND LITERATURE REVIEW………………………………….1

CHAPTER 2………………………………………………………………………….19

BACKGROUND…………………………………………………………………….19

CHAPTER 3…………………………………………………………………………43

METHODOLGIES USED AND CORRESPONDING UNCERTAINTIES……….43

CHAPTER 4…………………………………………………………………………82

RESULTS……………………………………………………………………………82

CHAPTER 5…………………………………………………………………………87

DISCUSSION……………………………………………………………………….87

CHAPTER 6………………………………………………………………………...95

CONCLUSIONS……………………………………………………………………95

CHAPTER 7………………………………………………………………………..98

v

FUTURE WORK……………………………………………………………………97

REFERENCES………………………………………………………………………98

APPENDIX – A…………………………………………………………………….106

APPENDIX – B…………………………………………………………………….107

APPENDIX – C…………………………………………………………………….119

vi

List of Figures

Figure 1-1 Major subdivisions and boundaries of the Permian Basin in

west Texas and southeast New Mexico (Dutton et al., 2005)

………...2

Figure 1-2 Combustion of Oil Shale (Wiki/Shale_oil)

...............5

Figure 1-3 World Shale Gas Resource Map (EIA, 2010)

…………6

Figure 1-4 Resources vs. Reserves Classification Diagram based on the

geologic certainty and economic viability (USGS 2008:

NAOG Fact sheet)

…………7

Figure 1-5 Resource Classifications (Modified from Devon, 2008)

…………8

Figure 1-6 North American shale gas reservoirs [NEB, 2009].

..………10

Figure 1-7 Barnett Shale Region Map with Thermal Maturity Regions

(Devon, 2008).

..………11

Figure 1-8 Thermal Maturity Regions in Eagle Ford (oil window in

Green, wet gas window in orange and dry gas window in the

red) (Drilling Info, 2010)

..………13

Figure 1-9 Bakken Regional Units (Transform, 2011)

..………15

Figure 1-10 Woodford Shale Depositional Unit (XTO 9 Energy, New

York – Analyst Conference, 2009)

…………17

Figure 2-1 Study Area showing the geological boundary of Permian Ba-

sin in West Texas & Southeast New Mexico with the surface

contours of Woodford Shale. (Bammidi et al., 2011)

..………20

Figure 2-2 Oil & Gas reservoirs in Delaware Basin shown with the strat-

igraphic column (Broadhead, 2005)

..………21

Figure 2-3 Oil & gas reservoirs in northwest shelf and central basin plat-

form with the stratigraphic unit (Broadhead, 2005)

..………21

Figure 2-4 Paleogeography of the Permian Basin at the beginning of the

late Devonian Age: 385 Ma (Comer, 2008)

..………22

Figure 2-5 Paleogeography of the Permian Basin during the Age: 360

Ma (Comer, 2008)

..………23

Figure 2-6 Detailed Stratigraphic column for the Devonian Age Wood-

ford Shale (Ellison, 1950; Meyer and Barrick, 2000; Broad-

head, 2010)

..………24

Figure 2-7 Detailed Geological Characteristics of the Woodford Shale

(Comer, 2008)

..………25

vii

Figure 2-8

(a)

Northwestern Shelf Humble No.1, A.E.State, Lea County,

New Mexico, 16-15S-33E (Comer 1991)

..………28

Figure 2-8

(b)


New Mexico, 16-15S-33E (Comer, 1991)

..………28

Figure 2-8

(c)


New Mexico, 16-15S-33E (Comer, 1991)

..………29

Figure 2-9 Humble No.1 Federal Elliott, Lea County, New Mexico, 1-

16S-34E (Comer, 1991)

..………29

Figure 2-10 Shell No.1, Champeau Federal, Chaves County, New Mexico,

31-15S-30E (Comer, 1991)

..………30

Figure 2-11

(a)

Shell No.5 Pacific Royalty, Lea County, New Mexico, 10-

15S-37E (Comer, 1991)

..………30

Figure 2-11

(b)

Shell No.5 Pacific Royalty, Lea County, New Mexico, 10-

15S-37E (Comer, 1991)

..………31

Figure 2-12 Logs characteristics of Woodford in Texas and New Mexico

(Reference log from Ellison 1950) Source: Comer (1991)

..………32

Figure 2-13 Log A: Odessa Natural Gasoline Co. No.1 Federal Dooley,

Sec.24 T20S R29E (Source: Broadhead 2010)

..………33

Figure 2-14 Log B: Penwell Energy No.1 Federal 14 Sec. 14 T20S R35E

(Broadhead, 2010)

..………34

Figure 2-15 Log C: Jake L. Hamon No. 1 Lynch Sec.17 T20S R35E

(Source: Broadhead 2010)

..………34

Figure 2-16 Log D: Gladiola Woodford oil pool (discovery well)

..………35

Figure 2-17 Isopach Map of the true thickness of Woodford Shale in

Southeast New Mexico (Broadhead, 2010)

..………37

Figure 2-18 Mineralogy of the Woodford Shale (Mnich, 2009)

..………38

Figure 2-19 Cross Plot of Young’s Modulus (E) versus Poisson’s Ratio

(v) (Nicholas et al., 2011)

..………40

Figure 2-20 Regions classified in southeast New Mexico based on the

thermal maturity (%), TOC (wt%) and the fracture network

intensity (Comer, 2005; Broadhead, 2010; Bammidi, 2011).

..………41

Figure 2-21 Structural Map of the Woodford Shale in New Mexico

..………42

Figure 3-1 Heim’s idea of stress at depth in the deeper Earth’s crust

(1878) (Zang et al., 2010)

..………46

Figure 3-2 Uncertainties involved in the ranking Region I with the Best

and Worst Case scenario of scores for the top 5 parameters on

a scale of 20 each for a total of 100 points.

..………52

viii

Figure 3-3 Uncertainties involved in the ranking Region II with the Best



..………53

Figure 3-4 Uncertainties involved in the ranking Region III with the Best



..………53

Figure 3-5 Uncertainties associated with the OOIP calculation in Region

I

..………65


II

..………66


III

..………67

Figure 3-7 Classification of Shale Plays into Shallow, Medium Depth,

Deep Play and Extreme Deep play based on the Depth ranges

of the Shale reservoirs.

..………70

Figure 3-8 Total Organic Carbon (TOC) composition (Nyahay, R., et al.,

2007)

..………71

Figure 3-9 Rock-Eval or SR Analyzer (Nyahay et al., 2007)

..………….72

Figure 3-10 Rock-Analysis terminology (Nyahay et al., 2007)

..………….72

Figure 3-11 TOC with the changing maturation (Nyahay et al., 2007)

..………….73

Figure 3-12 Shale Potential Interpretation Network (SPIN) workflow

..………….76

Figure 3-13

(a)

Potential regions for Oil &Gas in Southeast New Mexico with

the Contours of (TOCo-TOCpd)* Thickness displayed in

black and the Cored Wells in purple dots.

..………….78

Figure 3-13

(b)

Potential regions for Oil &Gas in southeast New Mexico with

the Contours of (TOCo-TOCpd)* Thickness] in black and the

Cored Wells in black dots.

..………….79

Figure 3-14 Workflow for High Potential based on the (TOCo –

TOCpd)*Thickness *Porosity.

..……….....80

Figure 3-15 Workflow for Medium Potential based on the (TOCo –

TOCpd)*Thickness *Porosity.

..……….....81

Figure 3-16 Workflow for Low Potential & Bad Potential based on the

(TOCo – TOCpd)*Thickness *Porosity.

..…………82

Figure 5-1 Existing 1100 Wells (approx) that have an Up-hole Potential

(Wristen, Fusselman, Simpson & Ellenburger).

..…………86

Figure 5-2 Existing 108 Wells (approx) have Down-hole Potential (Mis-

sissippian)

..…………87

ix

Figure 5-3 High Potential Oil & Gas regions with all the wells that have

both Up-hole and Down-hole Potential.

..…………88

Figure 5-4 Special Area – Secretary’s Potash Area with the 5 mile buffer

overlying the Woodford’s high potential oil and gas regions.

..…………89

Figure 5-5 Southeast New Mexico with the classified high oil & gas re-

gions

..…………90

Figure 5-6 Optimum resource development plan for downsizing in Hori-

zontal Wells (Newfield 2008)

..…………91

Figure B-1 Image of the interactive GIS maps for Woodford Shale in

New Mexico

..………..108

x

List of Tables

Table 1-1 Reservoir Profile for Barnett Shale (Transform, 2011)

..………11

Table 1-2 Reservoir Profile for Eagle Ford Shale (Transform, 2011)

..………13

Table 1-3 Reservoir Profile for Bakken Shale (Transform, 2011)

..………15

Table 1-4 Summary of the main parameter in comparison to the Woodford

Shale of New Mexico

..………18

Table 2-1 Sources of Core and Outcrop Data to determine the Source Rock

Characteristics (Bammidi et. al., 2011)

..………26

Table 3-1 Set of Parameters and their range of scores assigned (Modified:

Miller 2010)

..………43

Table 3-2 Summary of the ranking for the Regions based on the Miller’s

gas shale scorecard with all the ten parameters and their sources

..………50

Table 3-3 Summary of the best case ranking and worst case ranking for the

Regions based on the Modified Miller’s gas shale scorecard with

only Top five parameters and their sources

..………51

Table 3-4 Data used for calculating Reservoir Mass

..………56

Table 3-5 Data from the Organic Fraction used for the Assessment

..………56

Table 3-6 Whole rock data used in the Assessment

..………58

Table 3-7 Initial mass distribution

..………59

Table 3-8 Distribution of Hydrogen Mass Estimated

..………60

Table 3-9 Estimated Volumes of Generated, Expelled & Original In-Place

Oil & Gas

..………60

Table 3-10 Comparison of Volumes of Original In-Place Oil & Gas to Com-

er’s [2005] Assessment

..………62

Table 3-11 Uncertainty associated with the Mass and Volumetric Calcula-

tions of the Original Oil In-Place, Comer’s [2005] Assessment

..………63

Table 3-12 Core data available for the Woodford Shale in New Mexico. Out-

liers have been omitted from this table.

..………77

Table 4-1 Ranking Score Card of the Woodford Shale of New Mexico

..………83

Table 4-2 Comparison of Volumes of Original In-Place Oil & Gas to Com-

er’s (2005) Assessment

..………84

1

CHAPTER 1

Introduction and Literature Review

1.1 INTRODUCTION

Shales (mudstones) have historically been of interest to the petroleum industry be-

cause they form seals or source rocks. It is only within the last decade, largely due to

advances in drilling and stimulation techniques, that mudstones have been seriously

regarded as reservoirs for oil and gas. The shale-as-reservoir story began in 1820,

when a gas well was first drilled into the Devonian Fredonia Shale in New York State.

Relatively minor volumes of gas were produced from mudstones (e.g., the New Alba-

ny, Antrim and Lewis Shales) over the next 180 years. Furthermore, oil shales have

been mined since prehistoric times and continue to be used for power generation and

other purposes in some parts of the globe. However, it was only in the late 1990’s,

when Mitchell Energy demonstrated the ability to consistently drill commercial gas

wells in Barnett Shale, that the petroleum industry really took note of shales as a re-

source. Since about 2000, when the Barnett play started production, the United States

has seen several other important shale plays develop including the Marcellus,

Haynesville and Eagle Ford shales. Furthermore, with relatively robust prices for oil,

some operators are choosing to focus on parts of shale plays (generally less thermally

mature than gas-prone areas) where the production of petroleum fluids from mud-

stones is the primary economic interest (Hart et al., 2011).

The Permian Basin is a sedimentary basin largely contained in the western part of

Texas and the Southeastern part of New Mexico. It reaches from just south

of Lubbock, Texas, to just south of Midland and Odessa, extending westward into the

Southeastern part of the adjacent state of New Mexico. It is so named because it has

http://en.wikipedia.org/wiki/Sedimentary_basin

http://en.wikipedia.org/wiki/Texas

http://en.wikipedia.org/wiki/New_Mexico

http://en.wikipedia.org/wiki/Lubbock,_Texas

http://en.wikipedia.org/wiki/Midland,_Texas

http://en.wikipedia.org/wiki/Odessa,_Texas

http://en.wikipedia.org/wiki/New_Mexico

2

one of the world's thickest deposits of rocks from the Permian geologic period. The

greater Permian Basin is comprised of several component basins; of these, the Mid-

land Basin is the largest, the Delaware Basin is the second largest, and the

Marfa Basin is the smallest. The Permian Basin encompasses an area approximately

250 miles wide and 300 miles long (Figure 1-1).

Figure 1-1 Major subdivisions and boundaries of the Permian Basin in west Texas

and southeast New Mexico (Dutton et al., 2005)

1.2 OBJECTIVE AND APPROACH

The work described in this thesis was performed in conjunction with a contract from

the U.S. Bureau of Land Management, Pecos District, to aid in estimation of oil and

http://en.wikipedia.org/wiki/Rock_(geology)

http://en.wikipedia.org/wiki/Permian

http://en.wikipedia.org/wiki/Geologic_period

http://en.wikipedia.org/w/index.php?title=Midland_Basin&action=edit&redlink=1

http://en.wikipedia.org/w/index.php?title=Midland_Basin&action=edit&redlink=1

http://en.wikipedia.org/wiki/Delaware_Basin

http://en.wikipedia.org/wiki/Marfa,_Texas

3

gas development potential in Southeastern New Mexico for the next 20 years. The

objective of the work is to estimate a reasonable development of production, particu-

larly on federal lands managed by the U.S. Bureau of Land Management (BLM).

The Pecos district covers the bulk of the Permian Basin in New Mexico, and contains

numerous oil and gas reservoirs. Producing oil and gas fields of the region were di-

vided into 27 plays, based upon similarities such as depositional environment, litholo-

gy, tectonic history, and trapping mechanisms. The primary focus of this thesis was

on the evaluation of the resource potential of one of those plays, the Woodford Shale

in New Mexico.

The approach relied heavily on previous work of others, including source rock charac-

teristics from Broadhead (2010), a resource evaluation methodology given by Comer

(2008), and ranking the regions in New Mexico using the gas shale scorecard for po-

tential using the method of Miller (2010).The present study arrives at several inde-

pendent conclusions.

1.3 DEFINITIONS

Reasonable Foreseeable Development Scenario

Brister et al. (2005) defined the Reasonable Foreseeable Development Scenario

(RFDS) as “a planning tool used by Bureau of Land Management to provide a reason-

able estimate of what oil and gas exploration and development activities could rea-

sonably be expected should a decision be made to lease an area. Under this scenario,

the RFDS projects what activities might be conducted by a mineral lessee under cur-

rent and reasonably foreseeable regulatory conditions and industry interest. The

RFDS is a 20-year forward-looking estimation of oil and gas exploration and devel-

4

opment that is exclusive of other concerns that might compete for use of land in a

multiple-use scenario. As such, it is information about one resource, with a projection

of that resource as developed in a reasonable foreseeable manner.”

Rock Nomenclature

Source rock-associated resources have important similarities and equally important

differences. The confusion in nomenclature that identifies these resources is an on-

going issue with operators, technology developers, and policy makers. We need to

understand the definitions of gas shale, oil shale, and oil bearing shale in order to bet-

ter define those potential and existing resources.

Shale

Shale is a fine-grained sedimentary rock, which is easily broken into thin, parallel

layers. It is a very soft rock, but it does not disintegrate when it becomes wet. Reser-

voirs largely contain a mixture of shale, clay, and lime formations with ultra-low

permeability making production economically challenging.

Oil Shales vs. Shale Oil

Oil shale is an inorganic rock that contains a solid organic compound known as kero-

gen. Oil shales are “younger” in geologic age than crude oil-bearing formations; natu-

ral forces of pressure and temperature have not yet converted the kerogen to crude oil.

Organic matter in oil shale includes the remains of algae, spores, pollen, plant cuticle

and corky fragments of herbaceous and woody plants, and other cellular remains of

lacustrine, marine, and land plants. These materials are composed chiefly of carbon,

hydrogen, oxygen, nitrogen, and sulphur. Worldwide, there are nearly ten trillion bar-

5

rels of shale oil resource. These resources are located in North America, South Amer-

ican, Europe, Middle East, North Africa, Asia, and Australia (Biglarbigi et al., 2009).

Figure 1-2 Combustion of Oil Shale (Wiki/Shale_oil)

Shale oil or kerogen oil (Wiki/Shale_oil) is unconventional oil produced from oil

shale by pyrolysis, hydrogenation, or thermal dissolution (Figure 1-2). These process-

es convert the organic matter within the rock (kerogen) into synthetic oil and gas. The

resulting oil can be used immediately as a fuel or upgraded to meet refinery feedstock

specifications by adding hydrogen and removing impurities such as sulfur and nitro-

gen. The refined products can be used for the same purposes as those derived from

crude oil.

Gas Shales

Gas shales (Figure 1-3) contain natural gas, usually found where two thick, black

shale deposits ‘sandwich’ a thinner layer of shale. Shale gas resources form within the

organic-rich shale source rock. The low permeability of the shale greatly inhibits the

gas from migrating to more permeable reservoir rocks. Shale formations, in these cas-

es, act as both a source of gas and as its reservoir. Natural gas is stored in shale in

three forms: free gas in rock pores, free gas in natural fractures, and adsorbed gas on

6

organic matter and mineral surfaces. These different storage mechanisms affect the

speed and efficiency of gas production.

Figure 1-3 World Shale Gas Resource Map (EIA, 2010)

Figure 1-3 shows the World Shale Gas Resources republished from an initial assess-

ment of 14 regions outside of the United States by the Energy Information Admin-

istration (EIA, 2010). In total, the report assessed 48 shale gas basins in 32 countries,

containing almost 70 shale gas formations. Red colored areas represent the location

of assessed shale gas basins for which estimates of the ‘risked’ gas-in-place and tech-

nically recoverable resources were provided. Yellow colored area represents the loca-

tion of shale gas basins that were reviewed, but for which estimates were not

provided, mainly due to the lack of data necessary to conduct the assessment. White

colored countries are those for which at least one shale gas basin was considered.

Gray colored countries are those for which no shale gas basins were considered. It is

likely that shale gas resources will increase as they are better understood, and as data

from more countries is collected.

http://www.eia.doe.gov/analysis/studies/worldshalegas/pdf/fullreport.pdf

http://www.eia.doe.gov/analysis/studies/worldshalegas/pdf/fullreport.pdf

7

Resources Classification

Resource classification is very important to understand how the petroleum industry

assesses and quantifies the major driver of value for exploration and production com-

panies – oil and natural gas reserves and resources.

Petroleum Resources are defined as the total quantities of discovered (including hy-

drocarbon produced already from known accumulations) and undiscovered petroleum

at a specific date in a given area (Figure 1-4).

Figure 1-4 Resources vs. Reserves Classification Diagram based on the geologic certain-

ty and economic viability (USGS 2008: NAOG Fact sheet)

The classification of reserves and resources based on the geological and commercial

risk versus the increasing technical certainty is shown in Figure 1-5.

8

Figure 1-5 Resource Classifications (Modified from Devon, 2008)

Prospective Resources

Devon (2008) defines prospective resources as, “The estimated quantities of hydro-

carbons to be potentially recoverable from undiscovered accumulations. Mostly these

are “Exploration Prospects.””

Contingent Resources

Devon (2008) defines contingent resources as, “The estimated quantities of hydrocar-

bons to be potentially recoverable from known accumulations by application of de-

velopment projects, but not currently considered to be commercially recoverable due

to one or more contingencies. Mostly these are “Discovered, Subject to Conditions.””

Possible Resources

Devon (2008) defines possible resources as, “Additional estimated quantities of hy-

drocarbons that analysis of geoscience and engineering data indicate are less likely to

be recovered than probable resources.”

9

Probable Resources

Devon (2008) defines probable resources as, “Additional estimated quantities of hy-

drocarbons that analysis of geoscience and engineering data indicate are less likely to

be recovered than proved reserves but more certain to be recovered than possible re-

sources.”

Proved Reserves

Devon (2008) defines proved resources as, “The estimated quantities of hydrocarbons

that geological and engineering data demonstrate with reasonable certainty to be re-

coverable in future years from known reservoirs under existing economic and operat-

ing conditions.”

1.4 WOODFORD ANALOG SHALES IN THE UNITED STATES

It is useful to examine analogs to the Woodford shale to help reduce the learning

curve for understanding this particular play. A map of North America shale gas reser-

voirs with basins and fairways was published by the National Energy Board of Cana-

da in 2009 (Figure 1-6), with the circled plays as the analogues. The rest of this

chapter includes brief summaries of the geology and reservoir characteristics of ana-

logue shales through figures and tables, and ultimately a comparison of all the analogs

with the Woodford Shale of New Mexico.

10

Figure 1-6 North American shale gas reservoirs [NEB, 2009]. Circled in black are the

plays that are considered to be New Mexico Woodford Analogs in this study. From

North to South the Plays are the Bakken, Oklahoma Woodford, Barnett, and Eagle

Ford

Barnett – Fort Worth Basin

The Barnett Shale in the Fort Worth Basin is a Mississippian aged siliceous mudstone

spread over an area of 50,000 square miles (Figure 1-7). The Barnett Shale is the

source, reservoir and trap for the hydrocarbons. The permeability averages approxi-

mately 250 nanodarcies and the reservoir needs to be artificially fractured in order to

produce gas. The average depth of the play is around 7,500 ft with an average thick-

ness of 300 ft. The key reservoir properties are gathered and summarized to give a

better understanding of the resource potential of the play (Table 1-1). Average well

production reaches 2.65 bcf, with initial production rates of up to 13 mmcf per day.

Also worth noting is that vitrinite reflectance averages 2% in the Barnett Shale play,

but drops to the "oil window" in the northern basin (Figure 1-7).

11

Figure 1-7 Barnett Shale Region Map with Thermal Maturity Regions (Devon, 2008).

Barnett thermal maturity trends from the oil window in the west, through the conden-

sate gas window and into the Dry gas window in the east.

Table 1-1 Reservoir Profile for Barnett Shale (Transform, 2011)

Age: Mississippian, 340 MYA

Lithology: Siliceous Mudstone

Total Area Size (sq mi): 50,000

Total Gas (tcf): 327

GIP (bcf/sq mi): 150

Producable Gas (tcf): 50

Depth (feet): 7,500

Thickness (feet): 300

Horizontal Well Cost [$Million]: 2.8

Average EUR: 2.65

Pressure (psi): 4,000

Temperature (F): 200

Ro: 2

TOC (%): 4.5

12

Porosity (%): 6

Matrix Permeability (nD): 250

Pressure Gradient (psi/ft): .526

Clay Content (%): 45

Silica/Calcite/Carbonate (%): 55

Adsorbed Gas (%): 35

The Barnett Shale has geochemical characteristics similar to other Devonian-

Mississippian black shales found elsewhere in the U. S. like the Woodford Shale. The

Barnett is an analog because its total organic content, vitrinite reflectance, and

pressure gradient fall in the range of Woodford Shale in New Mexico. Some of the

attributes from Table 1-1 are used, in part to derive the characteristics as summarized

in Table 1-4 at the end of this chapter. The Barnett is exceptionally well understood in

comparison to other shales due to improvements of drilling, completions practices,

stimulation designs, and knowledge gain over time.

Eagle Ford – South Texas (Shale Oil & Gas Play)

The Eagle Ford is one of the newest shale reservoir plays and spreads over 1350

square miles in south Texas (Figure 1-8), and is of Cretaceous Age (100 MYA). The

permeability averages approximately 1100 nanodarcies and the reservoir needs to be

artificially fractured in order to produce gas. The average depth of the play is around

11,500 ft with an average thickness of 250 ft. The key reservoir properties are gath-

ered and summarized to give a better understanding of the resource potential of the

play (Table 1-2). Individual wells are expected to produce 5.5 bcf. At the time of this

writing, the Eagle Ford play is still in the initial stages of play development.

13

Figure 1-8 Thermal Maturity Regions in Eagle Ford (oil window in Green, wet gas win-

dow in orange and dry gas window in the red) (Drilling Info, 2010)

Table 1-2 Reservoir Profile for Eagle Ford (Transform, 2011)

Geologic Age: Cretaceous, 100 MYA

Lithology: Bituminous Shales


Total Gas (tcf): 84

GIP (bcf/sq mi): 200

Producable Gas (tcf): 9

Avg. Well Depth (feet): 11,500


Horizontal Well Cost ($M): 4.8

Average EUR: 5.5



Ro: 1.5

TOC (%): 4.5

Porosity (%): 11

Matrix Permeability (nD): 1,100

Pressure Gradient (psi/ft): 0.65

Clay Content (%): 8


Adsorbed Gas (%): 20

Average IP: 6.2

http://www.transformsw.com/media/transform_media/shale/eagle ford/Eagle Ford Map.JPG

14

The Eagle Ford is an analog since it is both an oil and gas play. The depth and

thickness ranges are similar to that of the Woodford Shale in the oil, dry gas, and wet

gas regions. While the Eagle Ford Shale play is still relatively new, the latest updates

from the play can be applied to that of the Woodford Shale in New Mexico. From

Table 1-2 average depth, thickness, vitrinite reflectance and total organic carbon are

the attributes that are used, in part to estimate potential of the Woodford Shale. These

characteristics are summarized in Table 1-4 at the end of this chapter.

Bakken - Williston Basin (Shale Oil Play)

The Mississippian/Devonian Bakken Formation is predominantly a low-permeability

oil reservoir with associated gas, spanning North Dakota, Montana and the Canadian

provinces of Saskatchewan and Manitoba (Figure 1-9). The formation is typically 150

feet thick, at depths of nearly 10,000 feet, with porosities of approximately 7% and

permeabilities of about 75 microdarcies. On average, wells are projected to produce

500,000 total barrels of oil. Horizontal wells are multi-stage completions and are es-

sential for economic production in the Bakken.

15

Figure 1-9 Bakken Regional Units (Transform, 2011)

Table 1-3 Reservoir Profile for Bakken Shale (Transform, 2011)

Age: Upper Devonian/Lower Mississippian, 360 MYA

Lithology: Sandstone/Siltstone/Carbonate


Total Gas (tcf): 945.1

GIP (bcf/sq mi): 28.3

Producable Gas (tcf): 20.66

Avg. Well Depth (feet): 10,000


Horizontal Well Cost ($M): 5.5

Average EUR: 1.41



Ro: 0.9

TOC (%): 10

Porosity (%): 5

Matrix Permeability (nD): 10,000

Pressure Gradient (psi/ft): 0.5

Clay Content (%): 5


Adsorbed Gas (%): 0

http://www.transformsw.com/media/transform_media/shale/bakken/Bakken Map.JPG

16

The Bakken Formation is an analog since it is liquid rich. The depth and thickness

ranges are similar to that of the Woodford Shale in the oil and wet gas regions in New

Mexico. The Upper Bakken is highly fractured, whereas the Woodford Shale, in the

deeper parts of the central basin platform is primarily wet gas. From Table 1-3

average depth, thickness, vitrinite reflectance and total organic carbon are the

attributes that are used, in part, to estimate potential of the Woodford Shale. These

characteristics are summarized in Table 1-4 at the end of this chapter.

Woodford Shale– Southeastern Oklahoma (Oil & Gas Play)

The Oklahoma Woodford Shale is an attractive target for unconventional oil and gas

development because it is a mature source rock that is widely distributed throughout

the southern midcontinent, and because it locally produces oil and gas from naturally

fractured intervals in conventionally completed wells. In addition, drilled intervals

yield oil shows from cuttings and cores, and produce a gas response on mudlogs, con-

firming that the Woodford Shale contains anomalously high oil and gas. Finally, the

Woodford play that has developed in Oklahoma (279 wells drilled from 2004 to 2007

with cumulative production of nearly 64 Bcf gas and 66,538 bbl oil/condensate) con-

firms the commercial viability of the Woodford and provides incentive for additional

exploration and development (Comer, 2008). The Woodford Play, as a whole, will be

discussed in great detail in Chapter 2.

17

Figure 1-10 Woodford Shale Depositional Unit (XTO 9 Energy, New York – Analyst

Conference, 2009)

The Woodford Shale in Oklahoma is the closest available analog to the Woodford

Shale in the Permian Basin, due to concurrent depostion and similar geochemical

characteristics. Some of the key paramters that were not available in the cores of the

Woodford Shale in New Mexico, were derived from the Oklahoma Woodford Shale.

These characteristics are shown in Table 1-4.

Summary:

The major parameters that help in considering these shales as analogues are their

depth range, thickness, % Quartz and Clay, TOC, vitrinite reflectance, porosity, brit-

tleness and pressure gradient. These parameters are used when there is no data availa-

ble for the Woodford Shale in New Mexico. A comparison is done, as shown in Table

1-4, to summarize the similarities and differences between the Woodford Shale of

New Mexico and rest of the analogues.

18

Table 1-4: Summary of the main parameter in comparison to the Woodford Shale of

New Mexico

Shale

Play

Depth

(ft)

Thickness Quartz Clay TOC Ro Phi Brittleness Pressure

Gradient

Barnett 6000-

9000

300-500 40-60 10-

30

3-8 1.2-

2.0

3-9 High 0.5-0.6

Eagle

Ford

6000-

14000

50-300 5-20 15-

25

2-6 1.0-

1.6

6-

14

Moderate 0.5-0.7

Bakken 8000-

10000

150 NA NA 8-10 0.6-

0.9

5 NA 0.5

Woodford

Oklahoma

6000-

14000

100-220 NA NA 3-10 1.1-

3.0

3-

6.5

NA 0.65

Woodford

New

Mexico

7000-

18000

0-350 30-45 45-

60

1.8-

6.8

0.6-

2.0

NA Moderate 0.6-0.7

Most of the important parameters like the TOC and vitrinite reflectance have useful

similarities.

19

CHAPTER 2

Background

2.1 UNCONVENTIONAL RESOURCES – PERMIAN BASIN

The Permian Basin is an oil and gas producing region located in West Texas and the

adjoining area of Southeastern New Mexico. The Permian Basin covers an area ap-

proximately 250 miles wide and 300 miles long and includes various counties of Tex-

as, and four counties in New Mexico. The Permian Basin consists of about 1,339

reservoirs having individual cumulative production >1 MMbbl (1.59 × 105 m3) as of

2000. As part of a previous study (Dutton et al., 2005), thirty-two Permian Basin oil

plays were defined, and each of the 1,339 significant-sized reservoirs were assigned to

a play. Approximately 300 of these reservoirs are in the New Mexico part of the Per-

mian Basin (Broadhead, 2004). For the purpose of the current work with the RFDS,

additional gas plays, along with some unconventional plays, were defined for the New

Mexico portion of the basin.

2.2 CASE STUDY: WOODFORD SHALE

Information concerning the Woodford Shale reservoir was mapped and compiled in a

Geographic Information System (GIS) and is available in the attached CD. Figure 2-1

shows study area with the structural tops in the form of contours along with the

boundaries of the states and the Permian Basin.

20

Figure 2-1 Study Area showing the geological boundary of Permian Basin in West Texas

& Southeast New Mexico with the surface contours of Woodford Shale. (Bammidi et al.,

2011)

History of Permian Basin of New Mexico

In 1924, the Flynn, Welch, Yates State No. 3 well opened the first commercial oilfield

in Southeast New Mexico (Lang, 1935). The Jal and Hobbs fields in Lea County were

discovered in 1927 and 1928, respectively, and the Permian Basin of Southeastern

New Mexico has continuously produced since then. Figure 2-2 shows the oil and gas

reservoirs present above and below the Woodford Shale in the Central Basin Platform

and the Northwest shelf. .Figure 2-3 shows the oil and gas reservoirs present above

and below the Woodford Shale in the Delaware Basin.

Study Area

21

Figure 2-2 Oil & Gas reservoirs in the Delaware Basin shown with the Stratigraphic

column (Broadhead, 2005)

Figure 2-3 Oil & gas reservoirs in northwest shelf and central basin platform with the

stratigraphic unit (Broadhead, 2005)

Definitions to understand the Depositional Environments

Coastal Upwelling:

Coastal Upwelling is an oceanographic phenomenon that involves wind-driven mo-

tion of dense, cooler, and usually nutrient-rich water towards the ocean surface, re-

placing the warmer, usually nutrient-depleted surface water. The increased

availability in upwelling regions results in high levels of primary productivity.

http://en.wikipedia.org/wiki/Physical_oceanography

http://en.wikipedia.org/wiki/Wind

http://en.wikipedia.org/wiki/Nutrient

http://en.wikipedia.org/wiki/Ocean

http://en.wikipedia.org/wiki/Primary_productivity

22

Epeiric Sea:

An epeiric sea (also known as an epicontinental sea) is a shallow sea that extends over

part of a continent.

Craton:

A craton (Greek: κράτος kratos "strength") is an old and stable part of the continental

lithosphere. Having often survived cycles of merging and rifting of continents, cratons

are generally found in the interiors of tectonic plates.

2.3 DEPOSITIONAL ENVIRONMENT OF WOODFORD SHALE

Figure 2-4 Paleogeography of the Permian Basin at the beginning of the late Devonian

Age: 385 Ma (Comer, 2008)

http://en.wikipedia.org/wiki/Sea

http://en.wikipedia.org/wiki/Continent

http://en.wikipedia.org/wiki/Greek_language

http://en.wikipedia.org/wiki/Continental_lithosphere

http://en.wikipedia.org/wiki/Continental_lithosphere

23

Paleogeography of Permian Basin at the beginning of the Late Devonian (Frasnian) is

shown in Figure 2-4 and Figure 2-5. Comer (2008) stated that “prior to the beginning

of the Late Devonian epoch much of the Southern Midcontinent was subaerially ex-

posed, and this extensively eroded and dissected landscape became a major regional

unconformity surface. A worldwide Late Devonian marine transgression flooded the

craton, creating an extensive epeiric sea that covered all but a few isolated areas dur-

ing highstand. Thick accumulations of biogenic silica document persistent coastal

upwelling along the Late Devonian continental margin, while sand dispersed south-

ward toward the subsiding Anadarko Basin from Ordovician sandstone exposures

flanking the Ozark Uplift and silt dispersed southward from shoals and emergent parts

of the Transcontinental Arch onto the Delaware and Midland Basins.”

Figure 2-5 Paleogeography of the Permian Basin during the Age: 360 Ma (Comer, 2008)

24

2.4 GEOLOGY OF THE WOODFORD SHALE

Southeastern New Mexico has a wide variety of potential unconventional reservoir

rocks, including black shales, black cherts, sandstones, siltstones, and lighter-colored

shales (Comer, 1991). Black shale is dominant in most places. The Woodford Shale of

the Permian Basin is Late Devonian in age (Figure 2-6). In the Permian Basin, the

Woodford overlays Silurian and Lower Devonian carbonate strata of the Wristen

Group and is in turn overlain by Lower Mississippian limestone. Both the Wristen and

Thirtyone carbonates have been a good source for oil and gas in New Mexico.

Figure 2-6 Detailed Stratigraphic column for the Devonian Age Woodford Shale (El-

lison, 1950; Meyer and Barrick, 2000; Broadhead, 2010)

The Woodford is identified primarily by high radioactivity on the gamma-ray log and

by its stratigraphic position between carbonates, as shown in Figure 2-7.

The Woodford shows low sonic velocity, low resistivity and low neutron-induced ra-

diation on the logs. Three subdivisions are commonly recognized in the Woodford,

and can be correlated regionally based on well log signatures. These subdivisions

have been named the lower, middle, and upper units (Ellison, 1950, Broadhead,

2010]. The lower unit immediately overlays the regional unconformity, has the lowest

radioactivity, and contains more carbonate, silt and sand than the other two units. The

middle unit has the highest radioactivity, is the most widespread lithofacies, and con-

25

sists of black shale with high concentrations of organic carbon, abundant pyrite, res-

inous spores and parallel laminae. The upper unit has intermediate radioactivity and

consists of black shale with few resinous spores and mostly parallel laminae.

Figure 2-7 Detailed Geological Characteristics of the Woodford Shale (Comer, 2008.

Representative GR and Electric logs help define the lithologies in the center column.)

2.5 WOODFORD SOURCE ROCK CHARACTERISTICS

Source rocks that contain the highest concentrations of organic hydrogen generate the

most hydrocarbons. These are typically beds of lacustrine and marine origin that con-

tain Type I and Type II kerogen and generate both oil and gas during thermal matura-

tion. Comer (2008) stated that “oil-to-rock correlation studies documents

the Woodford Shale as a prolific oil source, and estimates indicate that as much as

85% of the oil produced in Central and Southern Oklahoma originated in

the Woodford. The Woodford Shale contains high concentrations of marine organic

26

matter, with mean organic carbon concentrations of 4.9 percent weight for the Permi-

an Basin (Texas and New Mexico), 5.7 percent weight for the Anadarko Basin (Okla-

homa and Arkansas), and 5.2 percent weight for both regions combined. Organic

carbon concentrations range from less than 0.1 percent weight in some chert beds and

15 to 35 percent weight in black shale, and the organic matter is mostly oil-prone

Type II kerogen. Across the region, the Woodford Shale exhibits a wide range of

thermal maturities from marginally immature to metamorphic (Ro = 0.37-4.89 %).”

Broadhead (2010) states that the Woodford shales are black organic-rich shales that

are generally a hydrocarbon source facies. Present day Total Organic Carbon (TOC)

ranges from 1.7 to 4.9 wt % in comparison to original pre-maturation TOC ranging

from 1.8 to 6.8%. Both the original and present TOCs are greatest in southern Lea

County and decrease to the north and west in southeast New Mexico.

The kerogen fraction is dominated by amorphous and herbaceous type shales. Woody

and inertinitic types are prevalent to the north, closer to the Woodford pinch out.

Thermal maturity is greatest in Southwestern Lea and Southeastern Eddy counties,

with a thermogenic gas and condensate window and thermal maturity is lower to the

north and west with an oil window. Table 2-1 lists all the 23 cored wells and the four

outcrops that were collected to analyze the Woodford Shales source rock characteris-

tics.

Table 2-1 Sources of Core and Outcrop Data to determine the Source Rock Characteris-

tics (Bammidi et. al., 2011)

Sample ID Operator

Location [S-

T-R]

Sample Interval

[feet] Source

Core 1 Ralph Lowe 24-18S-32E 14600-14700 NMBGMR

Core 1 Ralph Lowe 24-18S-32E 14600-14700 NMBGMR

Core 2 Stanolind Oil&Gas Co. 29-17S-28E 11060-11070 NMBGMR

Core 3 T.P. Coal & The Pure Oil Co. 28-18S-36E 12030-12130 NMBGMR

Core 4 Southland Royalty Co. 20-25S-35E 18330-18430 NMBGMR

Core 5 Standard of Texas 10-16S-31E 13070-13090 NMBGMR

Core 5 Standard of Texas 10-16S-31E 13090-13120 NMBGMR

27

Core 5 Standard of Texas 10-16S-31E Average NMBGMR

Core 6 Phillips Petroleum 23-17S-33E 14970-15010 NMBGMR



Core 6 Phillips Petroleum 23-17S-33E Average NMBGMR

Core 7 Pure Oil Co. 32-25S-33E 17300-17330 NMBGMR

Core 8 Amerada Pet. Co. 02-12S-33E 10695-10750 NMBGMR

Core 9 The Ohio Oil Co. 20-08S-37E 12000-12080 NMBGMR

Core 10 Pan American Pet. Corp. 13-09S-30E 10600-10690 NMBGMR

Core 11 Continental Oil Co. 01-25S-36E 10100-10200 NMBGMR

Core 12 T.P. Coal & Oil Co. 12-14S-37E 13000-13100 NMBGMR

Core 13 E.P. Operating Co. 09-13S-29E 9400-9490 NMBGMR

Core 14 Delta Drlg. Co. 05-24S-25E 11600-11700 NMBGMR

Core 15 Richardson & Bass 27-22S-30E 15400-15500 NMBGMR

Core 16 Maralo, Inc. 34-20S-27E 11760-11800 NMBGMR

Core 17 Yates Pet. 21-26S-27E 13520-13620 NMBGMR

Core 18 Shell Oil Co. 04-22S-34E 14330-14430 NMBGMR

Core 19 Pan American Pet. Corp. 12-14S-34E 14780-14820 NMBGMR

Core 20 Humble 16-15S-33E 13754-13768 ComerRI



Core 20 Humble 16-15S-33E 13850 ComerRI

Core 21 Shell 31-15S-30E 10914 ComerRI

Core 21 Shell 31-15S-30E 10928 ComerRI

Core 22 Shell 10-15S-37E NA ComerRI

Core 23 Humble 01-16S-34E 14638 ComerRI

Outcrop 1 Bishop Cap 25-24S-03E NA ComerRI

Outcrop 2

Antony Gap, Northern Frank-

lin Mts 34-26S-04E NA ComerRI

Outcrop 3 Gulf 28-19S-18E NA ComerRI

Outcrop 4

Alamo Canyon, Sacramento

Mts 02-17S-10E NA ComerRI

Examples of some the core samples that were analyzed in Comer (1991) are presented

below to highlight the various types of shales in the Woodford. The various types of

shale have different rock characteristics and behavior; understanding the distribution

of these shale types would be highly beneficial to a better understanding of the play.

The following figures show core samples and SEM images demonstrating the variety

of types of shales that can be found in Southeast New Mexico.

0500

0

T

28

Figure 2-8 (a), Northwestern Shelf Humble No.1, A.E.State, Lea County, New Mexico,

16-15S-33E (Comer 1991)

Figure 2-8 (a), shows a well core sample from the Northwestern Shelf Humble No. 1,

A.E. State in Lea County, New Mexico. The core was taken from a depth of 13,768 ft,

and has a mean TOC of 1.6 wt%. The core shows stacked siltstone-shale couplets

with dolomite-dominated siltstone laminate are fine-grained Bouma sequences. They

document episodic deposition from mud-dominated turbid bottom flows. Silt is a sub-

equal mixture of dolomite, quartz, and pyrite.

Figure 2-8 (b), Northwestern Shelf Humble No.1, A.E.State, Lea County, New Mexico,

16-15S-33E (Comer, 1991)

Figure 2-8 (b) shows a well core sample from a depth of 13,771 ft with a TOC of 2.3

wt%. The sample is from a very thick dolomite-dominated siltstone bed. It contains

small-scale climbing ripples cross-laminae and grades into silty shale at the top.

29

Figure 2-8 (c), Northwestern Shelf Humble No.1, A.E.State, Lea County, New Mexico,

16-15S-33E (Comer, 1991)

Figure 2-8 (c) from Comer (1991) shows a well core sample from depth of 13,754 ft

with a TOC of 4.7 wt% and a vitrinite reflectance of 1.44%. This sample contains

numerous shattered trilobite fragments in silty black shale.

Figure 2-9 Humble No.1 Federal Elliott, Lea County, New Mexico, 1-16S-34E (Comer,

1991)

Figure 2-9 shows a core sample from a depth of 14,638 ft. In this sample, the dolo-

mite to quartz ratio is 40/1, and it is a fine-grained dolomite grainstone with contorted

laminae record flow shear during rapid deposition in a turbid bottom flow.

30

Figure 2-10 Shell No.1, Champeau Federal, Chaves County, New Mexico, 31-15S-30E

(Comer, 1991)

Figure 2-10 shows a core sample from a depth of 10,914 ft with a TOC of 5.0 wt%

and vitrinite reflectance of 1.03% where it is disrupted parallel siltstone laminae in

black shale and disrupted areas are burrows (B).

From the same well at a different depth of 10,928 ft, Figure 2-11(a) shows a silty

black shale bedding surface with scattered shiny coarse silt-sized mica flakes. Silt

fraction at this location is sub-arkosic. The composition and texture indicate deposi-

tion near an exposed terrigenous sediment source.

Figure 2-11 (a) Shell No.5 Pacific Royalty, Lea County, New Mexico, 10-15S-37E (Com-

er, 1991)

31

Figure 2-11 (b) Shell No.5 Pacific Royalty, Lea County, New Mexico, 10-15S-37E (Com-

er, 1991)

Figure 2-11 (b) shows a sample from a depth of 12,228 ft with the TOC is 3.2 wt%

and the vitrinite reflectance is about 0.92% where it is black shale with parallel lami-

nae, scattered silt, and burrows. Burrows are filled with secondary quartz (white), py-

rite (black), and patchy remnants of anhydrite (red).

2.6 LOG CHARACTERISTICS

Well logs of the Woodford Shale in Southeastern New Mexico were gathered by

Broadhead (2010) to show the classifications within the Woodford. Log A (Figure 2-

13) is from a well with the pre-Woodford shale, Log B (Figure 2-14) is from a well

where the pre-Woodford shale is not present, and Log C (Figure 2-15) indicates El-

lison’s (1950) three subdivisions of the Woodford Shale in the Permian Basin. The

three stratigraphic subdivisions are based on log patterns:Upper Woodford, Middle

Woodford and Lower Woodford, as shown in the log C (Figure 1-15). The Lower and

Upper Woodford are recognized by gamma-ray values that display high amplitude

32

fluctuations over scales of 3-10 m, whereas the Middle Woodford displays consistent-

ly high gamma-ray values, commonly in the range of 400-800 API units.

Figure 2-12 Logs characteristics of Woodford in Texas and New Mexico (Reference log

from Ellison 1950) Source: Comer (1991)

Upper Woodford (Figure 2-12) is missing and Middle Woodford is truncated in the

Lea County, New Mexico, and Cochran County, Texas, with well logs indicating that

there was a period of uplift and erosion before the Mississippian Limestone was de-

posited. In the Midland County, Texas, well, the Lower Woodford is missing due to

onlap over the Central Basin Platform.

33

Figure 2-13 Log A: Odessa Natural Gasoline Co. No.1 Federal Dooley, Sec.24 T20S

R29E (Source: Broadhead 2010)

34

Figure 2-14 Log B: Penwell Energy No.1 Federal 14 Sec. 14 T20S R35E (Broadhead,

2010)

Figure 2-15 Log C: Jake L. Hamon No. 1 Lynch Sec.17 T20S R35E (Source: Broad-

head 2010)

35

Figure 2-16 Log D: Gladiola Woodford oil pool (discovery well)

Figure 2-16 shows the log D of the productive well in the Gladiola Woodford oil pool,

indicating casing perforations within the Woodford. The Gladiola Woodford oil pool

is the only oil and gas pool productive from Woodford Shale in Southeastern New

Mexico. The Gladiola Woodford pool is a one-well oil pool located in section 5, T12S

R38E, Lea County. The discovery well was the Platinum Exploration No. 2 Angel,

36

which was originally drilled in 1957 as the Ralph Lowe No. 2 Aztec Adamson. The

original well was completed as an oil well in the Wristen (Silurian) carbonates over an

open-hole interval from 11,992 to 12,030 ft. In 1977, the Wristen reservoir was aban-

doned, and the well was plugged back to a depth of 9,640 ft and completed in

Wolfcamp (Lower Permian) carbonates through perforations from 9,475 to 9,561 ft.

In 2004, the Wolfcamp zone was abandoned, and the perforations were squeezed off.

The well was subsequently recompleted in the uppermost 10 ft of the Woodford Shale

through perforations from 11,920 to 11,930 ft (Figure 2-16). Initial production was

150 BOPD, 25 MCFGD, and 4,000 BWPD. Production commenced in December

2004, and continued until November 2006. Cumulative production from the Wood-

ford was 9,322 BO, 3,062 MCFG, and 435,625 BW.

Broadhead (2010) mapped the Woodford shale as a single unit. Thickness data uncor-

rected for structural dip were obtained from well logs. Consequently, an isopach map

(Figure 2-17) was prepared by eliminating wells where apparent thickness is more

than 300 ft.

37

Figure 2-17 Isopach Map of the true thickness of Woodford Shale in Southeast

New Mexico (Broadhead, 2010)

2.7 MINERALOGY AND CHEMISTRY

Mnich (2009) studied Woodford core from a well in the Texas part of the Permian

Basin to understand the mineralogy and chemistry. His work found that the “organic

rich mudstone is largely composed (Figure 2-18) of quartz, clay (primarily illite), or-

ganic matter, and pyrite. In samples with less than 10% dolomite (i.e., not containing

a discrete carbonate bed), quartz content ranges from 41 to 90% (average 66%), clay

from 3 to 40% (average 19%), feldspar from 0 to 10% (average 4.6%), and apatite

from 0 to 19% (average 1%).”

38

Figure 2-18 Mineralogy of the Woodford Shale (Mnich, 2009)

39

The mineralogy shows clear variation at a formation scale (Figure 2-18). Clay content

within the mudstone decreases systematically upward through the Woodford section,

from values of 20 to 40% in the Lower Woodford to 3-20 % in the Upper Woodford.

Quartz content varies from 41 to 65% in the Lower Woodford to 60-81% in the Upper

Woodford.

2.8 MECHANICAL ANISOTROPY

The rock mechanical properties of shales are critical to how they perform as reser-

voirs, determining both their tendency to develop natural fractures and their response

to hydraulic stimulation. These mechanical properties are, in turn, manifestations of

composition, fabric and porosity, fluid saturations. Such properties also dictate the

seismic response of shales, as well as their signature on many well logs. It has long

been recognized, or perhaps assumed, that shales are relatively homogeneous in the

plane parallel to bedding and relatively heterogeneous in the direction perpendicular

to bedding (Nicholas et al., 2011).

Young’s modulus (E) and Poisson’s ratio (v) determine rock brittleness and, there-

fore, the rock’s response to hydraulic fracturing (Rickman et al., 2008). These proper-

ties for the Woodford Shale, are calculated from density, Vp and Vs logs (Aoudia,

2009). The Poisson’s ratio measurements are derived from the dipole sonic log. It is

evident in the mechanical properties and the Vs, Vp, and bulk density logs that there

is a high degree of vertical anisotropy at several scales. Poisson’s ratio, in particular,

exhibits variation at the formation scale, high in the Lower Woodford, decreasing

56% to a minimum at 3908 m (12,821 ft) near the Middle Woodford –Upper Wood-

ford contact, then increasing above that to 78% of the maximum value.

40

Mentioned in the work of Harris, B. N., et al., (2011) is the following: “Rickman et al.

(2008) suggested that formations with high Young’s modulus and low Poisson’s ratio

are more brittle, whereas those with low Young’s modulus and high Poisson’s ratio

are more ductile. This type of behavior is important in hydraulic fracture stimulation

where brittleness is an indication of ability to not to initiate and place a hydraulic frac-

ture but also maintain its long-term conductivity. Figure 2-19 shows the Young’s

Modulus versus Poisson’s ratio measurements for the entire Woodford section, sepa-

rated into the Upper, Middle & Lower sections. As can be seen in Figure 2-19, the

Upper Woodford exhibits more brittle behavior, whereas Middle and Lower Wood-

ford are more ductile. This is primarily associated with variation in Poisson’s ratio.”

Figure 2-19 Cross Plot of Young’s Modulus (E) versus Poisson’s Ratio (v) (Nicholas et

al., 2011)

This brittle behavior was confirmed through hydraulic fracture computer modeling

(Harris et al., 2011) which showed preferential fracture growth in the Upper and

Lower section of the Woodford zones.

41

2.9 CLASSIFICATION INTO REGIONS

Southeast New Mexico is divided into three regions (Figure 2-20) based on a combi-

nation of reservoir parameters. Region I is thermally mature and is categorized into

early oil to oil generation window, and has high TOC and high fracture intensity. Re-

gion II is thermally mature and categorised into a wet gas, dry gas & condensate gen-

eration window, with moderate TOC and sparely fractured. Finally, Region III is

thermally mature and categorized into oil window, with reasonable TOC and mostly

local fractures.

Figure 2-20 Regions classified in southeast New Mexico based on the thermal maturity

(%), TOC(wt%) and the fracture network intensity (Comer, 2005; Broadhead, 2010;

Bammidi, 2011). Black dots are the Cored Wells and Gray Regions are where Woodford

is absent

42

Figure 2-21 Structural Map of the Woodford Shale in New Mexico

The structural contours of Woodford Shale are overlaid the regions that were classi-

fied (Figure 2-21). These contours were extracted from the Dutton’s (2005) GIS data.

It also shows that the oil window is mostly in the shallower parts of the basin and the

dry gas and wet gas window are in the deeper parts of the basin.

43

CHAPTER 3

Methodologies Used and Corresponding Uncertainties

3.1 MILLER’S SHALE GAS RANKING

Miller(2010) formulated a shale gas ranking scale that was used in this thesis to rank

the Woodford in New Mexico.

3.1.1 Parameters used for Ranking

The gas shale scorecard used geochemical parameters (total organic carbon, vitrinite

reflectance, clay content and quartz content), geo-mechanical parameters (natural

fracture intensity, tectonic stress and reservoir pressure gradient) and field develop-

ment parameters (shale thickness, gas-filled porosity and fluid compatibility).

3.1.2 Scale of each parameter

All ten parameters used in this score-card are equally weighted on a scale of 1-10.

Table 3-1: Set of Parameters and their range of scores assigned (Modified: Mil-

ler 2010)

1. Total Organic Carbon [TOC]

Range of Values < 1.0 1-3 3-6 6-9 >9

Assigned Score 0 4 6 8 10

2. Vitrinite Reflectance [Ro]

Range of Values < 0.5 0.5-1.0 1.0-1.5 1.5-2.0 > 2.0


3. Shale Thickness

Range of Values < 50 50-100 100-200 200-300 > 300


4. Gas-Filled porosity [Ave]

Range of Values < 2 2-4 4-6 6-8 >8


5. Clay content [wt %]

Range of Values > 60 45-60 30-45 15-30 < 15


6. Quartz content [wt %]

Range of Values < 15 15-30 30-45 45-60 > 60


44

7. Fluid compatibility [Fresh Water; CST ratio]

Range of Values > 4 3-4 2-3 1-2 < 1


8. Natural Fracture Intensity [per 10 feet]

Range of Values < 1 1-3 4-6 7-9 > 9


9. Tectonic stress [σ2 versus σ3]

Range of Values σ2>>σ3 σ2>σ3 σ2=σ3

Assigned Score 3 6 10

10. Reservoir pressure gradient [psi/ft]

Range of Values < 0.4 0.4-0.5 0.5-0.6 0.6-0.7 > 0.7


3.1.3 Importance of each parameter

Total Organic Carbon (TOC)

Total organic carbon and Rock-Eval are the two most common analyses performed on

rock samples to access various bulk geochemical characteristics. These techniques

were first used to access the source potential and thermal maturity of cuttings, core

and outcrop samples as an initial screening step. It is now common to evaluate poten-

tial reservoir rocks with regards to access to the oil content and oil quality by predic-

tion of API gravity.

The data should be considered as the initial assessment of source or reservoir rock

samples. Detailed analysis is required to confirm data quality and interpretations of

these results. Data, quality, and interpretation can be adversely affected by mud con-

tamination, analytical artifacts, and poorly calibrated instruments.

Total organic carbon (TOC) for the Woodford Shale consists of data points spanning

a range of 1.7 wt % to 4.93 wt % from Broadhead (2010). The average TOC in Re-

gion I from three cored wells ranges between 6-9 wt%, and was assigned a rank of 8

from Miller’s ranking. The average TOC in Region II from seven cored wells ranges

between 3-6 wt% and was assigned a rank of 6 from Miller’s ranking. Finally the av-

45

erage TOC in Region III from nine cored wells ranges between 1-3 wt% and was as-

signed a rank of 4 from Miller’s ranking.

Range of Values < 1.0 1-3 3-6 6-9 >9


Ro – Vitrinite Reflectance

Vitrinite reflectance (VF) is used for determining the thermal maturity of the shale.

Vitrinite reflectance (McFarland, 2010) is sensitive to temperatures that correlate

to hydrocarbon generation (60 to 120 degrees C). Generally, onset of oil generation

in an oil-prone shale is a VF of 0.6% and a VF of >1.35%, while the onset of genera-

tion in a gas-prone shale is a VF of 0.8% and a VF of >2%.

Vitrinite reflectance for the Woodford Shale consists of data points spanning a range

of 0.55 to 2.02 % from Comer (2005). Miller (2010) gives a higher rank for dry gas

generation with higher Ro values. The average vitrinite reflectance in Region I from

three cored wells ranges between 1-1.5 %. These results assigned a rank of 6 from

Miller’s ranking. The average vitrinite reflectance in Region II from seven cored

wells ranges between 1.5-2.0 %, resulting in a rank of 8 from Miller’s ranking. Lastly,

the average vitrinite reflectance in Region III from nine cored wells ranges between

0.5-1.0%, hence the rank of 4 from Miller’s ranking.

Range of Values < 0.5 0.5-1.0 1.0-1.5 1.5-2.0 > 2.0


Natural Fractures Intensity (per 10 ft)

Although these do not contribute to the permeability of the reservoir, they are im-

portant planes of weakness that tend to be reactivated by hydraulically induced frac-

46

tures. All natural fractures, including small sealed fractures and large potentially open

fractures, must be taken into account when predicting hydraulic fracture behavior.

Natural fracture intensity is defined as the number of fractures per foot for a given

length of rock. Natural fracture intensity for the Woodford ranges from 4 to 9 (per 10

ft) from Comer (1991) and Vulgamore et al. (2007). The average natural fracture in-

tensity per 10 ft (Comer, 1991 and Vulgamore et al., 2007) shows that the Woodford

Shale in Region I had higher density of fractures, earning this region a ranking of 8

Miller’s ranking. Natural fracture intensity in Regions II and III were not specifically

defined, but it was stated that they are less dense. The results led to ranks of 6 and 6

for both regions.

Range of Values < 1 1-3 4-6 7-9 > 9


Tectonic Stresses (σ2 versus σ3)

The rule of Heim (1878) is demonstrated by a shift in principal, as shown in Figure 3-

1.

Figure 3-1 Heim’s idea of stress at depth in the deeper Earth’s crust (1878) (Zang et al.,

2010)

47

The vertical stress is maximum and the two other stresses are smaller in magnitude

near the surface of the Earth to a lithostatic state of stress where all the principal

stresses are equal in magnitude at greater depth in the earth’s crust.

Region I and Region II are in the deeper parts of the basin and the tectonic stresses

would be ranked higher 10 each. However, in Region III, the tectonic stresses are as-

sumed to be almost same. So, a rank of 6 was assigned.

Range of Values σ2>>σ3 σ2>σ3 σ2=σ3

Assigned Score 3 6 10

Reservoir Pressure gradient (psi/ft)

The pressure gradients gives further understanding regarding the complexity in the

reservoir. The fluid densities can be interpreted from the formation pressure gradient.

Reservoir pressure gradient for the Woodford Shale ranges from 0.4 to 0.7 psi/ft from

Lee & Williams (2000).

The average pressure gradient in Region I and II in the deeper parts of the basins is

around .65 psi/ft from Lee & Williams’ work. This resulted in a rank 8 for both re-

gions from Miller’s ranking. The average pressure gradient in Region III from Lee’s

work is .55 psi/ft and results in a rank of 6 from Miller’s ranking.

Range of Values < 0.4 0.4-0.5 0.5-0.6 0.6-0.7 > 0.7


Clay and Quartz content (wt %)

Mineralogy plays an important role in determining the permeability of shales. In Pathi

(2008), higher permeability was observed in samples with high clay content, and low

48

permeability was observed in samples with high quartz and carbonate content. The

largest anisotropy was found in the clay-rich samples. Clay-rich shales also have a

well developed fabric with a strongly preferred orientation, while the quartz-rich

shales had random orientation of the fabric. Samples with higher clay content (>30%)

showed a higher intrusion volume in macro pores, while samples with higher quartz

content showed intrusion volume in micro pores. Clay content for the Woodford

Shale consists of data points spanning a range of 45 wt % to 60 wt % from Ruppel, S.

& Loucks, R., (2007) and Jarvie, D., (2008).

The average clay content across the Woodford Shale in the Permian Basin is around

50%. A rank of 4 from Miller’s ranking was given to all three regions.

Range of Values > 60 45-60 30-45 15-30 < 15


The average quartz content across the Permian basin from the core samples that were

tested by Ruppel (2007) and Jarvie (2008) ranges about 30 to 45 wt%. With a rank of

6 from Miller’s ranking, Miller (2010) gives higher rank for higher quartz content.

Range of Values < 15 15-30 30-45 45-60 > 60


Shale Thickness (ft)

Net thickness is a key parameter in shale reservoirs. Miller (2010) gives a higher rank

for thicker reservoirs. Shale thickness for the Woodford Shale ranges from zero to 300

ft (Broadhead, 2010).

49

Broadhead’s (2010) isopach map was used for determining an average thickness in

each region. In the deeper parts of the basin in Region I, the average thickness is 200

ft. The result was a rank of 8 from Miller’s ranking. The average thickness in Region

II is 150 ft. This resulted in a rank of 6 from Miller’s ranking. The average thickness

in Region III is 50 ft, which gives it a ranking of 4 from Miller’s ranking. A study

summary assigned a score of 8, 6 and 4 for Region I, Region II and Region III respec-

tively.

Range of Values < 50 50-100 100-200 200-300 > 300


Gas-filled Porosity (Average %)

The gas filled porosity is measured on the crushed sidewall sample. A formation in

which the pore space is filled by gas instead of liquid hydrocarbons would contribute

to this parameter. It can be estimated the formation is an oil or gas type reservoir. Mil-

ler (2010) gives a higher rank for higher gas-filled porosity reservoirs.

Gas filled porosity for the Woodford Shale consists of data points spanning a range of

less than 2 % to 8 % (Comer, 2005). Since Region I and Region II are in the wet gas

window and thermogenic gas window respectively, Region II is assigned a higher

score. In Region III, where it is mostly oil generation window, the expected gas filled

porosity is ranked lower. The study assigned a score of 6, 8 and 4 for Region I, Re-

gion II and Region III respectively.

Range of Values < 2 2-4 4-6 6-8 >8


50

Fluid Compatibility (with Fresh Water)

This parameter is very important for fracturing and completion of the formations.

There are no known fluid compatibility tests with fresh water for the Woodford Shale

in New Mexico, so the Barnett shale in the Permian basin was used as an analog to

provide data points. As a result, a value of 2-3 CST ratios (Miller, 2010) is used and

gives a higher rank for lower CST ratios. This study assigned a score of 6, 6 and 6 for

Region I, Region II and Region III respectively.

Range of Values > 4 3-4 2-3 1-2 < 1


In this section, Miller’s (2010) ranking method was applied to each of the three sub-

regions in the New Mexico Woodford shale. The assigned scores are listed in Table

3-2, with total scores at the bottom.

Table 3-2: Summary of the ranking for the Regions based on the Miller’s gas shale

scorecard with all the ten parameters and their sources

Parameters

Ranking on the Shale Scale

Data Source Region

I

Region II Region

III

Total Organic Carbon [TOC] – wt

%

8 6 4 Broadhead [2010] &

ComerRI[2005]

Vitrinite Reflectance [Ro] - % 6 8 4 Broadhead [2010] &

ComerRI[2005]

Shale Thickness - ft 8 6 4 Broadhead [2010] &

Comer [2005]

Gas-Filled porosity [Ave] 6 8 4 S Ruppel & Robert

Loucks [2007]

Clay content [wt %] 4 4 4 S Ruppel & Robert

Loucks [2007]; Dan

Jarvie[2008]

Quartz content [wt %] 6 6 6 S Ruppel & Robert

51

3.1.2 SENSITIVITY ANALYSIS OF THE GAS SHALE SCORECARD

In this section, Miller’s [2010] ranking method to each of the three sub-regions in the

New Mexico Woodford shale was modifie. The most important parameters like the

TOC, vitrinite reflectance, shale thickness, clay and quartz content are ranked on a

scale of 20 each both for the best case and worst case scenarios. The assigned scores

are listed in Table 3-3, with total scores at the bottom.

Table 3-3: Summary of the best case ranking and worst case ranking for the Regions

based on the Modified Miller’s gas shale scorecard with only Top five parameters and

their sources

Loucks [2007]

Fluid compatibility [Fresh Water;

CST ratio]

4 4 4 Randall S.”Randy” Mil-

ler [2010]; Dan Jar-

vie[2008]

Natural Fracture Intensity [per 10

ft]

8 6 6 John B. Comer [1991]

Tectonic stress [σ2 versus σ3] 10 10 6 John B Comer [1991]

Reservoir pressure gradient

[psi/ft]

8 8 6 Randall S.”Randy” Mil-

ler [2010]

Total Score 68 66 48

Parameters

Ranking on the Shale Scale

Data Source Region

I

Region II Region

III

Total Organic Carbon [TOC] – wt

%

12 8 12 8 12

8 Broadhead [2010] &

ComerRI[2005]

Vitrinite Reflectance [Ro] - % 12 12 20 16 12 8 Broadhead [2010] &

ComerRI[2005]

Shale Thickness - ft 16 12 12 10 8 4 Broadhead [2010] &

Comer [2005]

Clay content [wt %] 8 8 8 8 8 8 S Ruppel & Robert

Loucks [2007]; Dan

Jarvie[2008]

52

Ranking of the three regions using only the top five important parameters based on

maximum values (best case) and minimum values (worst case) from the sources

available, show that Region II has better prospects of Shale Gas than Region I with all

ten of Miller’s parameters. The window of uncertainty is shown using spider diagrams

below (Figure 3-2, 3-3 and 3-4).

Figure 3-2 uncertainties involved in the ranking Region I with the Best and Worst Case

scenario of scores for the top 5 parameters on a scale of 20 each for a total of 100 points.

The window of uncertainty for this region is high for both TOC and Shale thickness.

0

5

10

15

20TOC

VitriniteReflectance

Shale ThicknessClay content

Quartz Content

Best Case Ranking

Worst Case Ranking

Quartz content [wt %] 12 12 12

12 12 12 S Ruppel & Robert

Loucks [2007]

Total Score 60 52 64 54 52 40

53

Figure 3-3 uncertainties involved in the ranking Region II with the Best and Worst Case

scenario of scores for the top 5 parameters on a scale of 20 each for a total of 100 points.

The window of uncertainty for this region is high for TOC, Vitrinite Reflectance and

Shale thickness.

Figure 3-4 uncertainties involved in the ranking Region III with the Best and Worst

Case scenario of scores for the top 5 parameters on a scale of 20 each for a total of 100

points. The window of uncertainty for this region is high for TOC, Vitrinite Reflectance

and Shale thickness.

0

5

10

15

20TOC



Quartz Content

Best Case Ranking

Worst Case Ranking

0

2

4

6

8

10

12TOC



Quartz Content

Best Case Ranking

Worst Case Ranking

54

3.2 JOHN COMER’S IN-PLACE RESOURCE ESTIMATION

3.2.1 Methodology Used

The previous Woodford resource potential estimated by Comer (2005) had less data

from the Permian basin of New Mexico and his Woodford analysis was based on the

Woodford in the Arkoma Basin in Oklahoma. This work is based on the methods and

many of the assumptions used by Comer and others, but utilized New Mexico specific

data, and focused on the Woodford characteristics in New Mexico.

3.2.2 Assumptions & Observations

The first assumption made by Comer (2005) was that oil and gas in the Woodford

Shale are indigenous. And because it is indigenous, conventional source rock data like

organic carbon, organic hydrogen, organic matter type, thermal maturity, along with

facies volumes (thickness times area) etc., can be used for in-place oil and gas estima-

tion. Some of his other assumptions were that hydrogen from inorganic sources such

as water and hydrogen mineral do not appear to result in an increase in hydrogen

available for hydrocarbon (HC) generation. Comer also assumed losses of hydrogen

from the organic fraction in the form of H20 and H2 molecules did not represent large

losses of organic hydrogen mass during the main stages of hydrocarbon generation.

And finally, the amount of hydrogen available for hydrocarbon generation is equiva-

lent to the amount of organic hydrogen present at the onset of the main stage of oil

generation.

Comer [2005] observed that thermal maturation of organic matter results in CH4 and

graphite carbon residue. Thus the volume of hydrogen generated is limited by the

amount of hydrogen available in the system. Also, large amounts of water are elimi-

nated from organic matter by reactions of H- and OH- bearing organic molecules be-

55

fore a source bed enters the oil window. All the organic data in his work represent

kerogen that has matured to or beyond the inflection point on the van Kervelen dia-

gram [Broadhead, 2010] for Type II kerogen between organic reactions predominant-

ly involving H20 and C02 elimination and those involving hydrocarbon generations.

With all of Comer’s assumptions and observations, the volume of evolved HCs is es-

timated using mass balance of organic hydrogen (Horg). The units being used are Met-

ric Tons (MT), kilometers (km), weight fraction (wt fraction), barrels (bbl), and cubic

feet (ft3).

For this study, the estimation of oil & gas potential began with gathering essential da-

ta (Table 3-4, Table 3-5, and Table 3-6) for the Woodford Shale of New Mexico. E.g.:

Reservoir Area (km2), Average Thickness (km), Reservoir Mass (MT), Mean organic

carbon concentration (%), mean organic hydrogen concentration (%) and bulk density

(MT/km3). Southeastern New Mexico has been categorised into 3 regions based on

thermal maturity, TOC and fracture intensity (Figure 2-20) As a result, estimation for

each region follows a similar methodology to Comer (2005) except that due to the

variation in thermal maturity, we needed to use various conversion factors.

3.2.3 STEPS INVOLVED

Step 1: Reservoir Mass Determination

Reservoir Mass [MT] = Thickness [km] x Area [km2] x Density [MT/km

3] Eq. (1)

Table 3-4 gives the reservoir thickness, area, volume, and mass for the Woodford

Shale of New Mexico. The areas of regions I, II and III were calculated using ArcGIS,

and the corrected Woodford thickness used is obtained from Broadhead (2010). The

mean density of Woodford shale is 2.4 x 109 MT/km

3 (Comer and Hinch, 1987; Com-

er, 2005).

56

Table 3-4: Data used for calculating Reservoir Mass

Woodford

Shale of

New Mexi-

co

Thickness

[km]

Area

[km2]

Volume

[km3]

Density

[MT/km3 x

109]

Mass

[MT x 109]

Region I 0.030 3331.12 99.93 2.4 239.84

Region II 0.043 5806.55 252.20 2.4 605.28

Region III 0.015 22200.21 341.04 2.4 818.49

Step 2: Gathering Organic Fraction Data from Core Samples

Organic fraction of the present day carbon and hydrogen are needed for this assess-

ment. Data is not available for the Permian Basin in the format that we need, so or-

ganic fraction from the analogous Woodford Shale of Oklahoma was used. The

average vitrinite reflectance data is used from the cores of New Mexico (Broadhead

2010). Table 3-6 has data of the organic fraction of carbon and hydrogen used in the

assessment for the Permian Basin [Comer, 2005]. These values were taken from the

analyses of isolated, solvent extracted kerogen in the two Woodford Shale cores with

the lowest thermal maturity; these cores were recovered from two wells in Oklahoma

[Comer, 1991 and 2005]. Each region has been assigned a certain value of Present and

Immature Corg (%), Horg (%), & vitrinite reflectance (Ro %) respectively.

Table 3-5: Data from the Organic Fraction used for the Assessment

Oklahoma Woodford analogous to New Mexico Woodford Shale

Woodford

Shale of

New Mex-

ico

Present

Corg

[%]

Immature

Corg [%]

Present

Horg

[%]

Immature

Horg

[%]

Present

Ro [%]

Immature

Ro [%]

Region I 82.00 82.20 7.72 7.74 0.55 0.39

Region II 90.50 82.20 4.38 7.74 2.02 0.39

Region III 85.60 82.20 6.08 7.74 1.09 0.39

57

Step 3: Converting the organic fraction from core sample to Whole rock.

Data from the Anadarko Basin was used for the analogous facies of the Woodford in

the Permian basin. Kerogen data are converted to whole rock data by recognizing that

the ratio of Corg to Horg in kerogen is the same as the ratio of Corg to Horg in whole rock

using the relationship as below.

[Corg/Horg] kerogen = [Corg/Horg] whole rock Eq. (2)

Step 4: Calculating the Total hydrocarbon mass Horg (MT) using wt fraction of the

whole rock

Initial Immature Horg MT is calculated by multiplying the immature Horg (%) (Table

3-6) and the Reservoir Mass (Table 3-4). Similarly the residual Horg MT is calculated

by multiplying the Present Horg (%) (Table 3-6) and the Reservoir Mass (Table 3-4).

Immature Horg Mass [MT] = Reservoir Mass [MT] x Immature Horg [wt fraction]

Eq. (3)

Residual Horg Mass [MT] = Res. Mass [MT] x Present Horg [wt fraction] Eq. (4)

And finally the Total mass of hydrocarbon Horg (MT) is the difference between the

Immature Horg (MT) and the Residual Horg (MT).

Total Organic Hydrogen Horg [MT] = Immature Horg – Residual Horg Eq. (5)

Table 3-6: Whole rock data used in the Assessment

Woodford

Shale of New

Mexico

Present

Corg

[%]

Immature

Corg [%]

Present

Horg [%]

Immature

Horg [%]

Region I 7.80 8.00 0.73 0.75

58

Region II 4.20 5.80 0.20 0.55

Region III 3.60 4.00 0.26 0.38

Step 5: Corg Mass Determination

Values for the immature Corg in Table 3-7 are derived from the mean organic carbon

concentration observed in each region adjusted using the mean organic carbon con-

centration in the two immature cores, the difference between the immature and ob-

served level of thermal maturity, and the degree of dilution by the clastic sediment.

Corg Mass [MT] = Reservoir Mass [MT] x Immature Corg [wt fraction] Eq. (6)

For example in Region I, the initial Corg mass of 19.71 x 109 (MT) is equal to the res-

ervoir mass of 239.84 x 109 (MT) times the mean Corg weight fraction of 0.0822 in

immature shale.

Step 6: Total Natural Gas Co-Generated (Gas MT):

The amount of natural gas co-generated with oil during thermal maturation of low to

moderate maturity marine black shale is estimated based on data from literature (Ta-

ble 3-6). For thermal maturities between 0.4 and 0.9% Ro, the saturated light hydro-

carbons content is more than two orders of magnitude, mostly in the range of 1x 10-4

MT/MT Corg to 1 x 10-2

MT/MT Corg [Schaefer and Leythaeuser, 1983; Comer, 2005].

For those regions where Woodford Shale is in the Oil Window, the total mass of natu-

ral gas is estimated using the initial mass of Corg in immature shale (Table 3-7) and the

published ratio where

[Oil Window] Gas [MT] = Gas [MT/MT Corg] x Corg [MT] Eq. (7)

Table 3-7: Initial mass distribution

59

Woodford

Shale of

New Mexi-

co

Corg

MT x 109

Gas

MT x 109

Hgas

MT x 109

Hoil

MT x 109

Region I 19.71 0.0020 0.00049 0.047

Region II 35.11 4.45 1.48295 0.635

Region III 32.74 0.33 0.00085 0.981

In Region I, the mean vitrinite reflectance of Woodford shale is 0.55% and by analogy

with Mesozoic marine black shale, the gas concentration is on the order of 1 x 10-4

MT/MT Corg [Comer, 2005]. Also for Region III, where the mean vitrinite reflectance

is 1.09% Ro, the gas concentration value of 1 x 10-2

MT/MT Corg [Comer, 2005] was

used. But for Region II, where there is a thermogenic gas generation (Ro % > 2), there

is no published ratio that can be used. So, the total natural gas co-generated in MT is

calculated using the total volume of Generated Gas (ft3) (from Step 9) divided by the

volume occupied by a metric ton of natural gas (5 x 104 ft

3/MT).

Step 7: Total mass of organic hydrogen that exits as natural gas (Hgas)

For Region I, the total mass of natural gas is determined by multiplying the total

amount of natural gas (MT) times the weight fraction of hydrogen (0.25 for methane).

In Region III, The total mass of organic hydrogen that exits as natural gas (Hgas) is

calculated by multiplying the resulting mass of gas by the weight fraction of Horg in

gas where

Hgas [MT] = Gas [MT] x Horg [wt fraction] Eq. [8]

For Region II, the process is a bit different. Hgas is determined as a difference of Total

Hydrocarbon Horg (MT) and Total mass of Hydrogen in oil Hoil (Step 8).

60

Step 8: Total mass of hydrogen contained in Crude Oil (Hoil)

For regions I & III, the total mass of hydrogen contained in Crude Oil (Hoil) is the dif-

ference between the total mass of Horg in Hydrocarbons (Table 3-7) and the mass of

hydrogen in gas (Hgas). But for Region II where the thermogenic gas exists a different

approach was used. The Total amount of oil (Eq. 9) generated (Table 3-8) which is

the total hydrocarbon Horg (MT) divided by 2 x 10-2

was calculated and if 30% of this

is expelled, the difference between total Hydrocarbon Horg and the Oil Expelled would

result in Hoil.

Hoil = [Total Hydrocarbon Horg – Oil Expelled] x 2 x 10-2

Eq. (9)

Table 3-8: Distribution of Hydrogen Mass Estimated

Woodford Shale

of New Mexico

Initial Immature

Horg MT x 109

Residual

Horg MT x 109

Total Hydro-

carbon

Horg MT x 109

Region I 1.80 1.75 0.048

Region II 3.33 1.21 2.12

Region III 3.11 2.13 0.98

Table 3-9: Estimated Volumes of Generated, Expelled & Original In-Place Oil & Gas

Generated Expelled Original In-Place

Woodford

Shale of

New Mexi-

co

Oil

MMbbl

Gas

BCF

Oil

MMbbl

Gas

BCF

Oil

MMbbl

Gas

BCF

Region I 2398.40 98.57 719.52 78.85 1678.88 19.71

Region II 105924.74 222441.96 31777.42 177953.56 0 44488.39

Region III 49109.44 2.55 14732.83 2.04 34376.61 0.51

Step 9: Volumes of Oil & Gas Generated and Expelled

61

The oil volume generated in Region I, Region II & Region III was calculated using

total hydrocarbon Horg (MT) and converting it into barrels using the conversion of 1

unit of hydrogen mass per barrel of crude oil as 2 x 10-2

MT/bbl. The resulting rela-

tionship is shown in Eq. 10. The oil volume expelled in Regions I, II & III was taken

as 30% of the oil volumes generated in each region after Comer and Hinch [1987] and

Comer [2005].

Oil Volume [bbl] = Hydrocarbon Horg [MT]/ 2.0 X10-2

[MT/bbl] Eq. (10)

The gas volume generated in Region I was calculated by dividing Hgas (total amount

of natural gas (MT) times the weight fraction of hydrogen (0.25 for methane) by the

mass of hydrogen per in a cubic foot of natural gas (5 x 10-6

MT/ft3). However, for

Region II & Region III, the gas volume is calculated by equations 10 & 11. The vol-

ume of gas produced by thermal cracking 1 barrel of crude oil is 3000 ft3/bbl [Comer,

2005]. The gas volume expelled in Regions I, II & III is 80% [Comer and Hinch,

1987; Comer, 2005] of the gas volumes generated in each region.

Gas Volume [ft3] = Oil Volume [bbl] x 3000 [ft

3/bbl] Eq. (11)

The final estimation of in-place oil & gas is achieved by calculating the difference

between the volumes generated and volumes expelled.

Note: For Region II where Woodford Shale is in the gas window, it is assumed that all

of the indigenous oil has cracked to gas [Comer 2005].

62

Table 3-10: Comparison of Volumes of Original In-Place Oil & Gas to Comer’s

[2005] Assessment

Original In-Place

[Woodford Shale - Study Ar-

ea]

Original In-Place

[Woodford Shale - Total

Permian basin]

Oil

Billion bbl

Gas

Trillion ft3

Oil

Billion bbl

Gas

Trillion ft3

Region I 1.68 0.019 35 .11

Region II 0 44.49 0 220

Region III 34.38 0.00051 84 9.0

Total 36.06 44.6 119 229.11

This assessment strongly indicates that the Woodford Shale has high in-place oil and

gas resources in New Mexico.

3.2.4 UNCERTAINTY ANALYSIS OF THE IN-PLACE CALCULATIONS

A simple method is presented here to analyze the uncertainties associated with the

mass calculation and also volumetric calculation. The method uses the most common

uncertainty information – “plus-minus” (“degree of uncertainty”). The outcomes are

(i) an average value with a “plus-minus” uncertainty, and (ii) a ranking of uncertainty

sources.

Procedure of uncertainty analysis

Step 1: The relative uncertainty of each component is

Vj = sj/mj

Step 2: The average of OOIP is the product of component averages,

mΩ = product of all the components

63

Step 3: The relative uncertainty of OOIP is the sum of squared relative uncertainties

of components,

V2

Ω = ƩV2

j

Step 4: The relative uncertainty associated with OOIP is

VΩ = (V2

Ω)1/2

Step 5: The degree of uncertainty associated with OOIP is

sΩ = VΩ x mΩ

Uncertainty of Original Oil In-place Estimation:

The objectives are to estimate Original Oil In-place and quantify the associated uncer-

tainty of the Woodford Shale in Region I, Region II and Region III; see Table 3-10.

The information available is an average value attached with a “plus-minus” value re-

flecting the degree of uncertainty. The ratio of the “plus-minus” and the average value

is referred here as relative uncertainty. The formula used for this assessment is pre-

sented below.

Estimated Original Oil In-place (bbls) = [Thickness (km) x Area (km2) x Density

(MT/km3) x (Immature Horg (wt fraction) - Present Horg (wt fraction)) x (1- wt frac-

tion of Oil Expelled)]/2 x 10-2(MT/bbl)

Table 3-11: Uncertainty associated with the Mass and Volumetric Calculations of

the Original Oil In-Place, Comer’s [2005] Assessment

Parameters Units Mean Value with Uncertainty

Region I Region II Region III

Thickness (km) 0.030+0.01 0.043+0.01 0.015+0.01

Area (km2) 3331.12+500 5806.55+500 22200.21+500

Density (MT/km3)x 2.4+.15 2.4+.15 2.4+.15

64

10-9

Immature Horg Fraction% 0.75+0.01 0.55+0.01 0.38+0.01

Present Horg fraction 0.73+0.01 0.20+0.01 0.26+0.01

1- wt fraction of

Oil Expelled

fraction 0.30+0.01 0.30+0.01 0.30+0.01

1/(2 x 10-2) bbl/MT 50 50 50

Figures 3-5, 3-6 and 3-7 presents step-by-step calculations following the above stated

procedure. In Figure 3-5, Original Oil In-Place (OOIP) for Region I is estimated to be

1.678 +0.956 x 109 bbls. The relative uncertainty associated with the above OOIP is

57%. This high uncertainty is contributed primarily by the percentage difference of

weight fraction of Immature Horg and Present Horg. In Figure 3-6, Original Oil In-

Place (OOIP) for Region I is estimated to be 73.41 + 15.75 x 109 bbls. The relative

uncertainty associated with the above OOIP is 21%. In this case, the uncertainty is

contributed primarily by the 1-percentage of weight fraction of oil expelled. Some

areas of uncertainty are contributed by the thickness and area. In Figure 3-7, Origi-

nal Oil In-Place (OOIP) for Region I is estimated to be 33.57 + 12.68 x 109 bbls. The

relative uncertainty associated with the above OOIP is 38%. In this case, the uncer-

tainty is contributed primarily by the 1 - percentage of weight fraction of oil expelled.

Again, some areas of uncertainty are contributed by the thickness and area.

65

Figure 3-5 Uncertainties associated with the OOIP calculation in Region I

66

Figure 3-6 Uncertainties associated with the OOIP calculation in Region II

67

Figure 3-7 Uncertainties associated with the OOIP calculation in Region III

68

Uncertainty of Original Gas In-place Estimation:

Based on Comer’s methodology of estimation for Gas In-place, the uncertainty is cal-

culated as very high. Lots of gas concentration values that were used in the assess-

ment are constants and there are no specific derivations or formulas behind them.

For example, in Region I, the mean vitrinite reflectance of Woodford shale is 0.55%

and by analogy with Mesozoic marine black shale, the gas concentration is on the or-

der of 1 x 10-4

MT/MT Corg (Comer, 2005). Also for Region III, where the mean vit-

rinite reflectance is 1.09% Ro, the gas concentration value of 1 x 10-2

MT/MT Corg

(Comer, 2005) was used. However in Region II, where there is a thermogenic gas

generation (Ro % > 2), there is no published ratio that can be used. So, the total natural

gas co-generated in MT is calculated using the total volume of generated gas (ft3) di-

vided by the volume occupied by a metric ton of natural gas (5 x 104 ft

3/MT).

As a whole the uncertainty with Comer’s assessment is evaluated very high for the

gas in-place calculations.

69

3.3 Vidya Bammidi’s SPIN – Shale Potential Interpretation Network

Shale Potential Interpretation Network is designed to derive a high-graded hydrocar-

bon potential map using total organic carbon, hydrogen index, vitrinite reflectance,

thickness and average porosity. The difference between the original total organic car-

bon and the present day total organic carbon, when multiplied by thickness and aver-

age porosity, would give a potential map with relative volumes of hydrocarbon

generated. In order to find the relative volumes of hydrocarbons, we use the relation-

ship derived by Jarvie (2007).

3.3.1 Classifications Shale Plays Based on Depths

Shale plays (Figure 3-7) that are shallower in depth, i.e. below 3,000 ft are not con-

sidered for interpretation in SPIN. Shale plays that fall into a depth range of 3,000 to

7,000 ft are called Shallow Plays, and these are lower, thermally mature plays result-

ing in oils and liquids. Shale plays that fall into a depth range of 7,000 to 10,000 feet

are named Medium Depth Plays; similarly shale plays that are in a depth range of

10,000 to 15,000 ft are called Deep Plays. The shale plays with a depth range of

15,000 to 20,000 ft are called Extreme Deep Plays and fall into the thermogenic gas

generation window. For example, Region II of the Woodford Shale, depth range

(10,000 to 15,000 ft) is classified as a Deep Shale Play. Four important parameters

will help to identify whether this play is in a High Potential, Medium Potential, Low

Potential or Poor Potential regions: total organic content, thermal maturity, thickness

and hydrogen index. The relation of these parameters is derived in the next section.

70

Figure 3-7 Classification of Shale Plays into Shallow, Medium Depth, Deep Play and Ex-

treme Deep play based on the Depth ranges of the Shale reservoirs. Depths below 3000 ft

are not considered for this study.

71

3.3.2 Key Parameters to be used to Identify Potential

Total Organic Carbon (TOC), hydrogen index (HI), thickness (net to gross) and ther-

mal maturity are the four key variables that vary based on different regions that are

analyzed along with the average porosity for the play. The relationship between these

parameters can be derived using Jarvie’s (2007) methodology of calculating original

total organic carbon from the present day total organic carbon. Figure 3-8 shows the

derivation of the relationship.

Derivation of TOC original from TOC present day:

Figure 3-8 Total Organic Carbon (TOC) composition (Nyahay, R., et al., 2007)

The TOC mainly consists of live carbon and dead carbon (Figure 3-8). The live car-

bon is subdivided into free oil and gas along with the organic matter (kerogen).

72

Figure 3-9 Rock-Eval or SR Analyzer (Nyahay et al., 2007)

During the Rock-Eval analysis the S1 which is the free volatile hydrocarbons thermal-

ly flushed from a rock sample at 300ο C (nominal) (in mg HC/g rock) is the first peak.

The S2 is comprised of products that crack during standard Rock-Eval pyrolysis tem-

peratures (300– 600 C (nominal)) (in mg HC/g rock). The temperature at peak evolu-

tion of S2 hydrocarbons (in C) is the Tmax.

Figure 3-10 Rock-Analysis terminology (Nyahay et al., 2007)

73

During the Rock-Eval analysis the free oil is categorized as S1 and remaining organic

matter as S2. Based on the thermal maturity, the S2 is falls into oil prone region or gas

prone region.

Figure 3-11 TOC with the changing maturation (Nyahay et al., 2007)

With increased maturation, the conversion of organic matter into dead carbon occurs,

which in turn produces oil & gas. In order to get a reliable Tmax, it is necessary that S2

> S1 and the value of S2 > 0.2. If S1 > S2 or S2 has lower values than 0.2, that means

that there is very little remaining live carbon.

Based on the data gathered or measured, the HI (hydrogen index) which is the remain-

ing potential (S2) divided by TOC X 100 (in mg HC/g TOC) is calculated.

PI (production index) is defined as the free oil content as measured by S1 only divid-

ed by the sum of S1 plus the remaining generation potential [S2] or S1/[S1 + S2]

(values from 0.00 to 1.00).

74

Transformation or conversion ratio (TRHI) is calculated from HIo and HIpd [see equa-

tion below]. HIo value can be computed from visual kerogen assessments and as-

signed kerogen-type HIo average values using the following equation (Jarvie, 2007):

This equation requires input of percentages from visual kerogen assessment of a

source rock. For example, using the Barnett Shale consisting of 95% type II and 5%

type III, the calculated HIo value is 434 mg HC/g TOC. At 100% type II, HIo would

be 450 mg HC/gTOC. These values are comparable to those measured on immature to

low-thermal-maturity Barnett Shale that ranged from 380 to 475 mg HC/g TOC. Us-

ing the equations of Claypool (Jarvie, 2007 and Peters et al., 2006), the fractional

conversion, i.e., the extent of organic matter conversion, can be determined. The frac-

tional conversion, TRHI, is derived from the change in HIo to present-day values

(HIpd) (Espitalie et al., 1984; Pelet, 1985 and Peters et al., 2006), where PI is the pro-

duction index [S1/[S1 + S2]] as PIo = 0.02 to PIpd [Peters et al., 2006]:

This incorporates the formula of Pelet (1985) for computing kerogen transformation

where 1200 is the maximum amount of hydrocarbons that could be formed assuming

83.33% carbon in hydrocarbons. The PI is a ratio of hydrocarbons already formed to

the total hydrocarbons (determined from the ratio of S1 to S1 + S2 from Rock-Eval

data; Espitalie et al., 1977), but the solution is not overly sensitive to these values.

Once values for HIo and TRHI are determined by calculation or by measurements from

75

low-maturity samples, TOCo can be calculated:

83.33 is the average carbon content in hydrocarbons and k is a correction factor based

on residual organic carbon being enriched in carbon over original values at high ma-

turity [Burnham, 1989]. For type II kerogen, the increase in residual carbon CR at

high maturity is assigned a value of 15% (whereas for type I, it is 50%, and for type

III, it is 0%) (Burnham, 1989). The correction factor, k, is then TRHI x CR.

This calculation is needed for the generation of our hydrocarbon potential maps.

3.3.3 HYDROCARBON POTENTIAL MAPS

The difference between TOCo (Original) and TOCpd (Present Day) multiplied by

thickness of the Woodford will be an indication of the relative volumes of hydrocar-

bons generated (Broadhead, 2010). Contouring these relative volumes of remaining

hydrocarbons would help us generate the potential regions. This is used to identify the

high potential regions of oil and gas. Figure 4-1 shows the sections that have high oil

potential in green and the red sections are for high dry gas potential along with blue

for the wet gas potential. A summary of the total workflow involved in generating

these maps is shown in Figure 3-12.

76

Figure 3-12 Shale Potential Interpretation Network (SPIN) workflow

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TOC, HI, Thickness & Thermal Maturity

Porosity

Hydrocarbon Potential Maps

77

3.3.4 Example using the SPIN to generate Hydrocarbon Potential Maps

Data available:

Table 3.12 Core data available for the Woodford Shale in New Mexico. Outliers have

been omitted from this table. (TOCo-TOCpd)xThickness values are used for drawing

the Potential Maps with the contours. Data source: Broadhead (2010)

Operator Location TOCpd TOCo Woodford thickness

(TOCo-TOCp)Thickness

Ralph Lowe 24-18S-32E 2.55 3.12 116 66.12

Stanolind Oil&Gas Co.

29-17S-28E 1.99 2.71 10 7.2

T.P. Coal & The Pure Oil Co.

28-18S-36E 4.16 5.68 167 253.84

Southland Roy-alty Co.

20-25S-35E 4.36 6.79 213 517.59

Standard of Tex-as

10-16S-31E 3.63 4.42 63 49.77

Phillips Petrole-um

23-17S-33E 2.94 3.94 146 146

Pure Oil Co. 32-25S-33E 3.09 4.23 160 182.4

Amerada Pet. Co.

02-12S-33E 1.73 1.88 30 4.5

The Ohio Oil Co. 20-08S-37E 1.7 1.77 95 6.65

Continental Oil Co.

01-25S-36E 4.93 6.61 275 462

T.P. Coal & Oil Co.

12-14S-37E 2.03 2.44 143 58.63

E.P. Operating Co.

09-13S-29E 1.79 2.03 17 4.08

Richardson & Bass

27-22S-30E 3.44 4.14 165 115.5

Maralo, Inc. 34-20S-27E 2.19 2.53 37 12.58

Yates Pet. 21-26S-27E 3.49 4.25 136 103.36

Pan American Pet. Corp.

12-14S-34E 2.41 2.85 52 22.88

The Woodford Shale of New Mexico can be categorized into Medium Deep Play,

Deep Play or Extreme Deep Play based on the depths from the cored wells. Table 3-

11 contains the original TOC that were calculated using the present day TOC values

78

from the core samples. The thickness of the Woodford Shale, when multiplied with

the difference in the original TOC and the present day TOC, helps in assessing the

remaining hydrocarbon potential. Some of the outliers were removed to build the con-

tours for these values. When contours are drawn for these points we get the resultant

sections of high potential, medium potential, low potential and bad potential. Figure

3-13 (a) is a raw contour map drawn in the GIS using the data from the Table 3-11.

Figure 3-13(a) Potential regions for Oil &Gas in Southeast New Mexico with the Con-

tours of (TOCo-TOCpd)* Thickness displayed in black and the Cored Wells in purple

dots.

After refining the data and extending the contours the regions are generated based on

the contours. Figure 3-13 (b) is a resultant hydrocarbon potential map that is used for

resource development. By following the workflows in Figure 3-14, 3-15 and 3-16 de-

velopment strategies can be established for each of region.

79

Figure 3-13(b) Potential regions for Oil &Gas in southeast New Mexico with the Con-

tours of (TOCo-TOCpd)* Thickness] in black and the Cored Wells in black dots. The

High potential oil and gas regions are derived by the (TOCo-TOCpd)* Thickness values

greater than 50. The (TOCo-TOCpd)*Thickness values less than 50 are considered to be

low potential for remaining hydrocarbons.

3.3.5 Resource Development Strategies Based on the Potential Regions

With these potential maps, resource development in these sections can be done using

four hypothetical horizontal wells per section. Each well has one MMbbls (approx) of

oil as an available resource in the Green Region (High Potential Oil Region), 4.65

BCF of gas in the Red Region, and 0.94 MMbbls of wet Gas for the Blue Region

based on the in-place resource estimation demonstrated.

High Potential Oil Region

80

Figure 3-14 Workflow for High Potential based on the (TOCo – TOCpd)*Thickness *Porosity. This is the best case scenario

81

Figure 3-15 Workflow for Medium Potential based on the (TOCo – TOCpd)*Thickness *Porosity.

82

Figure 3-16 Workflow for Low Potential & Bad Potential based on the (TOCo – TOCpd)*Thickness *Porosity. This is the worst case scenario

83

CHAPTER 4

RESULTS

The estimations and rankings derived from this analysis are focused on the Southeast-

ern part of New Mexico. Previous work has included little data from the state. Some

rock properties were based on data collected in Oklahoma [Comer, 1991]. Further-

more, Broadhead (2010) mentioned “several works that have been published about the

Woodford in the Permian basin, but most of the data and analysis was done using data

from Texas.” Increased data density and quality for the New Mexico Woodford shale

data was used for ranking the Woodford Shale on the Miller Shale Scale. The Wood-

ford was divided into three regions based on the intensity of the fracture networks,

thermal maturity and Total Organic Carbon (TOC). A total score was assigned to each

of the region (Table 4-1). Region I, II & III were ranked as 68, 66 and 48 respectively

and region I and II has been identified as having higher chances of finding good gas

prospects. Region III was identified as the least productive region for shale gas pro-

spects.

Table 4-1: Ranking Score Card of the Woodford Shale of New Mexico

Esti- mat-

ed vol-

umes for the Woodford Shale in New Mexico were 36 billion barrels of original oil

in-place and 44.5 trillion cubic feet of original gas in-place compared to 119 billion

barrels of original oil in-place and 230 trillion cubic feet of gas in-place in the Wood-

ford in the entire Permian Basin (Texas & New Mexico).

Ranking and estimated potential gave highest gas resources to Region II and highest

oil resources to the Region III (Table 4-2).

Ranking on the Shale Scale Region I Region II Region III

Total Score 68 66 48

84

Table 4-2: Comparison of Volumes of Original In-Place Oil & Gas to Comer’s

(2005) Assessment

Original In-Place

[Woodford Shale - Study Ar-

ea]

Original In-Place

[Woodford Shale - Total

Permian basin]

Oil

Billion bbl

Gas

Trillion ft3

Oil

Billion bbl

Gas

Trillion ft3

Total 36.06 44.6 119 229.11

This assessment strongly indicates that the Woodford Shale has high in-place oil and

gas resources in New Mexico.

The difference between TOCo (original) and TOCpd (present day) multiplied by

thickness of the Woodford will be an indication of the relative volumes of hydrocar-

bons generated (Broadhead, 2010). This is used for identifying the high potential re-

gions of oil and gas. Figure 4-1 shows all sections that have high oil potential in green

and the red sections are for high dry gas potential along with blue for wet gas poten-

tial. Resource development in these sections can be done using four hypothetical hori-

zontal wells per section. Each well has one MMbbls (approx) of oil as available

resource in the Green Region (high potential oil region), 4.65 BCF of gas in the Red

Region and 0.94 MMbbls of wet gas for the Blue Region based on the in-place re-

source estimation done in Chapter 3.

If four hypothetical horizontal wells per section were drilled in the oil producing re-

gion with a recovery factor of 8%, then the total yield would be 80,000 barrels per

well. Similarly, in the gas producing regions the yield would be 372,000 MCF per

well and in the wet gas regions the yield would be 75,200 barrels per well.

85

Economics & completion technologies will be the primary deciding factors. A sum-

mary of best practices and case studies is presented in the Chapter 5 that can be used

in the applying for resource development.

86

CHAPTER 5

DISCUSSION

5.1 Recommendations

The first recommendation would be to identify existing wells that are either drilled to

the top of the Woodford or wells that have drilled through Woodford and then use

them for testing the true potential instead of drilling new wells. The formation directly

above the Woodford is the Mississippian and the producing formations below are

Wristen, Fusselman, Ellenburger and Simpson. A search using Dwights data (Oct

2010) (Figure 5-1) showed that there are approximately 1100 wells that have an up-

hole potential in the Woodford and Figure 5-2 shows 108 wells that have a down-hole

potential in the Woodford.

Figure 5-1 Existing 1100 Wells (approx) have am Up-hole Potential (Wristen, Fussel-

man, Simpson & Ellenburger). All these wells can be recompleted to the above zone

where Woodford is present to test the potential.

87

Figure 5-2 Existing 108 Wells (approx) have Down-hole Potential (Mississippian)

All these wells can be deepened to reach to the Woodford Shale to test and produce.

5.2 Special Area:

While there are estimated total resource potential and high potential regions for find-

ing oil and gas in the Southeast New Mexico, there needs to be an understanding that

there are some special areas where drilling of oil and gas wells have restrictions. The

secretary’s potash area (SPA) is one such area managed by Bureau of Land Manage-

ment (BLM) where oil and gas drilling is allowed by special permit. So, the Wood-

ford Shale underlies the SPA area, and one third of the high dry gas potential regions

fall into the SPA region (Figure 5-3).

88

Figure 5-3 High Potential Oil & Gas regions with all the wells that have both Up-hole

and Down-hole Potential. Green Region for High Potential Oil region, Red for High Dry

Gas regions and Blue for the Wet Gas region. Gray region is Woodford Absent Secre-

tary’s Potash Area (SPA) falls in the High Potential Oil & Gas regions.

The closer look at the SPA with the buffer of a five mile radius helps to compare the

resource potential that remains in the restricted area (Figure 5-4). The color codes are

having the same significance throughout the work. Shades of green for oil, shades of

red for dry gas and shades of blue for wet gas regions are used for interpreting.

Potential regions are impacted by areas that have restrictions for drilling. For exam-

ple, in the Secretary’s Potash Area (SPA) (Figure 5-4), high potential Woodford Shale

oil and dry gas regions exist, but drilling restrictions may delay or disallow develop-

ment. The SPA buffer was created by Balch et al., (2010) to compare the estimates of

oil and gas potential that is unexplored and lies within the SPA.

89

Figure 5-4 Special Area – Secretary’s Potash Area with the 5 mile buffer overlying the

Woodford’s high potential oil and gas regions.

There are approximately 106 sections in the high potential oil regions and approxi-

mately 360 sections in the high potential gas regions. Based on four hypothetical hori-

zontal wells per section with a recovery factor of 8%, the total potential reserves for

potash area is approximately 34 Million BBLs. In the gas producing regions the total

potential reserves for potash area is approximately 536 BCF.

5.2.3 Hydrocarbon Potential Maps

When the above TOCo – TOCpd is multiplied by the thickness and average porosity

plotted in the form of maps, we can generate hydrocarbon potential maps. These maps

can indicate prime locations for finding shale oil and gas. The below map is generated

using the Woodford data where the high potential oil generation window regions are

in green and progressing deeper into the basin is where the high potential gas & wet

gas regions are found.

90

Figure 5-5 Southeast New Mexico with the classified high oil & gas regions

Based on the TOCo, TOCpd, average porosity and thickness values there are various

workflows that can be followed for development. Figures result in High Potential,

Medium Potential, Low Potential and Bad Potential regions.

5.2.4 Resource Development Strategies (Best Practices)

Resource plays are heavily driven by technologies like use of long laterals, increased

frac stages, Simulfracs, re-fracs, and more. Resource development can be done using

four horizontal wells per section for the Woodford.

The main points that can be considered from various shale plays in the United States

can be used for the development strategies to reduce the learning curve.

1. Below are the examples of development plans for shale gas regions,

downspacing from 80 acre to 40 acre well spacing. (Best Practice: New Field

Exploration 2008)

91

Figure 5-6 Optimum resource development plan for downsizing in Horizontal Wells

(Newfield 2008)

2. Pad drilling helps reducing costs significantly. It is one of the best practices

for horizontal drilling. Forty acre spacing with wells approximately 660 ft

apart and with average lateral length greater than 4100 ft proved to be a good

development for New Field Exploration in 2008.

3. Long laterals in dry gas window improve performance, but not in condensate

windows (Source: Drilling Info (DI) Energy Strategy Partners 2010). This has

been analyzed by plotting MaxIP vs Lateral Length for all the three thermal

maturity regions (dry gas, oil & wet gas).

4. Petrohawk showed that restricted wells with a 14/64 choke decline at a slower

rate than the non-restricted wells with a 28/64 or a 24/64 choke, in the first six

months. For example, in the Haynesville, the restricted wells declined approx-

imately 25 to 45 % in the first six months, whereas the non-restricted wells

declined at approximately 60%.

92

5. During the development of these Shale plays, the percentage for drilling is

very important parameter. For example we might have a total acreage of

20,000 acres, but if only 50% is drillable, then the resource potential cuts

down to half. This is also an important parameter to be considered.

5.2.5 Economics (Source: Drilling Info (DI) Energy Strategy Partners 2010)

This section focuses on comparing some of the key parameters like drilling and com-

pleting costs, estimated ultimate recovery per well, initial production rates, initial de-

cline, formation volume factor and well spacing, that differ from a dry gas window

well to an oil window well.

The cost being incurred for drilling and completing a horizontal well in a dry gas

window and a wet gas window is approximately six million dollars as of 2011;

whereas, the drilling and completing cost for horizontal in an oil window is slightly

on the higher end (6.8 million dollars). The other important factor that varies a lot

from an oil generation window well to a dry gas generation window well is the initial

decline rate. Oil wells decline faster in the shale reservoirs. Below shown are the set

of the key parameters like that are compare

Dry Gas Window:

D&C Cost - $6 MM

EUR/well – 5.5 Bcf

IP rate – 9.5 MMCF/D

Initial Decline – 75%

B Factor – 1.2

Spacing – 120 – 160 acres

Wet Gas Window:

D&C Cost - $6 MM

EUR/well – 6.5 Bcf

93

IP rate – 9.5 MMCF/D

Initial Decline – 75%

B Factor – 1.2


Oil Window:

D&C Cost - $6.8 MM

EUR/well – 375-425 MBOE

IP rate – 900 bbl/D

Initial Decline – 85-90%

B Factor – 1.1 – 1.5


In each of the regions, oil, dry gas and wet gas, some valuable lessons can be take

from the Barnett, Eagle Ford, Bakken and Woodford (of Oklahoma Basin) Shale

plays. The costs incurred in the development are analogous to that of the Eagle Ford

Shale. A combination of pad drilling with long laterals having a well spacing of 40

acres and an optimum choke size would be the best way to develop the Woodford

Shale in New Mexico.

94

CHAPTER 6

CONCLUSION

In conclusion, the goal to identify areas of high potential unconventional resource re-

gions within the Woodford shale in Southeastern New Mexico was met through the

use of data from various sources and applying the methodologies given by Comer

(2005) and Miller (2010). Some of the uncertainties associated with the analysis were

also evaluated during this process.

Miller’s gas shale ranking scorecard was uded to rank the Region I, II and III at 68, 66

and 54, respectively, on a scale of 100 with ten equally weighted parameters taken

into consideration. A modified scorecard with five key parameters with equal weight-

age on a scale 100 - Total Organic Content, vitrinite reflectance, shale thickness, clay

content and quartz content was used for computing relative uncertainties. Ranking of

the three regions using only the five important parameters based on maximum values

(best case) and minimum values (worst case) from the sources available, show that

Region II has better prospects of shale gas than Region I with all ten parameters. The

window of uncertainty for each of the regions was shown using spider diagrams in

Chapter 3.

Comer’s hydrogen mass balance in-place estimation resulted in a total resource poten-

tial of 36 billion barrels of original oil in-place and 44.5 trillion cubic feet of original

gas in-place compared to 119 billion barrels of original oil in-place and 230 trillion

cubic feet of gas in-place in the Woodford in the entire Permian Basin (Texas & New

Mexico). Based on the uncertainty analysis, in summary, the Original Oil In-Place

95

(OOIP) for Region I, Region II and Region III is estimated to be 1.678 +0.956 x 109

bbls, 73.41 + 15.75 x 109 bbls and 33.57 + 12.68 x 10

9 bbls respectively. The relative

uncertainty associated with the above OOIP for Region I is 57% and high uncertainty

is contributed primarily by the percentage difference of weight fraction of Immature

Horg and Present Horg. The relative uncertainty associated with the Region II’s OOIP

is 21% ,and in this case, the uncertainty is contributed primarily by the 1-percentage

of weight fraction of oil expelled. Certain aspects of the uncertainty is also contribut-

ed by the thickness and area. Finally, the relative uncertainty associated with the

OOIP of Region III is 38%, and in this case, the uncertainty is contributed primarily

by the 1 - percentage of weight fraction of oil expelled, thickness and area. The uncer-

tainty with the original gas in-place estimation is very high due to the gas concentra-

tion values that were used in the assessment are constants and there are no specific

derivations or formulas behind them. The difference between TOCo (original) and

TOCpd (present day) multiplied by thickness of the Woodford will be an indication of

the relative volumes of hydrocarbons generated (Broadhead, 2010). This is used for

identifying the high potential regions of oil and gas.

Since the Woodford shale in New Mexico has had no gas production at the time of

this work, and only a single oil well in the Gladiola pool, some of the parameters used

in the analysis came from the Woodford Shale of the Permian Basin, the analogous

Woodford Shale of Oklahoma, and other active shale plays. The Woodford shale in

New Mexico is found at great depths which contributes to its lack of production.

The hydrogen mass balance estimate using the core data indicated one million barrels

of oil available in the oil window region, 4.65 billion cubic feet of gas in the dry gas

window region and 0.94 million barrels of oil equivalent in the wet gas region as the

available resources per section. With four hypothetical horizontal wells per section

96

and a recovery factor of 8%, the estimated recoverable reserves per well 80,000 bar-

rels per well in the oil region, 372,000 MCF per well in the dry gas region and 75,200

barrels per well in the wet gas region.

A new approach is defined as part of this work,Shale Potential Interpretation Network

(SPIN), which is a Case-Based Reasoning (CBR) approach to define prime locations

for hydrocarbon potential in a given region. The key parameters that are used are av-

erage porosity, present day and original Total Organic Carbon (TOC), thickness, Hy-

drogen Index (HI) and thermal maturity (Tmax).

The CD accompanying the work contains the calculation sheet of the hydrogen mass

balance in-place estimation, uncertainty calculations and an interactive GIS map that

were used in the Woodford play analysis.

In conclusion, this assessment strongly affirms the Woodford Shale as a primary

source rock in New Mexico, and with the correct economics a potential for oil & gas

resources exists. This potential could be tested by recompleting existing wells.

97

CHAPTER 7

Future Work

The assessment and uncertainty analysis done on the Woodford Shale in New Mexico

is limited to 19 cored wells and some of the analog field data that are spread over a

large areal extent. In order to do an extensive analysis in New Mexico additional

cores and their well logs could be acquired. A geological model could also be devel-

oped using the core data and log data to understand the reservoir engineering aspects

of the shale model.

A completion profile would be useful for determining focused areas forbetter devel-

opment of the Woodford Shale in New Mexico. Networking with the industry and

keeping track of the technological changes in completing the Woodford Shale and

other analogs would give a new direction to this analysis.

Deeper parts of the basin that are predicted to have gas resources should be confirmed

with production data. In-place estimation using Comer’s hydrogen mass balance

methodology has limitations, so a better resource in-place estimation would be valua-

ble.

98

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Appendix - A

Conversion Factors (SPE 2010)

Unit multiplied

by

Approximate Conver-

sion Factor

equals Unit

metric tonnes [t] X 1,000 = kilograms [kg]

kilograms [kg] X 2.2046 = pounds [lb]

barrels of oil [bbl] X 42 = US gallons [gal]

barrels of oil [bbl] X 0.136 = tonnes of oil

equivalent [toe]

barrels of oil [bbl] X 0.1589873 = cubic metres [m3]

barrels of oil

equivalent [boe]

X 5,658.53 = cubic feet [f3] of

natural gas

kilometer [km] X 0.62137 = miles [mi]

feet [ft] X 0.3048 = meters [m]

Geochemical Parameters reference data

Ranges and Classification of TOC (Jarvie, 1991)

< 1.00 % Inadequate [consider lithology: shale or carbonate; sample type; maturi-

ty]

1.00-2.00 % Marginal [consider lithology: shale or carbonate; sample type; maturi-

ty]

>2.00 % Adequate [consider lithology: shale or carbonate; sample type; maturi-

ty]

Ranges and Classifications of S2 (Espitalie, 1982)

0 – 2.0 Poor Source Potential [dependent on maturity]

2.0 - 5.0 Fair Source Potential [dependent on maturity]

> 5.0 Good Source Potential [dependent on maturity]

Categories of Thermal Maturity Tmax (Espitalie et al, 1985)

Type I Type II Type III Maturity

<425 C < 435 C Immature

440-448 C 425-450 C 435-465 C Oil Window

>450 C >465 C Gas Window

106

Categories of Productivity Index PI (derived from Espitalie, 1982)

0- 0.08 Immature

0.08 – 0.50 Oil Window

> .50 Gas Window

Categories of Hydrogen Index HI (Jones, 1984)

< 50 Type IV gas prone

50-200 Type III [gas/oil prone, usually terrestrial]

200-350 Mixed Type II/III [mixed oil/gas prone]

350-700 Type II [oil prone, usually marine]

>700 Type I [oil prone, often lacustrine]

Categories of Vitrinite Reflectance (Ro)

Immature <0.60% Ro

Oil Window 0.60 – 1.10% Ro

Condensate/Wet Gas Window 1.10-1.40%Ro

Dry Gas Window >1.40%Ro

107

Appendix –B

This section helps in using the maps generated using the geographic information sys-

tems (GIS). The version used for GIS is ArcGIS 10.0 with a student license.

If you have an ArcGIS license follow below steps: (Note: these maps are editable)

Use the WoodfordShale.mxd file to open the ArcMap to view the project. The geoda-

tabase data associated with this project is WoodfordShale.mdb. This geodatabase con-

tains tables of data that have been used in generating these maps.

If ArcGIS license is not available then follow the below steps: (Note: these maps are

for read-only purpose)

Step 1: Download the ArcReader for Free using the below link.

http://www.esri.com/software/arcgis/arcreader/download.html

Step 2: Open the .pmf file to view the ArcGIS maps.

WoodfordShale.pmf is the published map file that can be opened using ESRI Arc-

Reader software.

The view of the map when opened with ArGIS shows (see below) layers of Woodford

potentials, sections, New Mexico base maps such as sections, townships and counties,

etc.

108

Figure B-1Image of the interactive GIS maps for Woodford Shale in New Mexico

109

Appendix - C

This section helps in using the calculation sheet for estimating in-place resources us-

ing the hydrogen mass balance method (Comer 2005). This single worksheet is devel-

oped in Microsoft Excel 2007. The equations are available along with references.