Evaluation of Cretaceous and Jurassic Shales in the Burgos Basin, Mexico

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2017 Evaluation of Cretaceous and Jurassic shales in the Burgos Basin, Mexico

Cruz Luque, Marcela M

Cruz Luque, M. M. (2017). Evaluation of Cretaceous and Jurassic shales in the Burgos Basin, Mexico (Unpublished master's thesis). University of Calgary, Calgary, AB. doi:10.11575/PRISM/25985 http://hdl.handle.net/11023/4200 master thesis

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Evaluation of Cretaceous and Jurassic shales in the Burgos Basin, Mexico

Marcela Marian Cruz Luque

A THESIS

SUBMITTED TO THE FACULTY OF GRADUATE STUDIES

IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE

DEGREE OF MASTER OF SCIENCE

GRADUATE PROGRAM IN CHEMICAL AND PETROLEUM ENGINEERING

CALGARY, ALBERTA

SEPTEMBER, 2017

Successful activities in the Eagle Ford shale in Texas through drilling of horizontal wells and completions using multi-stage hydraulic fracturing jobs suggest that the potential of shale reservoirs south of the border will be quite significant.

This observation leads to the objective of this study: to integrate available geoscience and engineering data to evaluate the potential of Mexican shales, and their oil and gas endowment under different oil and gas prices scenarios. Endowment is defined by the United States Geological

Survey (USGS, 2010) as the sum of known volumes of oil and gas (cumulative production plus remaining reserves) and undiscovered volumes.

Emphasis is placed on the Upper Cretaceous Eagle Ford shale and the Upper Pimienta shale in

Burgos basin, located just south of the border with Texas (United States). Other shales considered in this study are found in the Sabinas, Tampico, Tuxpan (Platform), Veracruz and Chihuahua basins throughout Mexico. The economic potential of these plays is examined with the use of cumulative long run supply (or availability) curves.

It is concluded that the potential of unconventional resources in Mexico is quite significant and will help to change the slope of production rates in the country from negative to positive. As a result, it is anticipated that Mexico will become an important part of the shale petroleum revolution initiated in the United States.

ii Acknowledgements

I would like to acknowledge my supervisor, Dr. Roberto Aguilera, for accepting me in the GFREE

Research Group, for encouraging me to keep working, for his guidance, advice and feedback. I admire his work, and it was an honor for me to work with him as my supervisor.

Many thanks to the Department of Chemical and Petroleum Engineering for providing the research environment at the University of Calgary. Special thanks to Dr. Thomas Harding and Dr. Laurence

Lines for their valuable comments and suggestions.

I also want to thank Pemex Exploration and Production, and the scholarship program of the

Mexican National Council for Science and Technology (Conacyt) for providing the financial support to complete my degree at the University of Calgary. Especially to MSc. Mario Alberto

Vasquez Cruz, for his support during the development of this thesis.

My thanks to GFREE members for their continuous support and collaboration. Thanks to Bruno

A. Lopez Jimenez, Jaime Piedrahita Rodriguez and Daniel Orozco for their support and valuable comments.

I also extent my gratitude to my family and friends who encouraged me throughout this process, and who made this experience so extraordinary.

iii Dedication

This thesis is dedicated to my beloved family, especially to my grandmother, “Memi”; she is the motivation and inspiration to continue in my work everyday. To my mother, who is a role model for me, she is the light that guides me in my life. To my siblings, Jorge and Beatriz, for their continuous support through all my studies. To my niece, Valeria. And to my partner, Abraham, for his love, support and for giving me the strength to overcome all the difficulties during this process.

iv Table of Contents

Abstract ...... ii Acknowledgements ...... iii Dedication ...... iv Table of Contents ...... v List of Tables ...... viii List of Figures and Illustrations ...... x List of Symbols, Abbreviations and Nomenclature ...... xv

CHAPTER ONE: INTRODUCTION ...... 1 1.1 Unconventional Resources ...... 1 1.2 Eagle Ford Shale in Texas ...... 7 1.3 Eagle Ford Shale in Mexico ...... 8 1.4 Cumulative Long Run Supply Curves ...... 12 1.5 Research Objectives ...... 18 1.6 Thesis Organization ...... 19 1.7 Technical Publications ...... 20

CHAPTER TWO: REVIEW OF LITERATURE ...... 22 2.1 Geologic Aspects ...... 22 2.2 Engineering Aspects ...... 25 2.3 Resources ...... 33 2.4 Summary of Published Shale Resources ...... 35

CHAPTER THREE: GEOCHEMISTRY IN BURGOS BASIN ...... 37 3.1 Introduction ...... 37 3.2 Definition of a Shale ...... 37 3.3 Source Rock Richness ...... 40 3.3.1 Using Rock Eval Pyrolysis to estimate organic richness in the Eagle Ford formation ...... 43 3.3.2 Using Rock Eval Pyrolysis to estimate organic richness in Pimienta formation44 3.4 Source Rock Quality ...... 45 3.4.1 Estimating source rock quality in Eagle Ford and Pimienta formations ...... 47 3.5 Source Rock Maturity ...... 49 3.5.1 Estimating source rock maturation in Eagle Ford and Pimienta formations ...52 3.6 Geochemical logs ...... 56 3.7 North American shale resource play geochemistry assessment ...... 59

CHAPTER FOUR: FORMATION EVALUATION IN BURGOS BASIN ...... 60 4.1 Introduction ...... 60 4.2 Pickett Plots ...... 60 4.3 Method for evaluating the Mexican shales considered in this thesis ...... 61 4.4 Log interpretation of Cretaceous Eagle Ford Formation (well Habano 1) ...... 66 4.5 Log interpretation of Jurassic Pimienta Formation (Anhélido 1) ...... 72 4.6 Empirical comparison with the Eagle Ford shale in Texas ...... 79 4.7 North American shale resource play petrophysical assessment ...... 83

v CHAPTER FIVE: PRODUCTION ANALYSIS ...... 84 5.1 Production data analysis (PDA) and rate transient analysis (RTA) ...... 84 5.2 Importance of Flow Regimes ...... 84 5.3 Production Analysis Methods ...... 86 5.3.1 Straight Line Methods ...... 87 5.3.2 Type curve Methods ...... 88 5.3.3 Empirical Methods – Decline Curve Analysis (DCA) ...... 89 5.3.4 Hybrid Methods ...... 91 5.4 Field Cases ...... 93 5.4.1 Long transient linear flow periods in Mexican shales ...... 93 5.4.2 Production analysis of Cretaceous Eagle Ford Formation ...... 96 5.4.2.1 Using a new material balance to calculate OGIP in well Habano 1 ...... 97 5.4.2.2 Results and discussion for well Habano 1 ...... 102 5.4.3 Production analysis in Jurassic Pimienta Formation ...... 106 5.4.3.1 Using an Analytical Model to calculate OGIP, area of SRV, and fracture half-length in Anhélido-1 ...... 108 5.4.3.2 Results and discussion for well Anhélido-1 ...... 108

CHAPTER SIX: OTHER UNCONVENTIONAL BASINS IN MEXICO ...... 118 6.1 Sabinas Basin ...... 118 6.1.1 Geologic Aspects ...... 118 6.1.2 Engineering Aspects ...... 120 6.1.3 Resources ...... 122 6.2 Tampico Basin ...... 123 6.2.1 Geologic Aspects ...... 123 6.2.2 Engineering Aspects ...... 125 6.2.3 Resources ...... 127 6.3 Tuxpan (Platform) ...... 127 6.3.1 Geologic Aspects ...... 127 6.3.2 Engineering Aspects ...... 129 6.3.3 Resources ...... 130 6.4 Veracruz basin ...... 130 6.4.1 Geologic Aspects ...... 130 6.4.2 Engineering Aspects ...... 132 6.4.3 Resources ...... 132 6.5 Chihuahua Basin ...... 132 6.5.1 Geologic Aspects ...... 132 6.5.2 Engineering Aspects ...... 133 6.5.3 Resources ...... 133

CHAPTER SEVEN: DATA INTEGRATION AND MEXICAN SHALES POTENTIAL ...... 134 7.1 Geophysics, Geology and Geochemistry ...... 134 7.2 Petrophysics ...... 137 7.3 Shales and their Effect on U.S. and Mexican Production ...... 140 7.4 Effect of Low Oil and Gas Prices ...... 143 7.5 Learning Curves ...... 145

vi CHAPTER EIGHT: CONCLUSIONS AND RECOMMENDATIONS ...... 148 8.1 Conclusions ...... 148 8.2 Recommendations and future work ...... 149

REFERENCES ...... 151

vii List of Tables

Table 1-1 Top 10 Countries with technically recoverable shale oil resources (EIA, 2013) ...... 5

Table 1-2 Top 10 Countries with technically recoverable shale gas resources (EIA, 2013) ...... 5

Table 2-1 Comparison of Shale Formations (from Granados Hernandez et. al, 2017)...... 30

Table 2-2 Characteristics of the exploration and exploitation shale gas wells in Mexico (Modified from Dominguez-Vargas, 2014 and Comisión Nacional de Hidrocarburos, CNH, 2016)...... 31

Table 2-3 Estimated Shale gas and shale oil resources based on studies carried out by PEMEX (2012) and EIA/ARI (2013)...... 36

Table 3-1 Guidelines for TOC assessment (Jarvie, 1991) ...... 43

Table 3-2 Rock Eval Pyrolysis Results Habano-1 ...... 44

Table 3-3 Rock Eval Pyrolysis Results Anhélido-1 ...... 45

Table 3-4. Guidelines for Tmax maturation assessment ...... 50

Table 3-5 Geochemical parameters describing level of thermal maturation (Peters and Cassa, 1994) ...... 51

Table 3-6 Guidelines for PI maturation assessment ...... 52

Table 3-7 Comparison of geochemical parameters in North American shales ...... 59

Table 4-1 Properties used for petrophysical interpretation of the Eagle Ford formation penetrated by well Habano 1 ...... 67

Table 4-2 Triaxial Test on three samples of well Habano 1 ...... 71

Table 4-3 Properties used for petrophysical interpretation of the Pimienta formation penetrated by well Anhélido 1 ...... 73

Table 4-4 Triaxial Test on four samples of well Anhélido 1 ...... 77

Table 4-5 Comparison of petrophysical parameters in North American shales ...... 83

Table 5-1 Arps decline curve equations...... 90

Table 5-2 Reservoir and fluids parameters used for material balance calculations ...... 103

Table 5-3 Volumetric estimation of original gas in place for each storage mechanism ...... 104

Table 5-4 Parameters and calculations for deterministic model of well Anhélido-1 ...... 110

viii Table 5-5 Results from analytical model for well Anhélido-1 ...... 117

Table 7-1 Comparison of geochemical parameters in North American shales ...... 137

Table 7-2 Comparison of petrophysical parameters in North American shales ...... 139

ix List of Figures and Illustrations

Figure 1-1 Assessed Shale Gas and Shale Oil Resources in the World (from: U.S. EIA, 2013)...... 4

Figure 1-2 Eagle Ford map June 2017 (source: https://eaglefordshale.com/) ...... 8

Figure 1-3 Shale gas and oil basins of Eastern Mexico (Source: http://portal.cnih.cnh.gob.mx/iicnih/?lng=en_US)...... 10

Figure 1-4 Stratigraphic column of Mexican Basins including kerogen type and TOC (PEMEX E&P, 2012) ...... 11

Figure 1-5 Estimates of global natural-gas endowment (from Aguilera et al. 2014, GFREE Research team)...... 14

Figure 1-6 Estimates of global oil endowment (from Aguilera et al. 2014, GFREE Research team)...... 15

Figure 1-7 World cumulative long run supply curve for shale gas (Aguilera and Aguilera, 2015). Insert developed in this study for Burgos, Sabinas, Tampico, Tuxpan (Platform), and Veracruz Basins...... 17

Figure 1-8 World cumulative long run supply curve for tight and shale oil (Aguilera and Aguilera, 2015). Insert developed in this study for Burgos, Sabinas, Tampico, Tuxpan (Platform), and Veracruz Basins...... 18

Figure 2-1 Upper graph shows five production strips trending approximately N-S in the Burgos basin. Lower graph shows structural cross section A-A’ (PEMEX E&P Provincia Petrolera Burgos, 2013)...... 23

Figure 2-2 Seismic view including well Emergente-1 and comparison with wells drilled through the Eagle Ford shale in Texas, USA, including GR and Sonic logs. The U.S. wells produce from the deeper Cretaceous Edwards Formation (PEMEX E&P, 2012)...... 25

Figure 2-3 Horizontal length and depth of exploration wells drilled in the Eagle Ford shale (PEMEX E&P, 2014)...... 27

Figure 2-4 Location of 18 exploration wells drilled from 2010 to 2015 in Burgos and Sabinas Basins (Modified from PEMEX E&P, 2014)...... 32

Figure 2-5 Production history of the Emergente-1 well (CNH, 2016)...... 34

Figure 2-6 Production history of the Anhélido-1 well (CNH, 2016)...... 34

Figure 2-7 Production history of the Habano field (CNH, 2016)...... 35

Figure 3-1 North American shale plays (Source: EIA, 2011) ...... 39

x Figure 3-2 Schematic of quintuple porosity and solid kerogen (Lopez and Aguilera, 2013) ...... 39

Figure 3-3 A)Model of organic carbon distribution in a sample. B) Relationship of Rock Eval Pyrolysis process ...... 40

Figure 3-4 Pyrolysis diagram (adapted from Tissot and Welte, 1984, by Piedrahita and Aguilera, 2017) ...... 42

Figure 3-5 A) Van Krevelen diagram based on atomic H/C and O/C. B) Modified Van Krevelen diagram using HI and OI of Rock Eval pyrolysis to classify kerogen type...... 47

Figure 3-6 Modified Van Krevelen diagram for Habano 1 (Eagle Ford) and Anhélido 1 (Pimienta formation)...... 48

Figure 3-7 S2 vs. TOC diagram showing kerogen type for Habano 1 (Eagle Ford formation) and Anhélido 1 (Pimienta formation)...... 49

Figure 3-8 Maturation assessment from Vitrinite Reflectance (Tissot and Welte, 1984) ...... 51

Figure 3-9 Vitrinite Reflectance Histogram for well Habano-1 (Eagle Ford Formation)...... 53

Figure 3-10 HI vs. Tmax for well Habano 1 (EagleFord formation) ...... 54

Figure 3-11 Vitrinite Reflectance Histogram for well Anhélido-1 ...... 55

Figure 3-12 HI vs. Tmax for well Anhélido-1 (Pimienta formation)...... 56

Figure 3-13 Geochemical logs of well Habano-1 (Eagle Ford formation) ...... 57

Figure 3-14 Geochemical logs of well Anhélido-1 (Pimienta formation)...... 58

Figure 4-1 Types of shale classified by manner of distribution. Pictorial representations are shown above and volumetric representations below (Schlumberger)...... 63

Figure 4-2 Modified Pickett Plot for Eagle Ford formation (Habano 1) ...... 68

Figure 4-3 Well logs, porosity and water saturation for Eagle Ford interval penetrated by well Habano 1 ...... 69

Figure 4-4 Linear relationship between TOC and density for well Habano 1...... 70

Figure 4-5 Estimation of TOC from density log and Passey et al. method, well Habano 1...... 70

Figure 4-6 Poisson’s Ratio, Young’s Modulus and Brittleness Index for well Habano 1 ...... 72

Figure 4-7 Biot’s constant, overburden stress, pore pressure, MHS and net stress for well Habano 1...... 73

Figure 4-8 Pickett Plot Eagle Ford formation (Anhélido 1) ...... 74

xi Figure 4-9 Well logs, porosity and water saturation from well Anhélido 1 ...... 75

Figure 4-10 Linear relationship between TOC and density for well Anhélido 1 ...... 76

Figure 4-11 Estimation of TOC from density and Passey et al., Anhélido 1 ...... 76

Figure 4-12 Poisson’s Ratio, Young’s Modulus and Brittleness Index for well Anhélido 1 ...... 78

Figure 4-13 Biot’s constant, overburden stress, pore pressure, MHS and net stress for well Anhélido 1 ...... 79

Figure 5-1 Rate normalized pressure (RNP) and rate normalized derivative (RNP’) signature for a multi-stage hydraulic fracture in a horizontal well (MFHW) in a shale reservoir; te is material balance time. (from: Clarkson 2013, after Song and Ehlig-Economides 2011) . 85

Figure 5-2 Tight gas production performance using decline curves – Field example (from Kupchenko et al. 2008) ...... 92

Figure 5-3 Linear flow cross plot for gas well Emergente-1 (Eagle Ford shale, Burgos Basin) suggests that boundary dominated flow was not reached during 62 months of continuous production. Deviation from the linear flow straight line is likely the result of operational problems. Long transient linear flow periods are typical of many shale reservoirs in U.S. Basins...... 95

Figure 5-4 Linear flow crossplots for gas condensate production from well Habano-1, Habano-21, Habano-71 and Habano-2 indicate that boundary dominated flow was not reached over 40 months of continuous production. (Burgos Basin)...... 95

Figure 5-5 Linear flow cross plot for oil production from well Anhélido-1 suggests that boundary dominated flow was not reached during 12 months of continuous production. The last data point is an outlier due to operational problems. Anhélido-1 was the first well to produce oil from the Pimienta shale (Burgos Basin)...... 96

Figure 5-6 Gas rates and cumulative gas production of Habano field...... 97

Figure 5-7 Production history of well Habano 1 ...... 104

Figure 5-8 Determination of constant bpss for well Habano 1 ...... 105

Figure 5-9 Material balance plot for Habano 1. Total OGIP is estimated to be 6.69 BSCF...... 105

Figure 5-10 Location of 4 wells in Habano field (Courtesy of Pemex) ...... 106

Figure 5-11 Production and pressure of well Anhélido-1 ...... 107

Figure 5-12 Production history of well Anhélido-1 ...... 111

Figure 5-13 Normalized pressure vs. square root of time plot for well Anhélido-1 ...... 111

xii Figure 5-14 Flowing material balance plot for well Anhélido-1 ...... 112

Figure 5-15 Type curve plot for well Anhélido-1 ...... 112

Figure 5-16 Forecast for well Anhélido-1 ...... 113

Figure 5-17 Schematic of horizontal multi-fractured oil reservoir model ...... 113

Figure 5-18 Horizontal multi-fractured oil reservoir model for well Anhélido-1 ...... 114

Figure 5-19 Blasingame plot for well Anhélido-1 ...... 114

Figure 5-20 Pressure history matching for well Anhélido-1 ...... 115

Figure 5-21 Oil normalized pressure vs. Oil material balance square root of time for well Anhélido-1 ...... 115

Figure 5-22 Forecast of 240 months for well Anhélido-1 ...... 116

Figure 6-1 Seismic profile through well Percutor-1 completed at 3400 m in the Eagle Ford Shale and schematic of the well completion (PEMEX 2012)...... 120

Figure 6-2 Production history of well Percutor-1 (CNH, 2016)...... 122

Figure 6-3 Elements of Tampico Misantla basin in Mexico (PEMEX E&P Provincia Petrolera Tampico-Misantla, 2013)...... 125

Figure 6-4 Paleomodel of the middle Cretaceous, Tuxpan Platform (PEMEX E&P Provincia Petrolera Tampico-Misantla, 2013) ...... 129

Figure 6-5 Structural elements of Veracruz basin in Mexico (PEMEX E&P Provincia Petrolera Veracruz, 2013) ...... 131

Figure 7-1 Seismic view including well Emergente-1 and comparison with wells drilled through the Eagle Ford shale in Texas, USA, including GR and Sonic logs. The U.S. wells produce from the deeper Cretaceous Edwards Formation (PEMEX E&P, 2012). ... 135

Figure 7-2 Stratigraphic cross section including well Emergente-1 and comparison with wells drilled through the Eagle Ford shale in Texas, USA. The U.S. wells produce from the Eagle Ford shale (PEMEX E&P, 2011)...... 135

Figure 7-3 Modified Van Krevelen diagram for Habano 1 (Eagle Ford) and Anhélido 1 (Pimienta formation) ...... 136

Figure 7-4 Modified Pickett plot for Eagle Ford shale wells in the U.S. and Mexico (Burgos basin). U.S. data shown as green triangles. Mexican data shown as blue open circles...... 138

xiii Figure 7-5 Modified Pickett plot for Eagle Ford shale well in the U.S. and Pimienta shale well in Mexico (Burgos basin). U.S. data shown as green triangles. Mexican data shown as red open circles...... 138

Figure 7-6 Linear flow cross plot for gas well Emergente-1 (Eagle Ford shale, Burgos Basin) suggests that boundary dominated flow was not reached during 62 months of continuous production. Long transient linear flow periods are typical of many shale reservoirs in U.S. Basins...... 141

Figure 7-7 Linear flow cross plot for oil production from well Anhélido-1 suggests that boundary dominated flow was not reached during 12 months of continuous production. The last data point has been corroborated to be an outlier. Anhélido-1 was the first well to produce oil from the Pimienta shale (Burgos Basin)...... 141

Figure 7-8 Hubbert’s prediction vs. actual oil production in the U.S. lower 48 states. Significant increase in production starting in about 2010 is the result of contributions from shale oil reservoirs (Source: Hubbert, 1956; IEA, 2014)...... 142

Figure 7-9 Mexican crude oil production (thousand bopd). Actual data to 2015. Forecast from there on (adapted from presentation by Gustavo Hernandez-Garcia, Pemex CEO, SPE LACPEC, Quito, Ecuador, 18-20 November, 2015). Campos terrestres = onshore, Campos marinos = offshore, No conventional = unconventional, Nuevos descubrimientos = new discoveries, socios = partners...... 142

Figure 7-10 World cumulative long run supply curve for shale gas (Aguilera and Aguilera, 2015). Insert developed in this study for Burgos, Sabinas, Tampico, Tuxpan (Platform), and Veracruz Basins...... 144

Figure 7-11 World cumulative long run supply curve for tight and shale oil (Aguilera and Aguilera, 2015). Insert developed in this study for Burgos, Sabinas, Tampico, Tuxpan (Platform), and Veracruz Basins...... 145

Figure 7-12 Texas Eagle Ford shale learning curve shows outstanding increment in drilling productivity (EIA, 2017)...... 146

Figure 7-13 Louisiana Haynesville shale learning curve shows outstanding increment in peak gas production per month (Drillinginfo, 2010)...... 147

xiv List of Symbols, Abbreviations and Nomenclature

Acronyms Definition API American Petroleum Institute ARI Advanced Resources International BDF Boundary Dominated Flow CNH Comisión Nacional de Hidrocarburos CTV Cuenca Terciaria de Veracruz DFIT Diagnostic Fracture Injection Test EF Eagle Ford EIA Energy Information Administration EOM Extractable Organic Matter EUR Expected Ultimate Recovery FMB Flowing Material Balance FTS Frente Tectónico Sepultado GFREE Geoscience (G), formation evaluation (F), reservoir drilling, completion and stimulation (R), reservoir engineering (E), economics and externalities (EE) MB Material Balance MBE Material Balance Equation OGCR Oil and Gas Conservation Regulation OGIP Original Gas in Place OM Organic Matter OOIP Original Oil in Place PDA Production Data Analysis PEMEX Petróleos Mexicanos PEMEX E&P Petróleos Mexicanos Exploración y Producción PRMS Petroleum Resource Management System PVT Pressure/Volume/Temperature RNP Rate Normalized Pressure RNP’ Rate Normalized Pressure Derivative RTA Rate Transient Analysis SEM Scanning Electron Microscopy SPE Society of Petroleum Engineers SRV Stimulated Reservoir Volume SRV Stimulated Reservoir Volume TPS Total Petroleum System U.S. United States USGS United States Geological Survey VSD Variable Shape Distribution XRD X-Ray Diffraction

xv Nomenclature Definition a Constant related to tortuosity A Well drainage area, acres A0, A1, A2, A3, A4, A5 Coefficients of Eq. 5-22 Ash Shale number b Eaton exponent, dimensionless, unless otherwise stated b1, b2, b3, b4 Coefficients of Eq. 5-20 Bbo Billion (109) barrels of oil Bg Gas formation volume factor, RCF/SCF Boe Barrels of oil equivalent bpd Barrels per day bpm Barrels per minute bpss Reservoir constant (pseudo-steady state) Bscf Billion (109) standard cubic feet of gas C(P) Methane solubility (or concentration) in the solid kerogen, m3 of gas at NTP/m3 of kerogen (or ft3 of gas at NTP/ft3 of kerogen) C’ Effective matrix compressibility, psi-1 C’’ Effective fracture compressibility, psi-1 CGR Condensate-gas ratio, STB/MMSCF Cm Matrix compressibility, psi-1 Cw Water compressibility, psi-1 E Young’s Modulus F Formation factor ft Feet G Shear modulus, psi G2+hf Gas volume that is initially stored in natural and hydraulic fractures, MMSCF Ga Gas volume that is initially adsorbed in the organic matter, MMSCF Gd Gas volume that is initially dissolved in the solid kerogen, MMSCF GEC Equivalent gas production associated to condensate, SCF/STB GEW Equivalent gas production associated to water, SCF/STB

Gm Gas volume that is initially stored in the matrix, MMSCF Gp Cumulative gas production, MMSCF Gpt Total cumulative gas production, MMSCF GR Gamma Ray, API GR gamma ray from the log GRmax Maximum gamma ray (shaly zone) GRmin Minimum gamma ray (clean zone) HI Hydrogen Index, mg HC/g TOC

xvi I Resistivity Index Ish Resisitivity Index of shale k Permeability KB Kelly bushing elevation Km2 Square kilometer Kn Knudsen Number, dimensionless m Meter, Porosity or cementation cxponent m(P) Average reservoir pseudopressure, psi2/cp m(Pwf) Flowing pseudopressure, psi2/cp m3 Cubic meter MD Measured depth mi2 Square miles MMBTU Million (106) BTU (British Thermal Unit) MMcf/d Million (106) cubic feet per day MMMboe Billion (109) barrels of oil equivalent MWc Molecular weight of the condensate, lb-m/lb-mol n Water saturation exponent NC Cumulative condensate production, MSTB OI Oxygen Index, mg CO2/g TOC OSI Oil Saturation Index mg HC/g TOC P Pressure PI Production Index, dimensionless PL Langmuir pressure, psi Pn* Modified water normal pressure, kPa Pp Pore pressure Ppc Pseudo critical pressure, psia Ppi Pseudo-pressure at initial reservoir pressure, psi Ppr Pseudo reduced pressure, psia Ppwf Pseudo-pressure at flowing pressure, psi psi Pound per square inch PwD Dimensionless pressure Pwf Bottomhole flowing pressure, psi Qc Condensate production rate, MSTB qDd Decline curve dimensionless rate Qg Gas production rate, MMSCF/D Qgt Gas condensate production rate, MMSCF/D re External boundary radius, ft or m RF Recovery Factor, fraction or percentage Ro Reflectance of vitrinite Ro Resisitivity of formation at 100% saturated with water Rsh Shale resistivity, ohm.m Rt True resistivity, ohm.m rw Wellbore radius, ft or m S1 Free HC obtained from a sample during Rock Eval pyrolysis test, mg HC/g rock

xvii S2 HC obtained during thermal pyrolysis of a sample, mg HC/g rock S3 CO2 formed during Rock Eval pyrolysis test, mg CO2/g rock S4 Residual carbon content in a sample during a Rock Eval pyrolysis test, mg C/g rock SCI Spore Coloration Index Sw Water saturation, percentage Swf Water saturation in fractures, fraction Swm Average water saturation in matrix, fraction t time T Reservoir temperature, °C, R or K TAI Thermal Alteration Index tca Material balance pseudotime, days Tcf Trillion (1012) cubic feet tDd Decline curve dimensionless time Tmax Maximum temperature TOC Total organic carbon, % weight Tpc Pseudo critical temperature, °R Tpr Pseudo reduced temperature, °R TR Transformation Ratio of OM, percentage TVD True vertical depth Vc Compressional velocity, / VL Langmuir volume, SCF/ton Vs Shear velocity, / 𝜇𝜇𝜇𝜇 𝑚𝑚 Vsh Shale Volume Wp Cumulative water𝜇𝜇𝜇𝜇 production,𝑚𝑚 MSTB xe Reservoir half-width xf Fracture half-length, ft ye Distance from fracture to outer boundary Z Gas deviation factor, dimensionless Z2 Two-phase gas deviation factor, dimensionless Z2’ Modified two-phase gas deviation factor, dimensionless Poisson’s Ratio

𝑣𝑣

xviii Greek Symbols Definition µ Viscosity, cp αv Vertical Bio’s constant, dimensionless γg Specific gas gravity Δtc Compressional transit time, / Δtn Normalized sonic transient time, / Δts Compressional transit time, 𝜇𝜇𝜇𝜇/𝑚𝑚 ρb Shale bulk density registered by the𝜇𝜇𝜇𝜇 logging𝑚𝑚 tool 3 at depth, g/cm 𝜇𝜇𝜇𝜇 𝑚𝑚 ρf Fluid density used to calibrate the logging tool, g/cm3 ρs Grain density of the rock, g/cm3 σh,min Minimum horizontal stress, kPa σtech Tectonic stress, kPa σz Overburden Stress, psi ϕads Adsorbed porosity scaled to the bulk volume of the composite system, fraction ϕEff Effective porosity, fraction or percentage ϕhf Porosity of hydraulic fractures scaled to the bulk volume of the composite system, fraction ϕmt Total matrix porosity, fraction ϕN Neutron porosity, fraction or percentage ϕorg Organic porosity scaled to the bulk volume of the composite system, fraction ϕRHOB Density porosity, fraction or percentage ϕT Total porosity, fraction or percentage ωa Fraction of OGIP adsorbed in the organic matter, fraction ωd Fraction of OGIP dissolved in the solid kerogen, fraction ωf Fraction of OGIP stored in fractures, fraction ωm Fraction of OGIP stored in matrix, fraction

Subscripts Definition f Natural fractures g Gas i Initial o Oil pd Present days w Water x X-direction y Y-direction

xix

Chapter One: Introduction

1.1 Unconventional Resources

The SPE Board-approved Petroleum Resources Management System (PRMS) defines unconventional resources as follows: “Unconventional resources exist in petroleum accumulations that are pervasive throughout a large area and that are not significantly affected by hydrodynamic influences (also called “continuous-type deposits”).” Unconventional reservoirs are very complex and characterized by poor quality rocks with very low values of permeability and porosity. In the recent past, it was not economic to extract hydrocarbons from unconventional reservoirs due to technology limitations and unaffordable production costs.

However, the presence of large amounts of hydrocarbons in these formations has been widely

recognized for a long time. And recent advances in technology such as horizontal drilling and

completions including multi-stage hydraulic fracturing jobs have lead to obtaining commercial oil and gas production from unconventional reservoirs. These techniques increase the contact area between the well and the formation, making the production economically feasible. Nevertheless, when it comes to developing an unconventional reservoir, it is vital to understand the geologic aspects, geochemical properties, petrophysics, and production performance of the reservoir. If production history data are available, careful analysis might provide reliable information for calculating the estimated ultimate recovery (EUR), forecasting future production and predicting potential rates of new wells. There are five types of unconventional resources:

• Tight Oil/Gas

• Shale Oil/Gas

• Coalbed Methane

• Gas Hydrates

• Oil Sands

This thesis concentrates on shale oil and shale gas only. In a tight reservoir, oil/gas is trapped particularly in sandstone rocks (sometimes in other lithologies such as carbonates) characterized by very low permeabilities (around 0. 1 mD or less), due to fine grain size and poorly connected pores. Oil/gas migrates from a source rock, which could be a shale, and is trapped in the tight rock.

Their production success relies on wells that contact a significant volume of the reservoir. The best way to achieve this is by drilling horizontal wells and performing hydraulic fracturing jobs.

However, if several sandstone layers are stacked one on top of the other, hydraulically fractured vertical wells might provide better results. Proppants made up of fine sand, or ceramic beads are often used in hydraulic fracturing jobs to prevent closure of the hydraulic fractures when the well is open to production.

Generally, operating companies look for sweet spots in the continuous tight formations. Sweet spots are areas where permeability and porosity are higher than the remaining part of the continuous accumulation. If a well is connected to a sweet spot, it can provide significant production.

In shale reservoirs, petroleum is trapped within organic-rich sedimentary formations characterized by fine-grained rocks and silts. Shales can be plastic. In this case they can stop the growth of hydraulic fractures in conventional reservoirs. However, the shales with good probabilities of commercial oil and gas production are very brittle and can be easily broken into thin and parallel layers. In these cases, shales are both the source and the reservoir rock. Thus, there is no migration to other formations (like in the case of tight oil and tight gas reservoirs) and the hydrocarbons that have been generated in the shale under certain conditions of pressure and temperature remain trapped in the shale.

Shales gas reservoirs are characterized by having the following storage mechanisms (Lopez and

Aguilera, 2013):

1. Free gas trapped in nonorganic inter-particle (matrix) porosity.

2. Free gas trapped in microfracture and slot porosity.

3. Free gas stored in hydraulic fractures created during stimulation of the shale reservoir.

4. Free gas trapped in an intra-particle pore network developed within the organic matter of

kerogen (These items are discussed in more detail later in this thesis).

5. Adsorbed gas in the kerogen material.

For the case of shale oil reservoirs the first four storage mechanisms mentioned above are

dominant. Up to this point there are no documented cases of adsorbed oil in the kerogen material.

The U.S. Energy Information Administration (EIA), in partnership with Advanced Resources

International (ARI), has published extensive reports of the technically recoverable shale oil and shale gas resources in 2011 and 2013; these resources have been assessed in 41 countries in the world as seen in the following figure:

Figure 1-1 Assessed Shale Gas and Shale Oil Resources in the World (from: U.S. EIA, 2013).

According to the report of EIA/ARI (2013), the total technically recoverable shale gas resources are 7,795 trillion cubic feet. The leading countries are United States (1,161), China (1,115),

Argentina (802), Algeria (707), Canada (573), Mexico (545), Australia (437), South Africa (390),

Russia (285) and Brazil (245). The total technically recoverable shale oil resources were estimated at 345 billion barrels of oil. The leading countries are Russia (75), United States (58), China (32),

Argentina (27), Algeria (7.7), Libya (26), Venezuela (13), Mexico (13), Pakistan (9), Canada (9), and Indonesia (8) (From EIA, 2013).

In Mexico, the technically recoverable shale resources according to EIA/ARI (2013) have been estimated as 545 Trillion of cubic feet (Tcf) of natural gas and 13.1 billion barrels of oil and condensate, ranking 6th and 7th largest in the World, respectively. From the 545 Tcf of natural gas assessed in Mexico, over 72% belongs to Burgos basin (393.1 Tcf), making it the primary gas

basin in the country at this time. Table 1-1 and Table 1-2 summarize shale oil and shale gas technically recoverable resources as published by EIA/ARI.

Table 1-1 Top 10 Countries with technically recoverable shale oil resources (EIA, 2013)

Shale Oil Rank Country (Billion barrels) 1 Russia 75 2 U.S.1 58 (48) 3 China 32 4 Argentina 27 5 Libya 26 6 Venezuela 13 7 Mexico 13 8 Pakistan 9 9 Canada 9 10 Indonesia 8 World Total 345 (335) 1EIA estimates used for ranking order. ARI estimates in parenthesis

Table 1-2 Top 10 Countries with technically recoverable shale gas resources (EIA, 2013)

Shale Gas Rank Country (Trillion cubic feet) 1 China 1,115 2 Argentina 802 3 Algeria 707 4 U.S.1 665 (1,161) 5 Canada 573 6 Mexico 545 7 Australia 437 8 South Africa 390 9 Russia 285 10 Brazil 245 World Total 7,299 (7,795) 1EIA estimates used for ranking order. ARI estimates in parenthesis

Coalbed methane, or CBM, refers to methane that is produced from coal beds or seams. Coal beds are both, source and reservoir rocks. Natural gas is generated during the conversion of plant material to coal through burial and heating processes (coalification). Hydraulic pressure, rather than a conventional pressure seal or closed structure, is the dominant trapping force.

Fractures are usually called cleats in coalbed methane reservoirs. Face cleats are continuous throughout the reservoir while butt cleats are discontinuous and terminate at intersections with the face cleats. Cleats are often filled with water. Thus, when a CBM well is open to production, large amounts of water are produced in the dewatering stage. As time goes by, natural gas start desorbing from the matrix into the cleats, travels through the cleats and finally reaches to the wellbore.

Gas hydrate, also known as clathrate, is a frozen crystalline form of water trapping gas of low molecular weight, typically methane. Frozen water hosts molecules forming a cage that can hold gas molecules. Hydrates are thought to be the most abundant sources of natural gas on earth.

According to EIA in their report of Resources to Reserves 2013, one cubic meter of hydrates contains about 164 cubic meters of methane gas at standard conditions. Therefore, gas hydrates can contain gigantic amounts of methane.

Gas hydrates occur mostly in two different geological conditions: (1) arctic (under the permafrost layer) and (2) marine (along continental margins around the world). The development of gas hydrates remains in a research phase. Simulations indicate that depressurization and thermally stimulated methods are promising techniques to produce gas from hydrate reservoirs. In the depressurization case, the pressure of the fluids in contact with hydrates is lowered by putting the well on production. This destabilizes the hydrate leading to its decomposition. In the thermally stimulated method, heat is introduced into the reservoir causing destabilization of the hydrated particles (Pooladi-Darvish, 2004).

This thesis concentrates primarily on the development of Cretaceous and Jurassic shales in Burgos

basin, Mexico. The available data are presented, analyzed, and evaluated; and a comparison is

made with the Eagle Ford shale in Texas. In addition to Burgos, the thesis presents information of

Sabinas, Tampico, Tuxpan (Platform), Veracruz and Chihuahua Basins.

Imperial units are used throughout this thesis, as they are customary in Mexico, except when noted.

1.2 Eagle Ford Shale in Texas

The Eagle Ford (EF) shale is one of the best known shale play reservoirs in the world. It is located in the south of Texas, United States of America. It is a Cretaceous sedimentary rock formation containing up to 70% of carbonates, making it brittle and with a tendency to fracture. The average reservoir and geochemical properties are: Net thickness of 150-300 ft, porosity around 6-14%, permeability of 700-3000 nD, kerogen type II, with a Total Organic Carbon (TOC) average of

2.76% (this and subsequent TOC % values are presented by weight), and vitrinite reflectance (Ro)

from 0.8 to 1.6% (Jarvie, 2012a). Since 2008, the eagle Ford shale has been producing a wide

range of hydrocarbons, from dry gas to oil. According to the Railroad Commission of Texas, the

discovery well was hydraulically fractured in 10 stages, and flowed natural gas at a rate of 7.6 million cubic feet per day from a 3,200-foot lateral.

Although the Eagle Ford shale in Texas has probably been the most penalized in the U.S. because of recent low oil prices, as compared to other shale plays in the country, successful activities stemming from drilling of horizontal wells and completions using multi-stage hydraulic fracturing jobs suggest that the potential of shale reservoirs south of the border will be quite significant. This observation inspired the preparation of this thesis.

Figure 1-2 Eagle Ford map June 2017 (source: https://eaglefordshale.com/)

1.3 Eagle Ford Shale in Mexico

The exploration of unconventional resources began in northern Mexico in 2010 with the main objectives of corroborating the continuation of the Texas Eagle Ford shale into Mexico, and testing the Pimienta formation. Results of the initial wells attracted interest in the development of

unconventional reservoirs in Mexico. However, oil and gas exploration requires large investments,

new technologies, safe work conditions and the experience of qualified personnel that can be

obtained by hiring private companies. In the past Mexican laws have prohibited foreign firms to

bid on these types of contracts. But currently, Mexico is undergoing an Energy Reform that will

allow PEMEX to partner with private investors through different types of contracts (Suarez et al.,

2016). Mexican challenges to increase reserves in different types of Mexican reservoirs have been

discussed by Escalera Alcocer (2010), but only a few recommendations have been implemented

in PEMEX. Consequently, a great amount of work is needed to define geologic sweet spots, drill

horizontal wells effectively, and design stimulation treatments that can deliver large-scale

commercial production (Stevens and Moodhe, 2015).

One of the PEMEX objectives is to reduce drilling and completion costs as a key development strategy, to incorporate the experience of the Eagle Ford shale in Texas, to improve the learning

curve for Mexican plays, to create a massive strategy for developing Mexican shale prospects, to

continue the evaluation phase, and to expand the shale oil/gas potential. This strategy is based on

the 2014 Wet Gas and Liquid Hydrocarbons program by PEMEX (updated in the 2015 Annual

Report), which anticipates drilling of about 29 shale wells from 2015 to 2019.

Figure 1-3 shows the location of the basins considered in this thesis including from north to south

Chihuahua, Sabinas-Burro-Picachos, Burgos, Tampico-Misantla-Tuxpan (Platform), and

Veracruz basins. However, the main focus of this thesis is the Burgos basin, which has the largest

amount of available information at the time of this writing, although the play is barely getting

started. The one with the least amount of information is the Chihuahua basin. This will be the last

one to be discussed in this thesis. In my view, however, there is significant unconventional

potential in all of these basins that I anticipate will help to change the slope of production rates in

the country from negative to positive. Innovations such as refracturing (Urban et al., 2016), gas recycling and dry gas injection (Fragoso et al., 2015) will help to achieve the production increase goal. I anticipate that this will lead Mexico to become an important part of the shale petroleum revolution initiated in the U.S.

Notice that there are other basins not highlighted with black arrows that are not considered in this thesis.

Chihuahua Sabinas – Burro Picachos

Burgos

Tampico – Misantla - Tuxpan

Veracruz

Figure 1-3 Shale gas and oil basins of Eastern Mexico (Source: http://portal.cnih.cnh.gob.mx/iicnih/?lng=en_US).

Figure 1-4 Stratigraphic column of Mexican Basins including kerogen type and TOC (PEMEX E&P, 2012)

The stratigraphic column of the Mexican basins considered in this study is presented in Figure

1-4. In the legend, carbonates including limestones and dolomites are dominant but shales with good production potential are also omnipresent in all the basins considered in this study. Kerogens of mostly Type II and III are present in the Upper Jurassic (Tithonian) in all the basins, and also in the Devonian Woodford in the Chihuhua basin. The smallest reported Lower Jurassic TOC is

0.5%. The largest is in the Tampico-Misantla basin with a TOC = 8%. Burgos is shown to have a

TOC = 3.8%. Lower Jurassic shales in Chihuahua and Sabinas basins are known by the name of

La Casita. In the Burgos and Tampico-Misantla basin they are known as Pimienta shales. A comparison of the properties shown in Figure 1-4 and properties from Texas shales is provided later in this work.

In the Upper Cretaceous (Turonian) all the shales contain Kerogen of Type II. In the Chihuahua

basin shale, it is known as Ojinaga and has a TOC ranging between 0.5 and 2%. In the Sabinas

(TOC = 1 to 4%) and Burro Picachos (TOC = 2 to 4%) basins the shale is known as Eagle Ford.

In the Burgos (TOC = 1 to 3%) and Tampico-Misantla (TOC = 0.5 to 8%) basins the shale is

known as Maltrata. Finally, in the Veracruz (TOC = 0.5 to 8%) basin the shale is known as

Maltrata. Values of TOC going up to 3.8% in Burgos and 8% in Tampico-Misantla and Veracruz

suggest that the shale potential in Mexico is quite significant. Where data are available, Barrera

(2013) has reported Source Potential ranging between 2.5 and 5 mg HCs/g of rock.

1.4 Cumulative Long Run Supply Curves

These curves are presented as crossplots of recoverable volumes in the abscissa vs. production

costs in the ordinate. The recoverable volumes (endowment) are estimated with a Variable Shape

Distribution (VSD) model (Aguilera, 2006; Aguilera et al., 2009). The VSD is a size distribution

model that estimates petroleum recoverable volumes in previously unassessed areas. The VSD

uses input data from other resource assessments, and provides a match via non-linear regression.

The model is then extended out of sample to include areas not considered by the other studies.

Details can be found in Aguilera and Aguilera (2015). The production costs in the cumulative long run supply curves come from many sources including extensive research/communication with operating companies (the bulk of this research information is provided by companies on a confidential basis), and companies financial statements and financial reports. It is important to emphasize that the objective of the endowment cumulative long run supply curves is to examine the big picture potential of a given area or globally. However, the usual petroleum engineering

detailed economic analysis including for example capex, opex, anticipated oil and gas prices, and forecasted production rates, among others, are required for each individual project.

Despite the current low-price environment for hydrocarbons, the world supply cost curves presented by Aguilera and Aguilera (2015) indicate that significant volumes of unconventional gas and oil are available at or below current prices; and that small increases in prices can add substantial recoverable volumes of unconventional oil and gas. Historically, oil production costs have fluctuated as influenced by the cost-increasing effects of depletion versus the cost-reducing effects of technological progress. What we are learning from the recent past is that the cost- reducing effects of technology and innovation are in the lead and this technology can have direct application in the case of unconventional reservoirs in Mexico. As indicated previously, on-going research that could prove to be of significant value in unconventional reservoirs includes refracturing (Urban et al., 2016) and improved recovery of liquid through gas injection (Fragoso et al, 2015). These advances could help change the petroleum production curves in Mexico from negative to positive. The Mexican shales are continuous accumulations. Their potential is highlighted by the fact that data available at this time for up to 5+ years of production shows continuous transient linear flow without any indications of reaching boundary dominated flow.

Endowment is defined by the United States Geological Survey (USGS, 2010) as the sum of known volumes of oil and gas (cumulative production plus remaining reserves) and undiscovered volumes. We choose to use the term ‘endowment’ in this thesis as done by the USGS because development of Mexican shales is in its infancy. However, it is noted that endowment is approximately equivalent to cumulative production plus proved, probable, and possible reserves, plus contingent and prospective resources as defined by the PRMS (Chan et al., 2012).

Aguilera (2014) has presented worldwide gas and oil endowment pyramids that include

conventional and unconventional resources. It is observed that the natural gas endowment is

enormous, approximately 68,000 trillion cubic feet (tcf), of which around 70% is found in tight

(15,100 tcf) and shale gas (32,600 tcf) reservoirs, being the latter even larger than gas found in conventional reservoirs. The gas pyramid is shown in Figure 1-5, which also displays that unconventional gas is related to very low permeabilities, typically below 0.1 mD. The oil endowment pyramid is shown in Figure 1-6. Notice that in both, the gas and oil endowment cases, the bottom of the pyramids is unknown.

Figure 1-5 Estimates of global natural-gas endowment (from Aguilera et al. 2014, GFREE Research team).

Figure 1-6 Estimates of global oil endowment (from Aguilera et al. 2014, GFREE Research team).

Unconventional reservoirs must be hydraulically fractured to deliver commercial production rates.

Therefore, development of these formations has represented a technological and economic challenge in the past due to increases in production costs, activation indexes, research, and time.

The activation index is a measure of the total investment required to establish access to new oil or gas expressed in dollars per unit volume per day (Economides and Ronald, 2000). Recent data, however, shows that costs have been decreasing significantly, making unconventional plays economic in many instances despite low oil and gas prices.Figure 1-7 presents a cumulative long run supply curve for shale gas as a cross plot of average total production costs (including capital

and operating costs) vs. shale gas recoverable volume (this is equivalent to shale gas endowment

utilizing the UGSS terminology). A variable shape distribution model (VSD)1 calculates a world endowment of 22,000 trillion cubic feet of shale gas (Aguilera and Aguilera, 2015). This is the maximum endowment shown in Figure 1-7. Data for Mexican basins have been filtered from the world graph – using the specific costs and quantities related to Mexico from the data in Aguilera and Aguilera (2015) – and are presented in the insert of Figure 1-7. It is noticed in the insert that the shale gas recoverable volumes based on the VSD is in the order of 2,400 TCF, much larger than those published by PEMEX and EIA/ARI. These estimates will be shown and explained in the next chapter.

1 The VSD is a size distribution model developed in Aguilera (2006). It estimates petroleum volumes in previously unassessed areas. The VSD uses input data from other resource assessments, and provides a match via non-linear regression. The model is then extended out of sample to include areas not considered by the other studies. Details can also be found in Aguilera and Aguilera (2015). 16

12 50 MEXICAN SHALE GAS 10 WORLD SHALE GAS

8 40

4 30 2 Production Cost (USD / MCF)

0 20 0 500 1000 1500 2000 2500 Shale Gas Recoverable Volume (TCF)

10 Production Cost (USD / (USD Cost MCF) Production

0 0 5000 10000 15000 20000 Shale Gas Recoverable Volume (TCF)

Figure 1-7 World cumulative long run supply curve for shale gas (Aguilera and Aguilera, 2015). Insert developed in this study for Burgos, Sabinas, Tampico, Tuxpan (Platform), and Veracruz Basins.

A world cumulative long run supply curve for shale oil is shown in Figure 1-8 (Aguilera and

Aguilera, 2015). The quantities are vast, about 650 billion barrels as previously estimated by the

VSD model, and the costs of producing some of the endowment are below current market prices.

The average cost of production for shale oil in Mexico was estimated at around $60/bbl in 2014

(IHS, 2014), though there is a wide range. Estimated data for Mexican basins are presented in the insert of Figure 1-8. In the current low-price environment, costs have come down with some of the reductions likely to remain due to improved technology. However, the costs of field services and equipment are cyclical and expected to rise somewhat as prices and development activity pick up.

350

200 MEXICAN TIGHT/SHALE OIL 300 180 WORLD TIGHT/SHALE OIL 160 Tight/Shale Oil = 650 BBOE 140 250 120 100 80 200 60 40

Production Cost (USD /BOE) 20 150 0 0 10 20 30 40 50 60 Tight/Shale Oil Recoverabe Vlolume (BBOE)

100

50 Production Cost (USD / BOE)

0 0 100 200 300 400 500 600 700 Tight/Shale Oil Recoverable Volume (BBOE)

While some portions of the supply curves show quantities that can be produced economically, challenges include high drilling and completion costs, and lack of availability of inputs such as water for fracturing. As with all resource development, cost-reducing technology will be needed to tap the significant potential.

1.5 Research Objectives

The main objective of this thesis is the evaluation of the Cretaceous and Jurassic shales in Burgos basin in Mexico. This objective was achieved by:

1. Examining geochemical information by assessing the hydrocarbon’s content, producibility

and maturation of the system through different techniques.

2. Evaluating geophysical logs to determine petrophysical and geomechanical properties

including the total organic carbon (TOC) content of shale, porosity, permeability, water

saturation, Young’s Modulus, and Poisson’s Ratio.

3. Analyzing production and pressure data using production decline analysis and rate transient

analysis.

4. Integrating the results provided by geochemical, petrophysical and production analysis for

a complete and reliable model that can assess the potential of the Cretaceous and Jurassic

shales in Burgos basin in Mexico.

1.6 Thesis Organization

The thesis is divided into eight chapters. Chapter 1 (this chapter) is the introduction, which includes basic concepts of unconventional reservoirs, a brief explanation of the Eagle Ford shale in Texas, as well as an explanation of the five unconventional basins that had been identified in Mexico. The stratigraphic column of all the basins is presented showing kerogen type and TOC in each formation. Information regarding long run supply curves for the world and Mexican basins is included.

Chapter 2 includes a literature review about shale development in Burgos basin. When and how the exploration of shale reservoirs in Mexico was started as well as the results obtained from the wells that were drilled and completed. This chapter also explains the difficulties of exploiting those reservoirs and discusses the similarities with the Eagle Ford shale in Texas, USA. A table of estimates of shale gas and shale oil resources based on studies carried out by PEMEX and EIA/ARI

is presented and reviewed.

Chapter 3 presents the geochemical concepts and methodologies that had been used when characterizing unconventional shale oil and gas reservoirs. Hydrocarbons content, producibility and maturation of the system is evaluated with different techniques. Results are discussed.

Chapter 4 discusses the petrophysical properties calculated from well logs for each source rock

(Jurassic and Cretaceous periods) in Burgos basin, and how this information can be corroborated with results obtained in Chapter 3.

Chapter 5 focuses on production decline analysis and rate transient analysis for the two main formations. Estimates of ultimate recovery are included.

Chapter 6 is about other unconventional basins in Mexico and describes the geological and engineering aspects of each basin. Data about resources and production up to now is provided.

Chapter 7 integrates the information of geosciences, engineering and economics obtained from chapters 3, 4, 5 and 6. A summary of each formation is presented. Continuity of U.S. Eagle Ford in Mexico is corroborated through the use of Pickett Plots.

Chapter 8 states the conclusions and recommendations stemming from this thesis, highlighting the importance of a proper characterization of shale gas and shale oil reservoirs.

1.7 Technical Publications

Part of the research developed by the author in this thesis has been presented at the following SPE conference:

• Cruz, M., Urban, E., Aguilera, R. F., and Aguilera, R. (2016). Mexican Unconventional

Plays: Geoscience, Endowment and Economic Considerations. SPE/URTeC Paper

2460927 presented at the Unconventional Resources Technology Conference held in San

Antonio, Texas, USA, 1-3 August 2016. In press: SPE Reservoir Evaluation and

Engineering – Formation Evaluation (2017).

• Cruz, M., Aguilera, R. (2017). Linking the Emerging Mexican Eagle Ford Shale in Burgos

Basin with the Eagle Ford in Texas, for the First EAGE/AMGP/AMGE Latin-American

Seminar in Unconventional Resources in Mexico City, 23-24 November 2017.

• Cruz, M., Aguilera, R. (2018). Eagle Ford and Pimienta Shales in Mexico: A Case Study.

SPE paper 189797-MS for the SPE Unconventional Resources Conference in Calgary,

Alberta, Canada, 13-14 March 2018.

Chapter Two: Review of Literature

Burgos is considered the primary shale gas basin in Mexico. Due to the commercial success

obtained in wells completed in the Eagle Ford shale in Texas, shale exploration activity began in

Burgos basin in 2010. This literature review covers mainly geologic and engineering aspects,

including details and results of wells that have been completed in Burgos basin, and their

performance to date.

2.1 Geologic Aspects

Situated in the northeastern part of Mexico in the states of Coahuila, Tamaulipas and Nuevo Leon

(please see Figure 1-3 in Chapter One), Burgos basin was originated in the early Tertiary period

and covers an area of approximately 110,000 km2. Presently the major activity is centered in the

onshore part in an area of approximately 30,000 km2 (PEMEX E&P Provincia Petrolera Burgos,

2013). Geologically, it extends to the north into the Río Grande Embayment in the U.S. Thick

sediments from the Mesozoic and Cenozoic eras have been deposit through different periods of regional compression and extension, in addition to the deformation created by shale and salt diapirs

(Perez Cruz, 1993). During the early Mesozoic era, Burgos was exposed to extensional tectonic regimes associated with the opening of the Gulf of Mexico. The Laramide Orogeny, developed at the end of the Cretaceous period and during part of the Cenozoic era, caused uplift and folding in the western part of the basin, giving origin to the Fold-Thrust Belt of the Sierra Madre Oriental and the development of foreland basins, including the Burgos basin. (PEMEX E&P Provincia

Petrolera Burgos, 2013).

Production Strips Paleocene (Midway – Wilcox) Lower Eocene (Wilcox- Queen City) Upper Eocene (Yegua - Jackson) A Lower Oligocene (Vicksburg) Upper Oligocene (Frio Marino) Eocene Wilcox Paleocene Midway E.M.C. A Eocene Queen City Paleocene Wilcox Eocene Jackson Oligocene Vicksburg Miocene formations Oligocene Frio Eocene Wilcox Fault Yegua Fault Queen City Fault Vicksburg Fault

Paleocene Lower Eocene Upper Eocene Lower Oligocene Upper Oligocene Production Strips A Midway Wilcox- Queen City Yegua - Jackson Vicksburg Frio Marino A C F H A D G B B E A G C I D Creta ceous Jurassic

Figure 2-1 Upper graph shows five production strips trending approximately N-S in the Burgos basin. Lower graph shows structural cross section A-A’ (PEMEX E&P Provincia Petrolera Burgos, 2013).

According to the stratigraphic and structural geometry, the basin can be subdivided geologically

into five elongated and subparallel N-S production strips that obey primarily marine regressions

and extensional faulting activity. These strips, shown in Figure 2-1 Upper graph shows five

production strips trending approximately N-S in the Burgos basin. Lower graph shows structural

cross section A-A’ (PEMEX E&P Provincia Petrolera Burgos, 2013)., are referred to as the

Jurassic and Cretaceous strip, Paleocene strip, Eocene strip, Oligocene strip, and Miocene strip

(Echánove, 1986). The two prospective shale targets are the Upper Cretaceous (Eagle Ford and

Agua Nueva formations) and the Upper Jurassic (La Casita and Pimienta formations) as shown in

Figure 1-4 in Chapter One.

The EIA (2013) based on an analogy with the Texas Eagle Ford Formation, determined that the

net organically-rich shale thickness within the prospective area in Burgos basin ranges from 200 to 300 ft. However, recent exploration wells amplified the range from 100 to 300 ft. The total

organic content (TOC) ranges from 1.95 to 6% and the effective porosity from 1 to 9%. (Parra et

al. 2013). The EIA (2013) reported that the vitrinite reflectance (Ro) ranges from 0.85% to 1.6%

depending on depth. Most of the reservoirs in the formation are over-pressured with a gradient assumed to be in the order of 0.65 psi/ft. Advanced Resources International (ARI) identified the

Eagle Ford Shale in the Burgos Basin to be Mexico’s top-ranked shale prospect (EIA, 2013).

Morales Velasco et al. (2010) have also presented an assessment of the Eagle Ford shale in the

Burgos basin.

PEMEX made its first shale discovery in the Burgos Basin during the late 2010 and early 2011 while trying to prove the hydrocarbon continuity of the Eagle Ford Shale between Texas and

Mexico. Horbury et al. (2013) estimated the overall formation interval across the western margin of the Burgos Basin to range from 100 to 300 m in thickness. This objective of proving hydrocarbon continuity was achieved by drilling the Emergente-1 well in the wet gas window. The well is located a few kilometers south of the Texas/Coahuila border. This was followed by wells

Habano-1 and Montañés-1 in the limits of the oil and wet gas windows, and Nómada-1 in the oil

window, which resulted non-productive. Figure 2-2 shows a seismic section that includes well

Emergente-1 and four U.S wells drilled through the Eagle Ford shale in Texas.

2.2 Engineering Aspects

The exploitation of conventional reservoirs in the Burgos basin began in 1942. To date, 227 fields have been discovered (mostly natural gas). These conventional reservoirs typically have low permeability and are characterized by rapidly declining gas production. On the unconventional side, PEMEX has identified 133 exploration opportunities.

Eagle Ford shale gas well Emergente-1 (Figure 2-2) was hydraulically fractured in 17 stages using

8 million gallons of slick-water and 42,563 sacks of quartz sand proppant (Parra et al., 2013). The stimulation treatment design was based on log analysis, laboratory evaluation of cores, mineralogy

(X-Ray Diffraction and Scanning Electron Microscopy), capillary suction tests, and triaxial geomechanical tests, that helped to characterize the Eagle Ford shale in Mexico. Nonetheless,

Araujo et al. (2011) stated that running a Diagnostic Fracture Injection Test (DFIT) was the key to

succeed in the treatment. The investment for drilling well Emergente-1 was significant (US $20-

25 million). The well flowed at an initial rate of 2.8 MMcf/d through a 18/64” choke (time interval

not reported), which was not economic with current gas prices (EIA, 2013). The lateral was

oriented due south and positioned in the organic-rich lower Eagle Ford zone, where TOC reaches

4.5%. However, the learning-curve in the area has been good. The Emergente-1 was drilled completed in a total of five months, while the new wells in the area can be drilled and completed in about one month (Stevens and Moodhe, 2015).

After the successful technical (but not economic) results obtained in Emergente-1, well Nómada-

1 was completed in the oil window of Eagle Ford formation, but unfortunately, the well resulted non-productive.

Two years later, well Montañés-1 was drilled in the upper Eagle Ford Shale with an azimuth mostly parallel to the expected minimum horizontal stress direction and measured a pressure of 2800 psi, temperature of 169 °F, permeability of 200 nD, effective porosity of 1 to 8% and an average TOC of 1.95%, which increased from 2.71% to 6% the lower Eagle Ford. The well was hydraulically fractured with 14 stages at 55 bpm injection using 180,000 lb of white sand per stage and 2.5 million gallons of fracturing fluid (Parra et al. 2013). Subsequent Eagle Ford Shale wells in the northern Burgos basin tested low-moderate oil and gas rates, much lower than the rates obtained in the Pimienta Formation in the southern part of the Burgos basin. However, it is not clear whether the poorer results in the north are due to tighter rock quality or perhaps less efficient fracture stimulation designs (Stevens and Moodhe, 2015). Well Gamma-1 was drilled in mid-2013 and is considered the well with the maximum horizontal length of 2200 m (Figure 2-3). It produced disappointing rates of about 0.3 MMcf/d and 12 bpd of oil from the Eagle Ford shale.

Figure 2-3 Horizontal length and depth of exploration wells drilled in the Eagle Ford shale (PEMEX E&P, 2014).

Following Montañés-1, well Habano-1 was drilled 1 in the Mexican Eagle Ford shale and

Anhélido-1 in the Pimienta formation. The Habano-1 was drilled at 3770 m (MD), which corresponds to TVD of about 2,064 m, with a lateral length of approximately 1,493 m. The estimated reservoir properties stemming from this well are as follows: pressure 4,000 psi,

temperature 167 °F, permeability ~200 nD, effective porosity from 3 to 9% and TOC from 3 to

5% (Parra et al., 2013). Martinez Contreras (2015) characterized the formation as having a micritic

matrix with detrital clay, planktonic foraminifera, sealed with calcite and authigenic clay, and

occasional pyrite. Samples measured 54% calcite, 18% quartz, and 19% clay with 9% other

minerals.

The Habano-1 well was hydraulically fractured with 16 stages and five perforation clusters per stage. The first eight stages were hydraulically fractured using slick-water. Due to some pressure

spikes observed during these stages, the remaining stages used a combination of slick-water and

linear gel to place the proppant in the shale formation. The hydraulic fracturing jobs were pumped

at 65 barrels per minute (bpm), using a total of 350,000 lb of white sand per stage and

approximately 5.1 million gallons of fracturing fluid. The production test yielded a maximum gas

production of 4.6 MMcf/d and a maximum condensate production of 146 barrels per day (bpd)

while flowing by 28/64” and 26/64” chokes, respectively (Parra et al., 2013). The average wellhead

pressure was 2,265 psi. Interval 3,703 to 3,643 m showed commercial production capacity with an

initial production of 2.771 MMcf/d gas and 27 bpd crude. The volume of production justified the

drilling of three more wells (Habano-21, 71 and 2) that are in production.

The next horizontal well, Anhélido-1, tested the Pimienta formation. Stevens and Moodhe (2015)

with a large database established that “the Pimienta Formation is composed of marine-deposited black shale and shaly limestone containing Type II/III kerogen, divided into four intervals with varying concentration of carbonate mineralogy and TOC richness that ranged up to 4%. Tmax ranges from 450 to 454°C, which indicates a condensate to wet gas thermal maturity. The X-Ray

Diffraction measured favorably brittle mineralogy: 70% calcite, 1% dolomite, 10% quartz, and

11% illite clay.” Subsequently, based on XRD mineralogy, petrophysics and well log analysis,

Granados-Hernandez at al. (2017) indicated that oil prone kerogen type II was the most common and that TOC ranged from 0.5% to 8.5%, weight %. They also identified four lithological members with the following rock properties: porosity ranging from 1 to 19% (6% average); hydrocarbon

saturation from 35 to 95% (70% average); bulk volume hydrocarbon from 1 to 13 (4% average),

and matrix permeability ranging from 2.5 nD to 4.6 µD.

Well Anhélido-1 was stimulated with 17 stages and five perforation clusters about 1 m long, 20 deep-penetrating shots per meter, 60° phased (Stevens and Moodhe, 2015). The job was performed with a uniform injection using a total proppant mass of 5.1 million lb sand and 12 million gallons of fracturing fluid. The fractured interval is characterized by low clay content and high TOC. It is brittle and homogeneous with a medium-strong fracture gradient from 0.92 to 1.02 psi/ft. The estimated propped fracture length and height were 133 m and 95 m, respectively (Stevens and

Moodhe, 2015).

The initial production test achieved a maximum rate of about 500 bpd of 37° API oil with 1.5

MMcf/d of wet gas (24-hour rate). These rates dropped rapidly but stabilized at 80 to 90 bpd and

0.6 MMcf/d of gas after one year with a cumulative production of about 40,000 bbls and an estimated ultimate recovery (EUR) of over 100,000 bbl. (Stevens and Moodhe, 2015). Granados

Hernandez at al. (2017) calculated a slightly larger EUR of 120,000 bbls of oil and 0.9 Bscf of gas in 20 years. They made a comparison of various shale formations and observed that Pimienta has approximately twice the thickness of the Eagle Ford shale (Table 2-1). They further indicated that the resource base in Pimienta is around 2.6 MMBOE/mi2, which is larger as compared with Eagle

Ford, Avalon & Bone Springs, and Bakken shales. Although probably not economical at this time,

results in this formation show that there are outstanding opportunities in the Burgos basin. Based on experience in the Eagle Ford shale in Texas it is anticipated that there will be increases in productivity with advances in the learning curve. The learning curve includes many different issues such as hydraulic fracturing, completions, surface instalations and the general modus operandi.

Table 2-1 Comparison of Shale Formations (from Granados Hernandez et. al, 2017). Resource concentration Play Depth (ft) Thickness (ft) Porosity (%) TOC (%wt) (MMBOE/mi2) Pimienta 2,950-15,740 460 2-9' 3 2.6 Eagle Ford 7,000 200 9 4.25 1.0 Avalon & Bone Springs 8,750 1,300 - - 1.2 Bakken 6,000 22 8 - 0.6 Monterey/Santos 11,250 1,875 11 6.5 8.8

*Compiled from: EIA,2011; EIA/ARI, 2013

In 2013, six exploration wells were drilled parallel to the trace of the first wells expanding the

prospective limits. Well Tangram-1 encountered 215 m of Pimienta shale in the dry gas window.

The well produced dry gas at 10.9 MMcf/d, the highest rate for a shale gas well in Mexico so far.

In 2014 horizontal wells Cefiro-1, Nerita-1, Batial-1, and Mosquete-1 were completed with multi- stage hydraulic fractures in the Pimienta shale. The last well on record now, the Serbal-1, was completed in 2015. Table 2-2 summarizes the principal characteristics of the exploration wells in the Burgos Basin. The location of these wells is presented in Figure 2-4 Location of 18 exploration wells drilled from 2010 to 2015 in Burgos and Sabinas Basins (Modified from PEMEX E&P,

2014).

As indicated above the exploration wells were stimulated in highly brittle intervals but high fracture gradient 0.92 to 1.02 psi/ft. However, Medina Eleno and Valenzuela (2010) carried out a hydraulically fracturing job, and years later performed a refracturing operation in the overlying

Eocene tight sandstones with a low fracture gradient of 0.58 psi/ft. The fracture closure pressure was 6,150 psi at a depth of 3,217 m. This is an indicator of effective fracturing and refracturing

jobs to be kept in mind for future stimulations in the Burgos Basin (Stevens and Moodhe, 2015).

Water requirement to perform the stimulations is one of the major concerns in the program.

PEMEX expects to reduce the water requirement to half the volume for every treatment, and to recycle the water used in explorations wells, such as Habano-1 and Arbolero-1.

Table 2-2 Characteristics of the exploration and exploitation shale gas wells in Mexico (Modified from Dominguez-Vargas, 2014 and Comisión Nacional de Hidrocarburos, CNH, 2016).

PROD OIL EXPLORATION DEPTH FRAC GAS PROD YEAR INTERVAL RESULT PROD OBJECTIVE WELL M STAGES MMCF/D M BPD

Commercial Dry 2010 Emergente-1 4071 3,618-3,670 17 2.8 Eagle Ford Gas 2011 Nómada-1 2850 2,806-2,737 Dry Hole 16 Eagle Ford Non Commercial 2012 Montañés-1 3200 3,155-3,080 14 0.1 Eagle Ford Gas Condensate Commercial Dry 2012 Percutor-1 3436 3,330-3,390 16 2.2 Eagle Ford Gas Commercial Gas 2012 Habano-1 3770 3,703-3,643 16 2.8 27 Eagle Ford Condensate Commercial Dry 2012 Arbolero-1 4007 3,878-3,825 11 3.1 Pimienta Gas Commercial Oil 2012 Anhélido-1 3550 2,847-2,922 17 1.9 333 Pimienta and Gas Commercial Gas 2013 Chucla-1 4100 3,560-3,645 16 1.9 24 Eagle Ford Condensate Commercial Dry 2013 Durián-1 4200 4,155-4,215 18 1.9 Eagle Ford Gas Commercial Dry 2013 Nuncio-1 4900 4,821-4,865 2.9 Eagle Ford Gas Non Commercial 2013 Gamma-1 3793 3,690-3,740 0.3 12 Eagle Ford Gas Condensate Commercial Dry 2013 Kernel-1 4404 4,292-4,364 2.8 Eagle Ford Gas Commercial Dry 2013 Tangram-1 4426 4,320-4,400 10.9 Eagle Ford Gas Non Commercial 2014 Batial-1 4196 4,110-4,160 Dry Gas Commercial Dry 2014 Céfiro-1 4700 4,502-4,560 Gas 2014 Mosquete-1 4181 4,030-4,094 Dry Hole Non Commercial 2014 Nerita-1 3810 3,922-4,013 Dry Gas Non Commercial 2015 Serbal-1 4800 4,620-4,715 Wet Gas Oil Exploitation Gas prod prod Wells MMcf/d BPD 2012 Habano-21 2725 Gas Condensate 2.3 23 Eagle Ford

2012 Habano-71 3682 Gas Condensate 1.5 40 Eagle Ford

2013 Habano-2 3505 Gas Condensate 0.9 28 Eagle Ford

2013 Anhélido-2 3450 Oil and Gas 1.8 330 Pimienta

Figure 2-4 Location of 18 exploration wells drilled from 2010 to 2015 in Burgos and Sabinas Basins (Modified from PEMEX E&P, 2014).

2.3 Resources

Commercial production from conventional reservoirs started in 1945 with the discovery of the

Mision field. Production was gas condensate in the Vicksburg play. Pemex started exploring for

gas-rich and liquid-rich shale reservoirs in Burgos basin in 2010. Two shale targets were the initial steps of the exploration program: Eagle Ford (Cretaceous) and Pimienta (Jurassic) shales.

Emergente-1 was the first shale gas well to be drilled horizontally. It is located on the border of

Texas/Coahuila just south of the Rio Grande. Its initial production rate was 2.8 MMcf/d

(Dominguez-Vargas, 2014). It proved to be a very important well because it highlighted the shale

potential in Mexico as it corroborated the continuity of the Eagle Ford trend from Texas to Mexico.

The production history of well Emergente-1 is shown in Figure 2-5.

By 2012, three more wells had been completed in the Mexican Eagle Ford shale (Montañés-1,

Nómada-1 and Habano-1), and one well in the Pimienta formation, the Anhélido-1 that produced

oil and gas. The oil and gas production of well Anhélido-1 is presented in Figure 2-1. The well

was closed after 431 days due to budget constraints (Granados-Hernandez et al., 2017). The gas

production of Habano field is shown in Figure 2-7. The well Habano-1 is still producing at a rate

of 0.31 MMcf/d. These wells corroborated the existence of gas in these formations and were

instrumental for preparing plans for the development of these fields (Parra et al., 2013).

Prospective resources are undiscovered hydrocarbon volumes that are expected to be recovered

with an exploratory strategy. Prospective resources of Burgos Basin including oil, condensate and

dry gas in 2013 were 10.8 billion boe (PEMEX E&P, 2014). A complete summary of results

presented by PEMEX as well as the Energy Information Administration (EIA) is presented in

Table 2-3.

Figure 2-5 Production history of the Emergente-1 well (CNH, 2016).

Figure 2-6 Production history of the Anhélido-1 well (CNH, 2016).

Figure 2-7 Production history of the Habano field (CNH, 2016).

Four more unconventional basins in Mexico have also been identified. Their geological and reservoir properties are discussed in Chapter 6.

2.4 Summary of Published Shale Resources

In 2012, due to the success of wells completed in the Eagle Ford shale in Texas, PEMEX made its

evaluation of oil and gas resources in Mexican shales.

The parameters and methods that were used by PEMEX to calculate the oil and gas resources

remain undisclosed. But in 2013, EIA/ARI published a document where they presented their

estimates of oil and gas resources in Mexico. In their document, they showed the properties they

used to arrive at their resource estimates.

Table 2-3 summarizes results of the studies published by PEMEX in 2012 and the EIA/ARI in

2013. The results are different, but in both instances, there are important indications of oil, wet gas

and dry gas in the Mexican basins considered in their studies. It must be noted that at the time

PEMEX and EIA/ARI made their evaluations, there were limited geologic data and reservoir

information, which obviously affected the estimated volumes. As exploration and development of

shale resources are in their infancy in Mexico, it is likely that the volumes shown in Table 2-3 are conservative.

Based on experience in the United States, it is anticipated that optimization of completions, hydraulic fracturing jobs, refracturing (Urban et al., 2016) and improved recovery methods

(Fragoso et al. 2015) will lead to larger recoveries of oil and gas, as discussed in more detail in

Chapter 5 dealing with production decline analysis.

Table 2-3 Estimated Shale gas and shale oil resources based on studies carried out by PEMEX (2012) and EIA/ARI (2013).

PEMEX's Prospective Resources EIA/ARI 2013 Technically Recoverable Resources

Basin Oil Wet Gas Dry Gas OE Oil Assoc. Gas Wet Gas Dry Gas

[Bbo] [Tcf] [Tcf] [MMMboe] [Bbo] [Tcf] [Tcf] [Tcf]

Burgos 0.0 9.5 44.3 10.8 6.34 0.90 111.60 280.60

Sabinas -Burro Picachos 0.6 6.6 60.4 14.0 0.00 123.80

Tampico Misantla 30.7 20.7 0.0 34.8 5.52 4.70 9.50 9.00

Tuxpan 0.97 1.50

Veracruz 0.6 0.0 0.0 0.6 0.28 0.50 2.90

Chihuahua Under evaluation

Total 31.9 36.8 104.7 60.2 13.11 7.60 121.10 416.30

A summary of this Chapter is also found in the petroleum engineering literature (Cruz et al. 2016;

Cruz and Aguilera, 2017, 2018).

Chapter Three: Geochemistry in Burgos basin

3.1 Introduction

Geochemistry is an important branch of geoscience with strong application on the evaluation of

potential oil and gas prospects. Information provided by geochemistry allows determining the

organic richness, quality and thermal maturity of a source rock. A source rock is defined as a fine-

grained, organic rich rock that is capable of generating petroleum. However, not all source rocks

are considered economical; hence the importance of evaluating its potential. In this chapter,

different screening methods are reviewed and applied to the two source rocks present in Burgos

basin.

3.2 Definition of a Shale

The concept of Total Petroleum System (TPS) was introduced by Magoon and Beaumont (1999)

and Magoon and Schmoker (2000) to integrate all the geologic elements and required processes

for a hydrocarbon accumulation to exist. In a TPS, the word “Petroleum” includes high

concentrations of thermal and biological hydrocarbon gas, condensates, crude oils and natural

bitumen. According to Magoon and Beaumont (1999), geologic elements in hydrocarbon

generation include a source rock, reservoir rock, seal rock and overburden rock; and the processes

include trap formation and generation/migration/accumulation of hydrocarbons. A shale resource

system is a continuous accumulation that generally comprises large amounts of hydrocarbons that are generated and remain within the shale. Thus, the shale resource system is at the same time source and reservoir rock.

The Alberta Energy Regulator defines a shale as a “lithostratigraphic unit having less than 50% by weight organic matter, with: less than 10% of the sedimentary clasts having a grain size greater

than 62.5 micrometers; and more than 10% of the sedimentary clasts having a grain size less than

4 micrometers” (Oil and Gas Conservation Regulation, OGCR).

Figure 3-1 shows the most important shale plays in the world. Numerous studies have been

performed in Canada, USA and Mexico in efforts to evaluate the potential of these plays. Some of

these studies take advantage of knowledge acquired through drilling and production of thousands

of hydraulically fractured vertical wells in Devonian shales of the Appalachian basin. It must be

noted that Devonian shales production was proved in the US as early as 1821.

There are two types of shale systems (gas and oil), which are defined, as shale gas or shale oil,

depending on the predominant fluid being produced.

Generally, shales are organic-rich rocks characterized by different types of pores in the organic and non-organic matter. As a result, shales have multiple storage mechanisms (Lopez and

Aguilera, 2013) that include adsorbed gas in the kerogen material, free gas in non-organic inter- particle (matrix) porosity, free gas in micro fracture and slot porosity, free gas in an intra-particle pore network developed within the organic matter of kerogen, and free gas stored in hydraulic fractures created during the stimulation treatment (Figure 3-2).

Innovation in the combined use of horizontal drilling and multi-stage hydraulic fracturing techniques have led to the economic exploitation of shales in North America for the past few years.

Figure 3-1 North American shale plays (Source: EIA, 2011)

Figure 3-2 Schematic of quintuple porosity and solid kerogen (Lopez and Aguilera, 2013)

3.3 Source Rock Richness

Total Organic Carbon (TOC) is an important parameter in the measurement of the organic richness

of a rock because the amount of TOC in a rock is a determining factor in rock’s ability to generate

hydrocarbons. The three main components of TOC are the extractable organic matter (EOM

carbon), convertible carbon, and residual carbon (Jarvie, 1991). The pyrolysis process is used

commonly for determining the TOC. A diagram illustrating the pyrolysis process is shown in

Figure 3-4. Figure 3-3 shows the model of organic carbon distribution and the relationship to

Rock Eval Pyrolysis process.

Figure 3-3 A)Model of organic carbon distribution in a sample. B) Relationship of Rock

Eval Pyrolysis process

TOC values can be directly measured from rock samples. There are several methods to measure the TOC: direct combustion, modified direct combustion, indirect combustion (by difference), and pyrolysis plus combustion products (Peters and Cassa, 1994). However, most of them have been replaced by Rock Eval Pyrolysis. Petrophysical logs can be useful to estimate TOC when geochemical data is not available (i.e., Passey et al., 1990; Schmoker and Hester, 1983; Stocks and

Lawrence, 1990; Hester et al., 1990). Modified Pickett plots can also prove of value when geochemical data are scarce (Lopez and Aguilera, 2017). However, whenever possible, the well

logs should be calibrated with rock samples to deliver a more precise interpretation.

Rock Eval Pyrolysis (Figure 3-4) is a test developed by the Institut Français du Pétrole to measure the capacity of a source rock to generate hydrocarbons. It is a technique that uses pulverized rock

samples. Usually, 100 mg of sample is enough, and the samples are progressively heated under an

inert atmosphere, and then cooled. The decomposition of organic matter by heating at high

temperatures in the absence of oxygen is called pyrolysis (Law, 1999). Infrared detectors measure

CO and CO2 during each stage of pyrolysis. During the first stage, the sample is heated at 300 ºC;

the free hydrocarbons are volatilized and released from the rock, the amount of hydrocarbons is

measured and known as the peak S1. In the next stage, the temperature is increased from 300 ºC up to 850 ºC, hydrocarbons and compounds are generated due to the pyrolysis of the kerogen, also measured and known as the peak S2, this peak is very important because it indicates the potential

amount of hydrocarbons that the rock can generate if thermal maturation continues. While the

temperature is rising, the kerogen also releases CO2; this is recorded as the S3 peak. Residual

carbon is oxidized and respectively measured and recorded as S4 (McCarthy et al., 2011).

Maximum temperature (Tmax) is the temperature at the maximum generation of hydrocarbons;

this is reached when the kerogen is cracking during the second stage, and it is recorded too.

Figure 3-4 Pyrolysis diagram (adapted from Tissot and Welte, 1984, by Piedrahita and

Aguilera, 2017)

TOC can be estimated from pyrolysis with the use of the equation:

[0.082( + )] % = Eq. 3-1 10 𝑆𝑆1 𝑆𝑆2 𝑇𝑇𝑇𝑇𝑇𝑇 TOC is given in weight % organic carbon per weight of dry rock (milligrams hydrocarbon per gram of rock). TOC indicates the quantity but not the quality of organic carbon; therefore, another screening test must be run to provide a more complete assessment of the source rock. Quality of 42

organic carbon is discussed later in this thesis in section 3.4. Guidelines to assess organic richness are found in Table 3-1 (Jarvie, 1991).

Table 3-1 Guidelines for TOC assessment (Jarvie, 1991) TOC in Shales TOC in Carbonates Generation Potential (wt %) (wt %)

Poor 0.0 - 0.5 0.0 - 0.2

Fair 0.5 - 1.0 0.2 - 0.5

Good 1.0 - 2.0 0.5 - 1.0

Very Good 2.0 - 5.0 1.0 - 2.0

Excellent > 5.0 > 2.0

3.3.1 Using Rock Eval Pyrolysis to estimate organic richness in the Eagle Ford formation

Rock Eval Pyrolysis analysis was completed using core samples collected in well Habano 1.

Results are shown in Table 3-2. Eagle Ford source rocks can be ranked from excellent to very good in TOC, with values ranging from 3.10 to 5.74, and an average of 4.74%. Hydrogen Index corresponds to a kerogen type III-IV, which is gas prone, and ranges from 30 to 61, with an average of 38, with almost no hydrocarbon potential.

Table 3-2 Rock Eval Pyrolysis Results Habano-1

Depth Qty Tmax S1 S2 S3 PI PC TOC HI OI MINC

(mg Hc/g (mg Hc/g (mg CO2/g (mg Hc/g (mg CO2/g (m) (mg) (°C) (%wt) (%wt) (%wt) rock) rock) rock) TOC) TOC)

STD 65.4 416 0.160 12.49 0.96 0.01 1.10 3.37 371 28 3.38

X070.4 74.0 506 0.240 1.75 0.10 0.12 0.17 4.11 43 2 6.28

X071.7 68.0 506 0.300 1.89 0.16 0.14 0.19 3.10 61 5 8.01

X072.7 67.8 505 0.190 1.48 0.24 0.11 0.15 4.60 32 5 5.65

X073.5 74.8 507 0.240 2.36 0.17 0.09 0.23 5.29 45 3 6.76

X074.2 71.7 505 0.190 1.64 0.16 0.11 0.16 4.89 34 3 5.89

X075.2 77.5 504 0.210 1.37 0.16 0.13 0.14 3.80 36 4 6.64

X076.10 78.0 504 0.300 2.21 0.32 0.12 0.22 4.72 47 7 7.55

X077.8 69.6 506 0.250 1.69 0.16 0.13 0.17 4.52 37 4 5.10

X078.2 79.0 506 0.190 1.51 0.13 0.11 0.15 4.35 35 3 6.25

X079.2 67.7 506 0.250 2.07 0.21 0.11 0.20 5.74 36 4 6.57

STD 65.2 416 0.170 12.79 0.78 0.01 1.13 3.28 390 24 3.16

X080.47 73.3 504 0.170 1.64 0.13 0.09 0.16 5.47 30 2 6.31

X081.10 75.1 506 0.290 2.21 0.13 0.12 0.22 5.07 44 3 7.39

X082.52 65.5 505 0.200 1.52 0.14 0.11 0.15 4.55 33 3 7.16

X083.6 67.0 507 0.190 1.58 0.17 0.11 0.15 5.00 32 3 5.26

X084.9 72.3 507 0.260 1.93 0.21 0.12 0.19 5.13 38 4 6.73

X085.9 74.9 506 0.210 1.72 0.11 0.11 0.17 5.53 31 2 6.79

X086.4 79.7 506 0.200 1.69 0.16 0.10 0.16 4.86 35 3 7.26

X087.6 79.2 507 0.180 1.79 0.16 0.09 0.18 5.48 33 3 7.55

X088.1 79.2 506 0.280 1.82 0.17 0.13 0.18 3.79 48 4 7.70

3.3.2 Using Rock Eval Pyrolysis to estimate organic richness in Pimienta formation

Rock Eval Pyrolysis analysis was completed with core samples of well Anhélido 1. The results are shown in Table 3-3. Pimienta source rocks are very good with TOC ranging from 0.17 to 4.47 and an average of 2.88%. Hydrogen Index corresponds to a kerogen type I-II, which is oil prone, and ranges from 78 to 179 with an average of 150.

Table 3-3 Rock Eval Pyrolysis Results Anhélido-1

Depth Qty Tmax S1 S2 S3 PI PC TOC HI OI OSI MINC

(mg (mg Hc/g (mg Hc/g (mg CO2/g (mg Hc/g (mg Hc/g (m) (mg) (°C) (%wt) (%wt) CO2/g (%wt) rock) rock) rock) TOC) TOC) TOC)

STD 65.4 417 0.190 12.64 0.81 0.015 1.12 3.27 387 25 5.81 3.33

X104.4 60.3 452 0.040 6.98 0.34 0.006 0.61 3.95 177 9 1.01 3.12

X105.8 78.6 450 0.010 0.22 0.21 0.043 0.03 0.14 157 150 7.14 7.95

X106.5 69.2 453 0.040 6.42 0.18 0.006 0.55 3.93 163 5 1.02 2.4

X107.8 72.7 454 0.020 0.61 0.19 0.032 0.06 0.35 174 54 5.71 7.87

X108.7 75.2 450 0.050 7.26 0.35 0.007 0.63 4.47 162 8 1.12 2.42

X109.2 75.7 450 0.020 2.92 0.24 0.007 0.26 1.78 164 13 1.12 7.16

X110.1 65.2 440 0.030 0.36 0.33 0.077 0.04 0.46 78 72 6.52 6.67

X111.3 79.9 447 0.010 0.26 0.22 0.037 0.03 0.27 96 81 3.70 7.55

X112.8 79.9 452 0.050 4.64 0.27 0.011 0.41 3.23 144 8 1.55 1.66

STD 65.7 417 0.180 12.49 0.78 0.014 1.1 3.39 368 23 5.31 3.19

X113.3 70 451 0.040 4.75 0.26 0.008 0.41 3.38 141 8 1.18 1.65

X114.5 60.9 452 0.040 5.75 0.23 0.007 0.49 3.51 164 7 1.14 2.39

X115.2 62.3 450 0.040 5.43 0.31 0.007 0.47 3.6 151 9 1.11 2.64

X116.0 71.8 448 0.040 5.00 0.18 0.008 0.43 3.62 138 5 1.10 1.38

X116.5 61.6 447 0.050 4.67 0.31 0.011 0.41 3.5 133 9 1.43 2.64

X117.3 62.2 449 0.050 5.49 0.38 0.009 0.48 3.9 141 10 1.28 1.86

X118.5 74.1 453 0.040 6.36 0.29 0.006 0.55 3.87 164 7 1.03 1.59

X119.5 78 454 0.040 7.98 0.26 0.005 0.68 4.45 179 6 0.90 1.4

X120.7 67.5 454 0.030 5.10 0.25 0.006 0.44 3.28 155 8 0.91 2.49

X121.3 79.7 452 0.030 4.81 0.23 0.006 0.41 3.03 159 8 0.99 2.81

3.4 Source Rock Quality

According to Tissot and Welte (1984), kerogen is the organic component of sedimentary rocks

that cannot be soluble in common organic solvents. Kerogen type determines the source rock

quality, as it controls the type of hydrocarbons generated in that rock. It is closely related to the

depositional environment: from continental (terrestrial) to marine (lacustrine).

The more oil prone a kerogen is, the higher is its quality. Four basic types of kerogen are found in sedimentary rocks (Tissot and Welte, 1984):

• Type I: Source rock is hydrogen rich and it has high potential to generate oil

• Type II: Source rock presents more oil than gas potential

• Type III: Source rock yields gaseous hydrocarbon.

• Type IV: Inert. No hydrocarbon potential

Hydrogen and carbon are the main elements that form hydrocarbons. Thus, it is important to know the amount of hydrogen and carbon that is present within the source rock to assess its quality. The quantity of hydrogen found in a rock determines the type of kerogen found. The Hydrogen Index

(HI) represents the volume of hydrogen relative to the volume of organic carbon content in the rock. The S2 curve of the Rock Eval analysis can help to calculate the hydrogen index from the

equation:

100 = Eq. 3-2 𝑆𝑆2 𝐻𝐻𝐻𝐻 Where 𝑇𝑇𝑇𝑇𝑇𝑇TOC is in weight percent. In the same way, Oxygen Index (OI) represents the amount of

oxygen relative to the amount of organic carbon content in the rock. The S3 curve of the Rock Eval analysis can help to calculate the oxygen index from:

100 = Eq. 3-3 𝑆𝑆3 𝑂𝑂𝑂𝑂 Once the𝑇𝑇𝑇𝑇𝑇𝑇 Hydrogen and Oxygen Indices are calculated, a plot of HI vs. OI is prepared to help in

the interpretation. This plot is a modified Van Krevelen diagram. The types of kerogen can be seen

in Figure 3-5. The diagram shows that as more hydrocarbon is generated, the rock begins to lose

more hydrogen. As the source rock matures, the HI and OI decrease until they converge in the

origin, resulting in a gas prone interpretation.

Figure 3-5 A) Van Krevelen diagram based on atomic H/C and O/C. B) Modified Van Krevelen diagram using HI and OI of Rock Eval pyrolysis to classify kerogen type.

3.4.1 Estimating source rock quality in Eagle Ford and Pimienta formations

Based on data from rock eval analysis, the HI average is 38 for Eagle Ford and 150 for Pimienta formation. The plot of HI vs. OI is displayed in Figure 3-6. Black squares show data of Eagle

Ford, leading to the interpretation that kerogen type III (gas prone) is dominant. On the other hand, the gray triangles show data for Pimienta indicating the presence of either kerogen type I to III

(from oil to gas prone). Based on Figure 3-6 shows the modified Van Krevelen diagram for

Habano (Eagle Ford) and Anhélido (Pimienta). The figure identifies kerogen type III/IV (gas prone) for Eagle Ford, and kerogen type II/III (oil and gas prone) for Pimienta.

It has been proved that when plotting S2 vs. TOC, and a linear regression analysis is done based

on the tendency of the data, that generally the correlation has a high coefficient of determination,

and that the slope of the equation reflects the true average value of HI (Langford and Blanc-

Valleron, 1990). To use S2 vs. TOC diagram, it is important to set boundaries between kerogen types regarding HI. Several authors have set the values to differentiate kerogen type with the use of Hydrogen Index (Hunt, 1979; Tissot and Vandenbrouke, 1983; Jones, 1984; Peters, 1986;

Jarvie, 1991; Peters and Cassa, 1994). In general, samples with Hydrogen Indices ranging from

300 to 700 are kerogen type I, HI around 300-600 are represented by kerogen type II, HI of 150-

300 are kerogen type II/III, HI of 50-150 are kerogen type III, and finally samples with HI less than 50 kerogen type IV. Figure 3-7 shows an S2 vs. TOC diagram illustrating the kerogen type for Habano (Eagle Ford) and Anhélido (Pimienta).

Figure 3-6 Modified Van Krevelen diagram for Habano 1 (Eagle Ford) and Anhélido 1 (Pimienta formation).

Figure 3-7 S2 vs. TOC diagram showing kerogen type for Habano 1 (Eagle Ford formation) and Anhélido 1 (Pimienta formation).

3.5 Source Rock Maturity

Sedimentary rocks change over time because of maturation stemming from temperature changes.

Temperature is one of the most important parameters in hydrocarbon generation; therefore, it is important to know temperature for evaluating the thermal maturity of a source rock.

Transformation ratio (TR) is the rate at which hydrocarbons are generated from organic matter.

From the source rock maturity, it is possible to calculate the transformation ratio. Thermal transformation of organic matter is what causes a source rock to generate hydrocarbons.

Maturation indices like Tmax in Rock-Eval pyrolysis, Vitrinite reflectance (Ro, %), Spore

Coloration (SCI), Thermal Alteration Index (TAI) or concentration of biological markers are

indirect methods for estimating rock maturity. In this study, Tmax, Reflectance of Vitrinite,

Hydrogen Index, and Production Index are the methods used for evaluating the maturity of the

source rock. Tmax, as stated above, is the temperature at which the maximum rate of hydrocarbon

generation occurs in a kerogen sample during pyrolysis analysis. Guidelines to evaluate maturity

from Tmax published by Tissot et al. (1987) are shown in Table 3-4.

Table 3-4. Guidelines for Tmax maturation assessment Hydrocarbon Generation Rock Eval Pyrolysis

Zone Tmax (°C)

Immature < 435

Oil (from type II kerogen) 435-455

Oil (from type III kerogen) 435-465

Gas (from type II kerogen) > 455

Gas (from type III kerogen) > 465

Vitrinite is one of the three principal maceral groups existing in coals and sedimentary rocks (Stach

et al., 1982). Vitrinite reflectance is a measure of the percentage of light reflected off the vitrinite maceral. The result is generally shown as an average value; however, histograms showing the frequency distribution of reflectance must be built. The stage of thermal maturation can be

obtained from the Table 3-5 published by Peters and Cassa (1994). Kerogen boundaries for oil

and gas zones can be easily recognized from Figure 3-8 based on values of Vitrinite Reflectance

(Tissot and Welte, 1984).

Table 3-5 Geochemical parameters describing level of thermal maturation (Peters and Cassa, 1994) Stage of Thermal Maturation

Maturity for Oil Ro (%) Tmax (°C) Thermal Alteration Index

Immature 0.2 - 0.6 < 435 1.5 – 2.6

Mature

Early 0.6 – 0.65 435 – 445 2.6 – 2.7

Peak 0.65 – 0.9 445-450 2.7 – 2.9

Late 0.9-1.35 450-470 2.9 – 3.3

Postmature > 1.35 > 470 > 3.3

Figure 3-8 Maturation assessment from Vitrinite Reflectance (Tissot and Welte, 1984)

The Production Index (PI) is also very useful for estimating maturation. PI is obtained from the

Rock Eval Pyrolysis, and it can be estimated from:

= ( + ) Eq. 3-4 𝑆𝑆1 𝑃𝑃𝑃𝑃 𝑆𝑆1 𝑆𝑆2 51

PI increases in the oil window to a value of 0.50. Table 3-6 presents general guidelines that can

be applied for maturation assessment.

Table 3-6 Guidelines for PI maturation assessment Hydrocarbon Generation Production Index Zone

Immature < 0.10

Oil generation 0.10 – 0.30

Gas generation/ Oil cracking > 0.30

3.5.1 Estimating source rock maturation in Eagle Ford and Pimienta formations

Tmax, Ro, HI, and PI are considered in this thesis for evaluating the maturity of the source rock in

the Eagle Ford formation. Tmax from Rock Eval pyrolysis ranges from 504 to 507, with an average

of 506 °C. According to Table 3-4 this formation falls within the gas generation zone. A histogram

of the reflectance of vitrinite is presented in Figure 3-9. The average Ro is 1.67%. Therefore, the

source rock is found as post-mature in the condensate and wet gas window in Figure 3-8.

Description of the rock in reflected light (vitrinite) indicates an organic rich sample, with kerogen type III, and pyrobitumen deposited within the porous space of foraminiferans, granular kerogen and inertodetrinite (kerogen type IV). Algal organic matter is also present.

Figure 3-9 Vitrinite Reflectance Histogram for well Habano-1 (Eagle Ford Formation).

HI vs. Tmax plot is built to determine thermal maturity with the above guidelines and using data from cuttings and plug-core samples. From Figure 3-10 is possible to observe that thermal maturity in terms of Tmax ranges from early mature to post mature. HI indicates a mix of kerogen type III/IV, with an Ro equal to 1.67% that points to dry gas. Based on the Production Index, ranging from 0.09 to 0.14, Eagle Ford is in the oil generation zone.

Figure 3-10 HI vs. Tmax for well Habano 1 (EagleFord formation)

To evaluate the maturity of the source rock in Pimienta formation with data from well Anhélido-

1, Tmax, Ro, HI, and PI are considered. Tmax from Rock Eval pyrolysis ranges from 440 to 454, with an average of 450 °C. According to Table 3-4 this formation is within the oil generation zone.

A histogram of the reflectance of vitrinite is shown in Figure 3-11. The average Ro is 0.85%.

Therefore, the source rock is found as mature in the oil window in Figure 3-8. Description of the rock in reflected light indicates organic rich sample, with kerogen type III (vitrinite). The sample also contains quartz, carbonates, and pyrite.

Figure 3-11 Vitrinite Reflectance Histogram for well Anhélido-1

HI vs. Tmax plot was constructed to determine thermal maturity of Pimienta formation using the above guidelines and data from plug-core samples collected in well Anhélido 1. From Figure 3-12 it is possible to observe in terms of Tmax, that the source rock is thermally mature to oil. The HI indicates a mix of kerogen type II/III, and Ro is equal to 0.85%, which points to the oil window.

Based on the Production Index, which ranges from 0.005 to 0.077, Pimienta is immature.

Figure 3-12 HI vs. Tmax for well Anhélido-1 (Pimienta formation).

3.6 Geochemical logs

Geochemical logs are convenient when evaluating quantity, quality and thermal maturation of a source rock. The geochemical logs of Eagle Ford and Pimienta formations are shown in Figure

3-13 and Figure 3-14, respectively. For the case of Pimienta, the use of Oil Saturation Index (OSI) is included for shale oil evaluation. OSI is a geochemical indication of potentially producible oil in those cases when OSI reaches a value of 100 mg HC/g TOC. But OSI value of less than 100 mg

HC/g TOC do not necessarily discard the possibility of having producible oil, although there is a higher risk, based only in geochemical interpretation (Jarvie, 2012b). OSI can be estimated from:

100 = Eq. 3-5 𝑆𝑆1 𝑂𝑂𝑂𝑂𝑂𝑂 𝑇𝑇𝑇𝑇𝑇𝑇 56

Figure 3-13 Geochemical logs of well Habano-1 (Eagle Ford formation)

Figure 3-14 Geochemical logs of well Anhélido-1 (Pimienta formation).

3.7 North American shale resource play geochemistry assessment

Table 3-7 shows a comparison of geochemical parameters in U.S. and Mexican shales. Eagle Ford and Pimienta data are within the range of values found in most of the U.S. shales currently producing oil and gas.

Table 3-7 Comparison of geochemical parameters in North American shales

U.S. Shales Eagle Ford U.S. Shales Pimienta

(Maende et Mexico (Maende et Mexico

al., 2013) (This thesis) al., 2013) (This thesis)

Resource System: Shale gas Shale gas Shale oil Shale oil

Devonian-Up. Upper Devonian- Age: Upper Jurassic Cretaceous Cretaceous Miocene

Tmax (°C): > 455 506 435 - 465 450

TOCpd (wt %): 1 - 5' 4.74 0.1 - 15 2.88

HIpd (mg Hc/g TOC): 10 - 80' 38 50-620 150

Ro (%) 1.2 - 2.5 1.66 0.6 - 1.3 0.85

Chapter Four: Formation evaluation in Burgos basin

4.1 Introduction

This chapter focusses on formation evaluation by petrophysics and the estimation of parameters such as porosity, water saturation and elastic modules in the Mexican (Burgos basin) Eagle Ford and Pimienta formations. Water saturation is one of the most important parameters when evaluating petrophysics. The use of Pickett plots is useful and widely recognized method for evaluating water saturation when working with scarce petrophysical information. As explained in the previous chapter, shales are characterized for having multiple storage mechanisms. Previously, different models have been developed to calculate those porosities and with a view to have a better understanding of the reservoir. For example, Pickett plots have been extended to the case of naturally fractured shaly formations. Due to data limitations, nonetheless, some of those multiple porosity methods are not used in the present study. However, an empirical comparison is made with a multiporosity approach in section 4.6 at the end of his chapter.

Information of well logs from Eagle Ford and Pimienta formations, such as neutron, density and resistivity logs are analyzed in this chapter and calibrated with data from core analysis, when available. Geomechanical properties like Young’s Modulus, Poisson’s Ratio and Brittleness Index are calculated and calibrated with triaxial tests data. These calibrations with different sources of information, such as geochemical data, special core analysis, fluid recoveries from drill-stem, and production tests, are important to improve the interpretation.

4.2 Pickett Plots

Pickett Plots (Pickett, 1966, 1973) are graphical representations of Archie’s equation (1942) that make use of pattern recognition. The log-log plot of total porosity vs. true resistivity in Pickett 60

plots provide values of resistivity index and water saturation with an acceptable degree of certainty

particularly in those cases with minimum availability of petrophysical data. Archie’s equations are

as follows:

= / Eq. 4-1 −1 𝑛𝑛 𝑆𝑆𝑤𝑤 𝐼𝐼 = = Eq. 4-2 𝑅𝑅𝑡𝑡 𝑅𝑅𝑡𝑡 𝐼𝐼 𝐹𝐹𝑅𝑅𝑤𝑤 𝑅𝑅𝑜𝑜 = = Eq. 4-3 −𝑚𝑚 𝑅𝑅𝑜𝑜 𝐹𝐹 𝑎𝑎𝜙𝜙 𝑤𝑤 Where I, is the𝑅𝑅 resistivity index, Rw is water resistivity at formation temperature, which can be

determined by extrapolating the 100% water-bearing trend in the plot to 100% porosity, , Rt is true resistivity from well logs, Ro is the resistivity of the formation when it is 100% saturated𝜙𝜙 with water, a is a constant related by some authors to tortuosity, m is the porosity (or cementation exponent, and n is the water saturation exponent. The optimum is to obtain a, m and n from

laboratory analysis. Since not all the wells have data from laboratory; a, m and n are generally assumed for clean formations as 1, 2 and 2, respectively. Aguilera had extended the use of Pickett plots for analysis of naturally fractured reservoirs (1974, 1976) as well as shaly formations (1990).

4.3 Method for evaluating the Mexican shales considered in this thesis

Total porosity was calculated considering density and neutron logs. Porosity from the density log for each depth was calculated using the equation:

= Eq. 4-4

𝜌𝜌𝑠𝑠 − 𝜌𝜌𝑏𝑏 𝜙𝜙𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 𝜌𝜌𝑠𝑠 − 𝜌𝜌𝑓𝑓 Where ρs is the grain density, ρf is the density of the fluid used to calibrate the logging tool, and

ρb is the bulk density registered by the logging tool at depth. Densities considered in this thesis are 61

in gr/cc. Total Gaymard-Poupon (1968) porosity for oil and gas are obtained as the average between neutron porosity and porosity from the density log as follows:

+ : = Eq. 4-5 2 𝜙𝜙𝑁𝑁 𝜙𝜙𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 𝑂𝑂𝑂𝑂𝑂𝑂 𝜙𝜙𝑇𝑇 + : = 2 2 2 Eq. 4-6 𝜙𝜙𝑁𝑁 𝜙𝜙𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 𝐺𝐺𝐺𝐺𝐺𝐺 𝜙𝜙𝑇𝑇 � The shale volume can be computed from gamma ray logs:

= Eq. 4-7 𝑚𝑚𝑚𝑚𝑚𝑚 𝑆𝑆ℎ 𝐺𝐺𝐺𝐺 − 𝐺𝐺𝐺𝐺 𝑉𝑉 𝑚𝑚𝑚𝑚𝑚𝑚 𝑚𝑚𝑚𝑚𝑚𝑚 Where GR𝐺𝐺𝐺𝐺 is the− 𝐺𝐺gamma𝐺𝐺 ray from the well log, GRmin is a fixed minimum gamma ray (clean zone), and GRmax is a fixed maximum gamma ray (shaly zone). Effective porosity, which is the relationship between the interconnected pore space and the bulk volume, is determined from:

= (1 ) Eq. 4-8 𝜙𝜙𝑒𝑒𝑒𝑒𝑒𝑒 𝜙𝜙𝑇𝑇 − 𝑉𝑉𝑠𝑠ℎ For shaly formations the formation factor is determined with the use of the equation:

= Eq. 4-9 −𝑚𝑚 𝐹𝐹 𝑎𝑎𝜙𝜙𝑒𝑒𝑒𝑒𝑒𝑒 Shales can be classified as laminar, structural and dispersed as shown in Figure 4-1.

Figure 4-1 Types of shale classified by manner of distribution. Pictorial representations are shown above and volumetric representations below (Schlumberger).

In this study, modified Pickett plots are built assuming a laminar model to be representative of

shales in the Eagle Ford and Pimienta formations. Using this model, a shale number, Ash, is

calculated from (Aguilera, 1990):

( )(1 ) = Eq. 4-10 𝑅𝑅𝑠𝑠ℎ − 𝑅𝑅𝑡𝑡𝑉𝑉𝑠𝑠ℎ − 𝑉𝑉𝑠𝑠ℎ 𝐴𝐴𝑠𝑠ℎ 𝑅𝑅𝑠𝑠ℎ Where Rsh is shale resistivity and Vsh is shale fractional volume. The modified Pickett plot is built by determining first:

Eq. 4-11 𝑅𝑅𝑡𝑡 � 𝑠𝑠ℎ� Next𝐴𝐴 the value of Ro, that is, the resistivity of the system when it is 100% saturated with water is

calculated from:

= = Eq. 4-12 𝑅𝑅𝑡𝑡 𝑅𝑅𝑜𝑜 � � 𝐹𝐹𝑅𝑅𝑤𝑤 𝑠𝑠ℎ 𝑤𝑤𝑤𝑤𝑤𝑤𝑤𝑤𝑤𝑤 Water resistivity,𝐴𝐴 Rw, if unknown, can be obtained by trial and error while drawing the 100% water

saturation straight line on the modified Pickett Plot.

Resistivity index of shale can be found at each depth from:

/ / = = Eq. 4-13 𝑡𝑡 𝑠𝑠ℎ 𝑡𝑡 𝑠𝑠ℎ 𝑠𝑠ℎ 𝑅𝑅 𝐴𝐴 𝑅𝑅 𝐴𝐴 𝐼𝐼 𝑤𝑤 𝑜𝑜 Finally, 𝐹𝐹water𝑅𝑅 saturation𝑅𝑅 is calculated through Archie’s equation for shaly formations (Aguilera,

1990):

/ = Eq. 4-14 −1 𝑛𝑛 𝑆𝑆𝑤𝑤 𝐼𝐼𝑠𝑠ℎ Rock geomechanical properties of the rock, such as Poisson Ratio and Young Modulus, are also

considered in this thesis. Dynamic properties are obtained from well logs. Static properties are

determined from cores experiments in the laboratory, or estimated by approximate correlations

between core data and well logs. The compressional, Vc, and shear velocities, Vs, are computed from Eq. 4-15 and Eq.4-16, respectively:

1 = 1,000,000 Eq. 4-15

𝑐𝑐 𝑉𝑉 � 𝑐𝑐� 1∆,000𝑡𝑡 ,000 = Eq. 4-16

𝑠𝑠 𝑉𝑉 𝑠𝑠 Where ∆𝑡𝑡 is the compressional transit time (or slowness), and is the shear transit time given

𝑐𝑐 𝑠𝑠 by Sonic∆ 𝑡𝑡logs. Dynamic Poisson’s ratio can be obtained from well∆ logs𝑡𝑡 with the use of the equation:

0.5 = 2 2 Eq. 4-17 𝑉𝑉𝑐𝑐 − 𝑉𝑉𝑠𝑠 𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷 𝑣𝑣𝐷𝐷 2 2 𝑉𝑉𝑐𝑐 − 𝑉𝑉𝑠𝑠

And static Poisson’s ratio can be approximated from: Eq. 4-18 = (0.9857)

𝑆𝑆 𝐷𝐷 Shear𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆 modulus𝑣𝑣 measures the𝑣𝑣 resistance to change in shape, and is given by:

1.34 10 = 2 10 Eq. 4-19 ∗ 𝜌𝜌𝑏𝑏 𝐺𝐺 𝑠𝑠 Dynamic and∆𝑡𝑡 static Young’s Modulus are estimated with the use of the equations:

= 2 (1 + ) Eq. 4-20

𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷 Ε𝐷𝐷 𝐺𝐺 𝑣𝑣𝐷𝐷 = (0.809) Eq. 4-21

𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆 Ε𝑆𝑆 Ε𝐷𝐷 Brittleness Index indicates the tendency of the to be brittle or ductile. More brittle composition is characterized by a low Poisson’s Ratio and a high Young’s Modulus. Brittleness Index can be computed from:

= (0.0715 ) (1.43 ) + 0.57 Eq. 4-22

𝐵𝐵𝐵𝐵𝐵𝐵𝐵𝐵𝑖𝑖 ∗ Ε𝑆𝑆 − ∗ 𝑣𝑣𝑆𝑆 Biot’s constant is a relationship between compressibility of the rock grain and compressibility of rock framework. Vertical Biot’s constant, αv, it is determined as follows:

= 0.6 + Eq. 4-23 𝛼𝛼𝑣𝑣 �𝑚𝑚𝛼𝛼 ∗ 𝜙𝜙𝑒𝑒𝑒𝑒𝑒𝑒� Where is generally assumed to be equal to 1.0 (Detournay and Cheng, 1993). Overburden

𝛼𝛼 Stress is𝑚𝑚 calculated from:

= Eq. 4-24

𝜎𝜎𝑧𝑧 𝑑𝑑𝑑𝑑𝑑𝑑𝑑𝑑ℎ ∗ 𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜 𝑔𝑔𝑔𝑔𝑔𝑔𝑔𝑔𝑔𝑔𝑔𝑔𝑔𝑔𝑔𝑔

In order to calculate Pore pressure, it is necessary to obtain values of the modified water normal pressure ( ) and the normalized sonic transit time ( ) as proposed by Contreras (2011), and ∗ 𝑛𝑛 𝑛𝑛 Contreras 𝑃𝑃et al. (2012) modifying Eaton’s equation: ∆𝑡𝑡

= ( ) Eq. 4-25 ∗ 𝑃𝑃𝑛𝑛 𝜌𝜌𝑊𝑊𝑊𝑊𝑊𝑊𝑊𝑊𝑊𝑊𝑊𝑊𝑊𝑊𝑊𝑊𝑊𝑊𝑊𝑊𝑊𝑊 𝑇𝑇𝑇𝑇𝑇𝑇 − 𝐾𝐾𝑏𝑏 = 0.0682 415.11 Eq. 4-26

∆𝑡𝑡𝑛𝑛 − 𝑇𝑇𝑇𝑇𝑇𝑇 − = ( ) 𝑏𝑏 Eq. 4-27 ∗ ∆𝑡𝑡𝑛𝑛 𝑃𝑃 𝜎𝜎𝑧𝑧 − 𝜎𝜎𝑧𝑧 − 𝑃𝑃𝑛𝑛 � � The equation to calculate∆𝑡𝑡 the Minimum horizontal stress from log data was proposed by Anderson et al. (1973), and Newberry et al. (1985):

, = ( ) + + Eq. 4-28 1 𝐷𝐷 ℎ 𝑚𝑚𝑚𝑚𝑚𝑚 𝑣𝑣 𝑧𝑧 𝑣𝑣 ℎ 𝑡𝑡𝑡𝑡𝑡𝑡ℎ 𝜎𝜎 𝐷𝐷 𝜎𝜎 − 𝛼𝛼 𝑃𝑃 𝛼𝛼 𝑃𝑃 𝜎𝜎 In tectonic −relaxed𝑣𝑣 formations, tectonic stress, , is assumed negligible. Net stress can be

𝑡𝑡𝑒𝑒𝑒𝑒ℎ determined from: 𝜎𝜎

= ( ) Eq. 4-29

𝑁𝑁𝑁𝑁𝑁𝑁 𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠 𝜎𝜎𝑧𝑧 − 𝛼𝛼𝛼𝛼 The equations presented previously have been used for evaluation of wells Habano 1 and Anhélido

1 as explained in subsequent sections.

4.4 Log interpretation of Cretaceous Eagle Ford Formation (well Habano 1)

The Mexican Eagle Ford Formation penetrated by well Habano 1 was evaluated with the use of

Gamma Ray, Resistivity, Density, Neutron, and Sonic logs. Table 4-1 summarizes basic data used in the calculations. Notice that because of the presence of natural fractures the values of m and n are equal to 1.9, a number smaller than the conventional 2.0 that does not take into account the

presence of natural fractures. Notice also, that the grain density is shown as 2.65 gr/cm3. However,

Figure 1-4, in the Introduction of this thesis, shows that the lithology is dominated by carbonates.

Thus, the number in this table (Table 4-1) is an average that includes carbonates but also lithologies with values smaller than 2.65 g/cm3 as shown later in the crossplot of TOC vs. Density

(Figure 4-4).

Table 4-1 Properties used for petrophysical interpretation of the Eagle Ford formation penetrated by well Habano 1 Property Symbol Value Units 3 Grain density ρs 2.65 g/cm 3 Fluid density ρf 1 g/cm Minimum Gamma Ray value clean zone GRmin 60 Maximum Gamma Ray value shaly zone GRmax 120 Cementation exponent = saturation exponent m = n 1.9 Tortuosity factor a 1

Resistivity of shale Rsh 23 Ohm.m Tectonic stress σ 0 kPa tech Horizontal Biot’s Constant αh 1 Overburden gradient 1 psi/ft Eaton Exponent b 1

Normalized sonic transit time ∆tn -0.0682TVD+415.11 µs/ft Kelly bushing elevation KB 7.33 m

Formation water normal gradient ρWaterNormal 9.7 kPa/m

Figure 4-2 shows a modified Pickett plot of effective porosity vs. Rt/Ashale for well Habano 1.

To draw lines of constant water saturations equal to 100%, 50%, 25% and 12.5%, the values of

effective porosity from 0.001 to 1 were used along with the following equation:

= Eq. 4-30 𝑅𝑅𝑅𝑅 −𝑚𝑚 −𝑛𝑛 � � 𝑎𝑎𝜙𝜙𝑒𝑒𝑒𝑒𝑒𝑒 𝑅𝑅𝑤𝑤𝑆𝑆𝑤𝑤 𝐴𝐴𝑠𝑠ℎ The red line in the modified Pickett Plot (Figure 4-2) corresponds to a water saturation of 100%.

That line shows an estimated value of water resistivity, Rw, equal to 0.05 ohm-m. This value is

similar to some water resistivities observed in the Eagle Ford shale in Texas. The blue lines

correspond to other values of water saturation. The graph shows the good hydrocarbon potential

of the Eagle Ford shale penetrated by well Habano 1.

Figure 4-2 Modified Pickett Plot for Eagle Ford formation (Habano 1)

Total and Effective porosity calculated from equations 4-6 and 4-8 explained above are shown in

Figure 4-3. Total porosity ranges from 0.9 to 19%, with an average of 12%. Effective porosity varies from 0 to 14.6% with an average of 8.7%. Water saturation averages 25% and the zone with the lowest water saturation is found in interval X075 m to X095 m. There is a zone at the bottom of the calculated Sw log that seems to be more water saturated than the rest of the formation. The calculation of porosity and water saturation is in good agreement with the available information of core laboratory analysis. This is shown by black dots in the figure. In the case of porosity, the best agreement is with the effective porosity.

Figure 4-3 Well logs, porosity and water saturation for Eagle Ford interval penetrated by well Habano 1

Total Organic Carbon Carbon (TOC) was calculated using two methods: (1) linear relationship from TOC (pyrolysis) and density, and (2) Passey et al. method (1990). The available information to calibrate the models includes core samples and drill cuttings. The linear relationship (method 1) yields a good coefficient of determination (R2) equal to 0.93 as shown in Figure 4-4. Notice that the range of density goes from values for carbonates to sandstones. The assumed baseline to use

Passey’s method, is shown with an arrow in Figure 4-5. There is not a clear baseline; however, the points were the curve of resistivity and ∆tc cross-over are repetitive at different depths.

Therefore, those values were taken for calculation purposes resulting in good agreement of TOC values when compared with laboratory data. Both methods 1 and 2 were corroborated with the available information from core samples and drill cuttings with very good results as shown in

Figure 4-5, where the estimation of TOC from the density log linear relationship (method 1) is shown in red. Method 2 using Passey et al.’s (1990) approach is shown with an orange line in

Figure 4-5.

Figure 4-4 Linear relationship between TOC and density for well Habano 1.

Figure 4-5 Estimation of TOC from density log and Passey et al. method, well Habano 1.

Geomechanical properties were calculated with the methodology explained above (equations

4-15 to 4-23). Well logs (dynamic data) were calibrated with the information from triaxial test

(static data) presented in Table 4-2.

Table 4-2 Triaxial Test on three samples of well Habano 1

Triaxial Test

Confinement Bulk Young’s Poisson’s Compressive Strength Pressure Density Modulus Ratio Depth (m) (psi) (g/cm3) (psi) (psi)

X071.06 940 2.38 9438 4255000.00 0.23

X077.05 940 2.39 8993 3986000.00 0.24

X083.19 940 2.42 8319 2015000.00 0.25

Figure 4-6 presents results of the geomechanical calculations. Poisson’s Ratio is found in the first

track and is congruent with the three laboratory tests shown in Table 4-2. Young’s Modulus results are presented in track 2. There is one point that is not in good agreement with the laboratory triaxial tests for which I do not have an explanation at this time. Based on Poisson’s Ratio and Young’s

Modulus, the Brittleness Index (BI) was calculated for well Habano 1 to vary from 0.4 to 0.75, with an average of 0.48. Low Poisson’s Ratio and high Young’s Modulus suggest that the Eagle

Ford formation tends to be brittle and easy to fracture. This is positive, as it will improve the probabilities of having successful hydraulic fracturing jobs.

Figure 4-6 Poisson’s Ratio, Young’s Modulus and Brittleness Index for well Habano 1

Figure 4-7 shows calculated Biot’s constant, overburden stress, pore pressure, minimum horizontal stress (MHS) and net stress. These parameters are very important (particularly MHS) when designing a hydraulic fracturing job and for reservoir simulation purposes.

4.5 Log interpretation of Jurassic Pimienta Formation (Anhélido 1)

A similar approach to the one explained above for well Habano 1 was followed in the evaluation of Pimienta Formation using Gamma Ray, Resistivity, Density, Neutron, and Sonic logs recorded in well Anhélido-1. Table 4-3 summarized basic data used in the interpretation.

Figure 4-7 Biot’s constant, overburden stress, pore pressure, MHS and net stress for well Habano 1.

Table 4-3 Properties used for petrophysical interpretation of the Pimienta formation penetrated by well Anhélido 1 Property Symbol Value Units 3 Grain density ρs 2.65 g/cm 3 Fluid density ρf 1 g/cm Minimum Gamma Ray value clean zone GRmin 60 Maximum Gamma Ray value shaly zone GRmax 120 Cementation exponent = saturation exponent m = n 1.9 Tortuosity factor a 1

Resistivity of shale Rsh 23 Ohm.m Tectonic stress σ 0 kPa tech Horizontal Biot’s Constant αh 1 Overburden gradient 1 psi/ft Eaton Exponent b 1

Normalized sonic transit time ∆tn -0.0682TVD+415.11 µs/ft Kelly bushing elevation KB 10 m

Formation water normal gradient ρWaterNormal 9.7 kPa/m

The modified Pickett Plot (Figure 4-8) shows and estimated value of water resistivity, Rw, equal to 0.125 ohm-m. The red line in the graph corresponds to water saturations equal to 100%. The

blue lines show other water saturations of interest. The pattern distribution shows attractive

hydrocarbon potential in the Pimienta formation

Figure 4-8 Pickett Plot Eagle Ford formation (Anhélido 1)

Total and Effective porosities calculated from equations 4-6 and 4-8 are shown in Figure 4-9.

Total porosity ranges from 6 to 20%, with an average of 13%. Effective porosity varies from 0 to

16% with an average of 8%. Water saturation averages 17%. The zones with the lowest water saturation is found in interval X0105 m to X114 m. In this well, as opposed to the case of well

Habano 1, there are not laboratory data to calibrate porosity and water saturation from the well log interpretation.

Figure 4-9 Well logs, porosity and water saturation from well Anhélido 1

Total Organic Carbon Carbon (TOC) was also calculated using the two methods explained previously for the case of well Habano 1: (1) the linear relationship from TOC (pyrolysis) and density, and (2) Passey et al.’s method (1990). The available information to calibrate the model includes only core samples (no drill cuttings data in this case). From the linear relationship, the coefficient of determination (R2) is 0.96, which is acceptable as shown in Figure 4-10. For method

2 (Passey et al.), two baselines were established highlighted by the arrows shown in Figure 4-11.

However, none of them resulted in a definitive agreement with laboratory data. On the other hand,

TOC obtained from the linear relationship between density and TOC from pyrolysis (method 2) provides better agreement. The estimation of TOC with method 1 (Passey et al., 1990) is shown by the orange line in Figure 4-11. Results using method 2 (Passey et al.) are shown by the yellow line, and finally the TOC from density in displayed by the red line.

Figure 4-10 Linear relationship between TOC and density for well Anhélido 1

Figure 4-11 Estimation of TOC from density and Passey et al., Anhélido 1

Geomechanical properties were calculated with the same methodology used previously for the case of well Habano 1. The well logs were calibrated with laboratory information from cores triaxial tests presented in Table 4-4.

Table 4-4 Triaxial Test on four samples of well Anhélido 1

Triaxial Test

Confinement Bulk Young’s Poisson’s Compressive Strength Depth Pressure Density Modulus Ratio (m) (psi) (g/cm3) (psi) (psi)

X104.73 0 2.39 10730 3894000 0.26

X108.69 500 2.36 13582 3825000 0.25

X114.95 1000 2.56 18660 4576000 0.27

X121.12 1500 2.59 22200 5964000 0.27

According to the Triaxial Tests (Table 4-4) Poisson’s Ratio varies from 0.25 to 0.27 and Young’s

Modulus from 3.8 to 5.9 x 106 psi. Results obtained from geomechanical calculations (equations

4-15 to 4-23) show Poisson’s Ratios from 0.12 to 0.31 and Young’s Modulus from 3.9 to 6.7 x 106 psi. Calculated Poisson’s Ratios shown in Figure 4-12 do not match the last two tests shown in

Table 4-4. Young`s Modulus estimations from equations match three out of four samples evaluated in laboratory experiments. Brittleness Index (BI) based on Poisson’s Ratio and Young’s

Modulus was calculated for well Anhélido 1 to range between 0.46 and 0.79, with an average of

0.55. Low Poisson’s Ratio and a high Young’s Modulus suggest that Pimienta formation has a brittleness tendency. Overall, Pimienta formation seems to be more brittle than the Eagle Ford. 77

Figure 4-12 Poisson’s Ratio, Young’s Modulus and Brittleness Index for well Anhélido 1

Figure 4-13 shows Biot’s constant, overburden stress, pore pressure, minimum horizontal stress

(MHS) and net stress. Results show that Pimienta formation is amenable to successful hydraulic fracturing due to its brittleness.

Figure 4-13 Biot’s constant, overburden stress, pore pressure, MHS and net stress for well Anhélido 1 4.6 Empirical comparison with the Eagle Ford shale in Texas

The petrophysical work presented above throughout this chapter suggests that there is significant potential in the Eagle Ford and Pimienta shales in the Burgos basin (Mexico). This section presents an empirical comparison with the Eagle Ford shale in Texas (U.S.).

The comparison is made with a method developed recently by Lopez and Aguilera (2016) that uses flow units in a modified Pickett plot. A flow unit is defined as a stratigraphically continuous reservoir subdivision characterized by a similar pore type (Hartmann and Beaumont, 1999, p. 9-

7). In their method Lopez and Aguilera follow the philosophy advocated by Coates et al. (1983).

Coates at al.’s paper “intentionally avoids theoretical areas and concentrates instead in what can be observed from log data with respect to the conductivity and porosity of shales, shaly sands, and sands.” Coats et al. (1983) indicate that “the familiar Pickett plot (log-log plot of conductivity vs. porosity) is a convenient form for making this evaluation because it allows a relative pure look at the data”. The result of Lopez and Aguilera’s work (2016) leads to the modified Pickett plot for

the Eagle Ford shale in Texas presented in Figure 4-14, which is presented as a cross plot of total porosity from density and neutron porosity logs vs. true resistivity. U.S. Eagle Ford data is represented by green triangles. The data shows four flow units named FUA, FUB, FUC and FID.

The graph includes lines of constant water saturation, flow units (dependent on the ratio of permeability over porosity), Knudsen number (flow regime) and Bulk Volume Water (BVW).

Figure 4-14. Modified Pickett plot for Eagle Ford well, DJ Basin including lines of constant water saturation, flow units (same name but not related to the ones in the previous graph) A, B, C and D (dependent on the ratio of permeability over porosity), Knudsen number (flow regime) and Bulk Volume Water (BVW). Eagle Ford data from Devine (2014). (Lopez and Aguilera, 2016).

The petrophysical analysis and comparison with the U.S. Eagle Ford shale provides an indirect indication of the potential of Mexican shales.

Figure 4-15 is a repeat of Figure 4-14 but now including data from the Eagle Ford in the Burgos basin (Mexico). These data are represented by blue open circles.

Note in Figure 4-15 that data from both the Mexican and U.S. Eagle Ford shales fall within the range of flow unit A (FUA), with a smaller number of Mexican data points falling within the range of flow unit B (FUB). FUA is the flow unit with the best characteristics of porosity and permeability (Lopez and Aguilera, 2016). As the U.S. Eagle Ford shale has tested over and over its commercial production potential, the good comparison shown in Figure 4-15 provides empirical evidence as to the potential of the Mexican Eagle Ford shale.

The same type of comparison is shown in Figure 4-16 for the Mexican Pimienta shale (red open circles) and the U.S. Eagle Ford shale (green triangles). The comparison shows the Pimienta shale as corresponding to flow unit A (FUA). The good pattern recognition comparison highlights the potential of Pimienta shales.

The conclusion is reached that both the Mexican Eagle Ford and Pimienta shales have significant potential that could rival the potential of U.S. Eagle Ford shales.

Figure 4-15 Modified Pickett plot for Eagle Ford shale wells in the U.S. and Mexico (Burgos basin). U.S. data shown as green triangles. Mexican data shown as blue open circles.

Figure 4-16 Modified Pickett plot for Eagle Ford shale well in the U.S. and Pimienta shale well in Mexico (Burgos basin). U.S. data shown as green triangles. Mexican data shown as red open circles 82

4.7 North American shale resource play petrophysical assessment

Table 4-5 shows a comparison of the petrophysical parameters for Eagle Ford and Pimienta shales developed in this thesis and average parameters for U.S. shales extracted from the literature. Eagle

Ford and Pimienta data are within the range of values found in most of the U.S. shales currently producing oil and gas.

Table 4-5 Comparison of petrophysical parameters in North American shales

U.S. Shales, U.S. Shales Eagle Ford Pimienta Haynesville (Jarvie, Mexico Mexico (Gilbert, 2012a) (This thesis) (This thesis) 2009) Resource System: Shale gas Shale gas Shale oil Shale oil

Devonian-Up. Upper Devonian- Age: Upper Jurassic Cretaceous Cretaceous Miocene

Gross thickness (ft): 50 – 1,500 150 >1,000 460

Net thickness (ft): 50 - 700 106 200-300 262

Porosity (%): 1 - 14 12 4-15 13

Permeability (nD): 0 – 5,000 80 -340 > 100 2.5 – 4,600

Oil saturation (%): < 1 - 15 3.85 > 5 75

Water saturation (%): 13-30 25 15-20 17

Chapter Five: Production analysis

5.1 Production data analysis (PDA) and rate transient analysis (RTA)

Advances in technology such as horizontal drilling and completions including multi-stage hydraulic fracturing jobs have led to obtain commercial production from unconventional reservoirs, something that was not achievable in the too distant past.

Some of the objectives of reservoir engineering when characterizing a new reservoir are to calculate original fluids in place, estimating reserves, determining the Estimated Ultimate

Recovery (EUR) as well as production rates and recovery factors. Including an estimate of future hydrocarbon prices allows performing an economical evaluation of a given project and/or field development. However, all of these aspects are challenging particularly in those cases where information is scarce. Production data analysis is a useful reservoir characterization tool in high permeability reservoirs and provides a reasonable degree of accuracy. However, the approach is more challenging in shale reservoirs. Such challenge is faced in this chapter that deals with production data analysis and rate transient analysis. Some of the most common problems in a shale oil and gas wells include lack of initial and average reservoirs pressure, very low and ultra-low permeability, multi-phase flow, several storage mechanisms, stress-dependent porosities and permeabilities, and in the case if gas reservoirs desorption and diffusion gas and (Clarkson et al

2012).

5.2 Importance of Flow Regimes

The purpose of a multi-stage hydraulic fracturing in horizontal wells is to increase the contacted area between the well and the reservoir, creating hydraulic fractures that interact with the natural fracture network of the reservoir resulting in new pathways for fluid flow. These stimulation jobs 84

create complex geometries, leading to different flow regimes over the well production life.

Therefore, many authors have discussed analytical methods to understand in detail the behavior of the wells, to enhanced/optimize production, to predict production, and in general to aid in the design of future wells.

The first step to identify the flow regimes thru diagnostic plots. The pressure derivative versus time in a log-log plot can give the following results: transient radial flow period, which is defined by a slope equal to zero, linear flow period, which is characterized by a slope equal to 0.5, and boundary dominated flow, which generates a slope equal to 1 (Figure 5-1).

Since early linear flow from matrix to fractures is one of the most common flow regimes observed

in a multi-stage fractured horizontal well, and since this flow period can continue over the years, 85

the most popular method to analyze it is the square root of time plot. In a gas well, a plot of rate-

normalized pressure vs. square root of time can be drawn. In this cross plot, Ppi �𝑃𝑃𝑝𝑝𝑝𝑝 − 𝑃𝑃𝑝𝑝𝑝𝑝𝑝𝑝� � 𝑔𝑔 is the pseudo-pressure at initial reservoir𝑞𝑞 pressure and Ppwf is the pseudo-pressure at flowing

pressure. The slope from this plot can be used to calculate the product of fracture half-length and square root of permeability. The pseudo pressure is used to consider the changes in compressibility and viscosity of gas with respect to pressure.

Another way to analyze linear flow in a shale gas well is by plotting the reciprocal rate 1/q vs. square root of time in a Cartesian plot (Aguilera, 1980; Wattenbarger et al. 1998.). In this plot

linear flow appears as a straight line.

5.3 Production Analysis Methods

Once the flow regime is identified, the production analysis methods can be applied. These methods

usually include (Clarkson, 2013):

1. Straight-line. Hydraulic fracture properties or reservoir properties can be acquired in this

instance using pseudo time and pseudo pressures. This can be complemented with material

balance (MB) and flowing material balance (FMB) techniques.

2. Type curve. This approach allows matching production data to dimensionless solutions of

flow equations.

3. Analytical and numerical simulation. Analytical simulations provide solutions to

mathematical models derived analytically. Numeral simulations provide solutions to more

complex mathematical models with the use of numerical methods.

4. Empirical. Do not have a rigorous theoretical development but can be very useful in

practice in many instances.

5. Hybrid methods. These include a combination of analytical and empirical methods.

Permeability and skin might be obtained, and production forecasts can be carried out.

5.3.1 Straight Line Methods

Material balance (MB) and flowing material balance (FMB) are techniques commonly used to determine original fluids in place. Material balance is based on the law of conservation of mass, and production and static data are used to estimate original hydrocarbon in place as well to predict reservoir performance. Schilthius (1936) was the first person to develop a general MBE for oil and gas reservoirs, considering an isotropic tank at average reservoir P where oil gas and water are present. The general form of the MBE can be expressed as Initial volume = Produced volume +

Remaining volume. Since then, many authors have developing different material balance equations

(MBE) according to the characteristics of each type of reservoir, drive mechanisms, and fluid properties. A novel MBE for shale gas reservoirs developed by Orozco and Aguilera (2017) is discussed later in this chapter.

Flowing material balance (Mattar and McNeil, 1998, Mattar and Anderson, 2005) is useful when average reservoir pressures are not available. In a conventional reservoir, the wells are shut in for a period of time, and the average reservoir pressure is obtained from the build-up analysis. In unconventional reservoirs, shut the wells in is not possible due to the amount of time required to obtain a static value of pressure, therefore the importance of the method. This method is very interesting for tight and shales gas reservoir, and it can be applicable to either constant or variable flow rate. 87

5.3.2 Type curve Methods

Fetkovich in 1980 presented a method for determining Arps decline curve parameters from type curve matching, combining analytical solutions for constant flowing pressure. He expressed rate and time in dimensionless units:

1 Eq. 5-1 = 2 𝑟𝑟𝑒𝑒 𝑞𝑞𝐷𝐷𝐷𝐷 𝑞𝑞𝐷𝐷 �𝑙𝑙𝑙𝑙 − � = 𝑟𝑟𝑤𝑤 Eq. 5-2 1 1 1 𝐷𝐷 2 𝑡𝑡 2 𝑡𝑡𝐷𝐷𝐷𝐷 2 𝑟𝑟𝑒𝑒 𝑟𝑟𝑒𝑒 �� 𝑤𝑤� − � �𝑙𝑙𝑙𝑙 � 𝑤𝑤� − � 𝑟𝑟 𝑟𝑟 The matching points in transient radial flow can give the reservoir parameters such as permeability, skin and EUR.

Hydraulically fractured wells may exhibit a linear flow regime for many years. A method to analyze linear flow was suggested by Wattenbarger et al. 1998 using a correction in drawdown that accounts for fluid property and desorption with pressure to analyze long-term production performance of gas wells. Assuming a hydraulically fractured well in the center of a rectangular reservoir and the fracture assumed to be extended to the boundaries of the reservoir, they were able to show that the solution in case of constant rate production and closed reservoir is:

1 2 1 Eq. 5-3 = + ∞ 2 3 2 2 𝜋𝜋 𝑦𝑦𝑒𝑒 𝑥𝑥𝑓𝑓 𝑦𝑦𝑒𝑒 2 2 𝑥𝑥𝑓𝑓 𝑤𝑤𝑤𝑤 𝐷𝐷𝑥𝑥𝑓𝑓 2 2 𝐷𝐷𝑥𝑥𝑓𝑓 𝑃𝑃 � 𝑓𝑓� � � 𝑒𝑒� 𝑡𝑡 � − � 𝑓𝑓� � � � 𝑒𝑒𝑒𝑒𝑒𝑒 �−𝑛𝑛 𝜋𝜋 � 𝑒𝑒� 𝑡𝑡 � 𝑥𝑥 𝑦𝑦 𝜋𝜋 𝑥𝑥 𝑛𝑛=1 𝑛𝑛 𝑦𝑦

And dimensionless variables are:

Eq. 5-4 = 141𝑖𝑖.2 𝑤𝑤𝑤𝑤 𝐷𝐷 𝑘𝑘ℎ�𝑃𝑃 − 𝑃𝑃 � 𝑃𝑃 0.00633 Eq. 5-5 = 𝑞𝑞𝑞𝑞𝑞𝑞 𝑘𝑘𝑘𝑘 𝐷𝐷𝐷𝐷𝐷𝐷 2 𝑡𝑡 𝑡𝑡 𝑓𝑓 𝜙𝜙𝜙𝜙𝐶𝐶 𝑥𝑥 88

The application of square root of time plot was proved. They noticed that in a current analysis of a field with about 60 wells, long term linear flow was detected in one third of the wells. A more accurate EUR is provided with RTA.

5.3.3 Empirical Methods – Decline Curve Analysis (DCA)

Declination is the reduction in production capacity of oil or gas from a well or set of wells as a result of a decrease in reservoir pressure due to draining. The production decline of a conventional reservoir follows a behavior that obeys conventional decline curve proposed by Arps in 1945. The principal assumptions of traditional DCA can be summarized as follows:

• Constant reservoir and operating conditions

• Constant bottomhole flowing pressure

• Boundary-dominated flow regime

• The well is producing at capacity

• Single layer

This method of analysis is simple to use and requires minimum amount of data, however when it is applied to an unconventional reservoir can lead to significant errors due to the assumptions used in Arps’ curves. There are three types of decline curves: exponential, hyperbolic and harmonic.

The main difference between these three types or curves is the exponent b. Exponential decline is the simplest and widely used form of decline analysis for conventional reservoirs. Nevertheless, hyperbolic decline is more accurate but also more complicated. In very-low-permeability reservoir systems, it is common to observe primary violations of one or more of the assumptions related to traditional DCA, therefore, the use of the Arps' in production data conducts to significant 89

overestimation of reserves, precisely when the hyperbolic relation is extrapolated with a b-

exponent greater than one. The Arp’s equations can be seen in the next table:

Table 5-1 Arps decline curve equations.

Decline type Equations

Exponential Eq. 5-6 b = 0 = ( )

𝑖𝑖 𝑖𝑖 Hyperbolic 𝑞𝑞 𝑞𝑞 ∗ 𝑒𝑒𝑒𝑒𝑒𝑒 −𝐷𝐷 𝑡𝑡 Eq. 5-7 0 < b < 1 = (1 + 𝑞𝑞𝑖𝑖 ) 𝑞𝑞 1 Harmonic 𝑖𝑖 𝑏𝑏 Eq. 5-8 = 𝑏𝑏𝐷𝐷 𝑡𝑡 b = 1 1 + 𝑞𝑞𝑖𝑖 𝑞𝑞 𝐷𝐷𝑖𝑖𝑡𝑡

The values of b-parameter in hyperbolic decline varies from 0 to 1. The Arps decline exponent b ranges were provided with the assumption of boundary dominated flow (BDF) in the well and constant flowing pressure. Application of the hyperbolic relation to transient flow, which can be seen in unconventional reservoirs for extended periods, can result in optimistic production forecast.

Other authors like Ilk et al. 2008 have considered a power law exponential decline to match production better than the hyperbolic decline; it was empirically derived from tight gas/shale gas reservoir cases with a different D-parameter constrained by D∞ to convert the power-law

exponential equation to an exponential decline with a uniform transition. This constrain leads to a

more realistic production forecast.

Additional techniques have been presented, Valko and Lee 2009 introduced the stretched-

exponential decline method. Usually the stretched exponential function can be used to represent

decays in heterogeneous systems. “The actual production decline is determined by a great number

of contributing volumes individually in exponential decay, but with a specific distribution of

characteristic time constraints”. The applicability of this method continues to be investigated.

Despite DCA, which based on empirical observations, have work for conventional resources, none

of them are sufficient to forecast production for all unconventional plays. Each reservoir should

by analyzed by itself in order to apply these relations appropriately for production forecasts.

5.3.4 Hybrid Methods

Some authors like Kupchenko et al. (2008) have investigated the b-values during the production life of unconventional wells to avoid overestimations in EUR. They proposed that for a given period of time a b- value higher than one (superbolic decline) should fit the real data, and after that period, hyperbolic decline with a b-value lower tan unity will be able to forecast a more accurate production at a late time. Figure 5-2 illustrates the proposed example:

Figure 5-2 Tight gas production performance using decline curves – Field example (from Kupchenko et al. 2008) In this example, the red line corresponds to the superbolic decline with b=2 matching the real data, after that, two times (t=0.53, green line and t=1.05 years, purple line) are considered to forecast the production with a hyperbolic decline with b=0.25, the cumulative production variation ranges from 3750 to 5300, this difference is considerable when applying economics, the analyst must be careful when deciding which value is the most adequate. Definitive b-value for the Eagle ford in

Texas has not been determined at this time.

Nobakht, M and Clarkson (2012) proposed a new analytic method to analyze linear flow in tight and shale gas reservoirs. They derived an equation analytically to correct the slope of the square root of time plot for constant flowing pressure, and then validated their results against test cases using numerical simulation. They concluded that not doing the correction could lead in an overestimation of the fracture half-length. 92

5.4 Field Cases

5.4.1 Long transient linear flow periods in Mexican shales

For more than 35 years it has been known about the existence of very long linear flow periods in

shale reservoirs. For example, Aguilera (1980, p. 403) showed the presence of linear flow that

went for over 25 years in Devonian shales of the Appalachian basin without reaching boundary

dominated flow. This can happen in many instances in continuous accumulations. The same

conclusion about very long linear flow periods in unconventional reservoirs has also been reached

by many investigators including for example Arevalo-Villagran el at. (2006).

Long transient linear flow periods seem to be occurring also in Mexican shales. For example, the

62 months of production of well Emergente-1 (shale gas, Burgos basin) shown in Figure 2-5 are reproduced in Figure 5-3 as a simple cross plot of 1/rate (1/q) vs. the square root of time in months

(t^0.5). For transparency and easy visualization, the analysis is shown without modifying the real data with any time or rate functions.

The continuous red line in Figure 5-3 shows a straight-line trend throughout the 62 months of gas production in well Emergente-1 that is indicative of continuous linear flow without reaching boundary dominated flow. We have also observed similar linear flow periods in other shale gas wells in Mexico. Data points inside the purple ellipse in Figure 5-3 are probably due to operational problems although the actual reasons are not available in our records.

However, it must be noted that if the flow had been stopped at 36 months (t^0.5 = 6) the conclusion could have been reached erroneously that the outer reservoir boundaries (dashed red line) had been reached (pseudo steady state) and that the reservoir was too small. It is good that gas flow was continued for other 26 moths. This is the type of situation that in practice might kill a promissory play in a given area. 93

Habano field has four wells that have been completed in the gas condensate window of Eagle Ford formation. As seen in Figure 5-4, Habano 1, 21, 2 and 21 show a linear flow during the 43, 43,

42, and 40 months of production, respectively.

We have performed the same type of analysis for oil production from well Anhélido-1 as shown in Figure 5-5 Linear flow cross plot for oil production from well Anhélido-1 suggests that boundary dominated flow was not reached during 12 months of continuous production. The last data point is an outlier due to operational problems. Anhélido-1 was the first well to produce oil from the Pimienta shale (Burgos Basin).. There are indications of linear flow throughout 12 months of production. The last data point deviates from the linear trend but it is an outlier stemming from operational problem with the flowmeter equipment. Well Anhélido-1 is very important as it corroborates the presence of oil in the Burgos shale (Pimienta formation), something that had been discarded in the past in some studies.

The lack of boundary dominated flow in the analyses we have done up to this point adds to the potential of Mexican shale reservoirs as this is the same type of behavior we have observed in many shales and tight reservoirs in the U.S.

5.0 Operational 4.5 Problems? This 4.0 could have been misinterpreted as 3.5 sealed outer boundaries 3.0 (small reservoir) 2.5 2.0

1/q (1/MMCFd)1/q 1.5 1.0 0.5 0.0 0 2 4 6 8 10 t^0.5 (Months^0.5)

0.035

? 0.030

0.025

0.020

0.015 1/q (1/BOPD) 1/q

0.010

0.005

0.000 0 1 2 3 4 t^0.5 (Months^0.5) Figure 5-5 Linear flow cross plot for oil production from well Anhélido-1 suggests that boundary dominated flow was not reached during 12 months of continuous production. The last data point is an outlier due to operational problems. Anhélido-1 was the first well to produce oil from the Pimienta shale (Burgos Basin).

5.4.2 Production analysis of Cretaceous Eagle Ford Formation

The main objective of Habano-1 was to test Eagle Ford formation in the gas condensate window.

The well was hydraulically fractured with 16 stages and produced gas condensate in 2012.

Currently, the well is producing 0.31 MMSCFD and has a cumulative gas production of 0.81 BSCF as shown in Figure 5-6. Successful results in this well justified the development of three more wells: Habano-21, Habano-71 and Habano-2, whose production can be observed in Figure 5-6.

As of January 2017, gas cumulative production of the field was around 3.2 BSCF.

Figure 5-6 Gas rates and cumulative gas production of Habano field.

5.4.2.1 Using a new material balance to calculate OGIP in well Habano 1

Early production of Habano 1 was analyzed using dynamic data and considering that it is a stress- sensitive gas condensate reservoir. The first 20 days of production can be seen in Figure 5-7. The total gas/condensate rate Qgt was calculated from:

1 Eq. 5-9 = +

𝑄𝑄𝑔𝑔𝑔𝑔 𝑄𝑄𝑔𝑔 �𝑄𝑄𝑐𝑐 � 𝐺𝐺𝐺𝐺𝐺𝐺 Condensate rate can be either multiplied by 1/GCR if units are STB/MMSCF, or directly by GCR if units are shown in MMSCF/STB. Cumulative production that included gas, condensate and water was calculated using the equation (Rojas, 2003):

Eq. 5-10 = + +

𝐺𝐺𝑝𝑝𝑝𝑝 𝐺𝐺𝑝𝑝 𝐺𝐺𝐸𝐸𝐸𝐸𝑁𝑁𝑐𝑐 𝐺𝐺𝐸𝐸𝐸𝐸𝑊𝑊𝑝𝑝 97

Where GEC is gas production associated with condensate, and GEW is gas production associated

with water. Nc and Wp are the cumulative condensate and cumulative water, respectively. In this part of the analysis, water production was neglected as only flow back water obtained from the stimulation job was being produced. GEC can be computed from:

133,000 Eq. 5-11 = 𝛾𝛾𝑐𝑐 𝐺𝐺𝐸𝐸𝐸𝐸 42𝑀𝑀.29𝑊𝑊𝑐𝑐 Eq. 5-12 = 1.03 𝛾𝛾𝑐𝑐 𝑀𝑀𝑀𝑀𝑐𝑐 𝛾𝛾𝑐𝑐

Specific gravity of the condensate can be ontained from its ºAPI value, and the molecular weight

of the condensate is related to the specific𝛾𝛾𝑐𝑐 gravity. The next step is to calculate gas pseudo pressure

m(P) using an approach proposed by Al-Hussainy (1966), who studied the flow of real gases in

porous media. Gas pseudo pressure is a function of compressibility and Z-factor as shown in the

equation:

2 ( ) = Eq. 5-13 𝑃𝑃 𝑃𝑃 𝑚𝑚 𝑃𝑃 � � � 𝑑𝑑𝑑𝑑 0 𝜇𝜇𝑔𝑔𝑍𝑍

The following MBE methodology was used for calculating OGIP (Orozco and Aguilera, 2015;

Orozco and Aguilera, 2017):

1. Calculate the pseudo pressure corresponding to the initial reservoir pressure, m(Pi).

2. Convert flowing pressures Pwf, to pseudo pressures m(Pwf).

3. Determine material balance pseudo time (Mattar and Anderson, 2005):

Eq. 5-14 = 𝑑𝑑𝑑𝑑 𝑡𝑡𝑐𝑐𝑐𝑐 � 𝜇𝜇𝑔𝑔𝑍𝑍 98

4. Prepare a cross plot of (m(Pi)-m(Pwf))/Qgt vs. material balance pseudo time, tca. The y-

intercept corresponds to a reservoir constant, bpss (“pss” stands for pseudo steady state).

5. Calculate the average reservoir pressure using the Dynamic Material Equation by Mattar

and Anderson, 2005:

Eq. 5-15 ( ) = ( ) +

𝑔𝑔𝑔𝑔 𝑝𝑝𝑝𝑝𝑝𝑝 𝑚𝑚 𝑃𝑃 𝑚𝑚 𝑃𝑃𝑃𝑃𝑃𝑃 𝑄𝑄 𝑏𝑏

6. Convert average reservoir pseudo pressure to average reservoir pressure. This can be done

by creating a theoretical curve of pressure P vs. pseudo pressure m(P) and performing a

regression analysis to determine average reservoir pressure as a function of average

reservoir pseudo pressure.

7. Assume a unit value for the drainage area A (In this analysis, it is considered 1 acre) and

run a volumetric calculation to obtain an initial estimate of total OGIP per unit area. The

following volumetric equations are used to account for the different storage mechanism of

the shale:

43560 (1 ) Eq. 5-16 Free gas stored in matrix: = 𝐴𝐴ℎ𝜙𝜙𝑚𝑚𝑚𝑚 − 𝑆𝑆𝑤𝑤𝑤𝑤 𝐺𝐺𝑚𝑚 Free gas stored in natural 43560 𝐵𝐵𝑔𝑔(𝑔𝑔 + )(1 ) Eq. 5-17 = and hydraulic fractures: 2 ℎ𝑓𝑓 𝑤𝑤𝑤𝑤 𝐴𝐴ℎ 𝜙𝜙 𝜙𝜙 − 𝑆𝑆 𝐺𝐺2+ℎ𝑓𝑓 𝐵𝐵𝑔𝑔𝑔𝑔 Eq. 5-18 = 1.359.7 Adsorbed gas: + 𝑉𝑉𝐿𝐿𝑃𝑃𝑖𝑖 𝐺𝐺𝑎𝑎 𝐴𝐴ℎ𝜌𝜌𝑏𝑏 � � 𝑃𝑃𝐿𝐿 𝑃𝑃𝑖𝑖 Eq. 5-19 = 43043 ( ) Dissolved gas: 100 𝑇𝑇𝑇𝑇𝑇𝑇 𝐺𝐺𝑑𝑑 𝐴𝐴ℎ𝐶𝐶 𝑃𝑃𝑃𝑃 � − 𝜙𝜙𝑎𝑎𝑎𝑎𝑎𝑎 − 𝜙𝜙𝑜𝑜𝑜𝑜𝑜𝑜� 𝜌𝜌𝑟𝑟

Methane concentration in the solid kerogen, C(P) is a function of reservoir pressure and temperature

(Swami et al, 2013). Authors stated that solubility in the solid kerogen is the same as in the bitumen since they are similar:

Eq. 5-20 ( ) = + + + 2 𝑃𝑃 𝑃𝑃 𝐶𝐶 𝑃𝑃 𝑏𝑏1 𝑏𝑏2𝑃𝑃 𝑏𝑏3 𝑏𝑏4 � � 𝑇𝑇 𝑇𝑇

In the equation pressure P is expressed in MPa and temperature T is in Kelvin, b1 = -0.018931,

3 b2= -0.85048, b3= 827.26, and b4= -635.26. C(P) is given in m of gas at normal temperature and pressure NTP/m3 of kerogen (or ft3 of gas at NTP/ft3 of kerogen).

8. Calculate the fractional contribution of each storage mechanism (organic and inorganic

matrix, natural fractures, adsorbed gas and dissolved gas) to the total OGIP per unit area,

from:

Eq. 5-21 = ; = ; = ; = 𝐺𝐺𝑚𝑚 𝐺𝐺2+ℎ𝑓𝑓 𝐺𝐺𝑎𝑎 𝐺𝐺𝑑𝑑 𝜔𝜔𝑚𝑚 𝜔𝜔𝑓𝑓 𝜔𝜔𝑎𝑎 𝜔𝜔𝑑𝑑 𝐺𝐺𝑡𝑡 𝐺𝐺𝑡𝑡 𝐺𝐺𝑡𝑡 𝐺𝐺𝑡𝑡

9. Estimate the gas deviation factor, Z2, using equation from Rojas (2003), where Z2 takes

into account two phases and considers that liquid behaves as a gas below the dew-point

pressure. Above the dew-point, Z2, is equal to to the single-phase deviation factor Z.

1 1 Eq. 5-22 = + + + ( ) + 2 + 2 𝑃𝑃𝑝𝑝𝑝𝑝 𝑍𝑍2 𝐴𝐴0 𝐴𝐴1�𝑃𝑃𝑝𝑝𝑝𝑝� 𝐴𝐴2 � � 𝐴𝐴3 𝑃𝑃𝑝𝑝𝑝𝑝 𝐴𝐴4 � � 𝐴𝐴5 � � 𝑇𝑇𝑝𝑝𝑝𝑝 𝑇𝑇𝑝𝑝𝑝𝑝 𝑇𝑇𝑝𝑝𝑝𝑝

In this equation, A0= 2.24353, A1= -0.0375281, A2= -3.56539, A3= 0.000829231, A4= 1.53428,

A5= 0.131987. Pseudo reduced pressure and temperature are function of the pseudo critical pressure and temperature and gas gravity, this information can be obtained from PVT analysis or

100

they can be calculated using correlations published by Standing for gas condensate reservoirs

(Ahmed Tarek, 2006)

Eq. 5-23 = ; = 𝑃𝑃 𝑇𝑇 𝑃𝑃𝑝𝑝𝑝𝑝 𝑇𝑇𝑝𝑝𝑝𝑝 𝑃𝑃𝑝𝑝𝑝𝑝 𝑇𝑇𝑝𝑝𝑝𝑝 Eq. 5-24 = 706 51.7 11.1 2 𝑃𝑃𝑝𝑝𝑝𝑝 − �𝛾𝛾𝑔𝑔� − �𝛾𝛾𝑔𝑔� Eq. 5-25 = 187 330 71.5 2 Pseudo𝑇𝑇𝑝𝑝𝑝𝑝 critical− �pressure𝛾𝛾𝑔𝑔� − is�𝛾𝛾 𝑔𝑔found� in psia and pseudo critical temperature is given in degrees

ºRankine.

10. Compute the modified gas compressibility factor, Z2’, at each value of average reservoir

pressure from the new MBE (Orozco and Aguilera, 2017):

= 1 + + 35.315 (1 ) + Eq. 5-26 ′ ′′ 𝑚𝑚 𝑔𝑔 𝑏𝑏 𝐿𝐿 2 2 𝑎𝑎 𝑑𝑑 𝑚𝑚− 2+ℎ𝑓𝑓 𝜔𝜔 𝐵𝐵 𝜌𝜌 𝑉𝑉 𝑃𝑃 𝑍𝑍 ′ 𝑍𝑍 � − 𝜔𝜔 − 𝜔𝜔1.057− �𝜔𝜔 (𝐶𝐶) 𝜔𝜔 𝐶𝐶 �Δ𝑃𝑃 � � + 𝜙𝜙𝑚𝑚𝑚𝑚 − 𝑆𝑆𝑤𝑤𝑤𝑤 𝑃𝑃𝐿𝐿 𝑃𝑃 (1 ) 100 −1 𝜔𝜔𝑚𝑚𝐶𝐶 𝑃𝑃 𝐵𝐵𝑔𝑔 𝑇𝑇𝑇𝑇𝑇𝑇 � � � − 𝜙𝜙𝑎𝑎𝑎𝑎𝑎𝑎 − 𝜙𝜙𝑜𝑜𝑜𝑜𝑜𝑜�� 𝜙𝜙𝑚𝑚𝑚𝑚 − 𝑆𝑆𝑤𝑤𝑤𝑤 𝜌𝜌𝑟𝑟

11. Plot the production history as P/Z2’ vs. cumulative gas production, Gpt.

12. Identify the data points representing the boundary-dominated flow period, those points that

follow a linear trend on the P/Z2’ vs. Gpt plot.

13. Perform a linear regression analysis for the boundary-dominated flow data, and determine

total OGIP from the extrapolation of the straight line to an average reservoir pressure equal

to zero.

14. Since the calculations were carried out with data from early stages of production, error bars

are inserted in the plot discussed next.

101

5.4.2.2 Results and discussion for well Habano 1

Table 5-2 shows the parameters used for material balance calculations. Some properties were

taken from well logs and PVT analysis, and others were taken from analogous wells in the Eagle

Ford formation in the U.S. After 20 days, the well had a gas rate of 3.2 MMSCF/d and a cumulative

gas production of 45 MMSCF, the production profile is shown in Figure 5-7. Following the

methodology explained above, the determination of the constant bpss was done using the plot shown in Figure 5-8. The calculation of this parameter allowed to determine the average pseudo pressure, that later was converted back to average reservoir pressure. The total OGIP was calculated using the modified gas compressibility factor, Z2’, that considers the two phases in a gas condensate reservoir and the different storage mechanisms in shales. The MBE developed by Orozco and

Aguilera (2017) considers a stress- sensitive shale gas condensate reservoir. Stress-sensitivity has generally this has been omitted in the past while considering this kind of problem. A volumetric estimation indicated a Total OGIP of 6,569 MMSCF (Table 5-3), whereas the MBE methodology

indicates that Total OGIP ranges from 6,025 to 7,364 MMSCF as shown in Figure 5-9. Up to

January of 2017, the well had a cumulative gas production of 810 MMSCF during 43 moths of continuous production, leading to a current recovery factor of 12% for the volumetric estimation, and 13.4 to 10.9% for the material balance estimation. Ignoring the effects of adsorption and diffusion in shales can result in an underestimation of OGIP.

It is important to note that the pressure that was used in this analysis was the well head pressure, and the time of evaluating was only 20 days, which is not enough time for a rigorous material balance study. However, these limitations were not obstacles to continue with the calculation of

Total OGIP in order to make a comparison with the volumetric estimate. In practice, this type of calculation is useful as a quick indicator in in an exploratory well. 102

Table 5-2 Reservoir and fluids parameters used for material balance calculations

Parameter Symbol Value Units

Initial reservoir pressure Pi 4200.00 psi

Matrix water saturation Swm 0.25 Fraction

Fractures water saturation Swf 0 Fraction

Water compressibility Cw 3.00E-06 1/psia

Matrix compressibility Cm 1.00E-06 1/psia

Total stress on fractures σt 9000.00 psi

Healing pressure ph 20000.00 psi

Langmuir Volume VL 52.04 scf/ton

Langmuir Pressure PL 2256.39 psia

Initial inorganic matrix Porosity φm 0.0545061 Fraction

Organic porosity φorg 0.01 Fraction

Adsorbed porosity φads_c 0.002 Fraction

Initial porosity of natural fractures φ2 0.001 Fraction

Initial porosity of hydraulic fractures φhf 0.002 Fraction

Initial total matrix porosity φmt 0.0645061 Fraction

Initial total shale porosity φsh 0.0695061 Fraction

Inorganic matrix porosity attached to the matrix system φb 0.05970 Fraction Total Organic Carbon TOC 4.2 % weight 3 Shale bulk density ρb 2.65 gr/cm

Relative density of kerogen ρr 0.5 - Reservoir temperature T 666.67 °R Net pay h 106 ft Gas specific gravity SG 0.728 Fraction of OGIP stored in fractures ω 0.0407 Fraction

Fraction of OGIP stored in matrix ωm 0.6561 Fraction

Dissolved fraction of OGIP ωd 0.1473 Fraction

Adsorbed fraction of OGIP ωa 0.1559 Fraction

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Table 5-3 Volumetric estimation of original gas in place for each storage mechanism Volumetric

Free Gas in Matrix OGIPm 4,309.70 MMSCF

Free Gas in Natural and Hydraulic Fractures OGIP2+hf 267.24 MMSCF

Adsorbed Gas OGIPads 1,024.27 MMSCF

Dissolved Gas OGIPdiss 967.89 MMSCF Total OGIP OGIP 6,569.10 MMSCF

Figure 5-7 Production history of well Habano 1

104

Figure 5-8 Determination of constant bpss for well Habano 1

Figure 5-9 Material balance plot for Habano 1. Total OGIP is estimated to be 6.69 BSCF.

105

Figure 5-10 Location of 4 wells in Habano field (Courtesy of Pemex)

5.4.3 Production analysis in Jurassic Pimienta Formation

Two wells have tested Pimienta Formation in Burgos basin. Anhélido-1 was completed in 2012 with an initial oil production of 500 bopd of 37 API and 1.5 MMSCFD of wet gas. The well stabilized at 80-90 bpd and 0.6 MMSCFD after one year of production as shown in Figure 5-11.

106

Figure 5-11 Production and pressure of well Anhélido-1

Six key events have been identified during the production history of this well: (1) the well was open to production in 2012, (2) an orifice plate flowmeter was installed in the well to have continuous production measurements, (3) the well was produced through a choke of 18/64”, (4) the choke was reduced to 16/64”, (5) a piece of the flowmeter equipment was replaced because a plug of mud found in the flowmeter, and (6) the well was closed after 431 days of production due to budget availability problems. At that moment, the well had accumulated 48.5 MBO of oil and

274 MMSCF of gas.

107

5.4.3.1 Using an Analytical Model to calculate OGIP, area of SRV, and fracture half-length in Anhélido-1

Commercial software (IHS Harmony - Rate Transient Analysis) was used for evaluating well

Anhélido-1. For this analysis, it was very important to have production and pressure data as well

as PVT analysis. The evaluation of this well was done using (1) a deterministic model for

unconventional oil reservoirs, and (2) an analytical model for horizontal multi-fractured oil

reservoirs.

5.4.3.2 Results and discussion for well Anhélido-1

Parameters and properties used for the deterministic model were taken from well logs and PVT analysis. After 431 days, the well had a cumulative oil production of 48.5 Mstbo. The production profile is shown in Figure 5-12. A deterministic model for an oil unconventional reservoir was

utilized. Calculations from this model are shown in Table 5-4. Based on the straight line from the

normalized pressure vs. square root of time plot in Figure 5-13, we can observe linear flow during

the 14 months of production. The OOIP estimated from the flowing material balance plot shown

in Figure 5-14 is 1,074 Mstbo and the estimated ultimate recovery (EUR) is 123 Mstbo, leading

to a final oil recovery factor of only 11.5%. The straight-line follows the tendency of the last

portion of the data. From this plot, the area of the Stimulated Reservoir Volume (SRV) is 15 acres.

The type curve plot shown in Figure 5-15 is very important because it indicates the dominant flow

regime. The infinite acting linear flow period in represented by the brown line, whereas the green

line represents the bounded reservoir. Since there is uncertainty on the area of SRV, different

scenarios from 10 to 50 acres are considered. The red line corresponds to 15 acres, which is the

most likely area estimated with the model.

108

Figure 5-16 shows forecasts made for each different scenario. Values of EUR range between

72.458 and 693.443 Mstbo, being 123.34 Mstbo the one that corresponds to 15 acres in the SRV area. This is displayed by the red color.

Validation of the deterministic model is done analytically considering a multi-fractured horizontal well. The reservoir has rectangular shaped reservoir with heterogeneities (Figure 5-17). For simulating the pressure response, it was necessary to set the effective horizontal well length and the number of fractures, which is critical in low permeability reservoirs. This well has an effective horizontal length of 4,708 ft and was completed in 17 stages of hydraulically fracturing. In this part of the analysis, fracture conductivity, fracture half-length, and inner-outer permeabilities of the SRV area were obtained by iteration to improve history matching. Fracture half-length obtained from the analytical model was 14 ft, dimensionless fracture conductivity was 39,078, a large value indicating an infinite conductivity fracture, and the inner (between fracture tips) and outer permeabilities (beyond fracture tips) were 4.78x10-3 and 1.48x10-2 md, respectively (Figure

5-18 and Table 5-4). A Blasingame plot is shown in Figure 5-19 and the square root of material balance time is presented in Figure 5-21.

The history matching shows good agreement with real data. Figure 5-20 shows the measured pressures in light brown and the calculated pressures in dark brown. Once the parameters of fracture conductivity, fracture half-length and inner-outer permeabilities of the SRV area are estimated, it is possible to proceed with a reliable forecast. In this scenario, 240 months were forecast with the use of hyperbolic decline. From the forecast shown Figure 5-22, the EUR is

129.95 Mstbo with a remainder recoverable oil of 81.432 Mstbo.

109

Table 5-4 Parameters and calculations for deterministic model of well Anhélido-1

Parameter Symbol Value Units

Area of stimulated reservoir volume ASRV 15 acres Decline exponent b 0

Final oil rate qf 5 bpd Start date 1/17/2014 MM/DD/YYYY Forecast duration Δt 81.7 month End date 11/6/2020 MM/DD/YYYY

Sandface forecast pressure Pwff 476.16 psia Calculations Model type: Hz-Multifrac-Matrix model 1/2 1/2 2 Linear flow parameter Ack 36285.5 md ft 1/2 Product of fracture half-length and sq. root of permeab Xf 34.562 md ft

Effective horizontal well length Le 4708 ft √𝒌𝒌 Number of fractures nf 17

Matrix permeability km 8.20E-04 md

Fracture half-length in y-direction (Xf)y 71 ft 2 Cross sectional area to flow Ac 1.27E+06 ft

Time to end of linear flow telf 439 d Original oil in place OOIP 1074.2 Mstbo

Expected ultimate recoverable oil EURo 123.34 Mstbo

Cumulative oil production Np 48.5 Mstbo

Remaining recoverable oil RRo 74.8 Mstbo

Oil recovery factor RFo 11.5 %

110

Figure 5-12 Production history of well Anhélido-1

Figure 5-13 Normalized pressure vs. square root of time plot for well Anhélido-1 111

Figure 5-14 Flowing material balance plot for well Anhélido-1

Figure 5-15 Type curve plot for well Anhélido-1 112

Figure 5-16 Forecast for well Anhélido-1

Figure 5-17 Schematic of horizontal multi-fractured oil reservoir model

113

Figure 5-18 Horizontal multi-fractured oil reservoir model for well Anhélido-1

Figure 5-19 Blasingame plot for well Anhélido-1

114

Figure 5-20 Pressure history matching for well Anhélido-1

Figure 5-21 Oil normalized pressure vs. Oil material balance square root of time for well Anhélido-1

115

Figure 5-22 Forecast of 240 months for well Anhélido-1

116

Table 5-5 Results from analytical model for well Anhélido-1

Parameter Symbol Value Units Model type: Hz-Multifrac-Composite

Initial reservoir pressure Pi 4800 psia

Fracture half-length in y-direction (Xf)y 14 ft

Effective horizontal well length (X) Lex 4708 ft Dimensionless fracture conductivity FCD 39078.2 Number of fractures nf 17

Inner zone permeability k1 4.78E-03 md

Outer zone permeability k2 0.0148 md Net pay h 262.5 ft

Total porosity φt 6 %

Gas saturation Sg 0 %

Oil saturation So 75 %

Water saturation Sw 25 %

Formation compressibility Cf 6.01E-06 1/psi

Total compressibility Ct 1.42E-05 1/psi Boundaries

Reservoir length Xe 4708 ft

Reservoir width Ye 141.9 ft Drainage area A 15 acres

Area of stimulated reservoir volume ASRV 3 acres Original oil in place OOIP 1074.2 Mstbo

Original oil in place in stimulated region OOIPSRV 215.0 Mstbo Forecast Results Duration t 240 months

Expected ultimate recoverable oil EURo 129.95 Mstbo

Remaining recoverable oil RRo 81.432 Mstbo

117

Chapter Six: Other Unconventional Basins in Mexico

Other basins with unconventional resources are of interest in Mexico. These include the Sabinas,

Tampico-Misantla, Tuxpan (Platform), Veracruz, and Chihuahua basins. In this chapter, geologic and engineering aspects of each basin are described.

6.1 Sabinas Basin

6.1.1 Geologic Aspects

Located in the Mexican states of Coahuila and Nuevo Leon, the Sabinas basin (see Figure 1-3 in

Chapter One) includes the Platform of Burro Picachos, and is a producer of dry gas. It is considered an intracratonic basin filled mainly with marine sediments deposited during long-term subsidence throughout Upper Cretaceous and Paleogene Laramide orogenesis (Eguiluz de Antuñano, 2001).

As in the case of the adjacent Burgos basin, the origin of Sabinas is related to the opening of the

Gulf of Mexico. Structural styles are linked to the presence and thickness of the Jurassic salt and

Barremian evaporites, with mainly double dip anticlines that trend northwest-southeast and are limited by reverse faults (PEMEX E&P Provincia Petrolera Sabinas, 2013). “Four areas with different structural styles are known: (1) an area where Jurassic salt is the regional detachment level; (2) an area where salt diapirs are formed; (3) an area where deformation is controlled by a basement high northeast of the basin; and (4) an area where the absence of Jurassic salt resulted in the development of fault-bend folding” (Eguiluz de Antuñano, 2001).

The source rocks that have been identified are from Upper Jurassic, Lower Cretaceous, and Upper

Cretaceous periods, in the La Casita, La Peña and Eagle Ford formations (Tithonian, Aptian and

Turonian, respectively) (PEMEX E&P Provincia Petrolera Sabinas, 2013). The geochemical characteristics of the organic content and maturity define Tithonian rocks as the main source rock 118

in the Sabinas basin. The main reservoir rock based on volumes of hydrocarbons produced is the

Barremian La Virgen formation (PEMEX E&P Provincia Petrolera Sabinas, 2013). In March 2012,

PEMEX drilled one shale gas well in the basin, Percutor-1, confirming the continuation of the

Eagle Ford play. The well is a dry gas producer with an initial production rate of 2.17 MMcf/d.

The Mexican Eagle Ford Shale is distributed across the NW, NE, and central regions in the Sabinas

Basin. EIA (2013) reported a “300-m thick sequence of black shales rhythmically interbedded with sandy limestone and carbonate-cemented sandstone” as prospective targets in an estimated organic-rich thick interval of 152 m with a net pay of 121 m. EIA based his report in the analogy of the Mexican Eagle Ford Shale in Sabinas basin with the Maverick Basin of South Texas, where the shale presents a TOC of 4%, thermal maturity of 1.50% (Ro), and a porosity of 5%. However, a recent report by Parra et al. (2013) indicated TOC values of up to 6% and effective porosity from

1 to 8% in the exploration wells.

The high-graded prospective area “La Casita” formation is located at a mean depth of 3505 m, about 760 m deeper than the Eagle Ford Shale. A net pay thickness of around 73 m within a 243- m thick organic-rich interval has an average TOC of 2.0% that is gas prone (2.5% Ro). Similar to the Eagle Ford Shale, the average porosity was estimated at 5%, using an analogy of La Casita rock fabric and correlation with the deep Texas and Louisiana Haynesville Shale (EIA, 2013).

PEMEX has drilled two shale gas exploration well in the Sabinas Basin, the Percutor-1 and

Arbolero-1. The first one was completed in March 2012 in the lower Eagle Ford shale formation over the dry gas window. Total MD was 3400 m, equivalent to a TVD of about 1600 m and a lateral length of approximately 1493 m. This well had an inclination of approximately 85° in order to follow the dip of the formation. Thus, strictly it was not planned as a horizontal well. The

119

estimated reservoir properties are as follows: pressure of 2800 psi, temperature 162 °F, permeability 250 nD, effective porosity of 1 to 8% and TOC from 3 to 6% (Parra et al., 2013).

Area: Sabinas Basin Objective: Eagle Ford Result: Dry gas producer Initial Production: 2.2 MMcf/d

16 stages

Horizontal Length: 1,500 m.

Figure 6-1 Seismic profile through well Percutor-1 completed at 3400 m in the Eagle Ford Shale and schematic of the well completion (PEMEX 2012).

6.1.2 Engineering Aspects

In March 2012, PEMEX drilled one shale gas well in the Sabinas basin, Percutor-1, confirming the continuation of Eagle Ford play. Figure 6-1 shows a schematic of the well completion and a seismic profile through well Percutor-1 completed at 3400 m in the Eagle Ford Shale (PEMEX

E&P, 2012).

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The Percutor-1 well was stimulated with 16 hydraulic fracturing stages using hybrid fractures,

which combined the use slick-water and crosslinked fracturing fluids. Injection was from 55 to 60

BPM using 250,000 lb of a white sand combination proppant per stage and approximately 3.2

million gallons of fracturing fluid (Parra et al. 2013). Production evaluation from the 3,330-3,390

m interval indicated a maximum gas production of 3.9 MMcf/d through a 20/64” choke with a well

head pressure of 1900 psi (Parra et al., 2013), without evidence of condensate production.

Parra et al. (2013) indicated that production declined rapidly and that 85% of the gas production

was coming from stages 8 through 16. Stage 8 was the highest producer contributing

approximately 20% of the gas production. The well showed water accumulation towards the toe

of the well, probably because of the inclination with which the well was drilled, which caused the

denser fluid, water, to accumulate at the toe and eventually obstruct gas production (Parra et al.,

2013). Well Percutor-1 produced dry gas with an initial rate of 2.17 MMcf/d. The production

history is presented in Figure 6-2.

In 2012 well Arbolero-1 was drilled and successfully proved the Upper Jurassic Shale gas play, which was the first horizontal well to reach the Pimienta Formation. Total MD was 3901 m, which corresponds to a TVD was about 2639 m and a lateral length of approximately 960 m. The estimated reservoir properties were as follows: pressure 5500 psi, temperature 223 °F, permeability

50 nD, effective porosity about 6 %, and TOC from 2.5 to 3.5%. The well was hydraulically fractured in 11-stages with four perforation clusters each. All stages were stimulated injecting volumes at 62 BPM, using 350,000 lb of a white sand combined proppant per stage and approximately 3.7 million gallons of fracturing fluid (Parra et al., 2013). The production test showed a maximum gas production of 3.5 MMcf/d, while flowing though a 14/64” in choke with

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a well head pressure of 3600 psi, without condensate production. However, the status of

commercial dry gas well was granted by CNH (2016).

Figure 6-2 Production history of well Percutor-1 (CNH, 2016).

The hydraulic fracturing job was monitored with over 22,400 microseismic events from -2.5 to 0.5

degrees of magnitude. The average fracture half-length was estimated between 150 - 300 m, which smaller as compared with the initial design of 396 to 487 m (Parra et al. 2013).

6.1.3 Resources

Exploration in Sabinas for conventional reservoirs started in the 1930s with wells San Marcos-1 and San Marcos-2. Production was established eventually 1975 with the completion of Buena

Suerte-2A, a dry gas producer from dolomites of the Padilla Play. In the unconventional side,

PEMEX assessment of Sabinas-Burro-Picachos indicated prospective resources of 14 Bboe. A more complete summary of PEMEX results as well as the EIA was presented in Chapter 2 (Table

2-3).

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6.2 Tampico Basin

6.2.1 Geologic Aspects

The basin in located in the east central Mexico, in parts of the states of Tamaulipas, Veracruz, San

Luis Potosi, Hidalgo, Puebla and the western of the Gulf of Mexico. The basin is considered as a passive margin basin related to the opening of the Gulf of Mexico that evolved into a foreland basin when the Fold-Thrust Belt of the Sierra Madre Oriental was generated in the west of the basin. Tampico basin is composed mainly of the following tectonic-structural and stratigraphic elements (Figure 6-3): the Alto de Tamaulipas, the Homoclinal de San Jose de las Rusias,

Paleocañón Bejuco-La Laja, the Alto de la Sierra de Tantima, the Paleocanal de Chicontepec, the

Franja Volcánica Transmexicana, the Alto or Isla de Arenque, the Alto de la Plataforma de Tuxpan, and the Fold-Thrust Belt of the Sierra Madre Oriental. Some of these structural elements have influenced the creation of different lithostratigraphic units under their tectonic regime (PEMEX

E&P Provincia Petrolera Tampico-Misantla, 2013).

Tampico Misantla is mainly an oil producer basin. The principal source rocks are carbonaceous shales of the Lower and Middle Jurassic periods, mudstones and shales of the Upper Jurassic:

Oxfordian, Kimmeridgian, and Tithonian, the latter being the most important. Traps are a combination of structural, stratigraphic and associated with high basement.

According to a report prepared by EIA (2013), around 50 conventional wells have already reached the shales of the Pimienta Formation at depths of about 1,000 to 3,000 m. It is possible to distinguish three distinct thermal maturity windows (dry gas, wet gas, and oil) from west to east that reflect the structural dip angle in Tampico basin. The shale gas prospect had an average depth from 1600 to 2400 m. Ignoring the paleo highs, the prospective area of the Pimienta Shale is 123

approximately 13,600 mi2. The Pimienta Formation thickness ranges from 200 m to 10 m thick on paleo highs. EIA (2013) estimated an average net shale thickness of about 60 m, out of an average total organically rich interval of 150 m. The interval has an average net TOC of 3%. Thermal maturity ranges from 0.85% to 1.4% Ro.

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Figure 6-3 Elements of Tampico Misantla basin in Mexico (PEMEX E&P Provincia Petrolera Tampico-Misantla, 2013). 6.2.2 Engineering Aspects

“The southern area of the Tamaulipas basin hosts the well-known Chicontepec complex, a series of unconventional tight oil fields that since discovery in 1904 have produced a cumulative 5.5 Bbo and 7.5 Tcf from over 20,000 wells” (Gachuz-Muro and Sellami, 2009; Stevens and Moodhe, 125

2015). These oil fields in the Chicontepec paleo-channel are considered as unconventional tight

oil reservoirs. They produce 15–35° API gravity crude in an oil window from 1500 –2500 m.

These types of reservoir require the stimulation of large volumes of rock.

The Coyotes field, a mature low-permeability very heterogeneous oil reservoir in the north area of

Chicontepec has been exploited for approximately 38 years. The Coyotes field produces oil of 30

to 35 degrees API from a calcareous sandstone with an average permeability of 0.1 to 2.0 mD

(Gutierrez-Murillo et al. 2014). In order to maximize reserves and oil recovery, two horizontal

wells (Coyotes 1H and 2H) were drilled and hydraulically fractured over 900 m of lateral length.

Coyotes 1H was completed using crosslinked gel as the primary fracturing fluid with a perforation

spacing 150 m. Coyotes 2H was completed with a fluid designed to improve the coverage of the

reservoir using hybrid fluids consisting of linear and crosslinked gel, in order to achieve a better

stimulated reservoir volume (SRV) with a spacing of 50 m (Gutierrez-Murillo et al. 2014). In each

treatment, five fracturing stages were pumped at 60 bpm, placing a total of 3.2 million lbm of

white sand, and using 26,000 bbl of fluid. A 40% increase in production was achieved in Coyotes

2H compared to Coyotes 1H (Gutierrez-Murillo et al. 2014).

Microseismic downhole monitoring allowed to measure the fracture geometry. Fracture length was determined to go from 100 – 195 m to 127 – 250 m with a height of 190-250 m. This result helped to confirm that fracturing treatments would generate upward fracture height growth into adjacent formations. The maximum principal horizontal stress is oriented NE-SW with fracture azimuth of

30 to 40 degrees, and a minor deviation or reorientation during the fracturing jobs. The fracture

gradient was 0.70 psi/ft with a fracture closure of 0.65 psi/ft. The stress is consistent with regional

tectonics. Stress magnitude is uncertain but fracture height growth of around 90 m in the Tertiary

sandstone reservoirs indicates favorably moderate stress (Gutierrez-Murillo et al., 2014). 126

PEMEX E&P (2012) has planned in the past to drill up to 80 shale exploration wells to evaluate the shale geology of Tampico Basin in the next few years. The goal, however, is far from complete due primarily to current low oil and gas prices and budget exploration cuts.

6.2.3 Resources

Conventional oil exploration in the Tampico basin dates to the second half of last century when the first wells were drilled in the Furbero field in the state of Veracruz. In 1904, commercial production began from Cretaceous fractured limestones with the completion of well La Pez-1, followed by the astonishing discoveries of the Faja de Oro. During the 1920’s, the production reaches 500 mbopd. The cumulative production up to January 1st, 2013 was more than 5,500 million barrels of oil and 7.5 trillion cubic feet of gas. In the unconventional side, PEMEX assessment of Tampico-Misantla indicated prospective resources of 34.8 Bboe. A more complete summary of PEMEX as well as the EIA results was presented in in Chapter Two (Table 2-3).

6.3 Tuxpan (Platform)

6.3.1 Geologic Aspects

The Tuxpan Platform, located in Tampico Basin, is a carbonated Mesozoic bank developed on a high basement and currently buried by Tertiary clastic sediments. In this element of Tampico basin, a large number of producing fields are found in both marine and continental settings. The

Platform was formed during the middle Cretaceous period. The largest thickness of this sequence is precisely in the reef edges which are reduced laterally towards the slope and basin facies bordering the platform, and that formed the lithostratigraphic formations of Tamabra and

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Tamaulipas, respectively. Shallow limestones from El Abra formation constitutes the central part

of the Platform (PEMEX E&P Provincia Petrolera Tampico-Misantla, 2013).

Figure 6-4 shows a cross section of the Tuxpan Platform (PEMEX E&P Provincia Petrolera

Tampico-Misantla, 2013). The Tuxpan basin is composed of the Pimienta and Tamaulipas formations. The Pimienta formation is the organically rich portion of the Jurassic Pimienta Shale with an average thickness of 150 m in the high-graded area, and a net thickness estimated at 61 m.

Nevertheless, in the city of Poza Rica the shale can be thin or even absent in some southeast areas, probably due to submarine erosion or lack of deposition. The values obtained by EIA (2013), showed moderate average TOC of 3.0% in the oil to wet gas window (average Ro of 0.9%). Depth ranges from 2011 to 3261 m, averaging about 2590 m.

The Tamaulipas Formation (Lower Cretaceous) extents to a depth averaging about 7,900 ft. The organic-rich interval averages a thickness of 91 m, with net pay estimated at about 64 m. TOC is

in the order of 3.0%. The average thermal maturity is slightly lower than for the deeper Pimienta,

at 0.85% Ro (EIA, 2013).

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Figure 6-4 Paleomodel of the middle Cretaceous, Tuxpan Platform (PEMEX E&P Provincia Petrolera Tampico-Misantla, 2013)

6.3.2 Engineering Aspects

Exploration activity looking for shale gas or shale oil had been reported on the Tuxpan Platform by 2016. It is anticipated, however, that any efforts to establish commercial production from the

Pimienta shales in this Platform will require the drilling of horizontal wells and multi-stage hydraulic fracturing jobs.

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6.3.3 Resources

I do not have records of unconventional resources data or evaluations by PEMEX. A summary of

results by the EIA was presented in Chapter Two (Table 2-3).

6.4 Veracruz basin

6.4.1 Geologic Aspects

The Veracruz basin is placed in eastern Mexico, in the south portion of the state of Veracruz. This basin extends to the continental shelf covering an area of 38,000 km2. The structural elements

(Figure 6-5) consist of a buried portion of the Fold-Thrust Belt of the Sierra Madre Oriental known

as Frente Tectónico Sepultado and Cuenca Terciaria de Veracruz. The basin is considered an oil

and gas producer in Tertiary and Mesozoic formations. Source rocks are mostly Middle Cretaceous

shaly limestones and Upper Miocene shales. The richness and quality of kerogen make it possible

to classify the Jurassic and Cretaceous rocks as source rocks of oil and gas, whereas the Upper

Miocene shales are considered biogenic gas generators (PEMEX E&P Provincia Petrolera

Veracruz, 2013).

The Frente Tectónico Sepultado (FTS) composed principally of carbonate rocks of the Mesozoic

Platform of Córdoba, has oil and gas production. Its origin is a product of the Laramide orogenic event ending in the middle Eocene. FTS is part of a compression system that consists of blocks of limestone on Tertiary sediments that form anticlines whose main axis is oriented NW-SE with closure, and limited by reverse faults that trend northeast. The Cuenca Terciaria de Veracruz

(CTV) is a foreland basin that was filled by a clastic sequence of alternating shales, sandstones, and conglomerates of the Tertiary, overlaying the Mesozoic carbonate rocks, and forming a

Mesozoic- Cenozoic sedimentary column of approximately 12,000 m. The Upper Cretaceous 130

(Turonian) Maltrata formation is an important source rock in the Veracruz Basin because it

contains an estimated 300 ft of organic-rich, shaly marine limestone. EIA (2013) estimated the following properties for these shales: TOC ranging from 0.5% to 8%, averaging approximately

3%, Type II kerogen. thermal maturity ranging from oil-prone (Ro averaging 0.85%) within the oil window at depths of less than 11,000 ft, to gas-prone (Ro averaging 1.4%) within the gas window at average depths below 11,500 ft.

Figure 6-5 Structural elements of Veracruz basin in Mexico (PEMEX E&P Provincia Petrolera Veracruz, 2013)

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6.4.2 Engineering Aspects

PEMEX had planned in the past to drill up to 10 shale exploration wells in the Veracruz Basin in three years (PEMEX E&P, 2012). However, the reduction in oil prices has not permitted to carry out this project.

6.4.3 Resources

The conventional production from the Veracruz basin began in 1953 with well Angostura-2, a producer of oil from a limestone of the Upper Cretaceous. PEMEX has estimated a shale resource of 0.6 Bbo in Veracruz basin (PEMEX E&P, 2014). A summary of results by the EIA was

presented in Chapter Two (Table 2-3).

6.5 Chihuahua Basin

6.5.1 Geologic Aspects

Chihuahua basin is situated in the northeastern part of the Mexican state of Chihuahua. The basin

was developed on paleogeographic elements of the Paleozoic that were formed on the southern

edge of the North American craton, which evolved into an intracratonic basin linked to the opening

of the Gulf of Mexico during the Middle Jurassic period. The basin is bounded by known elements

of Península del Diablo in the northeast, Península Aldama in the southeast, and the Coahuila

Platform in the southeast. This basin has a sedimentary sequence that began its deposition from

Late Jurassic and reached the Late Cretaceous, which had three periods of sedimentary tectonic

evolution (PEMEX E&P Provincia Petrolera Chihuahua, 2013).

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There has been some evidence of hydrocarbons in Chihuahua Basin that were identified through

exploratory drilling and surface petroleum manifestations. Geochemical studies have suggested

the presence of Petroleum Systems related to four source rocks: Paleozoic, Tithonian, Aptian, and

Turonian. Due to the high maturity of the source rock and lack of synchrony, the Paleozoic system

has not been of economic interest. These rocks are usually thin and therefore it has been considered

that it is very risky to attempt any development. The Tithonian also has a high risk for its high

maturity. However, it is feasible for liquid hydrocarbons gases to possibly be stored in the same

Tithonian and Albian. Aptian is thin but the organic richness and maturity can also provide gaseous hydrocarbons. Finally, the Turonian source rocks have been related to liquid hydrocarbons detected in surface manifestations (PEMEX E&P Provincia Petrolera Chihuahua, 2013). The

structural traps are linked with the Laramide deformation. Currently, there are no hydrocarbon

discoveries, and this basin is considered to have medium to low potential (PEMEX E&P Provincias

Petroleras, 2013).

6.5.2 Engineering Aspects

No shale gas or oil exploration activity had been reported on the Chihuahua Basin by 2017.

6.5.3 Resources

It is noteworthy that PEMEX has almost 20 years without studying or working in the Basin of

Chihuahua. Exploration studies should be considered to evaluate the potential of this basin. There are no estimates of prospective resources in this basin (PEMEX E&P Provincia Petrolera

Chihuahua, 2013).

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Chapter Seven: Data Integration and Mexican shales potential

Successful activities in the Eagle Ford shale in Texas through drilling of horizontal wells and

completions using multi-stage hydraulic fracturing jobs has led me to posit the hypothesis that the

potential of shale reservoirs south of the border will be quite significant. This hypothesis has been

tested in the previous 6 chapters of this thesis by examining real data from Mexican shales and

comparing it with shale data from the United States, particularly the Eagle Ford shale. The data

analyzed in this thesis indicates that the hypothesis is correct, and that the Mexican shales potential

is significant both in terms of oil and gas production.

In this chapter, I attempt to highlight the key reasons that lead me to a positive conclusion regarding

this potential.

7.1 Geophysics, Geology and Geochemistry

The geologic continuity of the Texas Eagle Ford shale into the Mexican Burgos basin was

discussed in Chapter 2, and is presented here as Figure 7-1 and Figure 7-2, which depict seismic and geologic cross-sections covering the Eagle Ford shale in both sides of the border. The continuity is evident. However, “Mexico’s marine-deposited shales appear to have good rock quality, the geologic structure of its sedimentary basins often is considerably more complex than in the USA. Compared with the broad and gently dipping shale belts of Texas and Louisiana,

Mexico’s coastal shale zone is narrower, less continuous and structurally more disrupted. Regional

compression and thrust faulting related to the formation of the Sierra Madre Ranges have squeezed

Mexico’s coastal plain, creating a series of discontinuous sub-basins.” (EIA, 2015).

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The quality of the Mexican source rock and comparison with source rock in U.S. shales, as well as various geochemical parameters discussed in Chapter 3, add credibility to the potential of

Mexican shales. A Hydrogen Index (HI) vs. Oxygen Index (OI) modified Van Krevelen diagram presented in Figure 3-3 in Chapter 3, and reproduced here as Figure 7-3, shows that the Mexican

Eagle Ford shale penetrated by well Habano 1 is mature to gas, while the Pimienta shale penetrated by well Anhélido 1 is mature to oil. Table 3-7 in Chapter Three, reproduced here as Table 7-1 shows a comparison of geochemical parameters in U.S. and Mexican shales. Note that Mexican

Eagle Ford and Pimienta shale data are within the range of values found in most of the U.S. shales currently producing oil and gas successfully.

Figure 7-3 Modified Van Krevelen diagram for Habano 1 (Eagle Ford) and Anhélido 1 (Pimienta formation)

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Table 7-1 Comparison of geochemical parameters in North American shales U.S. Shales Eagle Ford U.S. Shales Pimienta (Maende et al., Mexico (Maende et al., Mexico 2013) (This thesis) 2013) (This thesis) Resource System: Shale gas Shale gas Shale oil Shale oil Devonian-Up. Upper Devonian- Age: Upper Jurassic Cretaceous Cretaceous Miocene Tmax (°C): > 455 506 435 - 465 450

TOCpd (wt %): 1 - 5' 4.74 0.1 - 15 2.88

HIpd (mg Hc/g TOC): 10 - 80' 38 50-620 150 Ro (%) 1.2 - 2.5 1.66 0.6 - 1.3 0.85

7.2 Petrophysics

The petrophysical analysis and empirical comparison with the U.S. Eagle Ford shale also indicates the potential of the Mexican shales. This is discussed in detail Figure 4-15 and Figure 4-16 in

Chapter 4, repeated here as Figure 7-4 and Figure 7-5. The graphs include lines of constant water saturation, flow units (dependent on the ratio of permeability over porosity), Knudsen number

(flow regime) and Bulk Volume Water (BVW).

Note in Figure 7-4 that data from both the Mexican and U.S. Eagle Ford shales fall within the range of flow unit A (FUA), with a smaller number of Mexican data points falling within the range of flow unit B (FUB). FUA is the flow unit with the best characteristics of porosity and permeability (Lopez and Aguilera, 2016). Figure 7-5 shows the same type of comparison for the

Mexican Pimienta shale and the U.S. Eagle Ford shale. The good pattern recognition comparisons highlight the potential of Mexican shales.

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Figure 7-4 Modified Pickett plot for Eagle Ford shale wells in the U.S. and Mexico (Burgos basin). U.S. data shown as green triangles. Mexican data shown as blue open circles.

Figure 7-5 Modified Pickett plot for Eagle Ford shale well in the U.S. and Pimienta shale well in Mexico (Burgos basin). U.S. data shown as green triangles. Mexican data shown as red open circles. 138

Table 4-5 in Chapter Four, reproduced here as Table 7-2. This table shows a comparison of the petrophysical parameters for Eagle Ford and Pimienta shales developed in this thesis and average parameters for U.S. shales extracted from the literature. Eagle Ford and Pimienta data are within the range of values found in most of the U.S. shales currently producing oil and gas.

Table 7-2 Comparison of petrophysical parameters in North American shales

U.S. Shales, U.S. Shales Eagle Ford Pimienta Haynesville (Jarvie, Mexico Mexico (Gilbert, 2012a) (This thesis) (This thesis) 2009) Resource System: Shale gas Shale gas Shale oil Shale oil

Devonian-Up. Upper Devonian- Age: Upper Jurassic Cretaceous Cretaceous Miocene

Gross thickness (ft): 50 – 1,500 150 >1,000 460

Net thickness (ft): 50 - 700 106 200-300 262

Porosity (%): 1 - 14 12 4-15 13

Permeability (nD): 0 – 5,000 80 -340 > 100 2.5 – 4,600

Oil saturation (%): < 1 - 15 3.85 > 5 75

Water saturation (%): 13-30 25 15-20 17

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7.3 Shales and their Effect on U.S. and Mexican Production

Chapter 5 discusses in detail Mexican shales wells-performance, rate transient analysis and specialized material balance calculations for shale petroleum reservoirs. The evaluations include the use of rigorous pseudo times and pseudo pressure functions. For transparency, the data are also plotted simply as a function of straight rates and times as measured in the field as shown in Figure

7-6 and Figure 7-7. These graphs present cross plots of 1/ rate vs. square root of time.

The graphs indicate that long transient linear flow periods are happening in Mexican shales without reaching boundary dominated flow. For example, the 62 months of production of well Emergente-

1 (Eagle Ford shale gas, Burgos basin) shown in Figure 7-6 indicate continuous linear flow without reaching boundary dominated flow. This is significant as long transient linear flow periods are characteristic of many commercial shale wells in the U.S. A similar situation is shown in

Figure 7-7 that presents 12 months of transient linear flow in well Anhélido 1 (Pimienta shale oil,

Burgos basin). The lack of boundary dominated flow in these analyses adds to the potential of

Mexican shale reservoirs as this is the same type of behavior observed in many shales and tight reservoirs in the U.S.

The data and the developments presented in this thesis suggest that shales have the potential to help change the production rate slope from negative to positive. This is what happened in the U.S. though intense development of shale petroleum reservoirs as shown in Figure 7-8. Up to 2010 production was declining but then there was rapid dramatic increase in production at about that time. Figure 7-9 shows historical crude oil production up to the year 2015 and Pemex forecast up to 2022. The forecast shows a projected increase in production. Unconventional oil (essentially shale oil) contributes to change this slope. Given the learnings from shales in the U.S. it is likely that the shale contribution to increasing Mexican oil production might be larger. 140

5.0 Operational 4.5 Problems? This 4.0 could have been misinterpreted as 3.5 sealed outer boundaries 3.0 (small reservoir) 2.5 2.0

1/q (1/MMCFd)1/q 1.5 1.0 0.5 0.0 0 2 4 6 8 10 t^0.5 (Months^0.5)

? 0.030

0.025

0.020

0.015 1/q (1/BOPD) 1/q

0.010

0.005

0.000 0 1 2 3 4 t^0.5 (Months^0.5)

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7.4 Effect of Low Oil and Gas Prices

The previous discussion with respect to potential increases in oil production also has application in the case of gas, given the rock maturity in the Mexican Eagle Ford shales and the tested production gas rates. But the question remains: Is it possible to accomplish these production increases from shales given the current environment of low oil and gas prices?

In an attempt to answer this question, I have used cumulative long run supply curves presented in

Figures 1-7 and 1-8 in Chapter 1, and reproduced here as Figure 7-10 and Figure 7-11. The production costs (including capital and operating costs) in the curves come from many sources including extensive research/communication with operating companies (the bulk of this research information is provided by companies on a confidential basis), and companies financial statements and financial reports (Aguilera and Aguilera, 2015). The objective of the curves is to examine the big picture potential of a given area or globally. However, the usual petroleum engineering detailed economic analysis including for example capex, opex, anticipated oil and gas prices, and forecasted production rates, among others, are required for each individual project.

We are learning from the recent past is that the cost-reducing effects of technology and innovation are having a profound effect on hydrocarbons production of U.S. shales. I anticipate that this technology will have direct application in the case of shale petroleum reservoirs in Mexico. Note in Figure 7-10 and Figure 7-11 that there are significant oil and gas recoverable volumes that can be produced at costs that are lower than current oil and gas prices. While some portions of the supply curves show quantities that can be produced economically, challenges include high drilling and completion costs, and lack of availability of inputs such as water for fracturing. And Escobar

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(2014) has indicated that Mexico will keep the shale projects postponed until oil and gas prices go

up. However, given the significant potential, I anticipate that these challenges will be overcome.

12 50 MEXICAN SHALE GAS 10 WORLD SHALE GAS

8 40

4 30 2 Production Cost (USD / MCF)

0 20 0 500 1000 1500 2000 2500 Shale Gas Recoverable Volume (TCF)

10 Production Cost (USD / (USD Cost MCF) Production

0 0 5000 10000 15000 20000 Shale Gas Recoverable Volume (TCF)

Figure 7-10 World cumulative long run supply curve for shale gas (Aguilera and Aguilera, 2015). Insert developed in this study for Burgos, Sabinas, Tampico, Tuxpan (Platform), and Veracruz Basins.

An important innovation is that recoveries of oil can be improved significantly through refracturing and gas injection (Fragoso et al., 2017). This will make production of oil from shale reservoirs more sustainable. There have been recent concerns about hydraulic fracturing and refracturing being detrimental to the environment through generation of earthquakes. However, many reports indicate that the earthquake movements are more the result of continuous water injection as opposed to a hydraulic fracturing operation.

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350

200 MEXICAN TIGHT/SHALE OIL 300 180 WORLD TIGHT/SHALE OIL 160 Tight/Shale Oil = 650 BBOE 140 250 120 100 80 200 60 40

Production Cost (USD /BOE) 20 150 0 0 10 20 30 40 50 60 Tight/Shale Oil Recoverabe Vlolume (BBOE)

100

50 Production Cost (USD / BOE)

0 0 100 200 300 400 500 600 700 Tight/Shale Oil Recoverable Volume (BBOE)

7.5 Learning Curves

The great advantage when it comes to development of Eagle Ford (Cretaceous) and Pimienta

(Upper Jurassic) shales in Mexico is that the learning curves in the United States that have been outstanding. Figure 7-12 (EIA, 2017) shows dramatic improvements in Eagle Ford (Texas) oil production per rig. In fact, the oil production per rig increased from about 40 barrels/day in 2008 145

to 1,400 barrels per day in 2017. This represents an astonishing oil production increase per rig of

4,567% in 9 years. Furthermore, the rig count decreased from approximately 260 in 2015 to 50 in the year 2017. If Mexico takes advantage of the Texas learning curve, the future of the Mexican

Eagle Ford shale will certainly be outstanding.

Figure 7-12 Texas Eagle Ford shale learning curve shows outstanding increment in drilling productivity (EIA, 2017).

The learning curve of Haynesville shales (Upper Jurassic) in Louisiana (USA) should also prove useful in development of the Upper Jurassic Pimienta shale in Mexico. This is demonstrated in

Figure 7-13 that shows an increase in peak gas production though time. The graph also shows the number of wells. A similar increasing trend through time has also been observed for cumulative gas production.

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Figure 7-13 Louisiana Haynesville shale learning curve shows outstanding increment in peak gas production per month (Drillinginfo, 2010).

In conclusion, it is my opinion that given the outstanding shale resource base in Mexico and by taking advantage of the learning curves in the United States shales, Mexico will become an important shale player in the world.

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Chapter Eight: Conclusions and Recommendations

8.1 Conclusions

This thesis has studied geoscience and engineering data of Cretaceous and Jurassic formations in the Burgos basin, to evaluate the potential of Mexican shales, and their oil and gas endowment under different oil and gas prices scenarios. Integration of the data has led to the following conclusions:

1. The potential of shale oil and shale gas reservoirs in Mexico is quite significant.

Technology innovations in the Eagle Ford shale of Texas should prove of value in

developing shale reservoirs in Mexico.

2. The quality of Mexican source rocks can be ranked from excellent to very good. Total

Organic carbon (TOC) in the Eagle Ford, with predominantly Type III kerogen, can be

classified thermally as post mature in the condensate and wet gas window. On the other

hand, Pimienta source rocks are characterized by Type II/III kerogen, very good in TOC

content, and thermally mature rocks in the oil window.

3. Petrophysical test results of Mexican Eagle Ford showed a total porosity average of 12%.

Effective porosity average of 8.7%. Water saturation average is 25%. Calculated TOC

curve in good agreement with laboratory data with an average of 4.16 wt %. According to

the estimates of Brittleness Index, Eagle Ford tends to be a brittle formation.

4. Petrophysical evaluation of the Pimienta shale resulted in an average total porosity of 13%,

and an average effective porosity equal to 8%. Average water saturation is 17%. Calculated

TOC values are in good agreement with laboratory data. Average Eagle Ford TOC is 2.75

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wt %. Pimienta shale shows a Brittleness Index slightly higher than Eagle Ford. But both

formations are brittle, a fact that will help to perform successful hydraulic fracturing jobs.

5. Production data available up to this point suggest suggests continuous transient linear flow

without reaching sealed outer boundaries. This is significant as it compares with good shale

oil and gas reservoirs in the U.S.

6. Production analysis of Mexican Eagle Ford up to January of 2017 showed that Habano-1

(gas condensate) had achieved a recovery factor of 12% up to that point, whereas the

Pimienta shale had a recovery 4.5% through well Anhélido-1 (oil and gas).

7. Mexico will become an important part of the world shale petroleum revolution initiated in

the United States.

8. Cumulative long run supply curves are useful for evaluating the economic potential of shale

petroleum reservoirs. While some portions of the supply curves show quantities that can

be produced economically, challenges include high drilling and completion costs, and lack

of availability of inputs such as water for fracturing. As with all resource development,

cost-reducing technology will be needed to tap the significant potential. If this is

accomplished, production from shale reservoirs will help to change the slope of Mexican

oil and gas production curves from negative to positive.

8.2 Recommendations and future work

This thesis provides an important evaluation of shale oil and shale gas reservoirs that had been tested in Mexico up to this date. However, additional work will help to refine results presented in this thesis. The following recommendations are presented to achieve this goal:

149

1. Update production and pressure data from wells drilled in the Mexican Eagle Ford and

Pimienta formations. Use the data to update the flowing material balance proposed for

Habano-1 to corroborate results presented in this thesis.

2. Calibrate the proposed model for total porosity and water saturation of Anhélido-1 with

laboratory data.

3. Use a double, triple or multi porosity models to calculate the various porosities in Mexican

Eagle Ford and Pimienta shales.

4. Calculate pore throat apertures of shales in Mexican Eagle Ford (Habano-1) and Pimienta

(Anhélido-1) formations.

5. Consider accelerating development of Mexican Eagle Ford and Pimienta shales,

6. Develop programs to evaluate other Mexican petroleum shales in Sabinas, Tampico,

Tuxpan (Plarform), Veracruz and Chihuahua basins.

7. Investigate the possibility to use seismic data to calculate Young’s Modulus and Poisson’s

Ratio.

150

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