Originally published as:

Han, Y., Horsfield, B., Mahlstedt, N., Wirth, R., Curry, D. J., LaReau, H. (2019): Factors controlling source and reservoir characteristics in the Niobrara shaleoil system, . - AAPG Bulletin, 103, 9, pp. 2045—2072.

DOI: http://doi.org/10.1306/0121191619717287 Q:1 Factors controlling source and AUTHORS Yuanjia Han ~ 1 German Research Centre reservoir characteristics in the for Geosciences (GFZ), Telegrafenberg, Potsdam, Germany; Key Laboratory of 2 Niobrara shale oil system, Tectonics and Petroleum Resources, China University of Geosciences, Wuhan, China; 3 Q:2 Denver Basin [email protected]; hanyj@cug. edu.cn 4 Yuanjia Han, Brian Horsfield, Nicolaj Mahlstedt, Yuanjia Han is a junior professor at China 5 Richard Wirth, David J. Curry, and Heather LaReau University of Geosciences, focusing primarily on hydrocarbon retention and migration processes in unconventional shale systems. He obtained his B.S. and M.S. degrees from 6 ABSTRACT China University of Geosciences and a Ph.D. from the Technical University of Berlin, both 7 This paper clarifies the controls of oil retention in the Niobrara with specialization in integrated petroleum 8 Formation, Denver Basin, in the western United States. Sweet systems analysis. He is the corresponding author. 9 spots have been recognized using a total of 98 core samples from Brian Horsfield ~ 10 5 wells with maturities covering the oil window. Section on Organic Geochemistry, GFZ, Telegrafenberg, 11 Oil retention in the source rock samples (carbonate content Potsdam, Germany; [email protected] 12 <70 wt. %) is controlled by organic matter richness and thermal fi 13 Q:6 maturity. In general, the vaporizable hydrocarbon (HC) yield at Brian Hors eld was a full professor of organic geochemistry and hydrocarbon systems at the 14 nominal temperatures at 300°C (572°F) (Rock-Eval S )is 1 Technical University of Berlin, Germany, as 15 positively correlated to total organic carbon (TOC). With in- · well as leader of organic geochemistry at the 16 creasing maturity, the so-called oil saturation index (S1/TOC GFZ. He is a member of the German Academy fi 17 100) rst increases until a maximum retention capacity (100 mg of Science and Technology. He has more than 18 HC/g TOC) is exceeded at the temperature at the maximum rate 30 years of experience working with and 19 of petroleum generation by Rock-Eval pyrolysis (Tmax)ofap- for industry in upstream research and 20 proximately 445°C (~833°F) and subsequently decreases. The development. The evaluation of gas in place 21 depletion in oil retention capacity is believed to be associated and producibility in unconventional hydrocarbon systems of the United States, 22 with the appearance of organic nanopores. South Africa, China, Australia, and North Africa 23 Oil retention in samples with distinct reservoir potential > are key activities in his service and research at 24 (carbonate 30 wt. %) is controlled by carbonate content, which the present time. 25 Q:7 is positively related to the amount of retained oil (S1). Petro- 26 graphic features indicate that oil or bitumen is stored in porous Nicolaj Mahlstedt ~ Section on Organic 27 calcite fossils (i.e., coccolith and foraminifera), which provide Geochemistry, GFZ, Telegrafenberg, Potsdam, Germany; nicolaj.mahlstedt@gfz- 28 additional space for petroleum storage. Chalk samples (car- potsdam.de 29 bonate >85 wt. %) are characterized by anomalously low Tmax 30 values caused by the influence of heavy petroleum or bitumen. Nicolaj Mahlstedt is a postdoctoral researcher at the GFZ. He studied applied geosciences and Q:3 31 The amount of this bitumen is higher than the initial petroleum holds a diploma and Ph.D. from the Technical 32 potential of kerogen in A and B chalks and thus must have been University of Berlin. He conducted his Ph.D. 33 emplaced here. The most likely sources are juxtaposed organic- within the GFZ–Industry Partnership Program 34 rich marl layers. investigating high temperature methane generation. His major scientificinterests include petroleum system analysis, oil and gas retention processes, compositional kinetic Copyright ©2019. The American Association of Petroleum Geologists. All rights reserved. modeling, and the development of Manuscript received July 12, 2017; provisional acceptance November 14, 2017; revised manuscript geochemical screening tools. received January 9, 2018; revised manuscript provisional acceptance February 6, 2018; 2nd revised manuscript received February 8, 2018; final acceptance January 21, 2019. DOI:10.1306/0121191619717287

AAPG Bulletin, v. nn, no. nn (nn 2019), pp. 1–28 1 Richard Wirth ~ Section on Chemistry Thus, sweet spots occur where carbonate content is either 35 and Physics of Earth Materials, GFZ, low (high TOC)orhigh(lowTOC), whereas production of 36 Telegrafenberg, Potsdam, Germany; wirth@ petroleum from the pore space of presumably brittle chalk seems 37 gfz-potsdam.de more attractive than production from organic- and clay-rich 38 Richard Wirth is a senior research scientist and rocks. 39 laboratory supervisor at the GFZ. He studied mineralogy and electron microscopy and holds a diploma and Ph.D. from the University of Wurzburg.¨ His work is focused on the INTRODUCTION 40 application of advanced electron microscopy (transmission electron microscopy and Shale oil systems are organic-rich mudstone units in which a 41 focused ion beam). significant portion of the generated oil is retained in situ or has 42 migrated into juxtaposed organic-lean rocks (e.g., carbonates) 43 David J. Curry ~ Noble Energy, Inc., (Jarvie, 2012). The Upper Cretaceous fits 44 Houston, Texas; David.Curry@nblenergy. com this description perfectly, with a combination of interbedded 45 organic-rich mudstones and relative organic-lean chalks. 46 David J. Curry is a senior geochemical advisor The Niobrara strata were deposited in the Western Interior 47 with the Geoscience Technology Organization at Noble Energy. He received his Ph.D. from Seaway (WIS) during the late Turonian to early Campanian 48 – The University of Texas at Austin in 1981 with a (89 82 Ma) (Da Gama et al., 2014). During that time 49 specialty in organic geochemistry. Since then, (Figure 1A), the WIS stretched from the Arctic Ocean in the 50 he has worked in petroleum systems analysis north, extending through Canada and the United States, all the 51 (basin modeling and geochemistry) in both way to the Gulf of Mexico in the south (Kauffman, 1977). 52 research and exploration positions at several Rhythmic stratification of chalk-marl beds is characteristic of the 53 petroleum companies, including ExxonMobil, Niobrara Formation (Locklair and Sageman, 2008). Brought 54 Q:4 Conoco, Devon, HRT Petroleo, and Noble. about by the variation of siliciclastic input, the rhythmical bed- 55 His interests include nonmarine petroleum ding is believed to have been controlled by eustatic and climatic 56 systems; source-facies depositional processes; kinetics and generation, expulsion, and cycles (Pollastro, 2010). In the Denver Basin, periods of pre- 57 migration processes and their effects on yields vailing cold currents from the Arctic Ocean in the north resulted 58 and fluid properties; and the characterization in the deposition of marls (Luneau et al., 2011; Da Gama et al., 59 of geopolymers. 2014) in which terrestrial detritus was primarily sourced from the 60 western uplifts (Figure 1A). Thus, the Niobrara strata become 61 Heather LaReau ~ Noble Energy, Inc., Denver, Colorado; heatherthegeologist@ progressively siliciclastic to the north, west, and northwest 62 gmail.com; [email protected] (Pollastro, 2010). 63 Stratigraphically, the Niobrara Formation overlies the Carlile 64 Heather L. LaReau is currently the geoscience Q:5 manager for the West Business Unit within BP’s Shale and is overlain by the Sharon Springs Member of the Pierre 65 Lower 48. She received her M.Sc. degree Shale (Figure 1B). The lower limestone part is known as the Fort 66 from McMaster University in 2001 with a Hays Member, and the upper units, namely “A,” B,” and “C” 67 concentration in geoarchaeology, stratigraphy, chalk and marl intervals, are grouped together as the Smoky Hill 68 and radiometric dating methods. In 2007, Member. The chalks and marls are considered as the major hy- 69 she received her Ph.D. from the University drocarbon (HC) reservoirs (Sonnenberg and Weimer, 1993; 70 fl of Wyoming with a focus on uvial Jarvie, 2012; Welker et al., 2013) and source rocks (Landon et al., 71 sedimentology and stratigraphy 2001), respectively. The marls, formed under suboxic-to-anoxic 72 (characterizing avulsion processes in the bottom water conditions (Tanck, 1997; Da Gama et al., 2014), Q:8 73 rock record) throughout Rocky Mountain basins. Her industry career has been are characterized by relatively high contents of type II organic 74 based in Denver, Colorado, working matter (OM) (Luneau et al., 2011; Sonnenberg, 2011). Thermal 75 unconventional oil and gas assets, maturity of the kerogen ranges from immature (thermal stress 76 exploration, reservoir characterization, and equivalent <0.6% vitrinite reflectance [Ro]) in the eastern 77 geochemistry at EnCana, Noble Energy, flank of the Denver Basin to gas-condensate mature (1.4% Ro) 78 ’ and, most recently, BP s Lower 48. Her in the western Wattenberg gas field (Higley et al., 2003; 79 O’Neal, 2015). 80

2 Factors Controlling Source and Reservoir Characteristics in the Niobrara Play 81 Petroleum exploration activities in the Denver Basin date interests include depositional processes; 82 back to 1881 when the first oil well was drilled in the Florence petroleum system characterization; 83 field (Figure 1A), which is the oldest continuously working oil generation, expulsion, and migration processes; innovation; and unconventional 84 field in the United States (Higley, 2015). More than 1.3 billion 3 resource plays and exploration. 85 bbl of oil and 7.4 trillion ft of gas have been produced from the 86 basin’s more than 47,000 conventionally drilled vertical wells. 87 Thermogenic gas accumulations are concentrated along the axis ACKNOWLEDGMENTS 88 of the Denver Basin in the Wattenberg gas field (Sherwood et al., We wish to thank Andrew Pepper, Tongwei 89 2013) where the deeply buried source rocks have entered the gas Zhang, and Norelis Rodriguez for their 90 window (Higley et al., 2003). Going eastward, the gently dipping careful reviews and useful comments. The 91 basin flank is buried to only shallow depth. Biogenic gas is pro- editorial comments and suggestions by AAPG 92 duced from the immature Niobrara Formation in the eastern Editor Barry J. Katz and Stephen C. Ruppel are also gratefully acknowledged. This work 93 basin that extends farther eastward into Kansas and Nebraska was carried out in the framework of Yuanjia 94 (Rice, 1984) (Figure 1A). Petroleum has been produced from ’ < Han s at the Technical University of Berlin, 95 various strata with depths ranging from less than 900 ft ( 270 m) which was sponsored by the China fi 96 of the in the Florence eld to approximately 10,000 Scholarship Council and Noble Energy. We 97 Q:9 ft (~3000 m) of the Muddy (J) Sandstone in the Wattenberg gas express our gratitude to Anja Schleicher, Elke 98 field (Higley, 2015). The Niobrara Formation has been an active Lewerenz, Ilona Schapan,¨ and Anja Schreiber 99 HC play in the Denver Basin since the mid-1970s (Pollastro, for their technical support in GFZ. Special 100 2010), and the production was substantially accelerated in the thanks are due to Marshall Deacon 101 early 1990s because of the onset of horizontal drilling as exem- and Richard George for their helpful collaborations in Noble Energy. 102 plified in the Silo field (Welker et al., 2013). The Silo field is 103 located in the northern part of the basin in Wyoming (Figure 1A). 104 Oil-bearing natural fractures are concentrated there in the more DATASHARE XX 105 brittle chalk units and are recognized as being important for Tables S1–S5 are available in an electronic 106 storage and production of HCs (Sonnenberg and Weimer, 1993; version on the AAPG website (www.aapg. 107 Welker et al., 2013). Although oil production in the Silo field org/datashare) as Datashare XX. 108 decreased sharply throughout the early 2000s, the application 109 of multistage brought about a renaissance in 110 exploration activity throughout the whole Rocky Mountain re- 111 gion (Siguaw and Estes-Jackson, 2011a, b). In the Denver Basin, 112 significant amounts of unconventional oil have been produced 113 from the oil-mature and brittle chalk units, especially from the 114 B-chalk interval (Jarvie, 2012). As of 2017, liquid production 115 from the newly drilled Niobrara wells has reached 1300 bbl/day 116 per rig, and production was steady at approximately 3 117 Q:10 4400 ft /day per rig (US Energy Information Administration, 2017). Q:11 118 The current study aims at clarifying the controls for oil re- 119 tention in the Niobrara shale oil system in the Denver Basin so 120 that zones of enrichment can be recognized. In general, the re- 121 tention of petroleum in organic-rich shales is controlled mainly 122 by the sorption capacity of its OM (Baker, 1962; Tissot et al., 123 Q:12 1971; Stainforth and Reinders, 1990; Pepper, 1991), and a re- 124 tention threshold of 100 mg HC/g total organic carbon (TOC) 125 has been proposed (Sandvik et al., 1992; Jarvie, 2012), irre- 126 spective of OM type and thermal maturity. Interestingly, Han 127 et al. (2015) reported that the shale intervals most enriched in 128 petroleum are not necessarily associated with the OM richest 129 layers but with associated porous biogenic matrices. Another key

HAN ET AL. 3 Figure 1. (A) Structural map of the Denver Basin showing the locations of the study wells. Detailed information concerning name and location of wells is confidential. The development of Western Interior Seaway (WIS) during the Late Cretaceous (85 Ma) is shown in the inset figure in which the study area is marked by a rectangle. Contours of top Niobrara Formation are in feet relative to sea level. Modified from Sonnenberg (2011). (B) Generalized stratigraphic column of the Denver Basin showing the Upper Cretaceous Niobrara Formation (89–82 Ma). Modified from Pollastro (2010). COL = Colorado; KAN = Kansas; NEB = Nebraska; WYO = Wyoming.

130 topic concerning the exploration of shale plays is retention or storage of oil. The current study uses 146 131 predicting the occurrence of organic pores. Organic a multifaceted approach, including x-ray diffrac- 147 132 pore development is commonly stated to be largely tion (XRD), optical microscopy, scanning electron 148 133 caused by the thermal cracking of kerogen and microscopy (SEM), transmission electron micros- 149 134 bitumen, following the pioneering work of Loucks copy (TEM), Rock-Eval, and open-system pyrol- 150 135 et al. (2009) and Bernard et al. (2012b), respectively. ysis gas chromatography (Py-GC) to address these 151 136 Numerous studies have actually revealed that organic issues. 152 137 pores can develop over a wide range of maturities 138 (Loucks et al., 2009; Curtis et al., 2011, 2012; Bernard 139 et al., 2012a, b; Brian et al., 2013; Jennings and Antia, METHODOLOGY 153 140 2013; Milliken et al., 2013; Loucks and Reed, 2014; 141 Pommer and Milliken, 2015; Reed and Loucks, X-Ray Diffraction 154 142 2015; Ko et al., 2016, 2017; Mathia et al., 2016; 143 Han et al., 2017), but it is still unclear how exactly A total of 98 core samples selected from 5 wells 155 144 organic pores are developed in the Niobrara shale (Tables S1–S5, supplementary material available as 156 145 oil play and whether they play a role in the AAPG Datashare XX at www.aapg.org/datashare) 157

4 Factors Controlling Source and Reservoir Characteristics in the Niobrara Play 158 along a north-to-south profile (Figure 1A) were prepared using focused ion beam (FIB) following the 202 159 prepared for x-ray powder diffraction measure- procedure described in previous reports (Wirth, 203 160 ments. Core samples were roughly pulverized and 2004, 2009). Rock chips were first mechanically Q:19204 161 extracted for 48 hr at 60°C (140°F) in a Soxhlet polished and coated with a conducting material (e.g., 205 162 apparatus (Soxhlet, 1879) using a ternary azeotropic Au) before FIB milling. During foil milling, the gal- 206 163 solvent system (30:38:32 for methanol, acetone, lium ions were accelerated in an electrical field up to 207 164 Q:13 chloroform, respectively). Extracted samples were 30 kV for sputtering atoms from the target material. 208 165 then milled in a McCrone Micronizing Mill in cy- We performed TEM with a Tecnai F20 X-Twin 209 166 clohexane for 10 min to assure uniform grain sizes transmission electron microscope with a field emis- 210 167 (<10 mm [0.39 mil]). Diffraction data were recorded sion gun electron source. The TEM was operated Q:20211 168 Q:14 from 5° to 85° 2W with a step width of 0.013° and a at 200 kV, with a nominal camera length of 330 mm 212 169 scan time of 60 s per step. We collected x-ray (13 in.). We acquired TEM images as high-angle 213 170 patterns using a Malvern Panalytical Empyrean annular dark-field images in Z-contrast mode or as 214 171 Q:15 powder diffractometer with Cu–K-a radiation, energy-filtered images applying a 200-kV window 215 172 automatic divergent, and antiscatter slits and a to the zero-loss peak. Energy-dispersive x-ray 216 3D 173 PIXcel detector. Qualitative mineral phase spectroscopy (EDXS) scanning was carried out 217 174 identification was achieved by automatic search- using an EDXS x-ray analyzer with an ultrathin 218 plus 175 and-match procedures of the DIFFRAC soft- window. We performed EDXS particularly within 219 176 Q:16 ware EVA (Bruker AXS). Semiquantitative mineral organic particles to determine possible structural 220 177 analysis was carried out using the Rietveld algorithm changes induced by high-energy electrons (e.g., 221 178 Q:17 BGMN (Bergmann et al., 1998) by the software 200 kV). 222 179 AutoQuant (General Electric Sensing and Inspection 180 Technologies). Rock-Eval Pyrolysis and Total Organic 223 Carbon Content Determination 224 181 Thin Section: Scanning Electron 182 Microscopy To evaluate the effects of retained oil on Rock-Eval 225 data and to assess total oil in place following ideas 226 183 Q:18 An optical microscope and a scanning electron mi- reported in Han et al. (2015), Rock-Eval pyrolysis 227 184 croscope were used to complement mineral charac- (Espitalie´ et al., 1977) was performed on both pul- Q:21228 185 terization. Thin sections were mechanically polished verized whole rocks and solvent-extracted samples 229 186 and analyzed under transmitted white light, reflected (98 in total) using a Rock-Eval 2 instrument. For Q:22230 187 white light, and blue excitation fluorescent light to TOC analysis, the finely crushed rock samples were 231 188 reveal organic–inorganic relationships. We conducted firstly treated with dilute hydrochloric acid (HCl to 232 189 SEM conducted on Au- and Pd-coated thin sections water at a 1:9 ratio) at 60°C – 5°C (140°F – 41°F) to 233 190 and rock fragments. Backscattered electron and sec- remove carbonate. The percent of carbonate was 234 191 ondary electron images were taken with a 12.5-mm measured according to the sample weight difference 235 192 (0.49-in.) working distance. We performed x-ray stage beforeandafterHCltreatment.Afterward,the 236 193 mapping for Si, Mg, Ca, Al, Fe, S, and C by energy- samples were combusted in oxygen at 1350°C 237 194 dispersive spectroscopy using a 20-kV accelerating (2462°F) in a Leco SC632 combustion oven. The 238 195 voltage. TOC was calculated from the peak area of generated 239

CO2 recorded by an infrared detector. 240

196 Focused Ion Beam–Transmission Electron 197 Microscopy Open-System Pyrolysis Gas 241 Chromatography 242 198 To evaluate the roles played by organic pores on the 199 retention of oil within organic-rich shales, TEM foils Open-system Py-GC was carried out on 20 un- 243 200 with dimensions of 15–20 mm · 10 mm · 0.15 mm extracted samples from the least mature well 1 to 244 201 (0.59-0.79 mil · 0.39 mil · 0.0059 mil) were characterize the labile macromolecular OM on a 245

HAN ET AL. 5 246 molecular level. Milligram amounts of material were LITHOLOGY AND SAMPLE CLASSIFICATION 267 247 placed into a glass tube and purged in a helium flow 248 at 300°C (572°F) for 5 min. Then, the temperature As an analog of the Eagle Ford Shale (Fairbanks et al., 268 249 was raised from 300°C to 600°C (572°F to 1112°F) 2016; Frebourg´ et al., 2016), the Niobrara Formation 269 270 250 at 50°C/min (122°F/min) and held for 2 min. is interpreted to be a binary sedimentary system 271 251 Generated products were transported and collected composed of alternating deposition of carbonates and siliciclastic influx (Locklair and Sageman, 2008). 272 252 in a liquid nitrogen cooled trap (-178°C [-352°F]). Chalks were reported to have been formed from the 273 253 After 10 min, products were liberated at 300°C accumulation of coccolith-rich oozes (Hattin, 1981), 274 254 (572°F) and transferred with helium with a flow rate and marl deposition is believed to be driven from 275 255 of 30 ml/min into an Agilent gas chromatograph variations in siliciclastic input (Locklair and Sageman, 276 256 (Gas Chromatograph 6890A series). The tempera- 2008). In line with that, the content of carbonate is 277 257 ture of the GC oven was programmed from 30°C to inversely proportional to the illite–smectite content 278 258 320°C (86°F to 608°F) at 5°C/min (41°F/min) to (Figure 2A) as well as the quartz content (Figure 279 259 mobilize products, which were then measured by 2B). Both clay minerals (Figure 3J) and quartz 280 fl fi 260 ame ionization detector. Product quanti cation was (Figure 3C, G, H) show features typical of clastic 281 261 based on external standardization using n-butane. particles. This points to a common detrital origin 282 fi 262 Prominent peaks were identi ed by reference chro- corroborated by a positive correlation of contents 283 263 matograms and using Gas Chromatography Chem- of quartz and illite–smectite mixed layers (Figure 284 © 264 Station software from Agilent Technologies. The 2C). According to the results of XRD (Tables 285 265 protocols of Horsfield et al. (1989) were used for S1–S5, supplementary material available as AAPG 286 266 data evaluation. Datashare XX at www.aapg.org/datashare)aswell 287

Q:64 Figure 2. Plots of the content of various minerals. (A) Illite–smectite mixed layers versus carbonate content. (B) Quartz versus carbonate content. (C) Illite–smectite mixed layers versus quartz content. (D) Calcite versus carbonate content. The carbonate content was de- Q:55 termined by HCl solution, and the contents of illite–smectite, quartz, and calcite were measured by x-ray diffraction (XRD). R2 = xxx.

6 Factors Controlling Source and Reservoir Characteristics in the Niobrara Play 288 as optical and electron microscopy (Figure 3), calcite is sufficient. In this case, samples are grouped in terms 337 289 the principal carbonate mineral (Figure 2D). Dolomite of mineral composition as well. According to the 338 290 Q:23 can be identified locally (Figure 3G). Low-magnesium major lithologies of the Niobrara sample set (Tables 339 291 calcite consists largely of a micritic matrix (Figure 3A), S1–S5, supplementary material available as AAPG 340 292 fecal pellets (Figure 3A), and foraminifera tests Datashare XX at www.aapg.org/datashare), chalk is 341 293 (Figure 3B, C). Fecal pellets are enriched in coccolith defined as a rock composed of more than 85 wt. % of 342 294 fragments, without noticeable diagenetic features carbonate (Table 1). Marly chalk is a transition rock 343 295 (Figure 3K, L). Coccolithophores disseminated in the type between chalk and marl in which the latter has 344 296 matrix were also commonly observed (Figure 3G, H). carbonate contents ranging from 70 to 30 wt. %. 345 297 Foraminiferal tests are generally cemented by sparry Likewise, marly mudstone is treated here as a tran- 346 298 calcite (Figure 3B–D) or less commonly by pyrite sition rock type between marl and mudstone, whereas 347 299 framboids (Figure 3G). As an end member of carbonate- the latter mainly consists of fine siliciclastic debris 348 300 Q:24 siliciclastic sediments, chalk is almost exclusively com- (quartz, feldspar, clay, mica, etc.) with carbonate 349 301 posed of calcareous fossils (Figure 3K, L) deposited in the content less than 15 wt. % (Table 1). 350 302 form of coccolith-rich oozes. Overall, the chalks and marly chalks are rela- 351 303 Chalk units are reported to be the main pro- tively organic-poor rocks (TOC <2.5 wt. %) showing 352 304 duction reservoirs in the Niobrara play (Sonnenberg reservoir potential, whereas the organic-rich (TOC 353 305 and Weimer, 1993; Jarvie, 2012; Welker et al., >2.5 wt. %) marl-mudstones are potential source 354 306 2013). The concept of “oil crossover,” a phenome- rocks (Table 1). This classification fits previous re- 355

307 non corresponding to oil saturation index (OSI = [S1/ ports indicating that marls are the major source 356 308 TOC] · 100) values exceeding 100 mg HC/g TOC rocks (Landon et al., 2001; Luneau et al., 2011). 357 309 (Jarvie, 2012), is here used to identify zones con- However, the 2.5 wt. % TOC cutoff value is just an 358 310 taining producible oil. In our Niobrara sample set, empirical criterion, and it should not be forgotten 359 311 asignificant increase in OSI canbeobservedfor that kerogen type and maturity are also critical pa- 360 312 samples with carbonate contents greater than 70 wt. rameters in determining an effective source rock 361 313 % (Figure 4A). Thus, samples with carbonate greater (Tissot and Welte, 1984). 362 314 Q:25 than 70 wt. % seem to be promising reservoir rocks. 315 In line with published studies (Ricken, 1996; 316 Tanck, 1997; Landon et al., 2001), carbonate con- SOURCE ROCK CHARACTERISTICS 363 317 tent is negatively correlated with TOC content for 318 single wells (well 3; Figure 4B). Samples with car- Type and Maturity of Source Rocks 364 319 bonate content less than 70 wt. % show TOC values 320 exceeding 2.5 wt. % (Figure 4B). Together with the Hydrogen index (HI) and oxygen index (OI)valuesof 365 321 previous identification of promising reservoir rocks unextracted source rock samples exhibiting carbonate 366 322 (carbonate >70 wt. %), 2.5 wt. % TOC can be contents <70 wt. % are shown in a pseudo Van Krevelen 367 323 treated as an empirical criterion for “organic-rich” diagram for kerogen typing (Figure 5). Confirming 368 324 rocks. In fact, TOC is positively correlated to con- earlier results of Landon et al. (2001) and Sonnenberg 369 325 tents of illite–smectite (Figure 4C) and quartz (2011), the majority of Niobrara samples plot on the 370 326 (Figure 4D). It can be concluded that the richer a evolution pathway for type II kerogens (Figure 5). Ex- 371 327 sample is in siliciclastic detritus, the higher is its ceptions are samples from the Fort Hays Member that 372 328 potential of being a source rock. As an end member seem to be of lower quality falling on the kerogen type 373 329 of carbonate-siliciclastic rocks, Niobrara mudstones III trend line. The overlying Sharon Springs Member 374 330 are the most potential source rocks. also appears to contain type II kerogen, whereas kerogen 375 331 In general, core samples are named after the of the underlying Carlile Shale is type III. Because of 376 332 intervals from which they were taken from. But in converging evolution pathways with increasing matu- 377 333 the extremely heterogeneous Niobrara Formation, rity, the lower maturity cores (wells 1 and 2) are far 378 334 decimeter-scale rhythmic stratification of chalk-marl better indicators of original OM type. It should be noted Q:26379 335 beds is characteristic of all intervals. Relating samples that samples from the B-chalk interval in wells 1 and 2 380 336 to named intervals is useful although not always (Figure 5A, B) are not really chalks but marls with high 381

HAN ET AL. 7 Figure 3. Photomicrographs showing petrographic features. (A) Sample G014905 from the A-marl interval of well 4; under polarized light, micritic calcite matrix, calcareous pellets, and foraminifera (forams) are the principal components (52 wt. % carbonate; oil saturation index [OSI] = 56 mg of hydrocarbons [HC]/g TOC). The rectangular marked area is magnified as seen in (B). (B) Under cross-polarized light, sparry calcite filling the tests of foraminifera. (C) Sample G014908 from the C-marl interval of well 4; under cross-polarized light, sparry calcite partly filling the tests of foraminifera (48 wt. % carbonate; OSI = 46 mg HC/g TOC). (D) Sample G014867 from the B-chalk interval of well 1; under polarized light, sparry calcite partly filling the foraminifera; 52 wt. % carbonate (OSI = 28 mg HC/g TOC). The same area is shown in as seen in (E, F). (E) Under fluorescent light, alginites are abundant. (F) Under reflected white light, foraminiferal tests are partly filled by organic matter (OM) (bituminite?). (G) Sample G014908 from the C-marl interval of well 4 via energy-dispersive spectroscopy element mapping. Calcite in red is the dominant mineral with abundant coccolith fragments, quartz in green is of detrital origin, clays in yellow are finely dispersed, and dolomite in magenta is scarce (48 wt. % carbonate; OSI = 46 mg HC/g TOC). (H) Sample G014874 from the C-marl interval of well 1 via backscattered electron (BSE) image; OM filling the chambers of coccolith (38 wt. %

8 Factors Controlling Source and Reservoir Characteristics in the Niobrara Play 382 TOC content (6.89–10.30 wt. %) (Tables S1 and S2, Open-system Py-GC was conducted for source 420 383 supplementary material available as AAPG Datashare rock samples from well 1 to further characterize ker- 421 384 XX at www.aapg.org/datashare). Brightly fluorescing ogen types on a molecular level (aromaticity and ali- 422 385 alginites are abundant in these samples (Figure 3E). phaticity, phenol abundance, and sulfur content) using 423 424 386 The Tmax–HI diagram proposed by Espitalie´ the triangular plots of Larter (1984) (Figure 7) and 387 Q:27 et al. (1984) takes maturity into account and yields Eglinton et al. (1990) (Figure 8). In accordance with 425 388 overall similar results for the sample set with respect previous Rock-Eval results (Figures 5A, 6A), all sam- 426 389 to kerogen typing (Figure 6). As seen in the pseudo ples from the Smoky Hill Member (and Sharon 427 428 390 Van Krevelen diagram (Figure 5), the alginite-rich Springs Member) plot very close to each other in the fi 429 391 samples from the B-chalk interval exhibit the highest organofacies elds characteristic of type II marine OM. The B-chalk source rock kerogens are the 430 392 kerogen quality of all type II kerogen containing samples most enriched in aliphatic moieties (n-C in 431 393 Niobrara samples (Figure 6A, B). 8:1 Figure 7 and n-C in Figure 8) but do not quite 432 394 The majority of the source rock samples exhibit 9:1 reach aliphaticity levels typically observed for ho- 433 395 Tmax values between 430°C and 465°C (806°F and mogeneous type I alginites. In contrast, aromatic 434 396 869°F) (Figure 6), characteristic for catagenetic moieties (m,p-xylene in Figure 7 and o-xylene in Q:28435 397 maturity levels. Values of Tmax at approximately Figure 8) dominate kerogens of samples from the Fort 436 398 440°C (~824°F) for samples in wells 1 and 2 are Hays Member (type IV) and Carlile Shale (type III). 437 399 indicative for early–peak oil window maturities, Pyrolysates of all samples are neither enriched in 438 400 whereas T values at approximately 450°C max phenolic compounds (Figure 7), indicating an ab- 439 401 (~842°F) for samples in well 3 and 4 are, in con- sence of terrestrial higher land plant–derived OM, 440 402 nection with a clearly depleted HC potential nor in sulfur compounds (Figure 8), which is possibly 441 403 – (Table 2), indicative of late oil wet gas window because of their mid–oil window maturity levels 442 404 maturities. Well 5 contains the most mature samples because sulfur bonds within the kerogen network are 443 405 with an average Tmax value of 458°C (856°F) known to be depleted very early during oil generation. 444 406 (Table 2) corresponding to end of oil window. The Overall, the majority of source rock samples 445 407 HI values gradually decrease from well 1 to well 5 (carbonate <70 wt. %) are classified as containing 446 408 (Figure 6; Table 2). It was recently proposed for the marine type II kerogen, whereas oil generation po- 447 409 Barnett Shale (Lewan and Pawlewicz, 2017) and tential correlates with aliphaticity of the kerogen. 448 410 the Posidonia Shale (Stock et al., 2017) that HI Organic-rich marls from the B-chalk interval are of 449 411 trendsofferabetterproxyformaturitythanthe highest quality, whereas the organic-poor (<2.5 wt. 450

412 Tmax trends. This also appears to be the case in the % TOC) types III and IV samples from the Fort 451 413 Niobrara Formation on first glance (Table 2). Hays Member and Carlile Shale exhibit lowest quality. 452 414 However, the Niobrara Formation is very hetero-

415 geneous and contains type II samples of very dif- Oil Retention in Source Rocks 453 416 ferent quality reflectedindifferencesinHI for 417 similar maturity levels (Figures 5, 6). The appli- A reliable approach of quantifying the total amount 454 418 cation of HI asthesolematurityproxyshouldbe of oil in place is prerequisite to assess oil retention 455

419 treated with caution. characteristics of shales. Rock-Eval S1 (Peters, 1986) 456

Figure 3. Continued. carbonate; OSI = 80 mg HC/g TOC). (I) Sample G014875 from the C-marl interval of well 1 via BSE image; OM and semieuhedral calcite crystals are filling the tests of foraminifera (25 wt. % carbonate; OSI = 72 mg HC/g TOC). (J) Sample G014905 from the A-marl interval of well 4 via transmission electron microscopy (TEM) image (high-angle annular dark-field [HAADF] imaging mode; Z-contrast); deformed clay minerals showing features of detrital origin (52 wt. % carbonate; OSI = 56 mg HC/g TOC). (K) Sample G015821 from the A-chalk interval of well 3 via secondary electron (SE) image; porous coccolith fragments are abundant (88 wt. % carbonate; OSI = 546 mg HC/g TOC). (L) Sample G015829 from the B-chalk interval of well 3 via SE image; porous coccolith fragments are abundant (93 wt. % carbonate; OSI = 382 mg HC/g TOC). Notably, photomicrographs were mainly selected here to show fossils and may not lithological representative of individual samples.

HAN ET AL. 9 Figure 4. Crossplots of (A) oil saturation index (OSI = [S1/total organic carbon (TOC)] · 100) versus carbonate content, (B) TOC versus carbonate content in well 3, (C) TOC versus illite–smectite content in well 3, and (D) TOC versus quartz content in well 3. HC = hy- drocarbon; R2 = xxx; XRD = x-ray diffraction.

457 and solvent extract yields (Claypool and Reed, 1976) during solvent evaporation (Peters et al., 2005). By 465 458 are traditionally used for evaluating the amount of applying comparative Rock-Eval pyrolysis (Delvaux 466 459 oil retained in rock samples. Nevertheless, neither et al., 1990) (i.e., comparing the pyrolysis results before 467

460 the S1 nor the extract yields can fully represent the and after solvent extraction), the total amount of re- 468 461 molecular weight range of retained oil (Larter, 1988) tained oil can be quantified (Han et al., 2015) as fol- 469

Q:29462 because heavy compounds (>C17) are not fully lows: total oil = S1whole rock + S2whole rock – S2extracted rock. 470 463 mobilized under pyrolysis conditions (Han et al., An excellent correlation exists for the sample set 471

464 2015), and compounds less than C15 HCs are lost between calculated total oil yields and both S1 and 472

Table 1. Major Niobrara Lithologies

Lithology Carbonate, wt. % Siliciclastics, wt. % Rock Type TOC Richness Chalk >85 <15 Reservoir Organic poor Marly chalk 85–70 15–30 Reservoir ↨ Marl 70–30 30–70 Source rock (reservoir?) Marly mudstone 30–15 70–85 Source rock Mudstone <15 >85 Source rock Organic rich

The major lithology types are empirically determined according to Tables S1–S5 (supplementary material available as AAPG Datashare XX at www.aapg.org/datashare), and the percentage of siliciclastic detritus (such as quartz, feldspar, clay minerals, mica, etc.) is relative to the content of carbonate (weight percent). Abbreviation: TOC = total organic carbon (wt. %).

10 Factors Controlling Source and Reservoir Characteristics in the Niobrara Play Figure 5. Pseudo Van Krevelen diagrams of hydrogen index versus oxygen index for source rock samples (carbonate <70 wt.%) in five Q:56 studied wells. (A–E) Wells 1–5, respectively. Modified from Espitalie´ et al. (1977). HC = hydrocarbon; TOC = total organic carbon.

473 solvent extract yields (Figure 9). Because S1 always proportions of volatile HCs in the calculated total 486 474 shows a better correlation coefficient with the total oil amount, whereas C1–5 gas HCs that were lost 487 2 2 475 Q:30 oil (R > 0.88) than extract yields (R < 0.87), S1 has during sampling (Larter, 1988; Sandvik et al., 1992) 488 476 been used in the ensuing discussions to act as a are not accounted for here. Q:31489 477 screening tool for the retained total oil amount. In general, the higher the OM richness, the 490

478 Because a similar maturity (Tmax) was obtained for higher the amount of retained oil (Baker, 1962; 491 479 wells 1 and 2 and wells 3 and 4, respectively (Table 2), Tissot et al., 1971; Stainforth and Reinders, 1990; 492 480 samples from these wells are plotted together. With Pepper, 1991). Accordingly, oil retention in the 493

481 increasing maturity, the proportion of S1 to total oil source rock samples seems to be controlled primarily 494 482 gradually increases from 46% (0.46 = 1/2.1650) in by OM richness (Figure 10). However, the organic- 495 483 wells 1 and 2 (Figure 9A) to 72% (0.72 = 1/1.3979) in rich B-chalk samples fall off the general trend and 496

484 wells 3 and 4 (Figure 9B) and 81% (0.81 = 1/1.2298) retain much less oil (S1) than the other samples in 497 485 in well 5 (Figure 9C). This reflects increasing wells 1 and 2 (Figure 10A). No source rock samples 498

HAN ET AL. 11 Figure 6. Kerogen typing diagrams of hydrogen index versus the temperature at the maximum rate of petroleum generation by Rock- Eval pyrolysis (Tmax) for source rock samples (carbonate <70 wt.%) in five studied wells. (A–E) Wells 1–5, respectively. Modified from Espitalie´ et al. (1984). HC = hydrocarbon; Ro = vitrinite reflectance.

499 are selected from the B-chalk interval in the other AAPG Datashare XX at www.aapg.org/datashare) 512 500 wells (Figure 10B, C). shows a distinct oil crossover and has the highest 513 501 Based on previous studies, the retention of oil OSI value (202 mg/g TOC)amongallsourcerock 514 502 in source rock is controlled mainly by the sorption samples (Figure 10B). Although being classified 515 503 capacity of its OM (Baker, 1962; Tissot et al., 1971; as a source rock (carbonate <70 wt. %), this and 516 504 Stainforth and Reinders, 1990; Pepper, 1991), and other marl samples showing oil crossovers have 517 Q:32505 a sorption threshold of 100 mg HC/g TOC was reservoir characteristics as well. In contrast, and 518 506 proposed, irrespective of kerogen type and thermal because of higher maturity, none of the samples 519 507 maturity (Sandvik et al., 1992; Jarvie, 2012). Some from well 5 show oil crossover effects (Figure 10C), 520

508 samples from wells 1 and 2 (Figure 10A) and wells and S1 values are lower (<3 mg/g) than those of 521 509 3 and 4 (Figure 10B) exceed this threshold value. wells 1 and 2 (<7 mg/g) (Figure 10A) and wells 522 510 For example, sample G015824 (65 wt. % carbon- 3and4(<8 mg/g) (Figure 10B) for comparable 523 511 ate; Table S3, supplementary material available as TOC contents. 524

12 Factors Controlling Source and Reservoir Characteristics in the Niobrara Play Table 2. Averaged Total Organic Carbon and Rock-Eval Data for Nonextracted Source Rock Samples (Carbonate <70 wt. %)

S1 S2 OSI HI

Well Name Sample Number Carbonate, wt. % TOC, wt. % mg HC/gTmax,°C mg HC/g TOC Well 1 20 40 3.97 2.36 14.74 441 60 303 Well 2 21 40 4.46 3.10 14.43 440 73 292 Well 3 12 42 4.30 4.36 7.03 450 102 162 Well 4 8 33 3.17 1.74 4.15 450 54 124 Well 5 17 37 3.13 1.51 1.20 458 47 37

Before Soxhlet extraction, and samples with more than 70 wt. % carbonate are not included.

Abbreviations: HI = hydrogen index ([S2/TOC] · 100; mg HC/g TOC); OSI = oil saturation index ([S1/TOC] · 100, mg HC/g TOC); S1 = the vaporizable hydrocarbons yield at nominal temperatures at 300°C (572°F); S2 = the yield of pyrolysis products generated at a temperature up to 650°C (1202°F); Tmax = the temperature at maximum rate of petroleum generation by Rock-Eval pyrolysis (°C [°F]); TOC = total organic carbon (wt. %).

525 To reveal the control of thermal maturity on et al., 2016 accepted), respectively. These high OSI Q:34560 526 retention, the OSI values of Niobrara source rock samples constitute the sweets spots that are keenly 561

527 samples are plotted against their Tmax values sought during exploration. In the Niobrara For- 562 528 (Figure 11). In general, the Niobrara source rock mation, the exceptional source rock samples have 563 529 samples fall on the maturity evolution pathway ear- carbonate between 49 and 69 wt. % and are char- 564 530 lier defined for the Barnett and Posidonia Shales (Han acterized by relative abundant calcite fossils (de- 565 531 et al., 2017). Because our Niobrara sample set does scribed in detail in the next section). Nevertheless, 566

532 not contain any immature source rocks with Tmax the main targets (i.e., sweet spots) are the chalk 567 533 values lower than 430°C (<806°F), data collected reservoir rocks discussed in the next section. 568 534 from Rice (1984) and Thul (2012) are plotted in To summarize this part, the retention of oil in 569 535 Figure 11. However, samples with reservoir charac- source rock samples (carbonate <70 wt. %) from the 570 536 teristic may be included in their sample set as well Niobrara Formation is controlled by OM properties 571 537 and thus exhibit OSI values greater than those of (i.e., TOC, kerogen type, and thermal maturity). 572 538 typical marine source rocks. In general, the OSI first The higher the richness in OM (TOC), the higher 573 539 increases in the oil window and subsequently de- is the amount of retained oil through sorption. 574 540 creases once the threshold value (100 mg HC/g

541 TOC)isexceededataTmax of approximately 542 445°C (~833°F). For the type II OM-containing 543 Barnett Shale, this temperature is equivalent to ther-

544 Q:33 mal stress levels of 0.85 Rc % according to Jarvie et al. 545 (2007) as follows: Rc % = 0.018 · Tmax – 7.16. Even 546 with allowing for variability in kinetics, this maturity

547 level (0.85 Rc %) is obviously not large enough for the 548 secondary cracking of oil into gas, which was reported

549 tostartatapproximately1.2%Ro in the Posidonia 550 Shale (Dieckmann et al., 1998) and at 1.1% Ro (Hill 551 et al., 2007) or 1.5% Ro (Lewan and Pawlewicz, 2017) 552 in the Barnett Shale. 553 Some samples clearly exhibit higher OSI values 554 than the majority of source rock samples that define 555 the generalized curve (Figure 11). In the Barnett 556 and Posidonia Shales, samples with exceptional 557 reservoir potential are characterized by the pres- Figure 7. Ternary diagram showing kerogen types and the 558 ence of porous fossil fragments, namely, sponge relative abundance of m,p-xylene, n-C8:1 and phenol in Niobrara Q:57 559 spicules (Han et al., 2015) and coccolith (Han source rock samples. Modified from Larter (1984).

HAN ET AL. 13 (Figure 12E–H). Except for the B-chalk samples, 601 there is no visible (>2 nm) pore observed in the 602 elongated organic particles of likely detrital origin 603 (Figure 12A, B, I, J) even after a longer EDXS 604 scanning time (Figure 12L). According to Han et al. Q:35 605 (2017) it can be inferred that the thermal breakdown 606 of OM and the release of HCs leads to pore formation 607 in the OM, that is, the occurrence of organic pores 608

Figure 8. Ternary diagram showing kerogen types and the relative abundance of dimethylthiophene (2,3-DMT), o-xylene, and n-C9:1 in Niobrara source rock samples, modified from Q:58 Eglinton et al. (1990). II-S = xxx.

575 More aliphatic type II samples show different re- 576 tention behavior than the more aromatic types III 577 and IV samples. For instance, and for a given OM 578 richness (TOC), the most aliphatic source rock 579 samples from the B-chalk interval retain much less

580 oil (S1) through sorption than samples from the 581 other intervals. With increasing maturity, the oil

582 retention capacity (expressed in OSI = S1/TOC · 583 100) of Niobrara source rock samples first increases

584 until a Tmax of approximately 445°C (~833°F) and 585 then decreases.

586 Organic Pores in Source Rocks

587 It is widely accepted that organic pores owe their 588 origin to the thermal cracking of kerogen and 589 bitumen in the sense of extractable OM (Loucks 590 et al., 2009; Bernard et al., 2012b, 2013; Curtis et al., 591 2012; Mastalerz et al., 2013; Romero-Sarmiento 592 et al., 2013; Pommer and Milliken, 2015; Ko et al., 593 2016; Han et al., 2017). Clearly, the maturity level 594 does not vary significantly in the least mature well

595 1(Tmax 437°C–444°C [819–831°C]) (Figure 6A). 596 However, nano-size pores are well developed within 597 OM from the B chalk of this well but not common Figure 9. The S1 values of original pulverized samples and 598 in other intervals (Figure 12). The organic pores solvent extract yields versus the amounts of calculated total oil 599 observed in the spatially isolated organic particles (total oil = S1whole rock + S2whole rock - S2extracted rock) in (A) wells 1 2 600 from the B chalk have a sponge-like character and 2, (B) wells 3 and 4, and (C) well 5. R = xxx. Q:59

14 Factors Controlling Source and Reservoir Characteristics in the Niobrara Play It is noteworthy that brightly fluorescing algin- 616 ites (Figure 3E) occur in the samples that are richest 617 in OM (6.89–10.30 wt. % TOC) (Tables S1 and S2, 618 supplementary material available as AAPG Datashare 619 XX at www.aapg.org/datashare), have the highest HIs 620 (Figures 5, 6), and are most aliphatic (Figures 7, 8). 621 Because the OM in the B chalk is therefore compo- 622 sitionally distinct, it is to be expected that its response 623 to thermal cracking might also be distinctive. Ac- 624 cordingly, the formation of organic pores in this OM is 625 one such characteristic that can be expected to follow 626 a different pattern. Indeed, the kerogen-like OM in 627 these B-chalk marls is porous in contrast to those from 628 other intervals in the least mature well 1. No TEM- 629 visible (>2 nm) pores are developed within the OM 630 stringers from other intervals in well 2 (Figure 13). 631 In addition to the organic particles occurring 632 as elongated stringers, others with a smeared, filmy 633 appearance were documented (Figure 12D, K). In 634 most cases, the filmy OM is hosted in mineral pores 635 whose straight boundaries likely correspond to 636 coccolith plate edges. This OM is extremely porous 637 with bubble-like appearance. These morphological 638 features suggest that the filmy OM may represent 639 relics of redistributed bitumen. Their presence in 640 mineral pores indicates an enhanced reservoir po- 641 tential of the two samples G014865 and G014872, 642 whereas it is hard to say whether it is producible oil 643 or not. Both samples exhibit relatively high OSI 644 values (102 and 97 mg HC/g TOC, respectively) and 645 plot above the generalized OSI evolution curve 646 (Figure 11). In other words, they are defined as source 647 rock samples (carbonate <70 wt. %), but they never- 648 theless exhibit some reservoir potential. Nevertheless, 649 the fact remains that the main targets (i.e., sweet spots) 650 are the chalk intervals as discussed in the next section. 651

Figure 10. Controls on oil retention in source rock samples 652 (carbonate <70 wt. %) are revealed by plotting S1 versus total RESERVOIR ROCK CHARACTERISTICS IN organic carbon (TOC) content in (A) wells 1 and 2, (B) wells 3 WELL 3 653 Q:60 and 4, and (C) well 5. OSI = oil saturation index. According to previous discussions, chalk and marly 654 609 can be treated as a tracer of nascent or ongoing chalk (Table 1) with carbonate contents greater than 655 610 petroleum generation and expulsion. Assuming this 70 wt. % are promising reservoir rocks exhibit- 656 611 hypothesis is correct, the occurrence of organic pores ing OSI values greater than 100 mg HC/g TOC 657 612 indicates a depleted oil retention capacity of the host (Figure 4A). Of the 98 analyzed samples (Tables 658 613 kerogen. In line with that, oil retention capacity of S1–S5, supplementary material available as AAPG 659 614 B-chalk samples is lower than that of other source Datashare XX at www.aapg.org/datashare), 20 can 660 615 rock samples (Figure 11). be classified as reservoir rocks. Of those core samples, 661

HAN ET AL. 15 In comparison to the chalks, the A, B, and C 681 marls contain higher amounts of siliciclastic min- 682 erals (e.g., illite–smectite mixed layers [IS] clays and Q:36 683 quartz [Figure 14]). As previously discussed, a pos- 684 itive correlation of quartz and IS-clay mineral con- 685 tents indicates a common detrital origin (Figure 2C). 686 Variations in siliciclastic flux therefore account for 687 the rhythmic bedding of chalk-marl intervals in 688 which autochthonous or allochthonous component 689 abundance is inversely related. Thus, changes in 690 illite–smectite and quartz contents are in contrast to 691 Figure 11. Total organic carbon (TOC) normalized oil re- changes in calcite content (Figure 14). Interestingly, 692 tention capacity (oil saturation index [OSI]) as a function of the and as previously discussed (Figure 4B–D), TOC is 693 temperature at the maximum rate of petroleum generation by positively correlated with quartz and IS-clay mineral 694 Rock-Eval pyrolysis (Tmax) in the Barnett Shale, Posidonia Shale, content and thus also inversely proportional to cal- 695 and Niobrara Formation. The evolution curves are taken from cite contents (Figure 14). A likely explanation for 696 Han et al. (2017) as well as the data of Barnett Shale (diamonds) low TOC is dilution by rapid carbonate sedimen- 697 and Posidonia Shale (triangles). Samples with an OSI greater than tation (Frebourg´ et al., 2016; Denne et al., 2016). Q:37 698 100 mg of hydrocarbons (HC)/g TOC are represented by empty Q:38 patterns. Only the source rock samples (carbonate <70 wt.%) Therefore, TOC canbeashighas7wt.%inthe 699 from the Niobrara Formation are plotted (circles). Samples from Sharon Springs Member, less than 5 wt. % in the 700 the Sharon Springs Member of Pierre Shale and the Carlile Shale marls, and lowest in the chalks (TOC < 2.5 wt. %). 701 are not shown. Data from Rice (1984) and Thul (2012) are plotted Volatile HCs (S1) make up a high proportion of 702 to show the relationship to immature Niobrara source rocks. the in-place OM fraction in the organic-lean chalks. 703 Sample G015824 is plotted beyond the plot because of its high This is manifested in high OSI values (>300 mg HC/g 704 OSI value (202 mg HC/g TOC). Samples G014865 and G014872 TOC). The HC potential (S ) evolves similarly to Q:39 705 Q:61 are shown in Figure 12 C–D and I–L, respectively. 2 the TOC content leading to similar HI values be- 706 tween 100 and 200 mg HC/g TOC throughout the 707 662 15 can be found in well 3 and were thus selected core. In contrast, OI values and Tmax are not stable. In 708 663 to characterize the chalk reservoirs in the Niobrara AandBchalks,OI values are higher, and Tmax values 709 664 shale oil play (Table S3, supplementary material are lower than in the other intervals (Figure 14). 710 665 available as AAPG Datashare XX at www.aapg.org/ 666 datashare). In the following, source rock samples 667 from well 3 are shown in comparison to the reservoir Maturation and Intraformational 711 668 samples because there is no clear lithological bound- Migration of Hydrocarbons in Well 3 712 669 ary between reservoir and source rock samples < 670 anyhow (Table 1). For source rock samples (carbonate 70 wt. %) of 713 well 3, Tmax values average approximately at 450°C 714 (~842°F) (Table 2). Reservoir samples from the A 715 671 Geochemical Log of Well 3 and B chalks exhibit much lower Tmax values 716 (i.e., 421°C –433°C [790°F–811°F] and 437°C 717 672 A geochemical depth profile of well 3 is shown in –446°C [819–835°F], respectively) (Figure 14). 718 673 Figure 14. Significant heterogeneities between the Clearly, besides being influenced by thermal stress, Q:40 719 674 chalk and marl intervals are revealed through XRD. other factors such as the presence of heavy petroleum 720

675 The A and B chalks are almost exclusively composed compounds might affect the Tmax values in the A and 721 676 of calcite (>85 wt. %), which is the empirical Bchalks. 722 677 criterion that is used to define the chalk lithology It is well known that migration and emplacement 723 678 (Table 1). Because of low-density sampling, we will of heavy petroleum compounds in reservoir rock 724

679 not focus on the C-chalk interval and the Fort Hays intervals can result in anomalously low Tmax values 725 680 Member. (Clementz, 1979; Peters, 1986; Jarvie, 2012; Han 726

16 Factors Controlling Source and Reservoir Characteristics in the Niobrara Play Figure 12. Transmission electron microscopy (TEM) images (high-angle annular dark-field [HAADF] mode; Z-contrast) showing organic pores (white arrow). Focused ion beam foils were extracted from source rock samples (carbonate <70 wt. %) from well 1. The rectangular marked areas are magnified in following figures. (A, B) Sample G014861 from the Sharon Springs Member (2 wt. % carbonate; oil saturation index [OSI] = 70 mg of hydrocarbons [HC]/g TOC); no TEM-visible (>2 nm) pores developed within the stringers of organic matter (OM). (C, D) Sample G014865 from the A-marl interval (68 wt. % carbonate; OSI = 102 mg HC/g TOC); bubble-like nanopores are observed in filmy OM of possible bitumen origin. Interparticle mineral pore (P) is partly occluded by those OMs. (E–H) Sample G014867 from the B-chalk interval (52 wt. % carbonate; OSI = 28 mg HC/g TOC); sponge-like nanopores are developed within the OM. (I–L) Sample G014872 from the C-chalk interval (55 wt. % carbonate; OSI = 97 mg HC/g TOC), no TEM-visible (>2 nm) pores developed within the elongated OM stringers of possible detrital origin; only bubble-like nanopores are observed within the filmy OM of possible bitumen origin. The rectangular area as seen in (L) is still not porous after energy-dispersive x-ray spectroscopy scanning.

727 et al., 2015). To assess whether this occurs here, This shift is only very subtle for marl samples (Figure 737

728 comparative Rock-Eval pyrolysis (Delvaux et al., 15B). Here, the S2 peak shapes are approximately 738 729 1990) was performed on samples both before and similar before and after solvent extraction, with the 739 730 after solvent extraction. Typical pyrolysis traces for exception of the removal of minor “pre-shoulders.” 740 731 samples from the chalk and marl intervals are shown As reported for an oil-mature Barnett Shale core 741 732 in Figure 15. After solvent extraction of the chalk (Han et al., 2015), it is very likely that petroleum 742

733 samples (Figure 15A), S2 peak areas significantly de- migrated into the chalk intervals, leading to a shift of 743

734 crease, whereas peak shape is lower in height and high to low Tmax values. For instance, after solvent Q:41744 735 shorter in width (red lines). In addition, a significant extraction, a significant depletion of TOC content 745

736 shift of the Tmax to higher values can be observed. (29–41 wt. %) occurs for samples from the A and B 746

HAN ET AL. 17 Figure 13. Transmission electron microscopy (TEM) images (high-angle annular dark-field [HAADF] mode; Z-contrast) of a focused ion beam foil extracted from sample G014887 from the A-marl interval of well 2. The rectangular marked areas in (A) are magnified as seen in (B) and (C), respectively. No TEM-visible (>2 nm) pores are developed within the organic matter stringers (52 wt. % carbonate; OSI = 70 mg of hydrocarbons per gram of total organic carbon).

747 chalks in well 3 (Table S3, supplementary material petroleum in a reservoir interval. With increasing 781 748 available as AAPG Datashare XX at www.aapg.org/ maturity going from wells 1 and 2 to well 3, shale and 782 749 datashare). In line with that, averaged OSI values are marl intervals exhibit decreasing QI values, con- 783 750 extremely high (>445 mg HC/g TOC, Table 3). It is firming source rock characteristics (Table 3). In 784 751 highly improbable that such huge quantities of re- contrast, QI values increase for the A, B, and C chalks 785 752 movable oil in A and B chalks could have originated of well 3, confirming reservoir characteristics. Thus, 786 753 from the indigenous OM, especially when taking HI oil generated within the organic-rich layers very likely 787 754 values of samples from the less mature wells 1 and 2 migrated into juxtaposed chalks where it was partly 788 755 into consideration (<450 mg HC/g TOC) (Table 3). emplaced. 789 756 As mentioned above, the gradual decrease of HI This migrated oil is mainly responsible for 790

757 going from well 1 to well 5 (Table 2) is likely a result skewing the S2 curve and lowering Tmax in the chalk 791 758 of thermal degradation. Comparing HI values of intervals (Figure 15A). As shown in Figure 15, the 792 759 A- and B-chalk samples from well 2 to those of well 3 Rock-Eval apparatus is held at a nominal isothermal 793 760 (Table 3), it becomes clear that their difference (154 temperature of 300°C (572°F) for the first 3 min 794 761 and 229 mg HC/g TOC, respectively) is obviously (actually 40°C [104°F] higher for the Rock-Eval 2 795 762 lower than the corresponding increase in OSI (381 and instrument). Some heavy-end oil compounds (be- 796

763 408 mg HC/g TOC,respectively).Thus,moreHCs ginning as early as n-C19+) cannot be fully vaporized 797 764 are present than could have been generated from their at those temperatures (Han et al., 2015) and ther- 798

765 initial OM. Furthermore, the assumed initial HC mally break down within the S2 peak temperature 799 766 generation potential for chalks of well 3 represents an range during programmed heating. For instance, 800

767 overestimation when taking into account the samples 69%–77% and 57%–71% of the S2 signal is lost after 801 768 from the A-chalk interval in wells 1 and 2 are inter- extraction for samples from the A and B chalks, re- 802 769 bedded organic-rich marls, but those of well 3 are true spectively (Table S3, supplementary material avail- 803 770 chalks with likely very low generation potential at able as AAPG Datashare XX at www.aapg.org/ 804 771 immature stages. The same applies to the B chalk. datashare), meaning that the major part of the py- 805 772 To keep things simple, we used (defined) the rolysate in fact originates from heavy petroleum 806

773 sumofthevolatileHCs(S1) and pyrolysate yield compounds and not from kerogen. Thus, the re- 807 774 (S2) normalized to TOC (QI = [S1 + S2]/TOC · 100) moval of extractable OM before pyrolysis is a pre- 808 775 as a quality index (QI) (Pepper and Corvi, 1995). In requisite for the Tmax value to reveal the maturity of 809 776 general, a decrease in QI with increasing maturity is a kerogen. 810

777 consequence of petroleum expulsion and primary For all solvent-extracted chalk samples, Tmax 811 778 migration out of source beds (Sykes and Snowdon, values are significantly increased by more than 10°C 812 779 2002). Nevertheless, QI values might also increase, [>50°F] (Table S3, supplementary material available 813 780 indicating the presence or emplacement of migrated as AAPG Datashare XX at www.aapg.org/datashare). 814

18 Factors Controlling Source and Reservoir Characteristics in the Niobrara Play Figure 14. Geochemical depth profile of well 3. HI = hydrogen index (S2/TOC · 100); IS = illite–smectite mixed layers; OI = oxygen index (S3/TOC · 100), in which S3 corresponds to the amount of CO2 produced during pyrolysis of organic matter; OSI = oil saturation index (S1/TOC · 100); TOC = total organic carbon; S1 = thermal extractable petroleum; S2 = petroleum generated by pyrolysis; Tmax = the temperature at maximum rate of petroleum generation by Rock-Eval pyrolysis. H NE AL. ET AN 19 Figure 15. Rock-Eval traces of representative samples from (A) chalk intervals and (B) marl intervals before and after Soxhlet ex- traction. Extracted samples are indicated with an “E.” Intensity (left y-axis) is normalized by dividing the initial signal intensity with the sample weight and total organic carbon (TOC). The right y-axis indicates the temperature program.

815 Extracted B-chalk sample Tmax values (456–459°C Kerogen type can affect the Tmax and many other 825 816 [853–858°F]) are now similar to those of the adjacent geochemical parameters (Espitalie´ et al., 1984; 826 817 marls (Table S3, supplementary material available Tissot and Welte, 1984; Espitalie,´ 1985). Using the Q:42 827 818 as AAPG Datashare XX at www.aapg.org/datashare). HI for typing of OM in extracted well 3 samples, a 828

819 However, Tmax values of extracted A-chalk samples more oxygen-rich (>20 mg CO2/g TOC) and less 829 820 (432–449°C [810–840°F]) are still lower than those of hydrogen-rich kerogen (~50 mg HC/g TOC) remains 830 821 all the other samples (Figure 16). Obviously, other in the A chalk compared to the other intervals 831

822 factors might affect Tmax values as a relatively (Figure 17A, B). Rock-Eval data of extracted A-chalk 832 823 stable maturity level should prevail throughout samples suggest type III kerogens. The particularly 833 824 well 3. low values for the temperature at maximum rate of 834

20 Factors Controlling Source and Reservoir Characteristics in the Niobrara Play Table 3. Rock-Eval Pyrolysis of Studied Wells

Rock-Eval Name Nr Sharon A Chalk A Marl B Chalk B Marl C Chalk C Marl Fort Carlile

OSI (mg HC/g TOC) Well 1 20 61 n.a. 79 30 78 83 82 26 31 Well 2 23 106 76 114 37 101 55 95 n.a. 34 Well 3 27 118 457 144 445 155 188 52 377 n.a. HI (mg HC/g TOC) Well 1 20 292 n.a. 358 450 299 318 391 43 122 Well 2 23 337 294 325 404 285 271 269 n.a. 98 Well 3 27 170 140 177 175 180 168 141 167 n.a. QI (mg HC/g TOC) Well 1 20 353 n.a. 438 479 377 401 474 69 153 Well 2 23 443 371 439 441 386 326 364 n.a. 132 Well 3 27 288 597 321 621 335 356 193 544 n.a.

Data are averages of all samples from each well before solvent extraction.

Abbreviations: HI = hydrogen index ([S2/TOC] · 100; mg HC/g TOC); n.a. = not available; Nr = number of samples; OSI = oil saturation index ([S1/TOC] · 100; mg HC/g TOC); QI = quality index ([S1 + S2]/TOC · 100; mg HC/g TOC).

835 petroleum generation by Rock-Eval pyrolysis de- chambers (Figure 19L) may indicate its allochthonous 865 836 Q:43 tected on solvent-extracted samples of A-chalk character. Association of OM with anomalously large 866 837 samples in well 3 (Figure 16) seem to be related to pores (Figure 19K, L) provides evidence for the em- 867 838 the presence of a different kerogen type. Neverthe- placement of bituminized OM within a fossil body 868 839 less, and taking data of wells 1 and 2 into consider- cavity. Figure 19L shows the infill of a coccolith spine by 869 840 ation (Figures 5C, 6C), the majority of extracted squeezed OM. The latter likely also surrounds the clay 870 841 samples from well 3 should be initially of a type II and calcite crystals at the right side and is in contact 871 842 origin (Figure 17A, B). with a large pore on the upper side. The pore, having 872 a channel-like morphology, may have acted as the 873 pathway for moving gaseous and aqueous phases. 874 fi 843 Oil Retention and Pore Development in Assuming the fossil body cavity is indeed lled by 875 844 Reservoir Rocks allochthonous OM, a morphological difference might 876 be noticeable for OM infilling intraskeletal pores 877 845 For nonreservoir rocks (carbonate <30 wt. %) in (Figure 19L) and OM infilling interparticle pores 878

846 wells 3 and 4, TOC is positively correlated to S1 (Figure 19H). Although nanopores are detected in 879 847 (i.e., volatile oil is preferentially present in a sorbed both types, OM in intraskeletal pores seems to be less 880 848 state [Figure 18A]). For samples with more than 30 porous (i.e., denser), and OM in interparticle pores 881 849 wt. % carbonate (reservoir rocks and source rocks seems to have a bubble-like texture with numerous 882 850 with some reservoir characteristic), carbonate con- pores. It is likely that the denser OM is solid (i.e., highly 883 851 tent shows a positive correlation with the amount viscous bitumen), which is difficult to dissolve in or- 884 852 of retained (stored) oil in all but one sample ganic solvent (Curiale, 1986; Ko et al., 2016). In 885 853 Q:44 (Figure 18B). Here, most oil is likely stored as a fluid contrast, the bubble-like OM is likely the relic of less 886 854 phase in pores of calcareous fossils rather than sorbed viscous bitumen after devolatilization, either naturally 887 855 onto OM. As shown for the Barnett Shale (Han et al., or artificially. Because the TEM was operated at 200 888 856 2015), for which the chambers of sponge spicules kV, devolatilization likely occurred if volatile HCs 889 857 provide additional storage capacity, porous coccolith remained after FIB extraction. Considering that 890

858 (Figures 3H, K, L; 19) and foraminifera test the maturity level of well 3 (450°C [842°F] Tmax)is 891 859 (Figure 3B–D, I) filled with OM (Figures 3F, H, I; not severe enough for secondary gas generation, the 892 860 19H, L) can be observed in Niobrara reservoir and bubble-like appearance of OM in well 3 (Figure 19H) 893 861 source rocks. can most likely be tracked back to bitumen devola- 894 862 We cannot distinguish easily between solid bitumen tilization during sample preparation and analysis. 895 863 and kerogen. But according to the criteria given by To avoid misunderstandings, we do not conclude 896 864 Loucks and Reed (2014), the presence of OM in fossil that all observable OM in intraskeletal or interparticle 897

HAN ET AL. 21 (Figure 19) are obviously more porous than those from 905 source rocks (Figure 12). Interparticle pores are typically 906 sheltered by calcite grains with straight edges 907 (Figures 12D, K; 19), presumably coccolith skeletal 908 debris (Figure 19B, D). Intraskeletal pores have dis- 909 tinct oval-equant shapes that are produced by the 910 surrounding coccolith plates (Figure 19G, L). Abun- 911 dance of both intraskeletal and interparticle pores will 912 be enhanced as the content of carbonate fossils in- 913 creases, directly resulting in the increase of producible 914

oil in place as observed by increasing S1 values for 915 potential reservoir samples (carbonate >30 wt. %) 916 (Figure 18B). 917 In general, and here for mudstones and marly 918 mudstones (carbonate contents <30 wt. %), the 919 higher the TOC content, the more oil is sorbed 920 (Figure 18A). Nevertheless, oil can also be stored in 921 the pores of calcareous fossils. Thus, for samples with 922 carbonate contents >30 wt. % (marls to chalks), the 923 higher the carbonate content, the more oil is stored 924 as a fluid phase (Figure 18B), irrespective of OM 925 richness. Therefore, because TOC and carbonate 926 content are negatively correlated for the Niobrara 927 Formation (cf. Figure 4B), the overall oil storage 928 capacity is directly determined by carbonate content 929 for marls to chalks (Figure 18B) and by TOC content 930 for carbonate poor mudstones to marly mudstones 931

(Figure 18A). Minimum oil-in-place values (S1) are 932 found for samples with approximately 20–40 wt. % 933 carbonate content. 934 Regarding exploration, the best target horizons 935 for high oil in place occur where carbonate is ei- 936 ther low or high. Nevertheless, because sorption 937 dominates in organic-rich mudstones, the saturation 938 of mobile fluid-phase petroleum is likely much 939 higher in the pore system of chalks. In addition, 940 chalksarelikelymorebrittleandthereforerepre- 941 sent the primary targets in Niobrara shale oil plays. 942 Figure 16. Geochemical depth profile of the temperature at maximum rate of petroleum generation by Rock-Eval pyrolysis E detected on solvent-extracted samples (Tmax ) from well 3. CONCLUSIONS 943

898 pores is solid bitumen only because nanopores are The Niobrara Formation is a binary sedimentary 944 899 present. Nanopores can be detected more or less system composed of alternating deposition of car- 945 900 within all kinds of OM (bitumen as well as kerogen) bonate and siliciclastic minerals. As an end member 946 901 in well 3 source rock and reservoir samples. of binary systems, chalk is almost purely composed 947 902 In any case, the enrichment of porous, calcare- of calcareous fossils (carbonate >85 wt. %). Chalks 948 903 ous fossils provides additional space for petroleum are relatively organic-poor rocks (TOC <2.5 wt. %) 949 904 storage. The FIB foils extracted from reservoir rocks with high reservoir potential (OSI > 100 mg HC/g 950

22 Factors Controlling Source and Reservoir Characteristics in the Niobrara Play TOC). As another end member, mudstone consists 951 of mainly fine siliciclastic debris (quartz, feldspar, 952 clay minerals, mica, etc.) with carbonate content less 953 than 15 wt. %. Mudstones are organic-rich source 954 rocks (TOC >2.5 wt. %). Marls hold intermediate 955 positions and have carbonate contents of 70–30 wt. 956 %. The majority of marls are treated as HC source 957 rocks while showing partly good reservoir potential. 958 The majority of Niobrara source rocks can be 959 classified as to contain type II kerogen. The most 960 hydrogen-rich and aliphatic kerogen is present in 961 organic-rich marl layers interbedded within the B- 962 chalk interval, whereas types III and IV kerogen (HI 963 based) is found in the A-chalk interval, Fort Hays 964 Member, and Carlile Shale. The sample set consists 965

of early–late oil window mature samples with Tmax 966 values ranging from approximately 440°C to 458°C 967 (~824°F to 856°F). The HI values gradually decrease 968 going from well 1 to well 5. 969

Figure 17. Crossplots of (A) hydrogen index (HI) versus ox- ygen index and (B) HI versus indices for the temperature at maximum rate of petroleum generation by Rock-Eval pyrolysis Q:62 for solvent-extracted (E) samples. HC = hydrocarbons; Ro = vitrinite reflectance; TOC = total organic carbon. Figure 18. Crossplots of (A) S1 versus total organic carbon (TOC) content and (B) S1 versus carbonate content. The sample without fill (G015815) is an outlier.

HAN ET AL. 23 Figure 19. Transmission electron microscopy (TEM) images (high-angle annular dark-field [HAADF] mode; Z-contrast) showing mineral-associated pores (P) and organic matter associated P (white arrow). Focused ion beam foils were all extracted from chalk samples from well 3. Rectangular marked areas are magnified in following figures. (A–D) Sample G015819 from A chalk (91 wt. % carbonate; oil Q:63 saturation index (OSI) = 512 mg of hydrocarbons (HC)/g TOC); mineral P associated to coccolith fragments. (E–H) Sample G015827 from B chalk (94 wt. % carbonate; OSI = 493 mg HC/g TOC); mineral P associated to coccolith fragments. (H) Interparticle mineral P is partly occluded by organic matter of possible bitumen origin in which bubble-like organic Ps are observed. (I–L) Sample G015834 from C chalk (88 wt. % carbonate; OSI = 318 mg HC/g TOC); mineral P and organic P are developed.

970 Oil retention in the source rock samples of approximately 445°C (~833°F) and subsequently 983

971 (carbonate <70 wt. %) is controlled by OM prop- decreases. In well 3 (Tmax at ~450°C [~842°F]), 984 972 erties (i.e., OM richness and thermal maturity). In nanopores are detected more or less in all intervals 985 973 general, the higher the TOC, the higher the amount within all kinds of OM, which appears to result in a 986

974 of retained oil (S1). The very organic-rich marls of the depleted oil retention capacity. 987 975 B chalk are an exception and retain much less oil (per Most analyzed chalk samples (carbonate >85 wt. 988 976 grams of TOC) than the other source rocks. In- %) were taken from the A, B, and C chalks of well 3. 989 977 terestingly, kerogen in the B-chalk marls of the least Those reservoir zones are characterized by anoma- 990

978 mature well 1 is in contrast to that of the other source lously low Tmax values. After solvent extraction, a 991 Q:45979 rocks in that it is highly porous. With increasing significant shift to higher Tmax values (>10°C 992 980 maturity, the OSI value of Niobrara source rock [>50°F]) indicates that much of the original pyrolysis 993 981 samples first increases until the maximum retention signals in fact originated from heavy petroleum 994

982 capacity (100 mg HC/g TOC) is exceeded at a Tmax compounds and not from kerogen. This is confirmed 995

24 Factors Controlling Source and Reservoir Characteristics in the Niobrara Play 996 by up to 41% of extractable TOC.BasedonOSI and maturation series from the Lower Toarcian Posidonia 1045 fl 997 HI values, it becomes clear that more bitumen is Shale, Germany: Nanoscale pore system and uid-rock 1046 interactions, in W. K. Camp, E. Diaz, and B. Wawak, 1047 998 present than could have been generated by indigenous eds., Electron microscopy of shale hydrocarbon reser- 1048 999 kerogen with the A and B chalks. Thus, oil generated voirs: AAPG Memoir 102, p. 53–66. 1049 1000 from the organic-rich marl layers is very likely to have Bernard, S., R. Wirth, A. Schreiber, H.-M. Schulz, and 1050 1001 migrated into those juxtaposed chalk units. B. Horsfield, 2012b, Formation of nanoporous pyrobitumen 1051 1002 For samples with distinct reservoir potential residues during maturation of the Barnett Shale (Fort 1052 Worth Basin): International Journal of Coal Geology, 1053 1003 (carbonate >30 wt. %), carbonate content is posi- v. 103, no. 0, p. 3–11, doi:10.1016/j.coal.2012.04 1054 1004 tively correlated to the amount of retained oil (S1). .010. 1055 1005 Petrographic features indicate that this volatile oil is Brian, D., W. Joel, D. Juliana, and W. S. Steven, 2013, Ap- 1056 1006 related to allochthonous OM within porous calcite plications of SEM imaging to reservoir characterization in 1057 the Eagle Ford Shale, South Texas, U.S.A, in W. K. Camp, 1058 1007 fossils (i.e., coccolith and foraminifera). Although E. Diaz, and B. Wawak, eds., Electron microscopy of 1059 1008 this OM infill cannot unequivocally be identified as shale hydrocarbon reservoirs: AAPG Memoir 102, 1060 “ ” 1009 migrated heavy petroleum, squeezed bituminized p. 115–136. 1061 1010 OM, or kerogen, it is nevertheless common sense Claypool, G. E., and P. R. Reed, 1976, Thermal-analysis 1062 1011 that enrichment of porous fossils will provide addi- technique for source-rock evaluation: Quantitative esti- 1063 mate of organic richness and effects of lithologic varia- 1064 1012 tional space for the storage and flowage of petroleum tion: AAPG Bulletin, v. 60, no. 4, p. 608–626. 1065 1013 fluids. Interparticle and intraskeletal OM associated Clementz, D. M., 1979, Effect of oil and bitumen saturation 1066 1014 with calcareous fossil fragments in chalks is more on source-rock pyrolysis: AAPG Bulletin, v. 63, no. 12, 1067 1015 porous than that in source rocks. p. 2227–2232. 1068 1016 Thus, overall oil retention or storage is de- Curiale, J. A., 1986, Origin of solid bitumens, with emphasis 1069 on biological marker results: Organic Geochemistry, 1070 1017 termined by either carbonate content for samples v. 10, no. 1–3, p. 559–580, doi:10.1016/0146-6380(86) 1071 1018 with distinct reservoir potential (carbonate >30 wt. 90054-9. 1072 1019 %) or by TOC content for nonreservoir rocks Curtis, M. E., R. J. Ambrose, C. H. Sondergeld, and C. S. Rai, 1073 1020 (carbonate <30 wt. %). Sweet spots can be expected 2011, Investigation of the relationship between organic 1074 1021 for intervals in which carbonate content is either low porosity and thermal maturity in the Marcellus Shale: 1075 Society of Petroleum Engineers North American Un- 1076 1022 or very high. However, extraction of fluid-phase pe- conventional Gas Conference and Exhibition, Wood- 1077 1023 troleum from the pore space of more brittle chalk lands, Texas, June 14–16, 2011, SPE-144370-MS, doi: 1078 1024 units seems to be more attractive, making chalk the 10.2118/144370-MS. Q:461079 1025 primary target for the Niobrara shale oil play. Curtis, M. E., B. J. Cardott, C. H. Sondergeld, and C. S. Rai, 1080 2012, Development of organic porosity in the Woodford 1081 Shale with increasing thermal maturity: International 1082 Journal of Coal Geology, v. 103, p. 26–31, doi:10.1016 1083 1026 REFERENCES CITED /j.coal.2012.08.004. 1084 Da Gama, R. O. B. P., B. Lutz, P. Desjardins, M. Thompson, 1085 1027 Baker, D. R., 1962, Organic geochemistry of Cherokee I. Prince, and I. Espejo, 2014, Integrated paleoenvir- 1086 1028 Group in southeastern Kansas and northeastern Okla- onmental analysis of the Niobrara Formation: Cretaceous 1087 1029 homa: AAPG Bulletin, v. 46, no. 9, p. 1621–1642. Western Interior Seaway, northern Colorado: Palae- 1088 1030 Bergmann, J., P. Friedel, and R. Kleeberg, 1998, BGMN – A ogeography, Palaeoclimatology, Palaeoecology, v. 413, 1089 1031 new fundamental parameters based Rietveld program for p. 66–80, doi:10.1016/j.palaeo.2014.05.005. 1090 1032 laboratory X-ray sources, it’s use in quantitative analysis Delvaux, D., H. Martin, P. Leplat, and J. Paulet, 1990, 1091 1033 and structure investigations: Commission of Power Dif- Comparative Rock-Eval pyrolysis as an improved tool 1092 1034 fraction Newsletter, v. 20, no. 20, p. 5–8. for sedimentary organic matter analysis: Organic Geo- 1093 1035 Bernard, S., B. Horsfield, H.-M. Schulz, R. Wirth, chemistry, v. 16, no. 4–6, p. 1221–1229, doi:10.1016 1094 1036 A. Schreiber, and N. Sherwood, 2012a, Geochemical /0146-6380(90)90157-U. Q:471095 1037 evolution of organic-rich shales with increasing matu- Dieckmann, V., H. J. Schenk, B. Horsfield, and D. H. Welte, 1096 1038 rity: A STXM and TEM study of the Posidonia Shale 1998, Kinetics of petroleum generation and cracking 1097 1039 (Lower Toarcian, northern Germany): Marine and Pe- by programmed-temperature closed-system pyrolysis of 1098 1040 troleum Geology, v. 31, no. 1, p. 70–89, doi:10.1016/j Toarcian Shales: Fuel, v. 77, no. 1–2, p. 23–31, doi: 1099 1041 .marpetgeo.2011.05.010. 10.1016/S0016-2361(97)00165-8. 1100 1042 Bernard, S., R. Wirth, A. Schreiber, L. Bowen, A. Aplin, Eglinton, T. I., J. S. Sinninghe Damste,´ M. E. L. Kohnen, and 1101 1043 E. Mathia, H.-M. Schulz, and B. Horsfield, 2013, FIB- J. W. de Leeuw, 1990, Rapid estimation of the organic 1102 1044 SEM and TEM investigations of an organic-rich shale sulphur content of kerogens, coals and asphaltenes by 1103

HAN ET AL. 25 1104 pyrolysis-gas chromatography: Fuel, v. 69, no. 11, Shale reservoirs—Giant resources for the 21st century: 1163 1105 p. 1394–1404, doi:10.1016/0016-2361(90)90121-6. AAPG Memoir 97, p. 89–119. 1164 1106 Espitalie,´ J., 1985, Use of Tmax as a maturation index for Jarvie, D. M., R. J. Hill, T. E. Ruble, and R. M. Pollastro, 1165 1107 different types of organic matter. Comparison with 2007, Unconventional shale-gas systems: The Mississip- 1166 1108 vitrinite reflectance, in J. Burrus, ed., Thermal mod- pian Barnett Shale of north-central Texas as one model 1167 1109 elling in sedimentary basins: Paris, Editions Technip, for thermogenic shale-gas assessment: AAPG Bulletin, 1168 1110 p. 475–496. v. 91, no. 4, p. 475–499, doi:10.1306/12190606068. 1169 1111 Espitalie,´ J., M. Madec, B. Tissot, J. J. Mennig, and P. Leplat, Jennings, D. S., and J. Antia, 2013, Petrographic character- 1170 1112 1977, Source rock characterization method for petroleum ization of the Eagle Ford Shale, South Texas, mineralogy, 1171 1113 exploration: Offshore Technology Conference, Houston, common constituents, and distribution of nanometer- 1172 1114 Texas, May 2–5, 1977, OTC-2935-MS, p. 439-444. scaleporetypes,in W.K.Camp,E.Diaz,andB.Wawak, 1173 1115 Espitalie,´ J., F. Marquis, and I. Barsony, 1984, Geochemical eds., Electron microscopy of shale hydrocarbon reservoirs: 1174 1116 logging, in K. J. Voorhees, ed., Analytical pyrolysis: AAPG Memoir 102, p. 101–113. 1175 1117 Techniques and applications: London, Butterworth- Kauffman, E. G., 1977, Geological and biological overview: 1176 1118 Heinemann, p. 276–304, doi:10.1016/B978-0-408- Western Interior Cretaceous Basin: Mountain Geologist, 1177 1119 01417-5.50013-5. v. 14, no. 3–4, p. 75–99. 1178 1120 Fairbanks, M. D., S. C. Ruppel, and H. Rowe, 2016, High- Ko, L. T., R. G. Loucks, S. C. Ruppel, T. Zhang, and S. Peng, 1179 1121 resolution stratigraphy and facies architecture of the 2017, Origin and characterization of Eagle Ford pore 1180 1122 Upper Cretaceous (Cenomanian–Turonian) Eagle Ford networks in the south Texas Upper Cretaceous shelf: 1181 1123 Group, Central Texas: AAPG Bulletin, v. 100, no. 3, AAPG Bulletin, v. 101, no. 3, p. 387–418, doi:10.1306 1182 1124 p. 379–403, doi:10.1306/12071514187. /08051616035. 1183 1125 Frebourg,´ G., S. C. Ruppel, R. G. Loucks, and J. Lambert, Ko, L. T., R. G. Loucks, T. Zhang, S. C. Ruppel, and D. Shao, 1184 1126 2016, Depositional controls on sediment body archi- 2016, Pore and pore network evolution of Upper Cre- 1185 1127 tecture in the Eagle Ford/Boquillas system: Insights from taceous Boquillas (Eagle Ford–equivalent) mudrocks: 1186 1128 outcrops in west Texas, United States: AAPG Bulletin, Results from gold tube pyrolysis experiments: AAPG 1187 1129 v. 100, no. 4, p. 657–682, doi:10.1306/12091515101. Bulletin, v. 100, no. 11, p. 1693–1722, doi:10.1306 1188 1130 Han, Y., B. Horsfield, R. Wirth, N. Mahlstedt, and S. Bernard, /04151615092. 1189 1131 2017, Oil retention and porosity evolution in organic- Landon, S. M., M. W. Longman, and B. A. Luneau, 2001, 1190 1132 rich shales: AAPG Bulletin, v. 101, no. 6, p. 807–827, Hydrocarbon source rock potential of the Upper Cre- 1191 1133 doi:10.1306/09221616069. taceous Niobrara Formation, Western Interior Seaway of 1192 1134 Han, Y., N. Mahlstedt, and B. Horsfield, 2015, The Barnett the Rocky Mountain region: Mountain Geologist, v. 38, 1193 1135 Shale: Compositional fractionation associated with in- no. 1, p. 1–18. 1194 1136 traformational petroleum migration, retention, and ex- Larter, S., 1988, Some pragmatic perspectives in source rock 1195 1137 pulsion: AAPG Bulletin, v. 99, no. 12, p. 2173–2202, geochemistry: Marine and Petroleum Geology, v. 5, 1196 1138 doi:10.1306/06231514113. no. 3, p. 194–204, doi:10.1016/0264-8172(88)90001-3. 1197 1139 Hattin, D. E., 1981, Petrology of Smoky Hill Member, Nio- Larter, S. R., 1984, Application of analytical pyrolysis tech- 1198 1140 brara Chalk (Upper Cretaceous) in type area, Western niques to kerogen characterization and fossil fuel ex- 1199 1141 Kansas: AAPG Bulletin, v. 65, no. 12, p. 831–849, doi: ploration/exploitation, in K. Voorhees, ed., Analytical 1200 1142 10.1306/2F919B11-16CE-11D7-8645000102C1865D. pyrolysis: Techniques and applications: London, But- 1201 1143 Higley, D. K., 2015, The history of oil and gas development terworth-Heinemann, p. 212–275, doi:10.1016/B978-0- 1202 1144 in the Denver Basin: AAPG Search and Discovery article 408-01417-5.50012-3. 1203 1145 70187, accessed xx xx, xxxx, http://www.search- Lewan, M. D., and M. J. Pawlewicz, 2017, Reevaluation of 1204 1146 anddiscovery.com/documents/2015/70187higley/ndx_ thermal maturity and stages of petroleum formation of 1205 1147Q:48 higley.pdf. the Mississippian Barnett Shale, Fort Worth Basin, Texas: 1206 1148 Higley, D. K., D. O. Cox, and R. J. Weimer, 2003, Petroleum AAPG Bulletin, v. 101, no. 12, p. 1945–1970, doi: 1207 1149 system and production characteristics of the Muddy (J) 10.1306/01251716053. Q:49 1208 1150 Sandstone (Lower Cretaceous) Wattenberg continuous Locklair, R. E., and B. B. Sageman, 2008, Cyclostratigraphy of 1209 1151 gas field, Denver basin, Colorado: AAPG Bulletin, v. 87, the Upper Cretaceous Niobrara Formation, Western 1210 1152 no. 1, p. 15–37. Interior, U.S.A.: A Coniacian–Santonian orbital time- 1211 1153 Hill, R. J., E. Zhang, B. J. Katz, and Y. Tang, 2007, Modeling scale: Earth and Planetary Science Letters, v. 269, 1212 1154 of gas generation from the Barnett Shale, Fort Worth no. 3–4, p. 540–553, doi:10.1016/j.epsl.2008.03.021. 1213 1155 Basin, Texas: AAPG Bulletin, v. 91, no. 4, p. 501–521, Loucks, R. G., and R. M. Reed, 2014, Scanning-electron- 1214 1156 doi:10.1306/12060606063. microscope petrographic evidence for distinguishing 1215 1157 Horsfield, B., U. Disko, and F. Leistner, 1989, The micro-scale organic-matter pores associated with depositional or- 1216 1158 simulation of maturation: Outline of a new technique and ganic matter versus migrated organic matter in mu- 1217 1159 its potential applications: Geologische Rundschau, v. 78, drocks: Gulf Coast Association of Geological Societies 1218 1160 no. 1, p. 361–373, doi:10.1007/BF01988370. Transactions, v. 3, p. 51–60. Q:50 1219 1161 Jarvie, D. M., 2012, Shale resource systems for oil and gas: Loucks, R. G., R. M. Reed, S. C. Ruppel, and D. M. Jarvie, 1220 1162 Part 2—Shale-oil resource systems, in J. A. Breyer, ed., 2009, Morphology, genesis, and distribution of nanometer- 1221

26 Factors Controlling Source and Reservoir Characteristics in the Niobrara Play 1222 scale pores in siliceous mudstones of the Mississippian geochemistry and source rock potential of carbonate 1281 1223 Barnett Shale: Journal of Sedimentary Research, v. 79, rocks: AAPG Memoir 18, p. 135–150. 1282 1224 no. 12, p. 848–861, doi:10.2110/jsr.2009.092. Ricken, W., 1996, Bedding rhythms and cyclic sequences as 1283 1225 Luneau, B., M. Longman, P. Kaufman, and S. Landon, 2011, documented in organic carbon-carbonate patterns, Up- 1284 1226 Stratigraphy and petrophysical characteristics of the per Cretaceous, Western Interior, U.S: Sedimentary 1285 1227 Niobrara Formation in the Denver Basin, Colorado and Geology, v. 102, no. 1–2, p. 131–154, doi:10.1016 1286 1228 Wyoming: AAPG Search and Discovery article 50469, /0037-0738(95)00060-7. 1287 1229 accessed xx xx, xxxx, http://www.searchanddiscovery Romero-Sarmiento, M.-F., M. Ducros, B. Carpentier, 1288 1230 Q:51 .com/documents/2011/50469luneau/ndx_luneau.pdf. F. Lorant, M.-C. Cacas, S. Pegaz-Fiornet, S. Wolf, 1289 1231 Mastalerz, M., A. Schimmelmann, A. Drobniak, and Y. Chen, S. Rohais, and I. Moretti, 2013, Quantitative evaluation 1290 1232 2013, Porosity of Devonian and Mississippian New Al- of TOC, organic porosity and gas retention distribution 1291 1233 bany Shale across a maturation gradient: Insights from in a gas shale play using petroleum system modeling: 1292 1234 organic petrology, gas adsorption, and mercury intrusion: Application to the Mississippian Barnett Shale: Marine 1293 1235 AAPG Bulletin, v. 97, no. 10, p. 1621–1643, doi: and Petroleum Geology, v. 45, p. 315–330, doi:10.1016 1294 1236 10.1306/04011312194. /j.marpetgeo.2013.04.003. 1295 1237 Mathia, E. J., L. Bowen, K. M. Thomas, and A. C. Aplin, Sandvik, E. I., W. A. Young, and D. J. Curry, 1992, Expulsion 1296 1238 2016, Evolution of porosity and pore types in organic- from hydrocarbon sources: The role of organic absorp- 1297 1239 rich, calcareous, Lower Toarcian Posidonia Shale: Marine tion: Organic Geochemistry, v. 19, no. 1–3, p. 77–87, 1298 1240 and Petroleum Geology, v. 75, p. 117–139, doi:10.1016 doi:10.1016/0146-6380(92)90028-V. 1299 1241 /j.marpetgeo.2016.04.009. Sherwood, O. A., P. D. Travers, and M. P. Dolan, 2013, 1300 1242 Milliken, K. L., M. Rudnicki, D. N. Awwiller, and T. Zhang, Hydrocarbon maturity and migration analysis using 1301 1243 2013, Organic matter–hosted pore system, Marcellus production gas stable isotopic signatures in the Watten- 1302 1244 Formation (Devonian), Pennsylvania: AAPG Bulletin, berg field, Denver Basin, Colorado, USA: Unconventional 1303 1245 v. 97, no. 2, p. 177–200, doi:10.1306/07231212048. Resources Technology Conference, Denver, Colorado, 1304 1246 O’Neal, D. L., 2015, Chemostratigraphic and depositional August 12–14, 2013, p. 1989–1995, doi:10.1190 1305 1247 characterization of the Niobrara Formation, CEMEX /urtec2013-204. 1306 1248 Quarry, Lyons, CO, Ph.D. thesis, Colorado School of Siguaw, S. G, and J. E. Estes-Jackson, 2011a, Fault Patterns in 1307 1249 Mines, Golden, Colorado, 101 p. the Niobrara Formation—Examples from the Eastern 1308 1250 Pepper, A. S., 1991, Estimating the petroleum expulsion and Central DJ Basin: AAPG Search and Discovery 1309 1251 behaviour of source rocks: A novel quantitative ap- article 10354, accessed xx xx, xxxx, http://www.search- 1310 1252 proach: Geological Society, London, Special Publications anddiscovery.com/documents/2011/10354siguaw 1311 1253 1991, v. 59, no. 1, p. 9–31, doi:10.1144/GSL.SP.1991 /ndx_siguaw.pdf. Q:521312 1254 .059.01.02. Siguaw, S. G., and J. E. Estes-Jackson, 2011b, Fault Pat- 1313 1255 Pepper, A. S., and P. J. Corvi, 1995, Simple kinetic models of terns in the Niobrara Formation—Examples from the 1314 1256 petroleum formation. Part I: Oil and gas generation from Eastern and Central Denver Basin, in J. E. Estes- 1315 1257 kerogen: Marine and Petroleum Geology, v. 12, no. 3, Jackson and D. S. Anderson, eds., Revisiting and 1316 1258 p. 291–319, doi:10.1016/0264-8172(95)98381-E. revitalizing the Niobrara in the Central Rockies: 1317 1259 Peters, K. E., 1986, Guidelines for evaluating petroleum Denver, Colorado, Rocky Mountain Association of 1318 1260 source rock using programmed pyrolysis: AAPG Bulle- Geologists,p.41–54. 1319 1261 tin, v. 70, no. 3, p. 318–329, doi:10.1306/94885688- Sonnenberg, S. A., 2011, The Niobrara petroleum system, a 1320 1262 1704-11D7-8645000102C1865D. major tight resource play in the Rocky Mountain region: 1321 1263 Peters, K. E., C. C. Walters, and M. J. Moldowan, 2005, The AAPG Search and Discovery article 10355, accessed 1322 1264 biomarker guide: Cambridge, United Kingdom, Cam- xx xx, xxxx, http://www.searchanddiscovery.com 1323 1265 bridge University Press, 1155 p. /documents/2011/10355sonnenberg/ndx_sonnenberg.pdf. Q:531324 1266 Pollastro, R. M., 2010, Natural fractures, composition, cy- Sonnenberg, S. A., and R. J. Weimer, 1993, Oil production 1325 1267 clicity, and diagenesis of the Upper Cretaceous Niobrara from Niobrara Formation, Silo field, Wyoming: Frac- 1326 1268 Formation, Berthoud field, Colorado: Mountain Geolo- turing associated with a possible wrench fault system: 1327 1269 gist, v. 47, no. 4, p. 135–149. Mountain Geologist, v. 30, no. 2, p. 39–54. 1328 1270 Pommer, M., and K. Milliken, 2015, Pore types and pore-size Soxhlet, F., 1879, The gravimetric determination of fatty 1329 1271 distributions across thermal maturity, Eagle Ford For- matter in milk (in German): Polytechnisches Journal, 1330 1272 mation, southern Texas: AAPG Bulletin, v. 99, no. 9, v. 232, p. 461–465. 1331 1273 p. 1713–1744, doi:10.1306/03051514151. Stainforth, J. G., and J. E. A. Reinders, 1990, Primary mi- 1332 1274 Reed, R. M., and R. G. Loucks, 2015, Low-thermal-maturity gration of hydrocarbons by diffusion through organic 1333 1275 (<0.7% VR) mudrock pore systems: Mississippian Bar- matter networks, and its effect on oil and gas generation: 1334 1276 nett Shale, Southern Fort Worth Basin: Gulf Coast Organic Geochemistry, v. 16, no. 1–3, p. 61–74, doi: 1335 1277 Association of Geological Societies, v. 4, p. 15–28. 10.1016/0146-6380(90)90026-V. 1336 1278 Rice, D. D., 1984, Occurrence of indigenous biogenic gas in Stock, A. T., R. Littke, J. Schwarzbauer, B. Horsfield, and 1337 1279 organic-rich, immature chalks of Late Cretaceous Age, C. Hartkopf-Froder,¨ 2017, Organic geochemistry and 1338 1280 Eastern Denver Basin, in J. G. Palacas, ed., Petroleum petrology of Posidonia Shale (Lower Toarcian, Western 1339

HAN ET AL. 27 1340 Europe) – The evolution from immature oil-prone to Tissot, B. P., and D. H. Welte, 1984, Petroleum formation 1363 1341 overmature dry gas-producing kerogen: International and occurrence: Heidelberg, Germany, Springer-Verlag, 1364 1342 Journal of Coal Geology, v. 176–177, p. 36–48, doi: 699 p., doi:10.1007/978-3-642-87813-8. 1365 1343 10.1016/j.coal.2017.04.016. US Energy Information Administration, 2017, Drilling pro- 1366 1344 Sykes, R., and L. R. Snowdon, 2002, Guidelines for as- ductivity report for key tight oil and shale gas regions, 1367 1345 sessing the petroleum potential of coaly source rocks accessed xx xx, xxxx, https://www.eia.gov/petroleum 1368 1346 using Rock-Eval pyrolysis: Organic Geochemistry, /drilling/pdf/dpr-full.pdf. Q:54 1369 1347 v. 33, no. 12, p. 1441–1455, doi:10.1016/S0146-6380 Welker, C., L. Stright, and T. Anderson, 2013, Geologic con- 1370 1348 (02)00183-3. trols on oil production from the Niobrara Formation, Silo 1371 1349 Tanck, G. S., 1997, Distribution and origin of organic carbon field, Laramie County, Wyoming: Unconventional Re- 1372 1350 in the Upper Cretaceous Niobrara Formation and Sharon sources Technology Conference, Denver, Colorado, August 1373 1351 Springs Member of the Pierre Shale, Western Interior, 12–14, 2013, p. 146–153, doi:10.1190/URTEC2013-016. 1374 1352 United States, Ph.D. thesis, The University of Arizona, Wirth, R., 2004, Focused ion beam (FIB): A novel technology 1375 1353 Tucson, Arizona, 430 p. for advanced application of micro- and nanoanalysis in 1376 1354 Thul, D. J., 2012, Niobrara source rock maturity in the geosciences and applied mineralogy: European Journal of 1377 1355 Denver Basin: A Study of differential heating and tec- Mineralogy, v. 16, no. 6, p. 863–876, doi:10.1127/0935- 1378 1356 tonics on petroleum prospectivity using programmed 1221/2004/0016-0863. 1379 1357 pyrolysis, Master’s thesis, Colorado School of Mines, Wirth, R., 2009, Focused ion beam (FIB) combined with 1380 1358 Golden, Colorado, 137 p. SEM and TEM: Advanced analytical tools for studies of 1381 1359 Tissot, B. P., Y. Califet-Debyser, G. Deroo, and J. L. Oudin, chemical composition, microstructure and crystal struc- 1382 1360 1971, Origin and evolution of hydrocarbons in early ture in geomaterials on a nanometre scale: Chemical 1383 1361 Toarcian shales, Paris Basin, France: AAPG Bulletin, Geology, v. 261, no. 3–4, p. 217–229, doi:10.1016 1384 1362 v. 55, no. 12, p. 2177–2193. /j.chemgeo.2008.05.019. 1385

28 Factors Controlling Source and Reservoir Characteristics in the Niobrara Play