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Light hydrocarbon geochemistry: insight into oils/condensates families and inferred source rocks of the Woodford–Mississippian tight oil play in North-Central Oklahoma, USA

Light hydrocarbon geochemistry: insight into oils/condensates families and inferred source rocks... The Woodford–Mississippian “Commingled Production” is a prolific unconventional hydrocarbon play in Oklahoma, USA. The tight reservoirs feature variations in produced fluid chemistry usually explained by different possible source rocks. Such chemical variations are regularly obtained from bulk, molecular, and isotopic characteristics. In this study, we present a new geochemical investigation of gasoline range hydrocarbons, biomarkers, and diamondoids in oils from Mississippian carbonate and Woodford Shale. A set of oil/condensate samples were examined using high-performance gas chromatography and mass spectrometry. The result of the condensates from the Anadarko Basin shows a distinct geochemical fingerprint reflected in light hydrocarbon characterized by heptane star diagrams, convinced by biomarker characteristics and diaman- tane isomeric distributions. Two possible source rocks were identified, the Woodford Shale and Mississippian mudrocks, with a variable degree of mixing. Thermal maturity based on light hydrocarbon parameters indicates that condensates from the Anadarko Basin are of the highest maturity, followed by “Old” Woodford-sourced oils and central Oklahoma tight oils. These geochemical parameters shed light on petroleum migration within Devonian–Mississippian petroleum systems and mitigate geological risk in exploring and developing petroleum reservoirs. Keywords Tight oil · Tight condensate · Woodford Shale · Mississippian limestone · Light hydrocarbon geochemistry · Anadarko Basin 1 Introduction the Woodford produces wet gas and condensates. The oil has been commingled produced from the Woodford/Mississip- Woodford Shale has not only been proven to be an excel- pian strata since 2010 on the Anadarko Shelf and Cherokee lent source rock charging conventional reservoirs in Kansas Platform. Many studies suggest that the Woodford Shale and Oklahoma (Comer and Hinch 1987; Burruss and Hatch accounts for more than 85% of commercial oil produced 1989; Philp et al. 1989; Jones and Philp 1990; Comer 1992; from conventional reservoirs in Oklahoma and Kansas Wang and Philp 1997), but also a frontier for unconventional (Welte et al. 1975; Lewan et al. 1979; Reber 1988; Burruss resource play exploration and production. In areas straddling and Hatch 1989), but few publications have shown strong between the basin and shelf, like the Cana-Woodford Play, evidence to prove the oils were actually sourced from the Woodford Shale. Comer and Hinch (1987) recognized expul- sion, or primary migration, of oil from the Woodford Shale Edited by Jie Hao in Oklahoma by identifying numerous small-scale accu- * You-Jun Tang mulations of bitumen within mature parts of the Woodford tyj@yangtzeu.edu.cn Shale, including fractures, stylolites, burrows, nodules, and 1 sandstone lenses, all of which are completely enclosed in Key Laboratory of Exploration Technologies for Oil and Gas the source rock. Additional evidence to prove the Woodford Resources (Yangtze University), Ministry of Education, Wuhan 430100, Hubei, China Shale has generated oil in situ has been described in Car- dott (2014a, b), where extracts found in the surface fractures School of Geology and Geophysics, University of Oklahoma, Norman, OK 73019, USA of the Woodford outcrop in the McAlister cemetery quarry and in the Criner Hills were shown to be low-maturity “oil” Devon Energy Corporation, Oklahoma City, OK 73102, USA Vol:.(1234567890) 1 3 Petroleum Science (2020) 17:582–597 583 (rock extract ll fi ed in the fractures) originating from the local was the depocenter for the Oklahoma Basin and the precur- Woodford Shale. Oil samples produced from multiple con- sor of the Anadarko Basin (Johnson 1989; Northcutt et al. ventional reservoirs of different ages and extracts of possible 2001). From Silurian to Middle Devonian clean-washed source rocks indicated that most of the oils were primarily skeletal limestones, argillaceous, and silty carbonates, derived from the Woodford Shale in the Anadarko Basin referred to as the Hunton Group in Oklahoma, were depos- (Jones and Philp 1990). Burruss and Hatch (1989) undertook ited in a shallow marine setting (Northcutt et  al. 2001). a detailed geochemical investigation of 104 crude oils and Epeirogenic Uplifts interrupted deposition resulting in two 190 core samples of dark-colored shales from the Anadarko regional unconformities. In southern Oklahoma, the pre- Basin. They identified three oil end members, which gener - Woodford–Chattanooga unconformity eroded to the Upper ally correlated with the reservoir and source rock age. One Ordovician and in northern Oklahoma the erosion sculpted oil shared the stable carbon isotope signature and biomarker out Upper Cambrian–Lower Ordovician rocks (Kirkland fingerprints of the Woodford extracts, indicating that it was et al. 1992; Fig. 1b). The Nemaha Uplift is a buried range possibly derived from the Woodford Shale in the deep Ana- of the Ancestral Rocky Mountains associated with a granite darko Basin (Burruss and Hatch 1989). high in the pre-Cambrian basement that extends approxi- An important factor affecting hydrocarbon richness in mately from Nebraska to Central Oklahoma (Gerhard 2004). Woodford–Mississippian tight play is associated with source The major deformation of the Nemaha Uplift took place in rock heterogeneity. The Woodford Shale is an organic-rich pre-Desmoinesian and post-Mississippian time (Lee 1943; source of hydrocarbon that charged Woodford–Mississip- Merriam 1963; Gerhard 2004). The Cherokee platform pian tight reservoirs, together with Mississippian mudrocks could be considered as part of the stable shelf area of the such as Caney Shale (Al Atwah et al. 2015, 2017). Typi- Arkoma Basin throughout most of the Woodford deposition cally, identifying petroleum source rock could be achieved (Campbell and Northcutt 2001). In the Late Devonian, the by using a collection of geochemical tools such as molecular Cherokee Platform was a broad shelf separated from the and isotopic fingerprints, which include biomarkers together proto-Anadarko Basin by the paleo-Nemaha Ridge (North- with stable carbon isotopes of saturate and aromatic hydro- cutt and Campbell 1996; Campbell and Northcutt 2001). carbon fractions (Al Atwah et al. 2017; Wang and Philp The Late Devonian to Early Mississippian age Wood- 1997). Currently, light hydrocarbon markers remain underu- ford Shale is an organic-rich black shale widely distributed tilized in crude oil recovered from Woodford–Mississippian over most of Oklahoma including the Anadarko Basin, the tight reservoirs. Oil–oil correlations, together with hydro- Anadarko Shelf, Cherokee Platform, and the Arkoma Basin carbon migration and maturity assessment, can be further (Comer and Hinch 1987; Comer 1992). On the Cherokee refined by utilizing the light hydrocarbon markers. Light Platform, the Woodford Shale was deposited on a major hydrocarbon geochemistry is an effective tool for refining regional unconformity developed during the Late Devonian petroleum systems especially with processes related to petro- (Amsden 1975). It is conformably overlain by limestone and leum migration and accumulation (Hu et al. 1990; Dai 1993; shale of Early Mississippian Age (Fig. 2). The predominant Hao et al. 1991; Zhang and Lin 1994; Lin and Wilk 1995). lithology of the Woodford Shale is black shale along with Here, we present new geochemical data of light hydrocar- other common lithologies including chert, siltstone, sand- bons produced from Woodford–Mississippian tight reser- stone, dolostone, and light-colored shale (Amsden 1967; voirs across the Anadarko Basin in Oklahoma. Data sug- Amsden 1975; Comer 1992). The Woodford Shale in Okla- gest different sources of hydrocarbons, with various thermal homa is a typical marine clay-rich siliciclastic shale based maturity stages. Moreover, these data shed light into factors on three key characteristics found from previous studies: (1) affecting petroleum accumulation in Woodford–Mississip- marine non-calcareous siliceous mudstone (Amsden 1975; pian tight reservoirs such as water-washing and petroleum Kirkland et al. 1992; Comer 2008; Kvale and Bynum 2014); mixing. (2) low-to-moderate sulfur content (Jarvie et al. 2007); and (3) high clay mineral content (Kirkland et al. 1992; Comer 2008; Kvale and Bynum 2014). 2 Geological settings In the early Paleozoic time, three major tectonic/depositional 3 Samples and methods provinces existed in Oklahoma: the Oklahoma Basin, the southern Oklahoma Aulacogen, and the Ouachita Trough. 3.1 Study area and sampling The Oklahoma Basin was a shelf-like area that received widespread and thick shallow marine carbonates interbed- The study area extends across two major Woodford resource ded with thin marine shales and sandstones (Johnson 1989; plays, namely Anadarko-Woodford and Nemaha-Woodford Northcutt et al. 2001). The southern Oklahoma Aulacogen (Fig. 1a). Areal coverage includes Dewey, Blaine, Canadian, 1 3 Nemaha Uplift Anadarko Basin (deep) Wichita Mts Anad. Basin 584 Petroleum Science (2020) 17:582–597 99°0′0″ 98°0′0″ 97°0′0″ (a) Woods Osage Garfield Noble Pawnee Woodward Major Tulsa Pane Ellis Anadarko Shelf 36°0′0″ 36°0′0″ Dewey Kingfisher Logan Creek Blaine Cherokee Platform Roger mills Anadarko Basin Lincoln Okmulgee Custer Oklahoma Canadian Okfuskee Beckham Washita Pottawatomie Cleveland Seminole Caddo Hughes 35°0′0″ Grady Mcclain 35°0′0″ Pittsburg Pontotoc Garvin Coal 50 km Stephens Murra Johnston Carter Cotton Atoka 99°0′0″ 98°0′0″ 97°0′0″ Anadarko Basin condensates Cherokee Platform tight oils “Old” WDFD-sourced oils (b) A B Wichita Anadarko Basin Mtns. Sea Sea Level Level Woodford shale 10,000’ 10,000’ 3,000 m 3,000 m 20,000’ 50 100 miles 6,000 m 100 km 0 80 30,000’ 9,000 m 40,000’ 12,000 m Major Lithologies Conglomerate (“granite wash”) Sandstone and shale Black shale Salt, anhydrite, and shale Limestone and dolomite Rhyolite granite and gabbro Shale, limestone, and sandstone Granite and rhyolite Fig. 1 a Map showing the location of examined crude oil samples relative to major geological features and hydrocarbon plays in Oklahoma; the dotted line marks the borders of the Anadarko Basin. b NE-SW structural cross section across the Anadarko Basin (Johnson 1989) (modified from Johnson 1989) 1 3 Pennsylvanian Mississippian Precambrian Sil.-Dev. Late Cambrian-Oradovician Early-Middle Cambrian Cim.A. Nemaha Uplift Petroleum Science (2020) 17:582–597 585 the separator in 240 ml borosilicate glass bottles and tightly System Unit sealed with a PTFE-lined cap. Table 1 lists the 24 crude oil and 5 condensate samples with key bulk characteristics in this study. An aliquot of the crude oil/condensate sample Permian Leonardian was dissolved in hexane to precipitate asphaltenes; dissolved Wolfcampian hydrocarbons in hexane were further fractionated using sil- ica gel column chromatography into saturate, aromatic, and Virgilian resin fractions. All samples are produced from horizontal Missourian wells that have been stimulated with hydraulic fracturing Pennsylvanian Desmoinesian except for the 8 “Old” Woodford-sourced oils (Group-3); therefore, the horizontal targets listed in Table 1 represent Atokan the landing zone of the horizontal well and not necessar- Morrowan ily the source of the produced oils. Eight “Old” Woodford- Chesterian sourced oil samples (Group-3), previously produced from Meramecian vertical wells into conventional reservoirs in Southern Mississippian Oklahoma and stored in Dr. Philp’s laboratory (University Ossgean L of Oklahoma), were also included in the study for compara- Kinderhookian tive purposes. Woodford - Chattanooga Devonian 3.2 Whole oil gas chromatography Misener For whole oil GC analysis, the crude oil sample was diluted Silurian into a 1 mg/ml n-hexane solution and analyzed on an Agilent Sylvan L Hunton 6890 series gas chromatograph with a split/splitless capil- Shale Group lary injection system and a 100 m × 0.25 mm (i.d.) J&W Viola Ls. Scientific DB-Petro 122-10A6 fused silica capillary column Prdovician coated with a 0.5 µm liquid film. The temperature program Simpson Group started with an initial temperature of 40 °C and 1.5 min hold Arbuckle Group time and increased to 130 °C at a rate of 2 °C per minute and Timbered Hills Gp. - Reagan Ss. subsequently increased to 300 °C at a rate of 4 °C per minute Cambrian M followed by an isothermal period of 26 min for a total run of 115 min. C light hydrocarbon analysis was performed using L 7 the GC data obtained from whole oil/condensates GC analy- sis stated above. The isolated fractions, saturates, and aro- Precambrian Undifferentiated matics, respectively, were analyzed using an Agilent 6890 series gas chromatograph with a splitless capillary injector and a 30 m × 0.25 mm (i.d.) J&W Scientific DB-5 122-5032 fused silica capillary column coated with a 0.25 µm liquid Fig. 2 Stratigraphic chart for the Cherokee Platform, North-Central film. The injector was set up in the splitless injection mode, Oklahoma (Charpentier 2001) and the temperature was held at 300 °C. The carrier gas was helium (He) with a flow rate of 1.4 ml/min. The temperature Garfield, Logan, and Payne counties. From a geological per - program started with an initial temperature of 40 °C held for spective, all counties are located within the Anadarko Basin 1.5 min and increased to 300 °C at a rate of 4 °C per minute except for Garfield, Logan, and Payne counties which are followed by an isothermal period of 34 min for a total run part of the shallow Cherokee Platform. The Nemaha Uplift time of 100.5 min. The flame ionization detector (FID) tem- is a major structural feature dividing the Cherokee Platform perature was set at 310 °C. n-Alkanes and isoprenoids were from the Anadarko Basin province. identified in each chromatogram by comparing their relative Crude oil/condensate samples were collected from Mis- retention times with standards. sissippian reservoirs, as well as the Woodford Shale strata. A generalized stratigraphic column of the Anadarko Basin 3.3 Gas chromatography–mass spectrometry is shown in Fig. 2, and major source rocks and all examined crude oils are produced from Devonian–Mississippian petro- The GC–MS analyses of the branched and cyclic alkanes leum systems. Well-head fluid samples were collected at (B&C) and aromatic fractions were performed on an 1 3 586 Petroleum Science (2020) 17:582–597 Table 1 Bulk compositional and physical characteristics of examined crude oil/condensate samples + + + + Sample Reservoir API %SAT %ARO %NSO %ASP Type Group-1Horizontal targets Lingo 1-13 H Woodford Shale 48.92 7.1 1.2 0.5 91.2 Condensates Crystal 1-28H Woodford Shale 47.98 65.0 26.6 7.8 0.6 Condensates York 1-2H Woodford Shale 48.56 91.9 6.2 1.1 0.8 Condensates Wion 1-29H Woodford Shale 49.23 85.2 3.5 10.5 0.8 Condensates Bros 1-18H Woodford Shale 49.39 96.5 1.1 1.7 0.7 Condensates Group-2Horizontal targets Johnson 1-33H Woodford Shale 36.21 90.9 3.5 0.1 5.5 Medium Oil Matthews 1-33H Mississippian “Lime” 37.93 81.3 10.6 3.1 5.0 Medium Oil Wilma 1-16H Woodford Shale 38.55 85.1 9.4 2.1 3.4 Medium Oil Elinore 1-18H Mississippian “Lime” 33.53 76.0 13.7 4.9 5.5 Medium Oil Elinore 1-17H Woodford Shale 38.21 68.5 16.7 3.6 11.2 Medium Oil Winney 1-8H Mississippian “Lime” 28.11 54.4 9.3 2.0 34.3 Black Oil Adkisson 1-33H Mississippian “Lime” 38.45 84.1 13.1 0.2 2.6 Medium Oil Winney 1-5H Woodford Shale 38.25 79.7 15.0 4.2 1.1 Medium Oil Smith 1-14WH Woodford Shale 34.22 88.3 7.0 0.2 4.5 Medium Oil Smith 1-23MH Mississippian “Lime” 32.55 78.0 9.1 2.0 10.9 Medium Oil Hopfer 1-20WH Woodford Shale 33.45 83.0 9.5 5.7 1.9 Medium Oil Peach 1-20WH Woodford Shale 35.58 86.6 8.7 3.5 1.3 Medium Oil Joyce 1-32H Woodford Shale 33.71 72.9 17.5 6.5 3.2 Medium Oil Williams 1-24WH Woodford Shale 36.63 85.3 7.6 5.6 1.5 Medium Oil Peach 1-19H Mississippian “Lime” 35.88 81.1 14.0 2.9 2.0 Medium Oil C. Matthews 1-8WH Woodford Shale 37.74 83.7 8.3 5.2 2.8 Medium Oil ** Group-3Conventional reservoir Ford-1 N.A. 28.1 83.6 15.1 1.3 0.0 Black Oil Thomas James 1-22 Pennsylvanian sandstone 27.13 75.9 9.5 2.6 12.1 Black Oil Anadarko Taylor 2118 N.A. 48.98 92.2 7.8 0.0 0.0 Light Oil “A” N.A. 36.55 83.5 10.9 2.9 2.7 Medium Oil Ellis Lewis Jet Viola limestone 37.93 87.5 7.2 2.4 2.9 Medium Oil ST Mary N.A. 49.49 99.0 1.0 N.D. N.D. Light Oil “F” N.A. 27.9 66.1 8.7 3.7 21.5 Black Oil 7-5 N-5E N.A. 22.1 73.7 9.9 3.7 12.7 Black Oil *Horizontal targets indicate the landing zone of the horizontal well, and not necessarily the actual source of the oil. +SAT: weight percentage of saturate hydrocarbons; ARO: weight percentage of aromatic hydrocarbons; POL: weight percentage of polar resin compounds (NSO); ASP: weight percentage of asphaltenes; N.A. denotes not available Agilent 7890A gas chromatography system coupled with were determined from fragmentograms corresponding to an Agilent Technologies 5975C mass selective detec- each ion using relative retention times and by comparison tor (MSD) using single ion monitoring. The GC used a with published data. 60 m × 0.25 mm Agilent/J&W Scientific DB-5 122-5562 For diamondoids analysis in crude oils/condensates, the fused silica capillary column coated with a 0.25 µm liquid sample was diluted with pentane in the concentration of film. The injected volume of branched and cyclic and aro- 16 mg oil/ml pentane. The pentane was reported to be a matic fractions was 1 µl per run. The injector temperature good solvent for adamantanes and diamantanes in terms of was set at 300 °C. The GC temperature program started at high solubility and low boiling point (Reiser et al. 1996). 40 °C with 1.5 min hold time and was later increased to The oil solution was well homogenized in ultrasonic bath 300 °C at a rate of 4 °C per minute and then held constant for at least 1  min. 1  µl of the resulting oil solution was for 34 min for a total run time of 100.5 min. Samples were injected to Agilent GC–MS to detect adamantanes and run in splitless mode, and helium was used as the carrier diamantanes using SIM mode and key ion fragments: 135, gas at a flow rate of 1.4 ml/min. Biomarker compounds 136, 149, etc., and 188, 187, 201, etc., respectively. DB-5 1 3 Petroleum Science (2020) 17:582–597 587 MS 60 m × 0.25 mm × 0.25 micron in film thickness was fingerprint is unique to the condensates (Group-1) from the used. Temperature program started at 40 °C and hold it for Anadarko Basin compared to other oil groups (Figs. 3, 4). 1.5 min before ramping 4 °C/min to 300 °C, and then held Group-2 oils located in Cherokee Platform, Central Okla- this temperature for 34 min. Compound ratios were calcu- homa, showed a narrow OCSD pattern, with significant lated directly from peak areas or peak heights of targeted enrichment in 3-ethylpentane (Table 2). Group-3 oils dis- markers and compared with internal standards. played more subtle variability where some oils are enriched in 3,3-dimethylpentane and relatively lower in 2,4-dimethyl- pentane isomer, while other oils display the opposite trend. 4 Results and discussion The observed variation of star diagram fingerprints across crude oil groups is a function of source rock inher- 4.1 Bulk geochemical parameters ent variation and evaporative fractionation. Mango (1987) reported that light hydrocarbons in crude oil are formed via Crude oils exhibit slight differences in bulk parameters that metal-catalyzed steady-state kinetic reaction of the kerogen. are consistent with the type of fluid, in which the majority of Moreover, it was observed that while the absolute concen- the samples are classified as medium oil. Key bulk param- tration of light hydrocarbons from the same source varied eters of the crude oils are listed in Table 1, including fluid by orders of magnitude, certain ratios of light hydrocar- type, API gravity, and SARA (short for saturates, aromatics, bons kept constant, such as the sum of 2-methylhexane and resin and asphaltene) component classes. API gravity values 2,3-dimethylpentane relative to the sum of 3-methylhexane ranged from 22.1 to 49.49, as reflected in the fluid type, in and 2,4-dimethylpentane (K1) (Mango 1987). To explain which lower API values are associated with heavier black the invariance of the C -C hydrocarbons, Mango (1987) 6 7 oils and higher API values from light oils. All of the oil postulated that light hydrocarbons originate from a higher samples are dominated by saturate hydrocarbons compared saturated hydrocarbon and the presence of metal catalysts to aromatic, resin, and asphaltenes. Heavier crude oils, such will result in a similar reaction rate for homologous series. as Winney 1-8H, were higher in asphaltene content relative OCSD parameters are based on branched C alkanes; there- to the rest of the oil samples. The crude oil bulk character- fore, those ratios would keep constant observed by Mango istic is a useful descriptive source of data with some inher- (1987). In examined crude oils, the variations in OCSD fin- ent limits. The dominance of the saturated hydrocarbon is gerprints between Group-1 and Group-2 are clearly indicat- reasonable to be found in thermogenic hydrocarbon expelled ing two different sources of hydrocarbons (Fig.  4), whereas from petroleum source rocks. Such enrichment in saturated Group-3 presumably is a mix of the two end members or hydrocarbons is usually observed in naturally produced from a third source. Within the Anadarko Basin, a number crude oil (Lewan et al. 2006). However, the source rock of of source rocks have been studied ranging in age from Cam- petroleum cannot be determined solely from bulk param- brian to Pennsylvanian (Al Atwah et al. 2017; Wang and eters; therefore, characteristics of molecular fingerprints Philp 1997). Observations from light hydrocarbon source discussed below can aid to identify hydrocarbon sources. parameters are discussed in the biomarker section below. 4.2 Light hydrocarbon analysis4.2.2 Alteration assessment 4.2.1 Source parameters The oil transformation star diagrams (OTSD), a multivari- ate plot in polar coordinates developed by Halpern based Heptane (C ) variability reflected the geographic loca- on different ratios of C -C hydrocarbons to character- 7 4 7 tion among the three distinct oil groups. Table 2 lists the ize secondary alterations of crude oils (Halpern 1995), ratios used for constructing the oil correlation star dia- are illustrated in Fig. 4 with ratios used to construct the gram (OCSD) and oil transformation star diagram (OTSD) diagrams listed in Table 2. Although light hydrocarbons (Halpern 1995). Group-1 samples located within the Ana- are controlled by the organic matter source, secondary darko Basin exhibited a unique fingerprint of the C OCSD alterations can affect light hydrocarbon distribution (i.e., (Figs.  3, 4). Specifically, these oils are enriched in the biodegradation, water-washing, thermal maturity, and 3,3-dimethylpentane isomer relative to the rest of heptane evaporation). In all the oil samples, lowest ratio values isomers. Similarly, enrichment in 2,2-dimethylpentane and are observed at TR-6 ranging from 0.01 to 1.09 (Table 2), 2,4-dimethylpentane is observed within tight oils located with Group-1 samples exhibiting the highest TR-1 values on the Cherokee Platform (Group-2). Additionally, Group-1 compared to the other two groups. Overall, Group-1 and condensates varied the most for 2,2-dimethylpentane, fol- Group-3 showed a relatively similar OTSD pattern maxi- lowed by 3,3-dimethylpentane isomers (Figs. 3, 4). How- mizing at TR-4 followed by TR-3, whereas Group-2 high- ever, even with those variations, the overall star diagram est ratio coexists at TR-7 and TR-8 followed by TR-6. The 1 3 588 Petroleum Science (2020) 17:582–597 1 3 Table 2 Key light hydrocarbon ratios of crude oil samples sensitive to source, transformation, and maturity Sample Oil correlation parameters Oil transformation ratio Maturity 2,3-DMP 2,2-DMP EtCP/P 3,3-DMP 2,4-DMP TR-1 TR-2 TR-3 TR-4 TR-5 TR-6 TR-7 TR-8 C ratio iso-C ratio 7 7 Group-1  Lingo 1-13 H 1.1 0.2 0.8 0.2 0.6 7.7 38.6 16.7 15.3 32.0 0.1 1.3 5.3 37.3 8.4  Crystal 1-28H 0.9 0.2 0.8 0.3 0.5 18.1 23.6 8.9 8.3 17.2 0.1 1.1 4.5 31.7 6.1  York 1-2H 1.1 0.2 0.9 0.3 0.6 5.5 18.6 7.0 6.1 13.1 0.1 1.3 4.7 33.0 4.5  Wion 1-29H 0.7 0.3 0.6 0.3 0.4 25.5 27.5 11.2 11.2 22.4 0.1 1.1 4.1 32.4 8.0  Bros 1-18H 1.3 0.2 1.0 0.2 0.6 4.8 23.1 8.7 7.3 16.0 0.1 1.4 5.2 36.0 4.7 Group-2  Johnson 1-33H 3.5 0.1 3.1 0.0 0.9 3.2 13.1 5.0 3.1 8.1 0.5 2.9 4.1 26.9 0.8  Matthews 1-33H 2.8 0.1 2.3 0.1 0.8 3.0 12.7 4.9 3.1 8.0 0.5 2.8 3.9 26.7 0.8  Wilma 1-16H 2.5 0.1 2.3 0.2 0.7 4.2 15.8 5.2 3.5 8.7 0.5 2.8 3.9 30.1 0.9  Elinore 1-18H 3.0 0.1 4.1 0.2 0.8 2.8 16.7 6.7 3.9 10.7 1.0 4.4 4.0 26.7 0.6  Elinore 1-17H 3.5 0.1 5.0 0.0 0.9 2.2 16.4 6.6 3.8 10.5 1.1 4.6 4.1 29.6 0.6  Winney 1-8H 3.5 0.1 3.7 0.0 0.9 3.5 14.4 5.5 3.3 8.9 0.7 3.3 4.1 27.4 0.7  Adkisson 1-33H 3.4 0.2 3.3 0.0 0.8 3.9 12.0 4.4 2.7 7.1 0.6 2.9 3.9 25.9 0.7  Winney 1-5H 3.0 0.1 3.0 0.2 0.7 3.1 13.0 5.1 3.1 8.3 0.7 3.2 3.8 26.2 0.7  Smith 1-14WH 2.3 0.1 1.7 0.2 0.7 3.8 14.8 5.4 3.7 9.1 0.4 2.4 3.8 29.2 1.1  Smith 1-23MH 2.8 0.1 2.7 0.2 0.7 4.5 15.1 5.0 3.2 8.2 0.5 2.6 3.8 29.8 0.9 Group-3  Ford-1 2.4 0.1 3.6 0.2 0.7 7.6 32.7 11.8 7.6 19.3 1.1 4.8 4.5 33.3 1.1  Thomas James 1–22 3.6 0.0 3.9 0.0 1.0 4.4 26.0 9.3 6.4 15.7 0.5 3.3 5.2 34.7 1.4  Anadarko Taylor 2118 2.2 0.1 2.1 0.2 0.7 6.8 42.7 15.5 11.1 26.6 0.5 3.5 5.0 39.3 2.5  “A” 3.4 0.1 3.9 0.1 0.8 2.4 13.0 4.8 2.9 7.7 0.7 3.0 3.7 27.1 0.7  Ellis Lewis Jet 2.4 0.1 2.8 0.2 0.7 5.3 31.1 10.6 7.2 17.8 0.6 3.5 4.8 37.2 1.5  ST Mary 2.0 0.2 2.2 0.3 0.5 16.3 53.8 17.6 14.2 31.8 0.0 2.8 5.5 40.9 4.7 “F” 4.9 0.0 6.1 0.0 1.0 4.7 14.3 5.1 3.0 8.2 0.7 3.1 4.1 27.9 0.7 P1: 2,2-dimethylpentane + 2,3-dimethylpentane + 2,4-dimethylpentane + 3,3-dimethylpentane + 3-ethylpentane; 2,2-DMP: 2,2-dimethylpentane/P1; 2,3-DMP: 2,3-dimethylpentane/P1; 2,4- DMP: 2,4-dimethylpentane/P1; 3,3-DMP: 3,3-dimethylpentane/P1; EtP: 3-ethylpentane/P1; X: 1,1-dimethylcyclopentane; P2: 2-methylhexane + 3-methylhexane; TR1: toluene/X; TR2: n C /X; TR3: 3-methylhexane/X; TR4: 2-methylhexane/X; TR5: P2/X; TR6: 1-cis-2-dimethylcyclopentane/X; TR7: 1-trans-3-dimethylcyclopentane/X; TR8: P1/P2; C ratio: 100*n-heptane/cyclohex- ane + 2-methylhexane + 1,1-dimethylcyclopentane (DMCP) + 3-methylhexane + 1-cis-3-DMCP + 1-trans-3DMCP + 1-trans-2-DMCP + n-heptane + methylcyclohexane; iso-C ratio: 2-methyl- hexane + 3-methylhexane/1-cis-3-DMCP + 1-trans-3DMCP + 1-trans-2-DMCP Petroleum Science (2020) 17:582–597 589 Group-1 Lingo1-13H Condensate Peak # Compound Abbreviation 1 n-Hexane n-C 2 2,2-Dimethylpentane 2,2-DMP 3Methylcyclopentane MCP 4 2,4-Dimethylpentane 2,4-DMP 5 Benzene 3,3-DMP 6 3,3-Dimethylpentane B 7 Cyclohexane CH 8 2,3-Dimethylpentane 2,3-DMP 9 2-Methylhexane 2-MH 10 1,1-Dimethylcyclopentane 1,1-DMCP 11 3-Methylhexane 3-MH 12 Cis-1,3-Dimethylcyclopentane C1,3-DMCP Group-2 Winney 1-8H Oil 13 Trans-1,3-Dimethylcyclopentane T1,3-DMCP 14 Trans-1,2-Dimethylcyclopentane T1,2-DMCP 15 3-Ethylpentane 3-EP 16 2,2,4-Trimethylpentane 2,2,4-TMP 17 n-Heptane n-C 18 2,2-Dimethylhexane 2,2-DMH 19 Cis-1,2-Dimethylcyclopentane C1,2-DMCP 20 Methylcyclohexane MCH 21 Ethylcyclopentane ECP 22 2,5-Dimethylhexane 2,5-DMH 23 2,4-Dimethylhexane 2,4-DMH Group-3 Ford-1 Oil 24 1,2,4-Trimethylcyclopentane 1,2,4-TMCP 25 1,2,3-Trimethylcyclopentane 1,2,3-TMCP 26 2,3,4-Trimethylpentane 2,3,4-TMP 27 2,3,3-Trimethylpentane 2,3,3-TMP 28 Toluene Tol 29 Isooctane i-C8 30 n-Pentane n-C5 31 2,2-Dimethylbutane 2,2-DMB 32 2,3-Dimethylbutane 2,3-DMB 33 2-methylpentane 2-MP 34 3-methylpentane 3-MP Fig. 3 Gas chromatogram (C light hydrocarbon range) of typical sample of different groups (compounds identified in the table above) apparent depletion in TR-1 in the oil samples is related from the high values of the transformation values rang- to the effect of water-washing, which is characterized ing from TR-2 to TR-8 (Table 2). In the Anadarko Basin, by using the ratio of toluene relative to 1,1-dimethylcy- variation in toluene abundance has been observed with a clopentane. (Toluene is more water-soluble; therefore, uniquely decreasing trend moving away from the basin a decreasing trend in TR-1 indicated water-washing depocenter toward the shallower shelf area. The low (Mango 1997.) From OTSD, it is clear that water-wash- molecular weight aromatic hydrocarbons, benzene and ing effects occurred, but at different magnitudes, Group-2 toluene, are the most water-soluble components in crude was severely water-washed, while Group-1 and Group-3 oils (Price 1976). As oils migrate farther, they contact were relatively slightly washed. No crude oil exhibited progressively larger amounts of formation water into any evidence of microbial biodegradation as observed which the water-soluble components will partition. There 1 3 12+13+14 21+23 24+25 28 590 Petroleum Science (2020) 17:582–597 OCSD OTSD [5.00] Group-1 [30] 2,3-DMP TR1 [8] [60] TR8 TR2 [1.00] 2,4-DMP 2,2-DMP [0.25] [10] TR7 [20] TR3 [3] [18] TR6 TR4 [0.35] [6.00] 3,3-DMP EtP [40] TR5 Group-2 [30] TR1 [5.00] 2,3-DMP [8] [60] TR8 TR2 [1.00] 2,4-DMP 2,2-DMP [10] TR7 [20] [0.25] TR3 [3] [18] TR6 TR4 [40] [0.35] [6.00] TR5 3,3-DMP EtP Group-3 [30] TR1 [5.00] 2,3-DMP [8] [60] TR8 TR2 [1.00] 2,4-DMP 2,2-DMP [0.25] [10] TR7 [20] TR3 [3] [18] TR6 TR4 [0.35] [6.00] 3,3-DMP EtP [40] TR5 Fig. 4 Oil correlation star diagrams (OCSD) (left) and oil transformation star diagrams (OTSD) (right). P1: 2,2-dimethylpentane + 2,3 dimeth- ylpentane + 2,4-dimethylpentane + 3,3-dimethylpentane + 3-ethylpentane. 2,2-DMP: 2,2-dimethylpentane/P1; 2,3-DMP: 2,3-dimethylpen- tane/P1; 2,4-DMP: 2,4-dimethylpentane/P1; 3,3-DMP: 3,3-dimethylpentane/P1; EtP: 3-ethylpentane/P1; X: 1,1-dimethylcyclopentane; P2: 2-methylhexane + 3-methylhexane; TR1: toluene/X; TR2: n C7/X; TR3: 3-methylhexane/X; TR4: 2-methylhexane/X; TR5: P2/X; TR6: 1-cis-2-dimethylcyclopentane/X; TR7: 1-trans-3-dimethylcyclopentane/X; TR8: P1/P2; C7 ratio: 100*n-heptane/cyclohexane + 2-methylhex- ane + 1,1-dimethylcyclopentane (DMCP) + 3-methylhexane + 1-cis-3-DMCP + 1-trans-3DMCP + 1-trans-2-DMCP + n-heptane + methylcy- clohexane; iso C7 ratio: 2-methylhexane + 3-methylhexane/1-cis-3-DMCP + 1-trans-3DMCP + 1-trans-2-DMCP (Thompson 1983) is also the possibility that toluene concentration is related trend was reported to indicate long-distance migration of to thermal maturation; however, the trend of toluene con- hydrocarbons (Burruss and Hatch 1989). centration versus depth is not strong, a fact shown by the relatively low concentrations of toluene in the central, 4.2.3 Thermal maturity deep-basin oils from Silurian and Devonian reservoirs and from Pennsylvanian reservoirs. Therefore, such a Light hydrocarbons are a useful geochemical tool to evaluate thermal maturity. A number of light hydrocarbon-(C –C ) 6 7 1 3 Petroleum Science (2020) 17:582–597 591 based maturity parameters have been published in the lit- explained based on the trend of Woodford Shale thermal erature, pioneered by Hunt et  al. (1980). These authors maturity across the Anadarko Basin. Particularly, Group-1 observed that certain ratios of light hydrocarbons such as condensates are located at the eastern edge of the Anadarko 2,2-dimethylbutane/2,3-dimethylbutane tend to increase Basin, where the Woodford Shale has been reported within with increase in depth. A similar work was done by Thomp- the late oil thermal maturity stage (Cardott 1989, 2012). son who introduced the heptane ratio as a maturity param- “Old” Woodford-sourced oils (Group-3) showed the high- eter, which is calculated by the ratio of n-heptane relative est heptane ratios; however, they are located at a shallower to the sum of different heptane isomers (Thompson 1983). depth where thermal maturity is not suc ffi ient for oil genera - Thompson defined stages for maturity estimation of oils tion (lower than 0.6 VRo %), and hence, these fluids may based on heptane ratio as follows: the heptane ratio from have resulted from long-distance migration from the Ana- 18 to 22 is normal uncracked oil, 22 to 30 is classified as darko depocenter where source rocks are buried at higher mature oil, and heptane ratio > 30 is classified as superma- maturity levels (Al Atwah et al. 2017). One exception within ture (Thompson 1983). Not only heptane ration, isoheptane Group-3 oils is sample ST Mary, which exhibits the feature ratio was also introduced by Walters et al. (2003) to better of a light oil from its bulk characteristics (Table 1) while characterize maturity stage, who proposed an empirical hep- plotting within normal oils in Fig. 5. This in part could be tane ratio (H) versus isoheptane ratio (I) diagram based on due to evaporative fractionation effect caused by light hydro- the C ratios measured for oils/condensates from the North carbons partitioning from initially normal oil as a function Sea to investigate the thermal maturity of oils/condensates. of migration distance and associated rock–fluid interactions In this study, thermal maturity is accessed using a cross- within the carrier beds (Dzou and Hughes 1993; Kim and plot (Fig. 5) comparing the heptane versus isoheptane ratio Philp 2001). Low heptane ratios of Group-2 oils can be (listed in Table 2) with maturity levels according to Walters classified as normal paraffinic oil, which coincide with the et al. (2003). The heptane ratio ranged from 25.8 to 45.8, overall maturity of the Woodford Shale (0.7 to 0.8 VRo %) and isoheptane ranged from 0.6 to 8.3. Group-1 exhibited in areas east of the Nemaha Uplift. The base map of Fig. 8 the highest thermal maturity level followed by Group-3, shows the Woodford Shale maturity based on the measured whereas Group-2 was the least mature (Fig. 5). The vari- vitrinite reflectance (Cardott 1989, 2012, 2017). The over- ability of heptane ratios in the different oil groups can be all Woodford Shale maturity trend coincides with the three groups’ oil maturity stages. However, Group-1 exhibits a higher maturity level than the rocks’ maturity where they Heptane Vs. isoheptane diagram are produced. This is due to the hydrocarbon charge history (Group-1) (Group-2) (Group-3) which is discussed in the following section. Anadarko basin Cherokee platform “Old” woodford- condensates WDFD-MSSP sourced oils tight oils 4.3 Biomarkers and diamondoids analysis Biomarker and diamondoid distributions in crude oils were investigated to support gasoline-ranged hydrocarbons pre- sented earlier. Selected biomarker and diamondoid ratios 30 Supermature oils are listed in Table 3. Certain specific ratios of sterane and terpane in the examined sample exhibit a wide variation. Mature oils For example, Group-3 oils are enriched in C regular Normal oils sterane relative to C , whereas Group-1 condensates are enriched in C regular sterane relative to C , with a Reg 10 27 29 C /C ratio ranging from 0.6 to 1.4 in Group-3, whereas 27 29 Group-1 condensates range from 1.9 to 5.6. Most nota- bly, the extended tricyclic terpanes (ETT) relative to the 01.0 2.03.0 4.05.0 6.0 7.0 8.0 9.0 hopane (Hop) ratio exhibit the highest variance among the Isoheptane ratio biomarker ratios. The ETT/Hop ratio stays around 0.6 in Group-1 condensates and ranges from 0.6 to 1.3 in Group-2 Fig. 5 Cross-plot of heptane versus isoheptane ratios to assess crude oils and 0.3 to 0.7 in Group-3. The relative abundance of oil maturity from Mississippian and Woodford of the three oils selected alkyl diamantane isomers (diamondoids) is listed groups defined in Table  1. Heptane ratio: 100*n-heptane/cyclohex- ane + 2-methylhexane + 1,1-dimethylcyclopentane (DMCP) + 3-meth- in Table 3. Group-1 condensates showed a higher relative y lhe x ane + 1-cis-3-DMCP + 1-tr ans-3DMCP + 1-tr ans-2- abundance of 3,4-dimethyldiamantane, and Group-2 oils are DMCP + n-heptane + methyl cyclohexane; isoheptane ratio: slightly higher in 8,4-dimethyldiamantane, whereas Group-3 2-methylhexane +3-methylhexane/1-cis-3-DMCP + 1-trans- 3DMCP + 1-trans-2-DMCP 1 3 Heptane ratio 592 Petroleum Science (2020) 17:582–597 Table 3 Key biomarker and diamondoid ratios sensitive to organic matter type and source rock lithology Sample Biomarker parameter Diamondoids parameter RegC /RegC DiaC /RegC Hop/RegC ETT/HH C TT/Hop Rc 4,8-DMD 4,9-DMD 3,4-DMD 27 29 29 29 29 23 Group-1 Rc from MAI  Lingo 1-13 H N.D. N.D. N.D. N.D. N.D. 1.31 0.33 0.22 0.45  Crystal 1-28H 3.0 0.5 0.7 0.6 0.7 1.52 0.35 0.40 0.25  York 1-2H 5.6 0.7 0.0 N.D. N.D. 1.23 0.38 0.18 0.44  Wion 1-29H 1.9 0.5 0.9 0.0 0.2 1.75 0.35 0.27 0.38  Bros 1-18H N.D. N.D. N.D. N.D. N.D. 1.33 0.44 0.23 0.33 Group-2 Rc from MPI-1  Johnson 1-33H 1.3 0.6 0.6 1.3 0.6 0.90 0.41 0.28 0.31  Matthews 1-33H 2.2 0.5 0.7 1.5 0.7 1.12 0.49 0.24 0.27  Wilma 1-16H 2.2 0.5 0.6 1.0 0.6 0.76 0.45 0.27 0.28  Elinore 1-18H 1.0 0.4 0.6 0.5 0.4 0.83 0.52 0.23 0.25  Elinore 1-17H 1.0 0.4 0.7 0.6 0.5 0.79 0.41 0.28 0.31  Winney 1-8H 2.3 0.5 0.7 0.8 0.5 0.85 0.56 0.22 0.22  Adkisson 1-33H 1.1 0.5 0.7 0.8 0.6 0.75 0.51 0.26 0.23  Winney 1-5H 2.2 0.5 0.7 1.2 0.6 1.03 0.40 0.22 0.37  Smith 1-14WH 0.9 0.6 0.7 0.8 0.5 1.03 0.40 0.28 0.32  Smith 1-23MH 3.3 0.4 0.7 1.1 0.6 0.77 0.49 0.25 0.26 Group-3 Rc from MPI-1  Ford-1 0.8 0.4 0.6 0.4 0.4 0.74 N.D. N.D. N.D.  Thomas James 1.0 0.5 0.7 0.6 0.5 0.81 N.D. N.D. N.D. 1–22  Anadarko Taylor 1.4 0.5 0.5 1.7 0.8 0.90 0.33 0.25 0.42  “A” 1.0 0.5 0.7 0.6 0.4 0.71 N.D. N.D. N.D.  Ellis Lewis Jet 1.0 0.5 0.7 0.7 0.5 0.82 N.D. N.D. N.D.  ST Mary N.D. N.D. N.D. N.D. N.D. N.D. 0.39 0.19 0.42  “F” 1.0 0.5 0.7 0.7 0.5 0.88 N.D. N.D. N.D.  7-5N-5E 0.6 0.5 0.6 0.3 0.3 0.79 N.D. N.D. N.D. RegC /RegC : ααR C sterane/ααR C sterane; DiaC /RegC: C 13β 17α 20R diasterane/C 13β 17α dia 20R + ααR C steranes; Hop/ 29 27 27 29 29 29 29 29 29 RegC: C 17α hopane/C 17α hopane + C αα 20R stigmastane; ETT/HH: sum of extended tricyclic terpanes C to C /sum of extended 29 29 29 29 30 39 tricyclic and C 17α hopane; CTT/Hop: C tricyclic terpane/C tricyclic terpane + C 17α hopane; Rc: calculated vitrinite reflectance for 30 23 23 23 30 the studied condensates from methyl adamantane index (MAI) values; Rc: calculated vitrinite reflectance for the studied oils from methylphen- anthrane index-1 (MPI-1) values; 4,9-DMD: 4,9-dimethyldiamantane/(sum of 4,8- + 4,9- + 3,4-dimethyldiamantanes); 4,8-DMD: 4,8-dimethyl- diamantane/(sum of 4,8- + 4,9- + 3,4-dimethyldiamantanes); 3,4-DMD: 3,4-dimethyldiamantane/(sum of 4,8- + 4,9- + 3,4-dimethyldiamantanes) oils exhibit similar abundance between these two isomers with a clear homohopane mass-chromatogram trace (Fig. 7). (Fig. 6a). Hopanes are pentacyclic terpanes (Van Dorsselacer et al. Biomarker ratio variation is controlled by the source 1977) that originate from hopanoids present in prokaryotes rock inherent composition. For example, enrichment in C (bacteria and cyanobacteria) and higher plants but appear to sterane of Group-3 oils has been observed in Woodford- be absent in eukaryotic algae (Ourisson et al. 1979). Such sourced crude oil and rock extracts (Miceli Romero and an abundance of hopanes in the examined oils is consistent Philp 2012; Wang et al. 2017; 2018; Wang and Philp 2019). with previous studies, in which the abundance of hopanes C steranes (stigmastane) are derived from terrigenous is diagnostic for the Woodford Shale extracts. From the oil organic matter sources and marine algae (Volkman 1986). correlation star diagram in Fig.  4, Group-1 condensates Therefore, C sterane enrichment was previously reported reflect hydrocarbons originated from the Woodford Shale. in terrigenously derived oils; Paleozoic marine shales were Additionally, the most notable biomarker characteristic of reported to have a similar fingerprint, too (Moldowan et al. Group-2 is the abundance of extended tricyclic terpanes up 1985). Group-1 condensates show enrichment in hopane to C (Fig. 7). This is accompanied by depletion of hopane 1 3 Petroleum Science (2020) 17:582–597 593 Low-mid maturity Mixed low-mid maturity & (a) %4,9-DMD (b) (non-cracked) cracked hydrocarbons 0 100 (Group-1) Anadarko basin condensates (Group-1) (Group-2) Anadarko basin Cherokee platform (Group-2) 20 80 condensates WDFD-MSSP Cherokee platform WDFD-MSSP tight oils (Group-3) tight oils “Old” woodford- 40 60 sourced oils (Group-1) 60 “Old” woodford- sourced oils 60 40 Carbonate Shale Type II Type II Coal Type III Cracking intensity 0 5.0 10.0 15.0 20.0 020406080 100 %4,8-DMD %3,4-DMD 3- + 4-Methyl diamantanes, ppm Fig. 6 a Ternary diagram comparing the relative abundance of three different isomers of dimethyldiamantane, including 4,9-dimethyldiaman- tane, 4,8-dimethyldiamantane, and 3,4-dimethyldiamantane. Dimethyldiamantanes are measured from m/z 201 mass fragmentogram. Polygons of different source rock facies are from Schulz et al. 2001); b cross-plot for evaluating extent of cracking and oil mixing, comparing regular stig- mastane biomarker versus 3- + 4-methyldiamantanes, after Dahl et al. 1999 Peak # Compound C24D Deuterated n-tetracosane (ISTD) 1C20 Tricyclic terpane (Cheilanthane) 2C21 Tricyclic terpane (Cheilanthane) 3C Tricyclic terpane (Cheilanthane) Adkisson 1-33H Oil 22 Oil produced 4C Tricyclic terpane (Cheilanthane from MSSP 5C Tricyclic terpane (Cheilanthane) 6C Tricyclic terpanes (Cheilanthanes 22S and 22R) 9 10 7C Tetracyc licterpane 18 24 8C26 Tricyclic terpanes (Cheilanthanes 22S and 22R) 9C28 Tricyclic terpanes (Cheilanthanes 22S and 22R) 10 C29 Tricyclic terpanes (Cheilanthanes 22S and 22R) 20 11 C27 18α(H)-22,29,30-Trisnorneohopane (Ts) 22 23 24 12 C Tricyclic terpanes (Cheilanthanes 22S and 22R) 17 28 3 26 I 29 13 C 17α(H)-22,29,30-Trisnorhopane (Tm) 14 C Tricyclic terpanes (Cheilanthanes 22S and 22R) 15 C 17α(H),21β(H)-30-Norhopane (H29) 16 C29Ts 18α(H)-30-Norneohopane (29Ts) 7-5N-5E WDFD- 17 D30 15α-methyl-17α(H)-27-Norhopane (Diahopane: D30) Oil produced 18 18 C30 17α(H),21β(H)-Hopane sourced historically from WDFD 19 C33 Tricyclic terpanes (Cheilanthanes 22S and 22R) produced oil in South OK 20 C31 17α(H),21β(H)-Homohopanes (22S & 22R) 21 C Tricyclic terpanes (Cheilanthanes 22S and 22R) 22 C 17α(H),21β(H)-Bishomohopane (22S & 22R) 23 C Tricyclic terpanes (Cheilanthanes 22S and 22R) 24 C 17α(H),21β(H)-Trishomohopane (22S & 22R) 2 +13 25 C36 Tricyclic terpanes (Cheilanthanes 22S and 22R) 9 16 26 C34 17α(H),21β(H)-Tetrakishomohopane (22S & 22R) 7 27 C35 17α(H),21β(H)-Pentakishomohopane (22S & 22R) 17 G 3 28 C38 Tricyclic terpanes (Cheilanthanes 22S and 22R) 29 C Tricyclic terpanes (Cheilanthanes 22S and 22R) G Gammacerane Fig. 7 Mass chromatogram (m/z 191) showing terpane biomarker distribution in the saturate hydrocarbons comparing two end members of Mississippian-sourced (Adkisson 1-33H) and Woodford-sourced (7-5N-5E) crude oils. Note the enrichment of extended tricyclic terpanes up to C in Mississippian-sourced oil and is depleted in Woodford-sourced oil. IS internal standard and homohopane relative to tricyclic terpanes, together with Johnson 1-33H and Matthews 1-33H (Table 1). However, dominance of C regular sterane relative to the C coun- since these oils show a strong Mississippian biomarker char- 27 29 terpart (Table 3). These biomarkers signature are diagnostic acteristic and a Mississippian OCSD imprint, it is likely that of a Mississippian-sourced oil and a Mississippian-extracted the stimulated rock volume has exceeded the Woodford into bitumen (Kim and Philp 2001). Group-2 oils should have the Mississippian Formation resulting in a mixing fluid with had at least Mississippian source contribution, evidenced relatively comparable contributions from the Mississippian in the narrow star diagram fingerprint in Fig.  4. Within and Woodford sources. Group-2 samples, two oils are recovered from the hori- Diamondoids are rigid fused-ring cycloalkanes with a zontal wells landed in the Woodford Formation including diamond-like structure that shows high thermal stability 1 3 C ααR sterane, ppm Diamondoid baseline 594 Petroleum Science (2020) 17:582–597 initially (Williams et  al. 1986; Wingert 1992; Lin and ratio and buck crude oil parameters of Group-1 and Wilk 1995; Dahl et al. 2003). Diamondoids are not found Group-3 oils, whereas the former suggests highly mature in living organisms but have been demonstrated to be f luids, whereas the latter indicates black oils. synthesized from a wide variety of organic precursors via Lewis acid catalysis (Schleyer 1990; Wingert 1992). 4.4 Proposed petroleum system Considering their ubiquitous occurrence, even in oils of low thermal maturity, this mode of formation suggests Based on the results of the oil/condensates family group- diamondoids form by hydrocarbon rearrangement reac- ing, integration of the Woodford thermal maturity map, and tions on acidic clay minerals in petroleum source rocks burial and thermal history (Schmoker 1988), it is proposed (Schleyer 1990). Hence, the isomeric distribution of cer- that there are three petroleum systems in the study area tain diamondoids could be sensitive to the source rock (Fig.  8). The first is in the shallow part of the Anadarko lithology. In particular, the alkylated diamantine infers Basin (Group-1), where the averaged measured Ro value source rock facies by comparing the relative abundance of the Woodford Shale is 1.2% (Cardott 2014a, b), which is of three isomers of dimethyldiamantanes to distinguish within the Rc range determined for the condensates based different kerogen contributions (e.g., II-carbonate, type on methyl adamantine index (MAI) values. The Rc from the II marl, and type III) (Schulz et al. 2001). According to MAI values is provided in Table 3. Therefore, the Group-1 ternary plots developed for identifying source rock facies, condensates were generated in situ. The second is in the most of the Group-1 and Group-3 samples plot within Nemaha area (Group-2; Logan County and western Payne marine shale polygon, while Group-2 oils are plotted in County), where the average measured Ro value of the Wood- between marine shale and carbonates polygon (Fig. 6a). ford Shale is 0.76%, which is within the Rc range determined Such observations support biomarker and C7 star dia- for the oils based on methylphenanthrane index (MPI) val- grams, with Group-1 and Group-3 likely sourced from ues. The Rc from the MPI values is provided in Table 3. The marine shale of the Woodford Shale Formation, and oil samples in this system share significant Mississippian Group-2 a mixture of the two end members. and Woodford source signatures and appear to be mixtures Unlike biomarkers, diamondoids in crude oils and of Woodford- and Mississippian-derived oils that have prob- source rocks are structurally very different from their ably been generated in situ. The third petroleum system is in probable precursors in living organisms. Diamondoids the southern Oklahoma (Group-3; Garvin County); the Rc of are good thermal maturity indicators for high-maturity oils is 0.81% in average (Table 3). This observation suggests samples (over 1.1% Ro) when biomarker thermal matu- these oils probably migrated short distances through the cen- rity indicators already thermally destroyed. Hydrocarbon tral Oklahoma faults zone from deeper Woodford Shale in mixing and extent of cracking are usually accessed by the basin to the reservoirs. Schmoker (1988) proposed the comparing methyldiamantane versus stigmastane (C Woodford Shale in Caddo County, Canadian County, and sterane) biomarker (Dahl et al. 1999). Figure 6b shows Grady County, Oklahoma (“area 3” in Schmoker’s paper) the different oil groups and their content of methyldia- went into the oil window circa 260 Ma (late Permian). This mondoid versus stigmastane. Group-1 samples are clearly area might be the kitchen for those old Woodford-type oils, enriched in diamondoids and depleted in stigmastane which migrated via some faults or other pathways formed indicating strong extent of oil cracking, whereas Group-2 during the Ouachita–Marathon orogeny (starting from Mid- oils are depleted in diamondoids which suggest low- dle to Late Pennsylvanian until early Permian). Such type maturity stage without oil cracking yet. Group-3 oils are of migration has been previously proposed by Burruss and depleted in diamondoids and rich in stigmastane. Moreo- Hatch (1989) and Jones and Philp (1990) to suggest these ver, Group-3 oils plot at the diamondoid baseline, which oils may have migrated from the more mature parts of the has been defined from immature rock extracts. This sug- Anadarko Basin in southern Oklahoma. gests that Group-3 oils were migrated likely from source rocks in deep Anadarko Basin as the source rock was not that mature. From a petroleum systems perspective, 5 Conclusions such hydrocarbon charge trend coincides with previous studies that postulated that oils in the southern part of Light hydrocarbon geochemistry provides an effective tool Oklahoma are a result of long-distance migration from to elucidate hydrocarbon source, maturity, and secondary the depocenter of the Anadarko Basin, whereas oils east alterations within Woodford–Mississippian tight reservoirs of the Nemaha Uplift are a result of localized hydrocar- across the Anadarko Basin, Anadarko Shelf, and Cherokee bon charge with no contribution from deep Anadarko (Al Platform of North-Central Oklahoma by the following: Atwah et al. 2017; Wang and Philp 2019). Moreover, this explains the inconsistent signature between the isoheptane 1 3 Group-1 Petroleum Science (2020) 17:582–597 595 Osage Alfalfa Woods 0.86%Ro Noble Garfield Anadarko Shelf Pawnee 0.82%Ro Major ~0.76%Ro Group-2 Group-1 (in-situ) 0.83%Ro Payne oewey ~1.2%Ro for WDFD Rock (Cardott, 2014a) Kingfisher 1.7% Rc Logan ~1.3%Rc for condensates Blaine 1.5% Rc 0.59%Ro 1.2% Rc Lincoln Cherokee Group-2 (in-situ) 0.86%Ro Platform custer 1.3% Rc ~0.76%Ro for WDFD Rock (Wang & Philp, 2019) Oklahoma Canadian 1.3% Rc ~0.76%Rc for tight oils 0.48%Ro 0.81%Ro Anadarko Basin Group-3 (migrated) washita Pottawatomie Cleveland WDFD-sourced reservoir (Jones & Philp, 1989) Seminole Caddo ~0.79%Rc for conventional oils Grady Mcclain Devon Woodford Cores Kiowa Kitchen (?) “Old” WDFD-sourced OGS Woodford Cores oils: ~0.81Rc Pontotoc Arvin Tight Oils Comanche (?) Group-3 Condensates Stephens 50 km Murray Tillman Johnston Carter “Old” WDFD-Sourced Oils Fig. 8 Petroleum system and proposed migration pathway of central Oklahoma (with the Woodford rock maturity in measured Ro %). Devon = Devon Energy. OGS = Oklahoma Geological Survey 1. Two diagnostic molecular fingerprints for two petroleum Woodford-sourced oils (Group-3) and central Oklahoma source rocks, Mississippian mudrocks and Woodford oils (Group-2). Shale, based on light hydrocarbons have been captured and further convinced by biomarker and diamondoid Acknowledgements The authors would like to express their thanks to evidence; National Natural Science Foundation of China (No. 41802152), Natu- 2. Condensates produced from the Woodford–Mississip- ral Science Foundation of Hubei Province, China (No. 2017CFB321), pian tight reservoir within the Anadarko Basin (Group- Open Fund of Key Laboratory of Exploration Technologies for Oil and 1) exhibit a distinct fingerprint and sourced from the Gas Resources (Yangtze University), Ministry of Education, China (No. K2017-18), Open Foundation of Top Disciplines in Yangtze Uni- Woodford Shale; versity, Open Fund of State Key Laboratory of Petroleum Resources 3. Tight oil from the Woodford–Mississippian tight reser- and Prospecting, and China University of Petroleum, Beijing (No. voir on the Cherokee Platform (east of Nemaha Uplift) PRP/open-1605) for providing financial support. The authors would (Group-2) exhibits a “mixed source” fingerprint and also like to recognize the Devon Energy for their generous donation of samples and additional information. Thanks are due to Dr. Paul Philp, in situ sourced by Mississippian mudrocks and Wood- Dr. Thanh Nguyen, and Dr. Roger Slatt for their valuable comments ford Shale with variable contribution; and suggestions. 4. Crude oil sampled from conventional reservoirs in southern Oklahoma (Group-3) was derived from the Open Access This article is licensed under a Creative Commons Attri- Woodford Shale of the deep Anadarko Basin via long- bution 4.0 International License, which permits use, sharing, adapta- tion, distribution and reproduction in any medium or format, as long distance migration; as you give appropriate credit to the original author(s) and the source, 5. Thermal maturity based on light hydrocarbon parame- provide a link to the Creative Commons licence, and indicate if changes ters indicates that condensates from the Anadarko Basin were made. 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Light hydrocarbon geochemistry: insight into oils/condensates families and inferred source rocks of the Woodford–Mississippian tight oil play in North-Central Oklahoma, USA

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Springer Journals
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1672-5107
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1995-8226
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10.1007/s12182-020-00441-1
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Abstract

The Woodford–Mississippian “Commingled Production” is a prolific unconventional hydrocarbon play in Oklahoma, USA. The tight reservoirs feature variations in produced fluid chemistry usually explained by different possible source rocks. Such chemical variations are regularly obtained from bulk, molecular, and isotopic characteristics. In this study, we present a new geochemical investigation of gasoline range hydrocarbons, biomarkers, and diamondoids in oils from Mississippian carbonate and Woodford Shale. A set of oil/condensate samples were examined using high-performance gas chromatography and mass spectrometry. The result of the condensates from the Anadarko Basin shows a distinct geochemical fingerprint reflected in light hydrocarbon characterized by heptane star diagrams, convinced by biomarker characteristics and diaman- tane isomeric distributions. Two possible source rocks were identified, the Woodford Shale and Mississippian mudrocks, with a variable degree of mixing. Thermal maturity based on light hydrocarbon parameters indicates that condensates from the Anadarko Basin are of the highest maturity, followed by “Old” Woodford-sourced oils and central Oklahoma tight oils. These geochemical parameters shed light on petroleum migration within Devonian–Mississippian petroleum systems and mitigate geological risk in exploring and developing petroleum reservoirs. Keywords Tight oil · Tight condensate · Woodford Shale · Mississippian limestone · Light hydrocarbon geochemistry · Anadarko Basin 1 Introduction the Woodford produces wet gas and condensates. The oil has been commingled produced from the Woodford/Mississip- Woodford Shale has not only been proven to be an excel- pian strata since 2010 on the Anadarko Shelf and Cherokee lent source rock charging conventional reservoirs in Kansas Platform. Many studies suggest that the Woodford Shale and Oklahoma (Comer and Hinch 1987; Burruss and Hatch accounts for more than 85% of commercial oil produced 1989; Philp et al. 1989; Jones and Philp 1990; Comer 1992; from conventional reservoirs in Oklahoma and Kansas Wang and Philp 1997), but also a frontier for unconventional (Welte et al. 1975; Lewan et al. 1979; Reber 1988; Burruss resource play exploration and production. In areas straddling and Hatch 1989), but few publications have shown strong between the basin and shelf, like the Cana-Woodford Play, evidence to prove the oils were actually sourced from the Woodford Shale. Comer and Hinch (1987) recognized expul- sion, or primary migration, of oil from the Woodford Shale Edited by Jie Hao in Oklahoma by identifying numerous small-scale accu- * You-Jun Tang mulations of bitumen within mature parts of the Woodford tyj@yangtzeu.edu.cn Shale, including fractures, stylolites, burrows, nodules, and 1 sandstone lenses, all of which are completely enclosed in Key Laboratory of Exploration Technologies for Oil and Gas the source rock. Additional evidence to prove the Woodford Resources (Yangtze University), Ministry of Education, Wuhan 430100, Hubei, China Shale has generated oil in situ has been described in Car- dott (2014a, b), where extracts found in the surface fractures School of Geology and Geophysics, University of Oklahoma, Norman, OK 73019, USA of the Woodford outcrop in the McAlister cemetery quarry and in the Criner Hills were shown to be low-maturity “oil” Devon Energy Corporation, Oklahoma City, OK 73102, USA Vol:.(1234567890) 1 3 Petroleum Science (2020) 17:582–597 583 (rock extract ll fi ed in the fractures) originating from the local was the depocenter for the Oklahoma Basin and the precur- Woodford Shale. Oil samples produced from multiple con- sor of the Anadarko Basin (Johnson 1989; Northcutt et al. ventional reservoirs of different ages and extracts of possible 2001). From Silurian to Middle Devonian clean-washed source rocks indicated that most of the oils were primarily skeletal limestones, argillaceous, and silty carbonates, derived from the Woodford Shale in the Anadarko Basin referred to as the Hunton Group in Oklahoma, were depos- (Jones and Philp 1990). Burruss and Hatch (1989) undertook ited in a shallow marine setting (Northcutt et  al. 2001). a detailed geochemical investigation of 104 crude oils and Epeirogenic Uplifts interrupted deposition resulting in two 190 core samples of dark-colored shales from the Anadarko regional unconformities. In southern Oklahoma, the pre- Basin. They identified three oil end members, which gener - Woodford–Chattanooga unconformity eroded to the Upper ally correlated with the reservoir and source rock age. One Ordovician and in northern Oklahoma the erosion sculpted oil shared the stable carbon isotope signature and biomarker out Upper Cambrian–Lower Ordovician rocks (Kirkland fingerprints of the Woodford extracts, indicating that it was et al. 1992; Fig. 1b). The Nemaha Uplift is a buried range possibly derived from the Woodford Shale in the deep Ana- of the Ancestral Rocky Mountains associated with a granite darko Basin (Burruss and Hatch 1989). high in the pre-Cambrian basement that extends approxi- An important factor affecting hydrocarbon richness in mately from Nebraska to Central Oklahoma (Gerhard 2004). Woodford–Mississippian tight play is associated with source The major deformation of the Nemaha Uplift took place in rock heterogeneity. The Woodford Shale is an organic-rich pre-Desmoinesian and post-Mississippian time (Lee 1943; source of hydrocarbon that charged Woodford–Mississip- Merriam 1963; Gerhard 2004). The Cherokee platform pian tight reservoirs, together with Mississippian mudrocks could be considered as part of the stable shelf area of the such as Caney Shale (Al Atwah et al. 2015, 2017). Typi- Arkoma Basin throughout most of the Woodford deposition cally, identifying petroleum source rock could be achieved (Campbell and Northcutt 2001). In the Late Devonian, the by using a collection of geochemical tools such as molecular Cherokee Platform was a broad shelf separated from the and isotopic fingerprints, which include biomarkers together proto-Anadarko Basin by the paleo-Nemaha Ridge (North- with stable carbon isotopes of saturate and aromatic hydro- cutt and Campbell 1996; Campbell and Northcutt 2001). carbon fractions (Al Atwah et al. 2017; Wang and Philp The Late Devonian to Early Mississippian age Wood- 1997). Currently, light hydrocarbon markers remain underu- ford Shale is an organic-rich black shale widely distributed tilized in crude oil recovered from Woodford–Mississippian over most of Oklahoma including the Anadarko Basin, the tight reservoirs. Oil–oil correlations, together with hydro- Anadarko Shelf, Cherokee Platform, and the Arkoma Basin carbon migration and maturity assessment, can be further (Comer and Hinch 1987; Comer 1992). On the Cherokee refined by utilizing the light hydrocarbon markers. Light Platform, the Woodford Shale was deposited on a major hydrocarbon geochemistry is an effective tool for refining regional unconformity developed during the Late Devonian petroleum systems especially with processes related to petro- (Amsden 1975). It is conformably overlain by limestone and leum migration and accumulation (Hu et al. 1990; Dai 1993; shale of Early Mississippian Age (Fig. 2). The predominant Hao et al. 1991; Zhang and Lin 1994; Lin and Wilk 1995). lithology of the Woodford Shale is black shale along with Here, we present new geochemical data of light hydrocar- other common lithologies including chert, siltstone, sand- bons produced from Woodford–Mississippian tight reser- stone, dolostone, and light-colored shale (Amsden 1967; voirs across the Anadarko Basin in Oklahoma. Data sug- Amsden 1975; Comer 1992). The Woodford Shale in Okla- gest different sources of hydrocarbons, with various thermal homa is a typical marine clay-rich siliciclastic shale based maturity stages. Moreover, these data shed light into factors on three key characteristics found from previous studies: (1) affecting petroleum accumulation in Woodford–Mississip- marine non-calcareous siliceous mudstone (Amsden 1975; pian tight reservoirs such as water-washing and petroleum Kirkland et al. 1992; Comer 2008; Kvale and Bynum 2014); mixing. (2) low-to-moderate sulfur content (Jarvie et al. 2007); and (3) high clay mineral content (Kirkland et al. 1992; Comer 2008; Kvale and Bynum 2014). 2 Geological settings In the early Paleozoic time, three major tectonic/depositional 3 Samples and methods provinces existed in Oklahoma: the Oklahoma Basin, the southern Oklahoma Aulacogen, and the Ouachita Trough. 3.1 Study area and sampling The Oklahoma Basin was a shelf-like area that received widespread and thick shallow marine carbonates interbed- The study area extends across two major Woodford resource ded with thin marine shales and sandstones (Johnson 1989; plays, namely Anadarko-Woodford and Nemaha-Woodford Northcutt et al. 2001). The southern Oklahoma Aulacogen (Fig. 1a). Areal coverage includes Dewey, Blaine, Canadian, 1 3 Nemaha Uplift Anadarko Basin (deep) Wichita Mts Anad. Basin 584 Petroleum Science (2020) 17:582–597 99°0′0″ 98°0′0″ 97°0′0″ (a) Woods Osage Garfield Noble Pawnee Woodward Major Tulsa Pane Ellis Anadarko Shelf 36°0′0″ 36°0′0″ Dewey Kingfisher Logan Creek Blaine Cherokee Platform Roger mills Anadarko Basin Lincoln Okmulgee Custer Oklahoma Canadian Okfuskee Beckham Washita Pottawatomie Cleveland Seminole Caddo Hughes 35°0′0″ Grady Mcclain 35°0′0″ Pittsburg Pontotoc Garvin Coal 50 km Stephens Murra Johnston Carter Cotton Atoka 99°0′0″ 98°0′0″ 97°0′0″ Anadarko Basin condensates Cherokee Platform tight oils “Old” WDFD-sourced oils (b) A B Wichita Anadarko Basin Mtns. Sea Sea Level Level Woodford shale 10,000’ 10,000’ 3,000 m 3,000 m 20,000’ 50 100 miles 6,000 m 100 km 0 80 30,000’ 9,000 m 40,000’ 12,000 m Major Lithologies Conglomerate (“granite wash”) Sandstone and shale Black shale Salt, anhydrite, and shale Limestone and dolomite Rhyolite granite and gabbro Shale, limestone, and sandstone Granite and rhyolite Fig. 1 a Map showing the location of examined crude oil samples relative to major geological features and hydrocarbon plays in Oklahoma; the dotted line marks the borders of the Anadarko Basin. b NE-SW structural cross section across the Anadarko Basin (Johnson 1989) (modified from Johnson 1989) 1 3 Pennsylvanian Mississippian Precambrian Sil.-Dev. Late Cambrian-Oradovician Early-Middle Cambrian Cim.A. Nemaha Uplift Petroleum Science (2020) 17:582–597 585 the separator in 240 ml borosilicate glass bottles and tightly System Unit sealed with a PTFE-lined cap. Table 1 lists the 24 crude oil and 5 condensate samples with key bulk characteristics in this study. An aliquot of the crude oil/condensate sample Permian Leonardian was dissolved in hexane to precipitate asphaltenes; dissolved Wolfcampian hydrocarbons in hexane were further fractionated using sil- ica gel column chromatography into saturate, aromatic, and Virgilian resin fractions. All samples are produced from horizontal Missourian wells that have been stimulated with hydraulic fracturing Pennsylvanian Desmoinesian except for the 8 “Old” Woodford-sourced oils (Group-3); therefore, the horizontal targets listed in Table 1 represent Atokan the landing zone of the horizontal well and not necessar- Morrowan ily the source of the produced oils. Eight “Old” Woodford- Chesterian sourced oil samples (Group-3), previously produced from Meramecian vertical wells into conventional reservoirs in Southern Mississippian Oklahoma and stored in Dr. Philp’s laboratory (University Ossgean L of Oklahoma), were also included in the study for compara- Kinderhookian tive purposes. Woodford - Chattanooga Devonian 3.2 Whole oil gas chromatography Misener For whole oil GC analysis, the crude oil sample was diluted Silurian into a 1 mg/ml n-hexane solution and analyzed on an Agilent Sylvan L Hunton 6890 series gas chromatograph with a split/splitless capil- Shale Group lary injection system and a 100 m × 0.25 mm (i.d.) J&W Viola Ls. Scientific DB-Petro 122-10A6 fused silica capillary column Prdovician coated with a 0.5 µm liquid film. The temperature program Simpson Group started with an initial temperature of 40 °C and 1.5 min hold Arbuckle Group time and increased to 130 °C at a rate of 2 °C per minute and Timbered Hills Gp. - Reagan Ss. subsequently increased to 300 °C at a rate of 4 °C per minute Cambrian M followed by an isothermal period of 26 min for a total run of 115 min. C light hydrocarbon analysis was performed using L 7 the GC data obtained from whole oil/condensates GC analy- sis stated above. The isolated fractions, saturates, and aro- Precambrian Undifferentiated matics, respectively, were analyzed using an Agilent 6890 series gas chromatograph with a splitless capillary injector and a 30 m × 0.25 mm (i.d.) J&W Scientific DB-5 122-5032 fused silica capillary column coated with a 0.25 µm liquid Fig. 2 Stratigraphic chart for the Cherokee Platform, North-Central film. The injector was set up in the splitless injection mode, Oklahoma (Charpentier 2001) and the temperature was held at 300 °C. The carrier gas was helium (He) with a flow rate of 1.4 ml/min. The temperature Garfield, Logan, and Payne counties. From a geological per - program started with an initial temperature of 40 °C held for spective, all counties are located within the Anadarko Basin 1.5 min and increased to 300 °C at a rate of 4 °C per minute except for Garfield, Logan, and Payne counties which are followed by an isothermal period of 34 min for a total run part of the shallow Cherokee Platform. The Nemaha Uplift time of 100.5 min. The flame ionization detector (FID) tem- is a major structural feature dividing the Cherokee Platform perature was set at 310 °C. n-Alkanes and isoprenoids were from the Anadarko Basin province. identified in each chromatogram by comparing their relative Crude oil/condensate samples were collected from Mis- retention times with standards. sissippian reservoirs, as well as the Woodford Shale strata. A generalized stratigraphic column of the Anadarko Basin 3.3 Gas chromatography–mass spectrometry is shown in Fig. 2, and major source rocks and all examined crude oils are produced from Devonian–Mississippian petro- The GC–MS analyses of the branched and cyclic alkanes leum systems. Well-head fluid samples were collected at (B&C) and aromatic fractions were performed on an 1 3 586 Petroleum Science (2020) 17:582–597 Table 1 Bulk compositional and physical characteristics of examined crude oil/condensate samples + + + + Sample Reservoir API %SAT %ARO %NSO %ASP Type Group-1Horizontal targets Lingo 1-13 H Woodford Shale 48.92 7.1 1.2 0.5 91.2 Condensates Crystal 1-28H Woodford Shale 47.98 65.0 26.6 7.8 0.6 Condensates York 1-2H Woodford Shale 48.56 91.9 6.2 1.1 0.8 Condensates Wion 1-29H Woodford Shale 49.23 85.2 3.5 10.5 0.8 Condensates Bros 1-18H Woodford Shale 49.39 96.5 1.1 1.7 0.7 Condensates Group-2Horizontal targets Johnson 1-33H Woodford Shale 36.21 90.9 3.5 0.1 5.5 Medium Oil Matthews 1-33H Mississippian “Lime” 37.93 81.3 10.6 3.1 5.0 Medium Oil Wilma 1-16H Woodford Shale 38.55 85.1 9.4 2.1 3.4 Medium Oil Elinore 1-18H Mississippian “Lime” 33.53 76.0 13.7 4.9 5.5 Medium Oil Elinore 1-17H Woodford Shale 38.21 68.5 16.7 3.6 11.2 Medium Oil Winney 1-8H Mississippian “Lime” 28.11 54.4 9.3 2.0 34.3 Black Oil Adkisson 1-33H Mississippian “Lime” 38.45 84.1 13.1 0.2 2.6 Medium Oil Winney 1-5H Woodford Shale 38.25 79.7 15.0 4.2 1.1 Medium Oil Smith 1-14WH Woodford Shale 34.22 88.3 7.0 0.2 4.5 Medium Oil Smith 1-23MH Mississippian “Lime” 32.55 78.0 9.1 2.0 10.9 Medium Oil Hopfer 1-20WH Woodford Shale 33.45 83.0 9.5 5.7 1.9 Medium Oil Peach 1-20WH Woodford Shale 35.58 86.6 8.7 3.5 1.3 Medium Oil Joyce 1-32H Woodford Shale 33.71 72.9 17.5 6.5 3.2 Medium Oil Williams 1-24WH Woodford Shale 36.63 85.3 7.6 5.6 1.5 Medium Oil Peach 1-19H Mississippian “Lime” 35.88 81.1 14.0 2.9 2.0 Medium Oil C. Matthews 1-8WH Woodford Shale 37.74 83.7 8.3 5.2 2.8 Medium Oil ** Group-3Conventional reservoir Ford-1 N.A. 28.1 83.6 15.1 1.3 0.0 Black Oil Thomas James 1-22 Pennsylvanian sandstone 27.13 75.9 9.5 2.6 12.1 Black Oil Anadarko Taylor 2118 N.A. 48.98 92.2 7.8 0.0 0.0 Light Oil “A” N.A. 36.55 83.5 10.9 2.9 2.7 Medium Oil Ellis Lewis Jet Viola limestone 37.93 87.5 7.2 2.4 2.9 Medium Oil ST Mary N.A. 49.49 99.0 1.0 N.D. N.D. Light Oil “F” N.A. 27.9 66.1 8.7 3.7 21.5 Black Oil 7-5 N-5E N.A. 22.1 73.7 9.9 3.7 12.7 Black Oil *Horizontal targets indicate the landing zone of the horizontal well, and not necessarily the actual source of the oil. +SAT: weight percentage of saturate hydrocarbons; ARO: weight percentage of aromatic hydrocarbons; POL: weight percentage of polar resin compounds (NSO); ASP: weight percentage of asphaltenes; N.A. denotes not available Agilent 7890A gas chromatography system coupled with were determined from fragmentograms corresponding to an Agilent Technologies 5975C mass selective detec- each ion using relative retention times and by comparison tor (MSD) using single ion monitoring. The GC used a with published data. 60 m × 0.25 mm Agilent/J&W Scientific DB-5 122-5562 For diamondoids analysis in crude oils/condensates, the fused silica capillary column coated with a 0.25 µm liquid sample was diluted with pentane in the concentration of film. The injected volume of branched and cyclic and aro- 16 mg oil/ml pentane. The pentane was reported to be a matic fractions was 1 µl per run. The injector temperature good solvent for adamantanes and diamantanes in terms of was set at 300 °C. The GC temperature program started at high solubility and low boiling point (Reiser et al. 1996). 40 °C with 1.5 min hold time and was later increased to The oil solution was well homogenized in ultrasonic bath 300 °C at a rate of 4 °C per minute and then held constant for at least 1  min. 1  µl of the resulting oil solution was for 34 min for a total run time of 100.5 min. Samples were injected to Agilent GC–MS to detect adamantanes and run in splitless mode, and helium was used as the carrier diamantanes using SIM mode and key ion fragments: 135, gas at a flow rate of 1.4 ml/min. Biomarker compounds 136, 149, etc., and 188, 187, 201, etc., respectively. DB-5 1 3 Petroleum Science (2020) 17:582–597 587 MS 60 m × 0.25 mm × 0.25 micron in film thickness was fingerprint is unique to the condensates (Group-1) from the used. Temperature program started at 40 °C and hold it for Anadarko Basin compared to other oil groups (Figs. 3, 4). 1.5 min before ramping 4 °C/min to 300 °C, and then held Group-2 oils located in Cherokee Platform, Central Okla- this temperature for 34 min. Compound ratios were calcu- homa, showed a narrow OCSD pattern, with significant lated directly from peak areas or peak heights of targeted enrichment in 3-ethylpentane (Table 2). Group-3 oils dis- markers and compared with internal standards. played more subtle variability where some oils are enriched in 3,3-dimethylpentane and relatively lower in 2,4-dimethyl- pentane isomer, while other oils display the opposite trend. 4 Results and discussion The observed variation of star diagram fingerprints across crude oil groups is a function of source rock inher- 4.1 Bulk geochemical parameters ent variation and evaporative fractionation. Mango (1987) reported that light hydrocarbons in crude oil are formed via Crude oils exhibit slight differences in bulk parameters that metal-catalyzed steady-state kinetic reaction of the kerogen. are consistent with the type of fluid, in which the majority of Moreover, it was observed that while the absolute concen- the samples are classified as medium oil. Key bulk param- tration of light hydrocarbons from the same source varied eters of the crude oils are listed in Table 1, including fluid by orders of magnitude, certain ratios of light hydrocar- type, API gravity, and SARA (short for saturates, aromatics, bons kept constant, such as the sum of 2-methylhexane and resin and asphaltene) component classes. API gravity values 2,3-dimethylpentane relative to the sum of 3-methylhexane ranged from 22.1 to 49.49, as reflected in the fluid type, in and 2,4-dimethylpentane (K1) (Mango 1987). To explain which lower API values are associated with heavier black the invariance of the C -C hydrocarbons, Mango (1987) 6 7 oils and higher API values from light oils. All of the oil postulated that light hydrocarbons originate from a higher samples are dominated by saturate hydrocarbons compared saturated hydrocarbon and the presence of metal catalysts to aromatic, resin, and asphaltenes. Heavier crude oils, such will result in a similar reaction rate for homologous series. as Winney 1-8H, were higher in asphaltene content relative OCSD parameters are based on branched C alkanes; there- to the rest of the oil samples. The crude oil bulk character- fore, those ratios would keep constant observed by Mango istic is a useful descriptive source of data with some inher- (1987). In examined crude oils, the variations in OCSD fin- ent limits. The dominance of the saturated hydrocarbon is gerprints between Group-1 and Group-2 are clearly indicat- reasonable to be found in thermogenic hydrocarbon expelled ing two different sources of hydrocarbons (Fig.  4), whereas from petroleum source rocks. Such enrichment in saturated Group-3 presumably is a mix of the two end members or hydrocarbons is usually observed in naturally produced from a third source. Within the Anadarko Basin, a number crude oil (Lewan et al. 2006). However, the source rock of of source rocks have been studied ranging in age from Cam- petroleum cannot be determined solely from bulk param- brian to Pennsylvanian (Al Atwah et al. 2017; Wang and eters; therefore, characteristics of molecular fingerprints Philp 1997). Observations from light hydrocarbon source discussed below can aid to identify hydrocarbon sources. parameters are discussed in the biomarker section below. 4.2 Light hydrocarbon analysis4.2.2 Alteration assessment 4.2.1 Source parameters The oil transformation star diagrams (OTSD), a multivari- ate plot in polar coordinates developed by Halpern based Heptane (C ) variability reflected the geographic loca- on different ratios of C -C hydrocarbons to character- 7 4 7 tion among the three distinct oil groups. Table 2 lists the ize secondary alterations of crude oils (Halpern 1995), ratios used for constructing the oil correlation star dia- are illustrated in Fig. 4 with ratios used to construct the gram (OCSD) and oil transformation star diagram (OTSD) diagrams listed in Table 2. Although light hydrocarbons (Halpern 1995). Group-1 samples located within the Ana- are controlled by the organic matter source, secondary darko Basin exhibited a unique fingerprint of the C OCSD alterations can affect light hydrocarbon distribution (i.e., (Figs.  3, 4). Specifically, these oils are enriched in the biodegradation, water-washing, thermal maturity, and 3,3-dimethylpentane isomer relative to the rest of heptane evaporation). In all the oil samples, lowest ratio values isomers. Similarly, enrichment in 2,2-dimethylpentane and are observed at TR-6 ranging from 0.01 to 1.09 (Table 2), 2,4-dimethylpentane is observed within tight oils located with Group-1 samples exhibiting the highest TR-1 values on the Cherokee Platform (Group-2). Additionally, Group-1 compared to the other two groups. Overall, Group-1 and condensates varied the most for 2,2-dimethylpentane, fol- Group-3 showed a relatively similar OTSD pattern maxi- lowed by 3,3-dimethylpentane isomers (Figs. 3, 4). How- mizing at TR-4 followed by TR-3, whereas Group-2 high- ever, even with those variations, the overall star diagram est ratio coexists at TR-7 and TR-8 followed by TR-6. The 1 3 588 Petroleum Science (2020) 17:582–597 1 3 Table 2 Key light hydrocarbon ratios of crude oil samples sensitive to source, transformation, and maturity Sample Oil correlation parameters Oil transformation ratio Maturity 2,3-DMP 2,2-DMP EtCP/P 3,3-DMP 2,4-DMP TR-1 TR-2 TR-3 TR-4 TR-5 TR-6 TR-7 TR-8 C ratio iso-C ratio 7 7 Group-1  Lingo 1-13 H 1.1 0.2 0.8 0.2 0.6 7.7 38.6 16.7 15.3 32.0 0.1 1.3 5.3 37.3 8.4  Crystal 1-28H 0.9 0.2 0.8 0.3 0.5 18.1 23.6 8.9 8.3 17.2 0.1 1.1 4.5 31.7 6.1  York 1-2H 1.1 0.2 0.9 0.3 0.6 5.5 18.6 7.0 6.1 13.1 0.1 1.3 4.7 33.0 4.5  Wion 1-29H 0.7 0.3 0.6 0.3 0.4 25.5 27.5 11.2 11.2 22.4 0.1 1.1 4.1 32.4 8.0  Bros 1-18H 1.3 0.2 1.0 0.2 0.6 4.8 23.1 8.7 7.3 16.0 0.1 1.4 5.2 36.0 4.7 Group-2  Johnson 1-33H 3.5 0.1 3.1 0.0 0.9 3.2 13.1 5.0 3.1 8.1 0.5 2.9 4.1 26.9 0.8  Matthews 1-33H 2.8 0.1 2.3 0.1 0.8 3.0 12.7 4.9 3.1 8.0 0.5 2.8 3.9 26.7 0.8  Wilma 1-16H 2.5 0.1 2.3 0.2 0.7 4.2 15.8 5.2 3.5 8.7 0.5 2.8 3.9 30.1 0.9  Elinore 1-18H 3.0 0.1 4.1 0.2 0.8 2.8 16.7 6.7 3.9 10.7 1.0 4.4 4.0 26.7 0.6  Elinore 1-17H 3.5 0.1 5.0 0.0 0.9 2.2 16.4 6.6 3.8 10.5 1.1 4.6 4.1 29.6 0.6  Winney 1-8H 3.5 0.1 3.7 0.0 0.9 3.5 14.4 5.5 3.3 8.9 0.7 3.3 4.1 27.4 0.7  Adkisson 1-33H 3.4 0.2 3.3 0.0 0.8 3.9 12.0 4.4 2.7 7.1 0.6 2.9 3.9 25.9 0.7  Winney 1-5H 3.0 0.1 3.0 0.2 0.7 3.1 13.0 5.1 3.1 8.3 0.7 3.2 3.8 26.2 0.7  Smith 1-14WH 2.3 0.1 1.7 0.2 0.7 3.8 14.8 5.4 3.7 9.1 0.4 2.4 3.8 29.2 1.1  Smith 1-23MH 2.8 0.1 2.7 0.2 0.7 4.5 15.1 5.0 3.2 8.2 0.5 2.6 3.8 29.8 0.9 Group-3  Ford-1 2.4 0.1 3.6 0.2 0.7 7.6 32.7 11.8 7.6 19.3 1.1 4.8 4.5 33.3 1.1  Thomas James 1–22 3.6 0.0 3.9 0.0 1.0 4.4 26.0 9.3 6.4 15.7 0.5 3.3 5.2 34.7 1.4  Anadarko Taylor 2118 2.2 0.1 2.1 0.2 0.7 6.8 42.7 15.5 11.1 26.6 0.5 3.5 5.0 39.3 2.5  “A” 3.4 0.1 3.9 0.1 0.8 2.4 13.0 4.8 2.9 7.7 0.7 3.0 3.7 27.1 0.7  Ellis Lewis Jet 2.4 0.1 2.8 0.2 0.7 5.3 31.1 10.6 7.2 17.8 0.6 3.5 4.8 37.2 1.5  ST Mary 2.0 0.2 2.2 0.3 0.5 16.3 53.8 17.6 14.2 31.8 0.0 2.8 5.5 40.9 4.7 “F” 4.9 0.0 6.1 0.0 1.0 4.7 14.3 5.1 3.0 8.2 0.7 3.1 4.1 27.9 0.7 P1: 2,2-dimethylpentane + 2,3-dimethylpentane + 2,4-dimethylpentane + 3,3-dimethylpentane + 3-ethylpentane; 2,2-DMP: 2,2-dimethylpentane/P1; 2,3-DMP: 2,3-dimethylpentane/P1; 2,4- DMP: 2,4-dimethylpentane/P1; 3,3-DMP: 3,3-dimethylpentane/P1; EtP: 3-ethylpentane/P1; X: 1,1-dimethylcyclopentane; P2: 2-methylhexane + 3-methylhexane; TR1: toluene/X; TR2: n C /X; TR3: 3-methylhexane/X; TR4: 2-methylhexane/X; TR5: P2/X; TR6: 1-cis-2-dimethylcyclopentane/X; TR7: 1-trans-3-dimethylcyclopentane/X; TR8: P1/P2; C ratio: 100*n-heptane/cyclohex- ane + 2-methylhexane + 1,1-dimethylcyclopentane (DMCP) + 3-methylhexane + 1-cis-3-DMCP + 1-trans-3DMCP + 1-trans-2-DMCP + n-heptane + methylcyclohexane; iso-C ratio: 2-methyl- hexane + 3-methylhexane/1-cis-3-DMCP + 1-trans-3DMCP + 1-trans-2-DMCP Petroleum Science (2020) 17:582–597 589 Group-1 Lingo1-13H Condensate Peak # Compound Abbreviation 1 n-Hexane n-C 2 2,2-Dimethylpentane 2,2-DMP 3Methylcyclopentane MCP 4 2,4-Dimethylpentane 2,4-DMP 5 Benzene 3,3-DMP 6 3,3-Dimethylpentane B 7 Cyclohexane CH 8 2,3-Dimethylpentane 2,3-DMP 9 2-Methylhexane 2-MH 10 1,1-Dimethylcyclopentane 1,1-DMCP 11 3-Methylhexane 3-MH 12 Cis-1,3-Dimethylcyclopentane C1,3-DMCP Group-2 Winney 1-8H Oil 13 Trans-1,3-Dimethylcyclopentane T1,3-DMCP 14 Trans-1,2-Dimethylcyclopentane T1,2-DMCP 15 3-Ethylpentane 3-EP 16 2,2,4-Trimethylpentane 2,2,4-TMP 17 n-Heptane n-C 18 2,2-Dimethylhexane 2,2-DMH 19 Cis-1,2-Dimethylcyclopentane C1,2-DMCP 20 Methylcyclohexane MCH 21 Ethylcyclopentane ECP 22 2,5-Dimethylhexane 2,5-DMH 23 2,4-Dimethylhexane 2,4-DMH Group-3 Ford-1 Oil 24 1,2,4-Trimethylcyclopentane 1,2,4-TMCP 25 1,2,3-Trimethylcyclopentane 1,2,3-TMCP 26 2,3,4-Trimethylpentane 2,3,4-TMP 27 2,3,3-Trimethylpentane 2,3,3-TMP 28 Toluene Tol 29 Isooctane i-C8 30 n-Pentane n-C5 31 2,2-Dimethylbutane 2,2-DMB 32 2,3-Dimethylbutane 2,3-DMB 33 2-methylpentane 2-MP 34 3-methylpentane 3-MP Fig. 3 Gas chromatogram (C light hydrocarbon range) of typical sample of different groups (compounds identified in the table above) apparent depletion in TR-1 in the oil samples is related from the high values of the transformation values rang- to the effect of water-washing, which is characterized ing from TR-2 to TR-8 (Table 2). In the Anadarko Basin, by using the ratio of toluene relative to 1,1-dimethylcy- variation in toluene abundance has been observed with a clopentane. (Toluene is more water-soluble; therefore, uniquely decreasing trend moving away from the basin a decreasing trend in TR-1 indicated water-washing depocenter toward the shallower shelf area. The low (Mango 1997.) From OTSD, it is clear that water-wash- molecular weight aromatic hydrocarbons, benzene and ing effects occurred, but at different magnitudes, Group-2 toluene, are the most water-soluble components in crude was severely water-washed, while Group-1 and Group-3 oils (Price 1976). As oils migrate farther, they contact were relatively slightly washed. No crude oil exhibited progressively larger amounts of formation water into any evidence of microbial biodegradation as observed which the water-soluble components will partition. There 1 3 12+13+14 21+23 24+25 28 590 Petroleum Science (2020) 17:582–597 OCSD OTSD [5.00] Group-1 [30] 2,3-DMP TR1 [8] [60] TR8 TR2 [1.00] 2,4-DMP 2,2-DMP [0.25] [10] TR7 [20] TR3 [3] [18] TR6 TR4 [0.35] [6.00] 3,3-DMP EtP [40] TR5 Group-2 [30] TR1 [5.00] 2,3-DMP [8] [60] TR8 TR2 [1.00] 2,4-DMP 2,2-DMP [10] TR7 [20] [0.25] TR3 [3] [18] TR6 TR4 [40] [0.35] [6.00] TR5 3,3-DMP EtP Group-3 [30] TR1 [5.00] 2,3-DMP [8] [60] TR8 TR2 [1.00] 2,4-DMP 2,2-DMP [0.25] [10] TR7 [20] TR3 [3] [18] TR6 TR4 [0.35] [6.00] 3,3-DMP EtP [40] TR5 Fig. 4 Oil correlation star diagrams (OCSD) (left) and oil transformation star diagrams (OTSD) (right). P1: 2,2-dimethylpentane + 2,3 dimeth- ylpentane + 2,4-dimethylpentane + 3,3-dimethylpentane + 3-ethylpentane. 2,2-DMP: 2,2-dimethylpentane/P1; 2,3-DMP: 2,3-dimethylpen- tane/P1; 2,4-DMP: 2,4-dimethylpentane/P1; 3,3-DMP: 3,3-dimethylpentane/P1; EtP: 3-ethylpentane/P1; X: 1,1-dimethylcyclopentane; P2: 2-methylhexane + 3-methylhexane; TR1: toluene/X; TR2: n C7/X; TR3: 3-methylhexane/X; TR4: 2-methylhexane/X; TR5: P2/X; TR6: 1-cis-2-dimethylcyclopentane/X; TR7: 1-trans-3-dimethylcyclopentane/X; TR8: P1/P2; C7 ratio: 100*n-heptane/cyclohexane + 2-methylhex- ane + 1,1-dimethylcyclopentane (DMCP) + 3-methylhexane + 1-cis-3-DMCP + 1-trans-3DMCP + 1-trans-2-DMCP + n-heptane + methylcy- clohexane; iso C7 ratio: 2-methylhexane + 3-methylhexane/1-cis-3-DMCP + 1-trans-3DMCP + 1-trans-2-DMCP (Thompson 1983) is also the possibility that toluene concentration is related trend was reported to indicate long-distance migration of to thermal maturation; however, the trend of toluene con- hydrocarbons (Burruss and Hatch 1989). centration versus depth is not strong, a fact shown by the relatively low concentrations of toluene in the central, 4.2.3 Thermal maturity deep-basin oils from Silurian and Devonian reservoirs and from Pennsylvanian reservoirs. Therefore, such a Light hydrocarbons are a useful geochemical tool to evaluate thermal maturity. A number of light hydrocarbon-(C –C ) 6 7 1 3 Petroleum Science (2020) 17:582–597 591 based maturity parameters have been published in the lit- explained based on the trend of Woodford Shale thermal erature, pioneered by Hunt et  al. (1980). These authors maturity across the Anadarko Basin. Particularly, Group-1 observed that certain ratios of light hydrocarbons such as condensates are located at the eastern edge of the Anadarko 2,2-dimethylbutane/2,3-dimethylbutane tend to increase Basin, where the Woodford Shale has been reported within with increase in depth. A similar work was done by Thomp- the late oil thermal maturity stage (Cardott 1989, 2012). son who introduced the heptane ratio as a maturity param- “Old” Woodford-sourced oils (Group-3) showed the high- eter, which is calculated by the ratio of n-heptane relative est heptane ratios; however, they are located at a shallower to the sum of different heptane isomers (Thompson 1983). depth where thermal maturity is not suc ffi ient for oil genera - Thompson defined stages for maturity estimation of oils tion (lower than 0.6 VRo %), and hence, these fluids may based on heptane ratio as follows: the heptane ratio from have resulted from long-distance migration from the Ana- 18 to 22 is normal uncracked oil, 22 to 30 is classified as darko depocenter where source rocks are buried at higher mature oil, and heptane ratio > 30 is classified as superma- maturity levels (Al Atwah et al. 2017). One exception within ture (Thompson 1983). Not only heptane ration, isoheptane Group-3 oils is sample ST Mary, which exhibits the feature ratio was also introduced by Walters et al. (2003) to better of a light oil from its bulk characteristics (Table 1) while characterize maturity stage, who proposed an empirical hep- plotting within normal oils in Fig. 5. This in part could be tane ratio (H) versus isoheptane ratio (I) diagram based on due to evaporative fractionation effect caused by light hydro- the C ratios measured for oils/condensates from the North carbons partitioning from initially normal oil as a function Sea to investigate the thermal maturity of oils/condensates. of migration distance and associated rock–fluid interactions In this study, thermal maturity is accessed using a cross- within the carrier beds (Dzou and Hughes 1993; Kim and plot (Fig. 5) comparing the heptane versus isoheptane ratio Philp 2001). Low heptane ratios of Group-2 oils can be (listed in Table 2) with maturity levels according to Walters classified as normal paraffinic oil, which coincide with the et al. (2003). The heptane ratio ranged from 25.8 to 45.8, overall maturity of the Woodford Shale (0.7 to 0.8 VRo %) and isoheptane ranged from 0.6 to 8.3. Group-1 exhibited in areas east of the Nemaha Uplift. The base map of Fig. 8 the highest thermal maturity level followed by Group-3, shows the Woodford Shale maturity based on the measured whereas Group-2 was the least mature (Fig. 5). The vari- vitrinite reflectance (Cardott 1989, 2012, 2017). The over- ability of heptane ratios in the different oil groups can be all Woodford Shale maturity trend coincides with the three groups’ oil maturity stages. However, Group-1 exhibits a higher maturity level than the rocks’ maturity where they Heptane Vs. isoheptane diagram are produced. This is due to the hydrocarbon charge history (Group-1) (Group-2) (Group-3) which is discussed in the following section. Anadarko basin Cherokee platform “Old” woodford- condensates WDFD-MSSP sourced oils tight oils 4.3 Biomarkers and diamondoids analysis Biomarker and diamondoid distributions in crude oils were investigated to support gasoline-ranged hydrocarbons pre- sented earlier. Selected biomarker and diamondoid ratios 30 Supermature oils are listed in Table 3. Certain specific ratios of sterane and terpane in the examined sample exhibit a wide variation. Mature oils For example, Group-3 oils are enriched in C regular Normal oils sterane relative to C , whereas Group-1 condensates are enriched in C regular sterane relative to C , with a Reg 10 27 29 C /C ratio ranging from 0.6 to 1.4 in Group-3, whereas 27 29 Group-1 condensates range from 1.9 to 5.6. Most nota- bly, the extended tricyclic terpanes (ETT) relative to the 01.0 2.03.0 4.05.0 6.0 7.0 8.0 9.0 hopane (Hop) ratio exhibit the highest variance among the Isoheptane ratio biomarker ratios. The ETT/Hop ratio stays around 0.6 in Group-1 condensates and ranges from 0.6 to 1.3 in Group-2 Fig. 5 Cross-plot of heptane versus isoheptane ratios to assess crude oils and 0.3 to 0.7 in Group-3. The relative abundance of oil maturity from Mississippian and Woodford of the three oils selected alkyl diamantane isomers (diamondoids) is listed groups defined in Table  1. Heptane ratio: 100*n-heptane/cyclohex- ane + 2-methylhexane + 1,1-dimethylcyclopentane (DMCP) + 3-meth- in Table 3. Group-1 condensates showed a higher relative y lhe x ane + 1-cis-3-DMCP + 1-tr ans-3DMCP + 1-tr ans-2- abundance of 3,4-dimethyldiamantane, and Group-2 oils are DMCP + n-heptane + methyl cyclohexane; isoheptane ratio: slightly higher in 8,4-dimethyldiamantane, whereas Group-3 2-methylhexane +3-methylhexane/1-cis-3-DMCP + 1-trans- 3DMCP + 1-trans-2-DMCP 1 3 Heptane ratio 592 Petroleum Science (2020) 17:582–597 Table 3 Key biomarker and diamondoid ratios sensitive to organic matter type and source rock lithology Sample Biomarker parameter Diamondoids parameter RegC /RegC DiaC /RegC Hop/RegC ETT/HH C TT/Hop Rc 4,8-DMD 4,9-DMD 3,4-DMD 27 29 29 29 29 23 Group-1 Rc from MAI  Lingo 1-13 H N.D. N.D. N.D. N.D. N.D. 1.31 0.33 0.22 0.45  Crystal 1-28H 3.0 0.5 0.7 0.6 0.7 1.52 0.35 0.40 0.25  York 1-2H 5.6 0.7 0.0 N.D. N.D. 1.23 0.38 0.18 0.44  Wion 1-29H 1.9 0.5 0.9 0.0 0.2 1.75 0.35 0.27 0.38  Bros 1-18H N.D. N.D. N.D. N.D. N.D. 1.33 0.44 0.23 0.33 Group-2 Rc from MPI-1  Johnson 1-33H 1.3 0.6 0.6 1.3 0.6 0.90 0.41 0.28 0.31  Matthews 1-33H 2.2 0.5 0.7 1.5 0.7 1.12 0.49 0.24 0.27  Wilma 1-16H 2.2 0.5 0.6 1.0 0.6 0.76 0.45 0.27 0.28  Elinore 1-18H 1.0 0.4 0.6 0.5 0.4 0.83 0.52 0.23 0.25  Elinore 1-17H 1.0 0.4 0.7 0.6 0.5 0.79 0.41 0.28 0.31  Winney 1-8H 2.3 0.5 0.7 0.8 0.5 0.85 0.56 0.22 0.22  Adkisson 1-33H 1.1 0.5 0.7 0.8 0.6 0.75 0.51 0.26 0.23  Winney 1-5H 2.2 0.5 0.7 1.2 0.6 1.03 0.40 0.22 0.37  Smith 1-14WH 0.9 0.6 0.7 0.8 0.5 1.03 0.40 0.28 0.32  Smith 1-23MH 3.3 0.4 0.7 1.1 0.6 0.77 0.49 0.25 0.26 Group-3 Rc from MPI-1  Ford-1 0.8 0.4 0.6 0.4 0.4 0.74 N.D. N.D. N.D.  Thomas James 1.0 0.5 0.7 0.6 0.5 0.81 N.D. N.D. N.D. 1–22  Anadarko Taylor 1.4 0.5 0.5 1.7 0.8 0.90 0.33 0.25 0.42  “A” 1.0 0.5 0.7 0.6 0.4 0.71 N.D. N.D. N.D.  Ellis Lewis Jet 1.0 0.5 0.7 0.7 0.5 0.82 N.D. N.D. N.D.  ST Mary N.D. N.D. N.D. N.D. N.D. N.D. 0.39 0.19 0.42  “F” 1.0 0.5 0.7 0.7 0.5 0.88 N.D. N.D. N.D.  7-5N-5E 0.6 0.5 0.6 0.3 0.3 0.79 N.D. N.D. N.D. RegC /RegC : ααR C sterane/ααR C sterane; DiaC /RegC: C 13β 17α 20R diasterane/C 13β 17α dia 20R + ααR C steranes; Hop/ 29 27 27 29 29 29 29 29 29 RegC: C 17α hopane/C 17α hopane + C αα 20R stigmastane; ETT/HH: sum of extended tricyclic terpanes C to C /sum of extended 29 29 29 29 30 39 tricyclic and C 17α hopane; CTT/Hop: C tricyclic terpane/C tricyclic terpane + C 17α hopane; Rc: calculated vitrinite reflectance for 30 23 23 23 30 the studied condensates from methyl adamantane index (MAI) values; Rc: calculated vitrinite reflectance for the studied oils from methylphen- anthrane index-1 (MPI-1) values; 4,9-DMD: 4,9-dimethyldiamantane/(sum of 4,8- + 4,9- + 3,4-dimethyldiamantanes); 4,8-DMD: 4,8-dimethyl- diamantane/(sum of 4,8- + 4,9- + 3,4-dimethyldiamantanes); 3,4-DMD: 3,4-dimethyldiamantane/(sum of 4,8- + 4,9- + 3,4-dimethyldiamantanes) oils exhibit similar abundance between these two isomers with a clear homohopane mass-chromatogram trace (Fig. 7). (Fig. 6a). Hopanes are pentacyclic terpanes (Van Dorsselacer et al. Biomarker ratio variation is controlled by the source 1977) that originate from hopanoids present in prokaryotes rock inherent composition. For example, enrichment in C (bacteria and cyanobacteria) and higher plants but appear to sterane of Group-3 oils has been observed in Woodford- be absent in eukaryotic algae (Ourisson et al. 1979). Such sourced crude oil and rock extracts (Miceli Romero and an abundance of hopanes in the examined oils is consistent Philp 2012; Wang et al. 2017; 2018; Wang and Philp 2019). with previous studies, in which the abundance of hopanes C steranes (stigmastane) are derived from terrigenous is diagnostic for the Woodford Shale extracts. From the oil organic matter sources and marine algae (Volkman 1986). correlation star diagram in Fig.  4, Group-1 condensates Therefore, C sterane enrichment was previously reported reflect hydrocarbons originated from the Woodford Shale. in terrigenously derived oils; Paleozoic marine shales were Additionally, the most notable biomarker characteristic of reported to have a similar fingerprint, too (Moldowan et al. Group-2 is the abundance of extended tricyclic terpanes up 1985). Group-1 condensates show enrichment in hopane to C (Fig. 7). This is accompanied by depletion of hopane 1 3 Petroleum Science (2020) 17:582–597 593 Low-mid maturity Mixed low-mid maturity & (a) %4,9-DMD (b) (non-cracked) cracked hydrocarbons 0 100 (Group-1) Anadarko basin condensates (Group-1) (Group-2) Anadarko basin Cherokee platform (Group-2) 20 80 condensates WDFD-MSSP Cherokee platform WDFD-MSSP tight oils (Group-3) tight oils “Old” woodford- 40 60 sourced oils (Group-1) 60 “Old” woodford- sourced oils 60 40 Carbonate Shale Type II Type II Coal Type III Cracking intensity 0 5.0 10.0 15.0 20.0 020406080 100 %4,8-DMD %3,4-DMD 3- + 4-Methyl diamantanes, ppm Fig. 6 a Ternary diagram comparing the relative abundance of three different isomers of dimethyldiamantane, including 4,9-dimethyldiaman- tane, 4,8-dimethyldiamantane, and 3,4-dimethyldiamantane. Dimethyldiamantanes are measured from m/z 201 mass fragmentogram. Polygons of different source rock facies are from Schulz et al. 2001); b cross-plot for evaluating extent of cracking and oil mixing, comparing regular stig- mastane biomarker versus 3- + 4-methyldiamantanes, after Dahl et al. 1999 Peak # Compound C24D Deuterated n-tetracosane (ISTD) 1C20 Tricyclic terpane (Cheilanthane) 2C21 Tricyclic terpane (Cheilanthane) 3C Tricyclic terpane (Cheilanthane) Adkisson 1-33H Oil 22 Oil produced 4C Tricyclic terpane (Cheilanthane from MSSP 5C Tricyclic terpane (Cheilanthane) 6C Tricyclic terpanes (Cheilanthanes 22S and 22R) 9 10 7C Tetracyc licterpane 18 24 8C26 Tricyclic terpanes (Cheilanthanes 22S and 22R) 9C28 Tricyclic terpanes (Cheilanthanes 22S and 22R) 10 C29 Tricyclic terpanes (Cheilanthanes 22S and 22R) 20 11 C27 18α(H)-22,29,30-Trisnorneohopane (Ts) 22 23 24 12 C Tricyclic terpanes (Cheilanthanes 22S and 22R) 17 28 3 26 I 29 13 C 17α(H)-22,29,30-Trisnorhopane (Tm) 14 C Tricyclic terpanes (Cheilanthanes 22S and 22R) 15 C 17α(H),21β(H)-30-Norhopane (H29) 16 C29Ts 18α(H)-30-Norneohopane (29Ts) 7-5N-5E WDFD- 17 D30 15α-methyl-17α(H)-27-Norhopane (Diahopane: D30) Oil produced 18 18 C30 17α(H),21β(H)-Hopane sourced historically from WDFD 19 C33 Tricyclic terpanes (Cheilanthanes 22S and 22R) produced oil in South OK 20 C31 17α(H),21β(H)-Homohopanes (22S & 22R) 21 C Tricyclic terpanes (Cheilanthanes 22S and 22R) 22 C 17α(H),21β(H)-Bishomohopane (22S & 22R) 23 C Tricyclic terpanes (Cheilanthanes 22S and 22R) 24 C 17α(H),21β(H)-Trishomohopane (22S & 22R) 2 +13 25 C36 Tricyclic terpanes (Cheilanthanes 22S and 22R) 9 16 26 C34 17α(H),21β(H)-Tetrakishomohopane (22S & 22R) 7 27 C35 17α(H),21β(H)-Pentakishomohopane (22S & 22R) 17 G 3 28 C38 Tricyclic terpanes (Cheilanthanes 22S and 22R) 29 C Tricyclic terpanes (Cheilanthanes 22S and 22R) G Gammacerane Fig. 7 Mass chromatogram (m/z 191) showing terpane biomarker distribution in the saturate hydrocarbons comparing two end members of Mississippian-sourced (Adkisson 1-33H) and Woodford-sourced (7-5N-5E) crude oils. Note the enrichment of extended tricyclic terpanes up to C in Mississippian-sourced oil and is depleted in Woodford-sourced oil. IS internal standard and homohopane relative to tricyclic terpanes, together with Johnson 1-33H and Matthews 1-33H (Table 1). However, dominance of C regular sterane relative to the C coun- since these oils show a strong Mississippian biomarker char- 27 29 terpart (Table 3). These biomarkers signature are diagnostic acteristic and a Mississippian OCSD imprint, it is likely that of a Mississippian-sourced oil and a Mississippian-extracted the stimulated rock volume has exceeded the Woodford into bitumen (Kim and Philp 2001). Group-2 oils should have the Mississippian Formation resulting in a mixing fluid with had at least Mississippian source contribution, evidenced relatively comparable contributions from the Mississippian in the narrow star diagram fingerprint in Fig.  4. Within and Woodford sources. Group-2 samples, two oils are recovered from the hori- Diamondoids are rigid fused-ring cycloalkanes with a zontal wells landed in the Woodford Formation including diamond-like structure that shows high thermal stability 1 3 C ααR sterane, ppm Diamondoid baseline 594 Petroleum Science (2020) 17:582–597 initially (Williams et  al. 1986; Wingert 1992; Lin and ratio and buck crude oil parameters of Group-1 and Wilk 1995; Dahl et al. 2003). Diamondoids are not found Group-3 oils, whereas the former suggests highly mature in living organisms but have been demonstrated to be f luids, whereas the latter indicates black oils. synthesized from a wide variety of organic precursors via Lewis acid catalysis (Schleyer 1990; Wingert 1992). 4.4 Proposed petroleum system Considering their ubiquitous occurrence, even in oils of low thermal maturity, this mode of formation suggests Based on the results of the oil/condensates family group- diamondoids form by hydrocarbon rearrangement reac- ing, integration of the Woodford thermal maturity map, and tions on acidic clay minerals in petroleum source rocks burial and thermal history (Schmoker 1988), it is proposed (Schleyer 1990). Hence, the isomeric distribution of cer- that there are three petroleum systems in the study area tain diamondoids could be sensitive to the source rock (Fig.  8). The first is in the shallow part of the Anadarko lithology. In particular, the alkylated diamantine infers Basin (Group-1), where the averaged measured Ro value source rock facies by comparing the relative abundance of the Woodford Shale is 1.2% (Cardott 2014a, b), which is of three isomers of dimethyldiamantanes to distinguish within the Rc range determined for the condensates based different kerogen contributions (e.g., II-carbonate, type on methyl adamantine index (MAI) values. The Rc from the II marl, and type III) (Schulz et al. 2001). According to MAI values is provided in Table 3. Therefore, the Group-1 ternary plots developed for identifying source rock facies, condensates were generated in situ. The second is in the most of the Group-1 and Group-3 samples plot within Nemaha area (Group-2; Logan County and western Payne marine shale polygon, while Group-2 oils are plotted in County), where the average measured Ro value of the Wood- between marine shale and carbonates polygon (Fig. 6a). ford Shale is 0.76%, which is within the Rc range determined Such observations support biomarker and C7 star dia- for the oils based on methylphenanthrane index (MPI) val- grams, with Group-1 and Group-3 likely sourced from ues. The Rc from the MPI values is provided in Table 3. The marine shale of the Woodford Shale Formation, and oil samples in this system share significant Mississippian Group-2 a mixture of the two end members. and Woodford source signatures and appear to be mixtures Unlike biomarkers, diamondoids in crude oils and of Woodford- and Mississippian-derived oils that have prob- source rocks are structurally very different from their ably been generated in situ. The third petroleum system is in probable precursors in living organisms. Diamondoids the southern Oklahoma (Group-3; Garvin County); the Rc of are good thermal maturity indicators for high-maturity oils is 0.81% in average (Table 3). This observation suggests samples (over 1.1% Ro) when biomarker thermal matu- these oils probably migrated short distances through the cen- rity indicators already thermally destroyed. Hydrocarbon tral Oklahoma faults zone from deeper Woodford Shale in mixing and extent of cracking are usually accessed by the basin to the reservoirs. Schmoker (1988) proposed the comparing methyldiamantane versus stigmastane (C Woodford Shale in Caddo County, Canadian County, and sterane) biomarker (Dahl et al. 1999). Figure 6b shows Grady County, Oklahoma (“area 3” in Schmoker’s paper) the different oil groups and their content of methyldia- went into the oil window circa 260 Ma (late Permian). This mondoid versus stigmastane. Group-1 samples are clearly area might be the kitchen for those old Woodford-type oils, enriched in diamondoids and depleted in stigmastane which migrated via some faults or other pathways formed indicating strong extent of oil cracking, whereas Group-2 during the Ouachita–Marathon orogeny (starting from Mid- oils are depleted in diamondoids which suggest low- dle to Late Pennsylvanian until early Permian). Such type maturity stage without oil cracking yet. Group-3 oils are of migration has been previously proposed by Burruss and depleted in diamondoids and rich in stigmastane. Moreo- Hatch (1989) and Jones and Philp (1990) to suggest these ver, Group-3 oils plot at the diamondoid baseline, which oils may have migrated from the more mature parts of the has been defined from immature rock extracts. This sug- Anadarko Basin in southern Oklahoma. gests that Group-3 oils were migrated likely from source rocks in deep Anadarko Basin as the source rock was not that mature. From a petroleum systems perspective, 5 Conclusions such hydrocarbon charge trend coincides with previous studies that postulated that oils in the southern part of Light hydrocarbon geochemistry provides an effective tool Oklahoma are a result of long-distance migration from to elucidate hydrocarbon source, maturity, and secondary the depocenter of the Anadarko Basin, whereas oils east alterations within Woodford–Mississippian tight reservoirs of the Nemaha Uplift are a result of localized hydrocar- across the Anadarko Basin, Anadarko Shelf, and Cherokee bon charge with no contribution from deep Anadarko (Al Platform of North-Central Oklahoma by the following: Atwah et al. 2017; Wang and Philp 2019). Moreover, this explains the inconsistent signature between the isoheptane 1 3 Group-1 Petroleum Science (2020) 17:582–597 595 Osage Alfalfa Woods 0.86%Ro Noble Garfield Anadarko Shelf Pawnee 0.82%Ro Major ~0.76%Ro Group-2 Group-1 (in-situ) 0.83%Ro Payne oewey ~1.2%Ro for WDFD Rock (Cardott, 2014a) Kingfisher 1.7% Rc Logan ~1.3%Rc for condensates Blaine 1.5% Rc 0.59%Ro 1.2% Rc Lincoln Cherokee Group-2 (in-situ) 0.86%Ro Platform custer 1.3% Rc ~0.76%Ro for WDFD Rock (Wang & Philp, 2019) Oklahoma Canadian 1.3% Rc ~0.76%Rc for tight oils 0.48%Ro 0.81%Ro Anadarko Basin Group-3 (migrated) washita Pottawatomie Cleveland WDFD-sourced reservoir (Jones & Philp, 1989) Seminole Caddo ~0.79%Rc for conventional oils Grady Mcclain Devon Woodford Cores Kiowa Kitchen (?) “Old” WDFD-sourced OGS Woodford Cores oils: ~0.81Rc Pontotoc Arvin Tight Oils Comanche (?) Group-3 Condensates Stephens 50 km Murray Tillman Johnston Carter “Old” WDFD-Sourced Oils Fig. 8 Petroleum system and proposed migration pathway of central Oklahoma (with the Woodford rock maturity in measured Ro %). Devon = Devon Energy. OGS = Oklahoma Geological Survey 1. Two diagnostic molecular fingerprints for two petroleum Woodford-sourced oils (Group-3) and central Oklahoma source rocks, Mississippian mudrocks and Woodford oils (Group-2). Shale, based on light hydrocarbons have been captured and further convinced by biomarker and diamondoid Acknowledgements The authors would like to express their thanks to evidence; National Natural Science Foundation of China (No. 41802152), Natu- 2. Condensates produced from the Woodford–Mississip- ral Science Foundation of Hubei Province, China (No. 2017CFB321), pian tight reservoir within the Anadarko Basin (Group- Open Fund of Key Laboratory of Exploration Technologies for Oil and 1) exhibit a distinct fingerprint and sourced from the Gas Resources (Yangtze University), Ministry of Education, China (No. K2017-18), Open Foundation of Top Disciplines in Yangtze Uni- Woodford Shale; versity, Open Fund of State Key Laboratory of Petroleum Resources 3. Tight oil from the Woodford–Mississippian tight reser- and Prospecting, and China University of Petroleum, Beijing (No. voir on the Cherokee Platform (east of Nemaha Uplift) PRP/open-1605) for providing financial support. The authors would (Group-2) exhibits a “mixed source” fingerprint and also like to recognize the Devon Energy for their generous donation of samples and additional information. Thanks are due to Dr. Paul Philp, in situ sourced by Mississippian mudrocks and Wood- Dr. Thanh Nguyen, and Dr. Roger Slatt for their valuable comments ford Shale with variable contribution; and suggestions. 4. Crude oil sampled from conventional reservoirs in southern Oklahoma (Group-3) was derived from the Open Access This article is licensed under a Creative Commons Attri- Woodford Shale of the deep Anadarko Basin via long- bution 4.0 International License, which permits use, sharing, adapta- tion, distribution and reproduction in any medium or format, as long distance migration; as you give appropriate credit to the original author(s) and the source, 5. Thermal maturity based on light hydrocarbon parame- provide a link to the Creative Commons licence, and indicate if changes ters indicates that condensates from the Anadarko Basin were made. 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