Diagenesis of Organic-Rich Shale: Views from Foraminifera Penetralia, Eagle Ford Formation, Maverick Basin, Texas* Wayne Camp1 Search and Discovery Article #51054 (2014)** Posted December 29, 2014 *Adapted from oral presentation given at AAPG Rocky Mountain Section Meeting, Denver, Colorado, July 20-22, 2014 **Datapages © 2014 Serial rights given by author. For all other rights contact author directly. 1 Anadarko Petroleum Corporation, The Woodlands, TX, USA ([email protected]) Abstract Diagenetic studies for conventional reservoirs is well-established by the petroleum industry to better understand the geologic controls of reservoir quality, designing appropriate completion fluids, and evaluating potential rock-fluid changes during primary and enhanced recovery. Until recently, shales were not considered as important petroleum reservoirs, and industry interest in shale diagenesis has been much more limited, mainly concentrated on clay diagenesis, fluid expulsion and the genesis of overpressure. Recent advances in sample preparation and scanning electron microscope (SEM) techniques have allowed researches to adequately image clay-sized gains and to peer into nanometer scale pores that lie beyond the capabilities of optical microscopy. This study presents new methods and observations using color-enhanced backscattered electron SEM images to interpret mineral cement and organic matter paragenesis to develop a diagenetic model for Eagle Ford organic-rich shale and reservoir quality evolution. Planktonic foraminifera tests are abundant and widespread in the Eagle Ford shale of south Texas. The initially hollow internal chambers of these minute foraminifera tests (commonly less than 100 mm long) provide sturdy and stable miniature crucibles that offer a unique opportunity to study the evolution of diagenetic products resulting from changing thermo-chemical reactions during sediment burial. Cement mineralogy and paragenesis within a single SEM specimen differs between foraminifera chambers the interparticle pores found within the surrounding calcareous and siliceous matrix. These differences may reflect fluid flow circulation and chemistry differences between the relatively isolated and restricted foraminifera chambers and the more open matrix pore network. References Cited Camp, W.K., E. Diaz, and B. Wawak, 2013, Electron microscopy of shale hydrocarbon reservoirs: AAPG Memoir 102, 260 p. Jarvie, D.M., R.J. Hill, T.E. Ruble, and R.M. Pollastro, 2007, Unconventional shale-gas systems: The Mississippian Barnett Shale of north-central Texas as one model for thermogenic shale-gas assessment: AAPG Bulletin, v. 91/4, p. 475-499. Diagenesis of OrganicRich Shale: Views from Foraminifera Penetralia, Eagle Ford Formation, Maverick Basin, Texas Wayne K. Camp Anadarko Petroleum Corporation July 2022, 2014 Purpose Preliminary results of a study to address three main questions: 1. Do cements exist in shale (mudstone) reservoirs? 2. How can cements be identified? 3. What are the potential diagenetic impacts on reservoir quality and completion response? Outline • Introduction • Methodology • Observations – Cements – Porosity • Diagenetic Model • Summary Diagenesis • Premetamorphic physical and chemical changes of sediments during burial – Physical Processes • Bioturbation • Compaction – Chemical Processes • • • • Cementation Grain replacement Dissolution Hydrocarbon generation Potential Applications • Reservoir quality – Porosity occlusion – Secondary porosity development • Source rock quality – Type and maturation of organic matter – Organic matter porosity • Mechanical properties – Grain fabric, rigidity • Fluid sensitivity Eagle Ford Play Texas Giddings field N San Marcos Arch San Antonio Maverick basin Type log N Study well 50 mi40 mi 80 km GR Age (Ma) Rt Maverick Type Log Campanian 83.6 Santonian 86.3 93.9 Upper Cretaceous 89.8 Austin Coniacian 200 ft Turonian Upper Eagle Ford Cenomanian Lower Eagle Ford Buda Pay & Sample Interval Lower Eagle Ford • Laminated, graydark gray, fossiliferous mudstone • Organic rich (TOC > 2wt%) • Local thin bentonite (volcanic ash) interbeds METHODOLOGY SEM Methodology • Arion milled, uncoated, FESEM imagery – Backscattered (BSE) & secondary electron (SE) – EDS mineral identification – Pseudocolor enhancement AAPG Memoir 102 (2013) Why Forams? • Foraminifera chambers provide a sturdy, stable and fairly uniform “crucible” from which to study thermochemical reactions (diagenetic products) • Chambers originally void and significantly larger than matrix pores – Facilitates interpretation and tie to optical petrography • Abundant and widespread in Eagle Ford shale – Vertical and lateral (basinscale) comparisons Foraminifera Morphology oral aperture Fluid Flow test (shell) chamber foramina (if present) External View septa internal aperture Section View MINERAL CEMENTS Foram CementsMaverick (SW) VR: 1.0 %Ro foraminifera chamber om pyr kaol qtz BSE calc 50 �m Foram CementsMaverick (NE) VR: 0.52%Ro C calc kaol pyr qtz om BSE SEM image courtesy Core Laboratories Foram CementsGiddings VR: 1.15 %Ro pyr calc kaol om or BSE 50 �m ORGANIC CEMENTS Dispersed Organic Matter (TOC Components) Increasing thermal maturity immature Kerogen (insoluble) overmature Bitumen (soluble) Residual Oil (soluble) Oil (liquid) matrix not imaged in SEM Pyrobitumen (insoluble) cements Outcrop Kerogen (Matrix) VR: 0.45%Ro amorphous kerogen pores & kerogen structured kerogen BSE/SE 30 �m SEM image courtesy B. Wawak Residual Oil (MigraBitumen) VR: 0.52%Ro bitumen (blue) “pores” (white) coccoliths BSE 10 �m SEM image courtesy Core Laboratories Pyrobitumen VR: 1.0 %Ro pyrobitumen kerogen pyrobitumen foraminifera BSE 20 �m MATRIX POROSITY Calcite, TOC & Porosity GRI Total Porosity (%) 15 Normalized Calcite (XRD vol%) high low Maverick Giddings 0 Leco TOC (wt%) 8 Matrix Overgrowths TOC: 2.59 wt% Calcite: 12 vol% Quartz: 12 vol% Clay: 35 vol% GRI total �: 11% qtz or plag pores BSE 5 �m Matrix Calcite & Illite Cement TOC: 2.16 wt% Calcite: 76 vol% Quartz: 3 vol% Clay: 5 vol% GRI total �: 15% calc illite pores BSE 4 �m Calcite Cemented Matrix TOC: 0.25 wt% Calcite: 96 vol% Quartz: 3 vol% Clay: 0 vol% GRI total �: 5.6% calc pores BSE 30 �m PreOil Bitumen(?) Meniscus Cement VR: 0.45%Ro Enlarged area next slide BSE/SE Wawak (2013) PreOil Bitumen(?) Meniscus Cement pore (water?) Wawak (2013) Bitumen Shrinkage Artifacts BSE VR: 0.52 %Ro C Shrinkage foraminifera chamber 20 �m SEM image courtesy Core Laboratories Bitumen Matrix “Porosity” VR: 0.52 %Ro Bitumen “pores” coccolith BSE/SE SEM image courtesy Core Laboratories Pyrobitumen Porosity SE VR: 1.0 %Ro pores coccolith artifact organic matter 4 �m Kerogen Porosity Model (Barnett ShaleJarvie et al, 2007) Porosity Generative Organic Carbon Carbon Residue Inert Kerogen Initial TOC, HI & S2 + Oil Inert Kerogen Thermal Maturation Remaining TOC, HI & S2 Hydrocarbon Yield OM Porosity Evolution Model (Eagle Ford) Residual Oil (bitumen) Bitumen (in situ) Inert Labile Oil Refractory Primary Migration Kerogen Oil Cracking Pyrobitumen porous OM Diagenesis Model Meniscus Cement Porous Pyrobitumen Top oil window Bitumen Plug hydrous mineral cementation ceases in presence of oil Oil Wet Gas Dry Gas Residual Oil Summary • Mineral and organic cements are observable with SEM within foraminifera chambers & the matrix • Foraminifera cement associations & paragenesis exhibit little variation regionally – Suggests uniform (predictable) diagenetic processes • Cement diversity is greatest within the matrix – Potentially reflects variation in matrix grain composition, and pore fluid chemistry & circulation • Organic cements are the most pervasive type – Form updip lateral seals (bitumen plugs), and – Down dip interconnected porous networks • Most mineral cements predate primary oil migration (except late stage pyrite) Acknowledgements • For permission to publish study results • Ahmed Chaouche & Harry Dembickitechnical advice • For providing SEM images References Cited • Camp, W.K., E. Diaz and B. Wawak, eds., 2013, Electron microscopy of shale hydrocarbon reservoirs: AAPG Memoir 102, 260 p. ISBN13:9780891813835 • Jarvie, D.M., et al., 2007, Unconventional shale gas systems: The Mississippian Barnett Shale of northcentral Texas as one model for thermogenic shalegas assessment: AAPG Bull., v. 91, p. 475 499. DOI:10.1306/12190606068