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ABSTRACT

Organic-rich Mississippian carbonates and oil samples from wells completed in the Mississippian and Woodford zones in northern Oklahoma were sampled and geochemically assessed to evaluate charge history. Rock and oil samples were collected from the Cherokee platform and the Anadarko shelf. Samples were analyzed using gas chromatography and gas chromatography-mass spectrometry (GC-MS) techniques for quantitative analysis of diamondoids and saturate and aromatic biomarkers. Results indicate Mississippian hydrocarbon source rocks have generation potential and reached the early oil window thermal maturity. Extracted bitumen from Mississippian rocks and related oils show unique biomarker signatures such as the presence of extended tricyclic terpanes and high input of C27 relative to C28 and C29 in regular and rearranged steranes. The extent of cracking, as measured by diamondoids, reveals a dramatic change in diamondoids concentration between areas east and west, respectively, of the Nemaha uplift. The higher concentration of diamondoids and biomarkers observed west of the Nemaha uplift indicates mixing of uncracked oil with cracked oil migrating out of the Anadarko Basin. This mix of uncracked and cracked oils west of the uplift suggests episodic hydrocarbon charge and a long-distance component to the migration model. In contrast, the Mississippian samples from east of the Nemaha uplift are depleted in diamondoids, suggesting limited migration distance and localized hydrocarbon generation under lower thermal stress.

INTRODUCTION

The Mississippian carbonate section in northern Oklahoma and southern Kansas contains prolific petroleum reservoirs that produce large volumes of oil, especially since the onset of horizontal drilling and multistage hydraulic fracturing technology (Boyd, 2012). Oil and gas fields producing from Mississippian carbonate reservoirs extend across large areas of Oklahoma and Kansas (Figure 1). Informally, the oil- and gas-producing Mississippian carbonates are known as the Mississippian play, with specific reservoir intervals informally labeled as “Mississippian chat,” “Mississippian chert,” or “Mississippian limestone.” Producing intervals within the Mississippian chat have been characterized as having dual porosity types (matrix and fracture) with porosity averaging between 25% and 30%, permeability ranging from 0.1 to 50 millidarcies (mD), and associated salt water production with the oil and gas (Rogers, 2001; Boyd, 2008, 2012). Mississippian limestone sections have much lower porosity that often averages less than 5% and permeability in the nano and microdarcy range (LeBlanc, 2014; Flinton, 2015; Vanden Berg and Grammer, 2015; Jaeckel, 2016). Both high- and low-porosity and permeability Mississippian reservoirs are characterized as self-sealed by the change from more porous to lower porosity carbonate facies, and trapped by a combination of structural and stratigraphic mechanisms (Adler et al., 1987).

Figure 1.

Major Mississippian oil and gas fields across Oklahoma and Kansas. Contour lines represent Mississippian (pre-Chester) thickness. Modified from Adler et al. (1987).

Figure 1.

Major Mississippian oil and gas fields across Oklahoma and Kansas. Contour lines represent Mississippian (pre-Chester) thickness. Modified from Adler et al. (1987).

Because the Mississippian carbonate section is stratigraphically superjacent to the organic-rich Woodford Shale, regional studies have assumed that the Woodford Shale, which is a regional hydrocarbon source rock within the southern midcontinent region, charged Mississippian reservoirs (Burruss and Hatch, 1989; Dolton and Finn, 1989). However, Mississippian carbonate reservoirs are known for their heterogeneity with respect to reservoir quality as well as produced fluids. Hence, hydrocarbons from Mississippian reservoirs are chemically heterogeneous and cannot be explained solely by a single Woodford Shale source rock model (Wang and Philp, 1997).

Geochemical studies of oil and related source rocks within Oklahoma have been very broad in terms of petroleum systems analysis. In these studies, Mississippian and Devonian oils and organic-rich rocks were studied geochemically as one petroleum system and compared with either older or younger geologic successions such as the Silurian and Pennsylvanian petroleum systems (Engel et al., 1988; Burruss and Hatch, 1989; Jones and Philp, 1990). However, Wang and Philp (1997) noted chemical variations between produced oils and rock samples taken from the Lower Mississippian (Osagean) when compared with samples from the Woodford Shale. Moreover, they identified the most distinctive biomarker characteristic of Lower Mississippian samples, which is a high abundance of extended tricyclic terpanes that reaches up to C45 (Wang and Philp, 1997). In a subsequent study, the presence of extended tricyclic terpanes within samples of the organic-rich Lower Mississippian interval was attributed to a marine algal origin, possibly accompanied by algal bloom events that occurred during Early Mississippian (Kim and Philp, 2001).

The aim of this study is to evaluate the hydrocarbon generation potential and the thermal maturity of the dark-colored Mississippian carbonate facies in north–central Oklahoma (Figure 2) and to investigate the origin of crude oil produced from both Mississippian and Woodford Shale intervals. A set of Mississippian limestone samples taken from cores were assessed for total organic carbon (TOC), total inorganic carbon (TIC), macerals description, vitrinite reflectance (%VRo) and Rock–Eval pyrolysis. Potential source rocks were then analyzed along with crude-oil samples for aromatic and saturate biomarkers, together with diamondoids. Geochemical assessment based on thermal maturity of crude oil samples was compared to regional depositional and structural patterns, with the aim to better understand dynamics of hydrocarbon charge to the Mississippian reservoirs.

Figure 2.

Map of study area showing approximate locations and county names where core and oil samples were collected for this study, including east of Nemaha uplift (Payne and Logan counties) and west of Nemaha uplift (Woods and Alfalfa counties).

Figure 2.

Map of study area showing approximate locations and county names where core and oil samples were collected for this study, including east of Nemaha uplift (Payne and Logan counties) and west of Nemaha uplift (Woods and Alfalfa counties).

GEOLOGICAL SETTING

The tectonic setting of the North American continent (Laurussia) during the Early Mississippian featured active and passive shelf edges (Gutschick and Sandberg, 1983). The southern margin of Laurussia was dominated by a carbonate shelf-ramp setting along the passive margin of the Ouachita embayment (Lane and De Keyser, 1980; Gutschick and Sandberg, 1983; Mazzullo et al., 2011, 2013). The eastern and western margins were bounded by three extended foreland depressions formed by Neo-Acadian, Ellesmerian, and Antler orogenesis (Lane and De Keyser, 1980; Gutschick and Sandberg, 1983). Tectonically active edges bordering these foreland basins were accompanied by convergence in the west with the Pacific plate, to the east by Africa and Europe, and to the south by the South American plate (Gutschick and Sandberg, 1983). The convergence and associated compression resulted in a series of orogenies, namely, Acadian orogeny (east), Antler orogeny (west), and the proto-Ouachita orogeny (Gutschick and Sandberg, 1983, and references therein). By the Late Mississippian, collision between Gondwana and Euramerica resulted in uplift of the subducted complex and an increased relief on the Ouachita orogeny, which increased siliciclastic sediment supply to the cratonic basins (Curtis and Champlin, 1959; Walper, 1977).

During the Early to mid-Mississippian, Oklahoma and most of the southern margin of the North America continent was covered with an extensive carbonate platform (Figure 3; Gutschick and Sandberg, 1983). The wide carbonate shelf margin was shallow to intermediate water depth and warm as a result of its subtropical setting (Curtis and Champlin, 1959; Gutschick and Sandberg, 1983). More specifically, present-day Oklahoma was close to the equator around 15° south latitude. Based on the regional tectonic setting and paleogeography during the Mississippian, the southwest–northeast trending Transcontinental arch was bounded by a subparallel-oriented carbonate shelf, starved basins, and orogenic highlands, respectively (Figure 3; Lane and De Keyser, 1980; Gutschick and Sandberg, 1983; Noble, 1993). More recent interpretations highlight the influence of local tectonics on depositional features and propose a carbonate ramp setting during the Early Mississippian (Mazzullo et al., 2011, 2013; Boardman et al., 2013).

Figure 3.

Proposed depositional model of the midcontinent region during Early Mississippian, modified from Lane and De Keyser (1980).

Figure 3.

Proposed depositional model of the midcontinent region during Early Mississippian, modified from Lane and De Keyser (1980).

The discussed paleogeographic and paleobathymetric settings during the Mississippian favored development of hydrocarbon source rocks. Moreover, both isotopic and petrographic data suggest that Lower Mississippian carbonates in Oklahoma were deposited within low-energy outer-ramp settings (Koch et al., 2014). Similarly, carbonate hydrocarbon source rocks in the Mississippian section are documented in other basins, such as the Lodgepole Limestone in the Williston Basin (Jiang et al., 2001).

SAMPLES AND METHODS

Rock samples were obtained from cuttings and cores recovered from Mississippian-producing wells in north–central Oklahoma. A total of 12 oil samples were collected, including some from the same intervals that provided rock samples, to ensure better source–oil correlation (Figure 4). Four oil samples were collected from Alfalfa and Woods counties in northwestern Oklahoma, whereas eight oil samples together with cuttings and core samples were obtained from Logan and Payne counties in central Oklahoma (Figure 2). Stratigraphically, samples were collected from the Lower Mississippian carbonates and the Woodford Shale (Table 1; Figure 4). Cores were examined and dark-colored and finer grained intervals were sampled. A total of 61 samples were collected and screened for richness in organic carbon, resulting in a representative subset of 18 rock samples for further analyses.

Figure 4.

Generalized stratigraphy column of northern Oklahoma showing oil and source rock sampling intervals.

Figure 4.

Generalized stratigraphy column of northern Oklahoma showing oil and source rock sampling intervals.

Table 1.

Details of both rock and oil samples used in this study.

Sample IDSample TypeCountyFormationDepth (ft)
Ad-Lo-1CoreLoganLower Mississippian5570
Ad-Lo-2CoreLoganLower Mississippian5589
Ad-Lo-3CoreLoganLower Mississippian5633
Ad-Lo-4CoreLoganLower Mississippian5701
Ad-Lo-5CoreLoganLower Mississippian5820
Ad-Lo-6OilLoganLower Mississippian6250
Da-Wo-1OilWoodsMississippian (Meramec)5565
El-Py-1CorePayneLower Mississippian4365
El-Py-2CorePayneLower Mississippian4462
El-Py-3OilPayneLower Mississippian4829
Ho-Py-1CuttingPayneWoodford Shale5155
Ho-Py-2CuttingPayneWoodford Shale5160
Ho-Py-3CuttingPayneWoodford Shale5165
Ho-Py-4CuttingPayneWoodford Shale5170
Je-Py-1OilPayneLower Mississippian3280
Ka-Al-1OilAlfalfaMississippian (Meramec)5924
Me-Py-1OilPayneWoodford Shale3450
Ri-Wo-1OilWoodsMississippian (Osage)5307
St-Al-1OilAlfalfaMiddle Mississippian5670
To-Py-1OilPayneLower Mississippian3900
Wd-Py-1CorePayneWoodford Shale3367
Wd-Py-2CorePayneWoodford Shale3381
Wh-Lo-1OilLoganLower Mississippian5632
Wh-Lo-2OilLoganWoodford Shale5785
Wi-Py-1CorePayneLower Mississippian5144
Wi-Py-2CorePayneLower Mississippian5157
Wi-Py-3CorePayneLower Mississippian5162
Wi-Py-4CorePayneLower Mississippian5185
Wi-Py-5CorePayneLower Mississippian5281
Wi-Py-6OilPayneLower Mississippian5656
Sample IDSample TypeCountyFormationDepth (ft)
Ad-Lo-1CoreLoganLower Mississippian5570
Ad-Lo-2CoreLoganLower Mississippian5589
Ad-Lo-3CoreLoganLower Mississippian5633
Ad-Lo-4CoreLoganLower Mississippian5701
Ad-Lo-5CoreLoganLower Mississippian5820
Ad-Lo-6OilLoganLower Mississippian6250
Da-Wo-1OilWoodsMississippian (Meramec)5565
El-Py-1CorePayneLower Mississippian4365
El-Py-2CorePayneLower Mississippian4462
El-Py-3OilPayneLower Mississippian4829
Ho-Py-1CuttingPayneWoodford Shale5155
Ho-Py-2CuttingPayneWoodford Shale5160
Ho-Py-3CuttingPayneWoodford Shale5165
Ho-Py-4CuttingPayneWoodford Shale5170
Je-Py-1OilPayneLower Mississippian3280
Ka-Al-1OilAlfalfaMississippian (Meramec)5924
Me-Py-1OilPayneWoodford Shale3450
Ri-Wo-1OilWoodsMississippian (Osage)5307
St-Al-1OilAlfalfaMiddle Mississippian5670
To-Py-1OilPayneLower Mississippian3900
Wd-Py-1CorePayneWoodford Shale3367
Wd-Py-2CorePayneWoodford Shale3381
Wh-Lo-1OilLoganLower Mississippian5632
Wh-Lo-2OilLoganWoodford Shale5785
Wi-Py-1CorePayneLower Mississippian5144
Wi-Py-2CorePayneLower Mississippian5157
Wi-Py-3CorePayneLower Mississippian5162
Wi-Py-4CorePayneLower Mississippian5185
Wi-Py-5CorePayneLower Mississippian5281
Wi-Py-6OilPayneLower Mississippian5656

The methods used in this study are summarized in Figure 5. Rock samples were screened using Rock–Eval pyrolysis and carbon analysis (i.e., organic and inorganic carbon) at GeoMark Research Ltd (Humble, Texas). Rock samples with good hydrocarbon generation potential as determined by TOC, S1 and S2 were prepared for optical organic microscopy and vitrinite reflectance analysis.

Figure 5.

Schematic workflow of the laboratory analysis. TOC = total organic carbon; GC-FID = gas chromatography flame ionization detector; GC-MS = gas chromatography-mass spectrometry; GC-MS-MS = gas chromatography equipped with triple quadrupole spectrometer.

Figure 5.

Schematic workflow of the laboratory analysis. TOC = total organic carbon; GC-FID = gas chromatography flame ionization detector; GC-MS = gas chromatography-mass spectrometry; GC-MS-MS = gas chromatography equipped with triple quadrupole spectrometer.

Rock samples were reduced to small chips approximately 5–10 mm in length and mounted to 1-inch (2.5 cm) epoxy pellets. These polished rock pellets were examined using a Nikon optical microscope equipped with a CRAIC MP-2TM Microscope Photometer and ultraviolet light source. About 25 reflectance measurements per sample were recorded for both vitrinite (VRo) and solid bitumen (BRo) following standards of dispersed vitrinite analysis in sedimentary rocks (ASTM, 2014). Rock samples were finely powdered and bitumen was extracted using an accelerated solvent extractor with dichloromethane solvent. Rock extract and oil sample analyses were performed at Biomarker Technologies, Inc. (Rohnert Park, California). Samples were fractionated into saturate and aromatic hydrocarbons using silica-gel column chromatography. Afterword, the saturate fraction was spiked with an internal standard (5β-cholane and deuterated diamondoids), and the normal alkanes removed from the saturate fraction using silicalite (zeolite). Saturate and aromatic fractions were analyzed using GC-MS and gas chromatography-tandem mass spectrometry (GC-MS-MS) instruments to obtain biomarker and diamondoid concentrations. Data were processed using both MassHunter and ChemStation software. Concentrations were derived from peak height and area of targeted markers and compared with internal standards and an external standard (Stanford-1) for quality control. In this study, biomarkers and diamondoids are reported as concentrations (ppm) or normalized ratios.

To obtain the overall n-alkanes and isoprenoids distribution profile, samples were analyzed using an Agilent HP 6890 gas chromatography-flame ionization detector (GC-FID), equipped with a DB-1-fused silica column 30 m in length with an internal diameter of 0.25 mm and film thickness (df) of 0.25 μm (30 m × 0.25 mm × 0.25 μm) with hydrogen as a carrier gas, and oven programmed with an initial temperature of 50°C for 1 minute, an increase of 10°C/minute up to a maximum temperature of 320°C and held at maximum temperature for 15 minutes. Analyses of biomarkers and diamondoids of the saturate and aromatic fractions were conducted using an Agilent 7890 gas chromatograph interfaced to an Agilent 5975C mass selective detector (GC-MS), with a DB-1-fused silica column of dimensions 60 m × 0.25 mm × μm, and helium as a carrier gas. Moreover, the GC-MS oven was programmed at an initial temperature of 35°C for 2 minutes and increased at a rate of 2°C/minute to 80°C, then 3°C/minute from 80°C to 320°C, followed by 15 minutes at 320°C. Sterane biomarkers were further analyzed using an Agilent 7890-7000B triple quadrupole (GC-MS-MS), equipped with the DB-1-fused silica column of dimensions 60 m × 0.25 mm × 0.25μm, and oven programmed for initial temperature of 80°C for 1 minute, then increased by 2°C/minute to 320°C, followed by 5 minutes at 320°C. Helium was used as a carrier gas with flow rate of 2.25 mL/minute, and in the second quadrupole, nitrogen was used as collision gas. The GC-MS-MS was run in parent–daughter mode monitoring transitions from C26 up to C30 of regular and rearranged steranes (i.e., m/z 358 → 217, 372 → 217, 386 → 217, 400 → 217, and 414 → 217).

RESULTS AND DISCUSSION

Source Rock Potential

Bulk geochemical parameters are summarized in Table 2. Dark mudrock intervals within the Mississippian carbonate section have total organic carbon (TOC) values ranging from 0.8 wt. % (Wi-Py-4) to 2.6 wt. % (Ad-Lo-5), and average 1.4 wt. % TOC. Woodford Shale samples are notably higher in organic carbon than Mississippian samples, with TOC in the Woodford Shale ranging from 4.4 wt. % (Ho-Py-2) to 8.4 wt. % (Ho-Py-1), and averaging at 7.9 wt. % (Table 2). Similarly, free hydrocarbons as measured by the Rock–Eval S1 peak are generally lower in Mississippian samples (average 0.8 mg hydrocarbons per total rock gram [HC/g], and higher in Woodford Shale samples [average 3.6 mg HC/g]), Using a modified Van Krevelen diagram derived from pyrolysis parameters hydrogen index (HI) and oxygen index (OI), Mississippian samples plot within the Type-II kerogen field, whereas Woodford Shale samples plot as Type-I marine kerogen (Figure 6).

Figure 6.

(A) Modified Van Krevelen diagram showing kerogen type of potential Mississippian source rock and Woodford Shale samples. (B) Kerogen conversion measured from plotting Rock–Eval parameters (i.e., production index (S1/(S1 + S2)) vs. Tmax).

Figure 6.

(A) Modified Van Krevelen diagram showing kerogen type of potential Mississippian source rock and Woodford Shale samples. (B) Kerogen conversion measured from plotting Rock–Eval parameters (i.e., production index (S1/(S1 + S2)) vs. Tmax).

Table 2.

Carbon analysis, Rock–Eval pyrolysis and vitrinite reflectance data of rock samples.

Sample IDCarbonate (wt. %)TOC (wt. %)S1 (mg HC/g)S2 (mg HC/g)Tmax (°C)Measured %Ro*Calculated %Ro**Hydrogen Index (S2× 100/TOC)Oxygen Index (S3× 100/TOC)Production Index (S1/S1+S2)
Ad-Lo-134.061.331.153.064430.770.81230380.27
Ad-Lo-242.420.990.582.464450.840.85249420.19
Ad-Lo-336.591.171.092.974440.810.83254400.27
Ad-Lo-439.501.290.823.274400.820.76253330.20
Ad-Lo-538.042.581.2711.734410.860.78455220.10
El-Py-144.502.070.8310.234310.750.60494220.08
El-Py-255.070.870.673.014400.810.76348530.18
Ho-Py-18.365.0733.644380.710.7240260.13
Ho-Py-24.372.6420.694370.710.71474110.11
Ho-Py-35.483.1725.944330.710.6347390.11
Ho-Py-45.262.3924.794370.720.7147180.09
Wd-Py-13.857.413.9744.454420.820.8060060.08
Wd-Py-26.308.343.2342.464360.810.6950950.07
Wi-Py-122.141.930.717.304370.740.71378180.09
Wi-Py-246.061.250.594.194420.780.80335300.12
Wi-Py-321.361.030.292.164350.730.67210490.12
Wi-Py-435.890.830.432.394430.790.81287580.15
Wi-Py-540.211.300.773.854440.820.83296360.17
Sample IDCarbonate (wt. %)TOC (wt. %)S1 (mg HC/g)S2 (mg HC/g)Tmax (°C)Measured %Ro*Calculated %Ro**Hydrogen Index (S2× 100/TOC)Oxygen Index (S3× 100/TOC)Production Index (S1/S1+S2)
Ad-Lo-134.061.331.153.064430.770.81230380.27
Ad-Lo-242.420.990.582.464450.840.85249420.19
Ad-Lo-336.591.171.092.974440.810.83254400.27
Ad-Lo-439.501.290.823.274400.820.76253330.20
Ad-Lo-538.042.581.2711.734410.860.78455220.10
El-Py-144.502.070.8310.234310.750.60494220.08
El-Py-255.070.870.673.014400.810.76348530.18
Ho-Py-18.365.0733.644380.710.7240260.13
Ho-Py-24.372.6420.694370.710.71474110.11
Ho-Py-35.483.1725.944330.710.6347390.11
Ho-Py-45.262.3924.794370.720.7147180.09
Wd-Py-13.857.413.9744.454420.820.8060060.08
Wd-Py-26.308.343.2342.464360.810.6950950.07
Wi-Py-122.141.930.717.304370.740.71378180.09
Wi-Py-246.061.250.594.194420.780.80335300.12
Wi-Py-321.361.030.292.164350.730.67210490.12
Wi-Py-435.890.830.432.394430.790.81287580.15
Wi-Py-540.211.300.773.854440.820.83296360.17
*

This represent both vitrinite reflectance and corrected solid bitumen reflectance using Landis and Castaño (1995) calibration.

**

Calculated vitrinite reflectance equivalent using Tmax formula: (0.018 × Tmax) – 7.16.

Moreover, petrographic examination reveals that Mississippian kerogen is dominantly amorphous and lack identifiable organic structures. Conversely, Woodford Shale kerogen is enriched in marine alginite macerals with some preserved structures of telalginite (i.e., Tasmanites), which are associated with Type-I marine kerogen (Figure 7; Cook and Sherwood, 1991). However both Mississippian and Woodford Shale samples are similar in that they contain solid bitumen filling elongated microfractures in the Mississippian samples and are occurring as wispy bodies and isolated clasts in the Woodford Shale.

Figure 7.

Photomicrographs of macerals in both organic-rich Mississippian carbonate and Woodford Shale, examined under reflected white light and fluorescence light (UV) with oil immersion; scale bar is 25 μm. Am = Amamorphous organic matter fused with the rock matrix; SB = solid bitumen filling microfracture network; Alg = alginite (possibly prasinophyte alginate); T = telalginite (Tasmanites).

Figure 7.

Photomicrographs of macerals in both organic-rich Mississippian carbonate and Woodford Shale, examined under reflected white light and fluorescence light (UV) with oil immersion; scale bar is 25 μm. Am = Amamorphous organic matter fused with the rock matrix; SB = solid bitumen filling microfracture network; Alg = alginite (possibly prasinophyte alginate); T = telalginite (Tasmanites).

Thermal maturity was assessed on both kerogen and extracted bitumen. Both Mississippian and Woodford Shale samples have reached the early to peak oil window with vitrinite reflectance values ranging from 0.7 to 0.9 %VRo, and Tmax ranging from 431°C to 445°C (Table 2). Similarly, maturity indicators of extracted bitumen suggest that these liquids have reached the early oil window, with the ratios of triaromatic and monoaromatic steroids averaging 0.4 and 0.2, respectively (Table 3).

Table 3.

Selected molecular markers and ratios of rock extracts and oil samples.*

     TerpaneSteraneAromatic Steroids
Sample IDOEP*Pr/PhPr/n-C17Ph/n-C18TetC24/HopBisnorh op/HopExtended TTC21/(C21 + C22)C22/(C22 + C27)Dia/RegC27/S29MA(I)/M A(I + II)TA(I)/TA(II)
Ad-Lo-50.941.241.241.240.350.570.960.230.390.351.320.190.54
Ad-Lo-60.981.461.461.460.340.470.910.260.380.301.190.230.52
Da-Wo-10.961.571.571.570.170.060.500.420.530.270.680.190.33
El-Py-31.040.770.770.770.250.390.820.310.340.460.980.160.27
Je-Py-11.021.651.651.650.160.110.730.400.440.280.870.200.34
Ka-Al-10.961.501.501.500.190.130.710.410.530.270.690.270.49
Me-Py-11.011.661.661.660.160.120.680.420.490.260.540.220.38
Ri-Wo-11.011.401.401.400.140.070.430.450.450.240.660.170.25
St-Al-10.991.611.611.610.190.070.630.440.500.240.790.240.45
To-Py-10.981.651.651.650.150.120.660.400.340.241.060.170.31
Wd-Py-11.021.391.391.390.220.150.600.460.600.350.320.240.54
Wh-Lo-10.951.531.531.530.130.100.720.430.440.240.750.200.39
Wh-Lo-21.031.481.481.480.160.100.730.390.450.260.840.210.38
Wi-Py-10.971.251.251.250.250.260.780.330.540.261.000.210.36
Wi-Py-61.001.631.631.630.290.090.850.130.320.311.240.270.35
     TerpaneSteraneAromatic Steroids
Sample IDOEP*Pr/PhPr/n-C17Ph/n-C18TetC24/HopBisnorh op/HopExtended TTC21/(C21 + C22)C22/(C22 + C27)Dia/RegC27/S29MA(I)/M A(I + II)TA(I)/TA(II)
Ad-Lo-50.941.241.241.240.350.570.960.230.390.351.320.190.54
Ad-Lo-60.981.461.461.460.340.470.910.260.380.301.190.230.52
Da-Wo-10.961.571.571.570.170.060.500.420.530.270.680.190.33
El-Py-31.040.770.770.770.250.390.820.310.340.460.980.160.27
Je-Py-11.021.651.651.650.160.110.730.400.440.280.870.200.34
Ka-Al-10.961.501.501.500.190.130.710.410.530.270.690.270.49
Me-Py-11.011.661.661.660.160.120.680.420.490.260.540.220.38
Ri-Wo-11.011.401.401.400.140.070.430.450.450.240.660.170.25
St-Al-10.991.611.611.610.190.070.630.440.500.240.790.240.45
To-Py-10.981.651.651.650.150.120.660.400.340.241.060.170.31
Wd-Py-11.021.391.391.390.220.150.600.460.600.350.320.240.54
Wh-Lo-10.951.531.531.530.130.100.720.430.440.240.750.200.39
Wh-Lo-21.031.481.481.480.160.100.730.390.450.260.840.210.38
Wi-Py-10.971.251.251.250.250.260.780.330.540.261.000.210.36
Wi-Py-61.001.631.631.630.290.090.850.130.320.311.240.270.35
*

OEP, odd-to-even predominance (Scalan and Smith, 1970); Pr/Ph, pristine/phytane ratio; TetC24/Hop, C24H42 tetracyclic terpane/hopane ratio; Gam/Hop, gammacerane/hopane ratio; Bisnorhop/Hop, 17α(H), 21β(H)-28,30-bisnorhopane/hopane ratio; HHI, homohopane index = C35αβ(S + R)/(ΣC31 – C35αβ + R); Extended TT, extended tricyclic terpane = extended trycyclic ΣC28–40(S + R)/(ΣC28–40(S + R) + hopane); C21/(C21 + C22), C21αβ sterane/(C21αβ sterane + C22αβ sterane); C22/C22 + C27, C22αβ sterane/(C22αβ steranes + C27αα20R sterane); Dia/Reg, C27βα20S + R diasterane/(C27βα20S + R diasterane/(C27βα20S + R diasterane + C27αα20[S + R] + C27ββ20[S + R] regular steranes); C27/C29, C27αα20R sterane/C29αα20R sterane.

Carbonate source rocks tend generally to have lower TOC (1–5 wt. %) when compared to shale source rocks (Hunt, 1967; Palacas, 1988). Even though our Mississippian carbonate samples averaged 1.4 wt. % TOC and only reached 0.8 %VRo, these Mississippian zones can be classified as potential hydrocarbon source rocks with fair to very good petroleum generation quality (Peters and Cassa, 1994). Furthermore, it is likely that Mississippian source rocks are more effective in terms of hydrocarbon expulsion when compared with Woodford Shale, or that the Woodford Shale is effective at retaining than expelling hydrocarbons. This inference is supported by data provided in Table 2, which include (1) lower pyrolysis-derived values of free hydrocarbons (S1) in Mississippian samples and higher S1 values for Woodford Shale samples, a relationship that could indicate that Woodford Shale samples retain generated hydrocarbons, (2) higher carbonate mineral content in Mississippian samples resulting in a more brittle rock with a propensity to fracture as compared to the Woodford Shale, and (3) solid bitumen structures in Mississippian samples that form connected microstructure pathways, in contrast to Woodford Shale samples containing isolated bitumen clasts (Cardott et al., 2015). This is not to say that the Woodford Shale is not an effective source rock in north–central Oklahoma as a number of studies have reported the organic richness and generative capacity of the Woodford Shale (Comer and Hinch, 1987; Jones and Philp, 1990). Instead, we provide evidence that Mississippian carbonate rocks have generated hydrocarbons in addition to the significant hydrocarbon contribution from the Woodford Shale.

Source Rock n-Alkanes and Biomarkers

Rock extracts of both Mississippian carbonate and Woodford Shale exhibit a similar n-alkane profile typical of marine-derived organic matter. Both samples exhibit unimodal distribution of n-alkanes, maximizing at n-C13. More specifically, Mississippian samples maximize at n-C13 and n-C14, whereas Woodford Shale samples maximize at n-C13 followed by n-C12. Also, Mississippian rocks tend to have slightly lower ratios of both pristane/phytane (Pr/Ph) and odd-to-even predominance (OEP) than Woodford Shale samples (Table 3).

Mississippian source rocks exhibit unique biomarkers and diamondoids that are differentiable of Woodford Shale. Mississippian rock extracts show the presence of extended tricyclic terpanes up to C35, together with high C27 input relative to C28 and C29 regular and rearranged steranes (Figure 8). Such results also coincide with previous studies that examined Mississippian (Osagean) samples from the Anadarko Basin (Wang and Philp, 1997; Kim and Philp, 2001). Also, we observe relatively high bisnorhopane to hopane ratios compared to Woodford sample, which could be reflecting more influence of algal sourced organic matter as opposed to bacterial organic matter input (Table 3; Schoell et al., 1992; Kim and Philp, 2001; Peters et al., 2005). In contrast, the Woodford Shale showed a relatively low abundance of extended tricyclic terpanes (up to C31), together with high C29 input relative to C28 and C27 regular steranes. In the Woodford Shale the abundant C29 regular sterane is believed to be of marine origin as opposed to terrestrial organics input (Jones and Philp, 1990; Wang and Philp, 1997; Romero and Philp, 2012). This observation is further confirmed with the enrichment in C30 sterane (Figure 9).

Figure 8.

Ternary diagram of relative concentrations of ααα-C27, C28, and C29 regular steranes of Woodford Shale and Mississippian carbonate as measured by GC-MS-MS. Plot modified from Moldowan et al. (1985).

Figure 8.

Ternary diagram of relative concentrations of ααα-C27, C28, and C29 regular steranes of Woodford Shale and Mississippian carbonate as measured by GC-MS-MS. Plot modified from Moldowan et al. (1985).

Figure 9.

GC-MS-MS of C27–30 steranes composite mass fragmentogram showing end-members of both Woodford and Mississippian oils. The Woodford end-member oil can be identified by having abundance in both C29ααα 20R biomarkers relative to the rest ααα 20R steranes.

Figure 9.

GC-MS-MS of C27–30 steranes composite mass fragmentogram showing end-members of both Woodford and Mississippian oils. The Woodford end-member oil can be identified by having abundance in both C29ααα 20R biomarkers relative to the rest ααα 20R steranes.

Crude Oil n-Alkanes and Biomarkers

Most of the crude oil samples located east of Nemaha uplift show similar n-alkane profiles maximizing at n-C11–13. Such profiles are believed to be indicative of marine-derived petroleum. Similarly, the Pr/Ph ratio is relatively similar for most of the oil samples, ranging from 1.26 to 1.65, and with average of 1.51. The one exception is sample El-Py-3 that has a Pr/Ph of 0.77. However, oil samples located at Woods and Alfalfa counties show a bimodal n-alkane distribution maximizing at n-C7-9 and n-C11-14. Therefore, bulk chemical characteristics would not be sufficient to depict differences between end-members of Mississippian carbonate and Woodford Shale derived oils (Engel et al., 1988). Hence, we looked for more organic-matter-sensitive biomarkers.

Unlike n-alkanes, biomarker ratios varied among crude oil samples and were useful in delineating end-members of Mississippian and Woodford Shale derived oils (Table 3). Some of the oil samples exhibit the presence of extended tricyclic terpane up to C35 (Figure 10) with the extended tricyclic ratio ranging from 0.4 to 0.9 (Table 3). Moreover, samples such as Ad-Lo-6 and El-Py-3 plot close to C27 sterane and exhibit high input of C27 relative to C28 and C29 steranes (Figure 8). However, Ka-Al-1 and Me-Py-1 samples showed high input of C29 relative to C28 and C27 in both regular and rearranged steranes. Such variations are also observed with other biomarkers such as diasteranes and pregnanes ratios (Table 3).

Figure 10.

Mass chromatogram (m/z 191) of saturate hydrocarbons comparing end-members of Woodford Shale oil and rock samples with Mississippian oil and rock (* is depicting extended tricyclic terpanes).

Figure 10.

Mass chromatogram (m/z 191) of saturate hydrocarbons comparing end-members of Woodford Shale oil and rock samples with Mississippian oil and rock (* is depicting extended tricyclic terpanes).

Source Rock–Crude Oil Correlation

The use of biomarkers is crucial in delineating petroleum systems by establishing source rocks and identifying genetically related oils (Magoon and Dow, 1994; Peters et al., 2005; Curiale, 2008). We observed diagnostic biomarkers that appear to represent the contribution of the Mississippian carbonate source rock. Mississippian carbonate samples and related oils (i.e., Wi-Py-6, Ad-Lo-5, and Ad-Lo-6) exhibit OEP < 1, the presence of the extended tricyclic terpane series up to C35, and high C27 sterane together with relatively high 28,30-bisnorhopane to hopane (Figure 10). Such markers are likely to indicate both carbonate lithology and large input of marine algae and/or an algal blooming event occurring during Mississippian time (De Grande et al., 1993; Kim and Philp, 2001; Peters et al., 2005). Woodford Shale samples and related oils (i.e., Wd-Py-1, Me-Py-1, and Ri-Wo-1) feature OEP > 1, high C29 sterane, and high homopregane relative to pregnanes (Table 3). These markers have been previously observed and are typical of the signature of distal marine shale source rocks (Jones and Philp, 1990; Peters et al., 2005; Romero and Philp, 2012; Wang et al., 2015).

Maturity and Oil Mixing

We examined different series of maturity sensitive compounds in the saturate and aromatic fractions of the oil sample set (Figure 11). Overall maturity of the samples suggest early to middle oil generation stage. Ratios of different epimers of C29 sterane together with monoaromatic steriods indicate that samples have reached a maturity range equivalent to 0.7–0.9 %Ro (Peters and Moldowan, 1993). The triaromatic steroid ratio values vary slightly from 0.25 to 0.54; this range coincides with measured %VRo of the rocks in Table 2 suggesting an early to peak oil stages (Peters et al., 2005). Moreover, phenanthrene and dibenzothiophene together with their alkylated homolog ratios coincide with observed ratios of C29 steranes and aromatic steroids suggesting early to middle oil generation stages (Figure 11; Radke and Welte, 1981; Cassani et al., 1988; Radke and Willsch, 1994; Li et al., 2014). However, these maturity ratios only reflect the maturity of the cyclic hydrocarbons in the range of C12+ and do not capture the contribution and maturity of the light hydrocarbons charge.

Figure 11.

Maturity ratios of Mississippian and Woodford oil samples: (A) C29 20S/(20S + 20R) = C29 aa stigmastane 20S/(20S + 20R), C29ββ/(ββ + αα) C29 stigmastane ββ S/(ββS + ααR); (B) TA(I)/TA(II) = triaromatic steroid ratio (C21 + C22)/(C21 + C22 + C26 + C27 + C28), MA(I)/MA(I + II) = (C) MDR = (4-/4- + 1-methyldibenzothiophene), DMDBTs = (2,6 + 3,6)/(1,4) dimethyldibenzothiophenes; (D) MPI-1 = 1.89 × (2- + 3-) methylphenanthrene/(phenanthrene + 1.26 × (1- + 9-) methylphenanthrene), PP-1 modified = (1- + 9-) methylphenanthrene/(2- + 3-) methylphenanthrene. The ratios of C29 epimers together with monoaromatic steroids indicate these samples reached a maturity equivalent to 0.7–0.9 %Ro (Peters and Moldowan, 1993).

Figure 11.

Maturity ratios of Mississippian and Woodford oil samples: (A) C29 20S/(20S + 20R) = C29 aa stigmastane 20S/(20S + 20R), C29ββ/(ββ + αα) C29 stigmastane ββ S/(ββS + ααR); (B) TA(I)/TA(II) = triaromatic steroid ratio (C21 + C22)/(C21 + C22 + C26 + C27 + C28), MA(I)/MA(I + II) = (C) MDR = (4-/4- + 1-methyldibenzothiophene), DMDBTs = (2,6 + 3,6)/(1,4) dimethyldibenzothiophenes; (D) MPI-1 = 1.89 × (2- + 3-) methylphenanthrene/(phenanthrene + 1.26 × (1- + 9-) methylphenanthrene), PP-1 modified = (1- + 9-) methylphenanthrene/(2- + 3-) methylphenanthrene. The ratios of C29 epimers together with monoaromatic steroids indicate these samples reached a maturity equivalent to 0.7–0.9 %Ro (Peters and Moldowan, 1993).

Biomarkers when supplemented with diamondoids and gasoline range hydrocarbons, all collectively provide an effective tool to unravel cosourcing and oil maturity mixing (Moldowan et al., 2015). Summarized in Table 4 are concentration results of major diamondoid compounds in both oil and rock extract samples, together with selected light hydrocarbon maturity ratios. Whole-oil chromatograms in Figure 12 clearly show different n-alkanes distribution based on sample location, west of Nemaha uplift oil feature a bimodal distribution maximizing at n-C7 and at n-C14, whereas east of Nemaha uplift samples exhibit a unimodal n-alkane distribution with a maxim at n-C11 (Figure 12). Furthermore, samples across the Anadarko shelf exhibit relatively high concentrations of regular C29 sterane and diamondoid compounds, particularly alkylated adamantane and diamantane. Moreover, high ratios of heptane and isoheptane are also observed for oil samples west of the Nemaha uplift (Table 4). Samples located east of the Nemaha uplift contained relatively low concentrations of diamondoid compounds and low ratios of heptane and isoheptane (Table 4), but high concentration of regular C29 sterane. Thermal fragility of C29 sterane, combined with thermal stability of methylated diamantanes, provides insight into the extent of hydrocarbon cracking and mixing (Dahl et al., 1999). Moreover, thermal stability of methylhexanes and n-heptane to their counterpart isomers is used to assess thermal maturity of gasoline range hydrocarbons, with heptane ratio for noncracked oils ranging from 18 to 22, and isoheptane ratio from 0.8 to 1.2, whereas cracked and mature oils exhibit heptane ratios >22 and isohopetane >1.2 (Thompson, 1983). Mississippian-reservoir-produced oils from the Anadarko Shelf west of the Nemaha uplift are a mixture of cracked and noncracked oils, the contribution of cracked oils is indicated by high 3 + 4-methyldiamantane (average of 4.1 ppm) and high heptane and isoheptane ratios (average of 46.7 and 1.4), and the contribution of noncracked oil is evident from the high concentration of C29 sterane (average of 50.4 ppm; Figure 13). In contrast, sampled oils from east of the Nemaha uplift contained low 3 + 4-methyldiamantane (average of 1.8 ppm), low ratios of heptane and isoheptane (average of 29.6 and 0.7), and high C29 sterane (average of 26.1 ppm; Figure 13).

Figure 12.

Whole-oil chromatogram showing n-alkanes distribution of sample Ri-Wo-1 (west of Nemaha uplift) and Ad-Lo-6 (east of Nemaha uplift). Note the bimodal distribution of n-alkanes in the sample located west of Nemaha uplift and the unimodal distribution of n-alkanes in sample east of the Nemaha uplift.

Figure 12.

Whole-oil chromatogram showing n-alkanes distribution of sample Ri-Wo-1 (west of Nemaha uplift) and Ad-Lo-6 (east of Nemaha uplift). Note the bimodal distribution of n-alkanes in the sample located west of Nemaha uplift and the unimodal distribution of n-alkanes in sample east of the Nemaha uplift.

Figure 13.

Extent of cracking determined by comparing concentration of ααα-C29 sterane and 3,4-3 +4-methyldiamantane. Mississippian oil samples collected west of the Nemaha uplift are a mixture of cracked and uncracked oils with an average diamondoid concentration of 4.1 ppm and C29 sterane concentration of 50.4 ppm. Woodford Shale oil samples from east of the Nemaha uplift have an average diamondoid concentration of 1.8 ppm and average C29 sterane concentration of 26.1 ppm.

Figure 13.

Extent of cracking determined by comparing concentration of ααα-C29 sterane and 3,4-3 +4-methyldiamantane. Mississippian oil samples collected west of the Nemaha uplift are a mixture of cracked and uncracked oils with an average diamondoid concentration of 4.1 ppm and C29 sterane concentration of 50.4 ppm. Woodford Shale oil samples from east of the Nemaha uplift have an average diamondoid concentration of 1.8 ppm and average C29 sterane concentration of 26.1 ppm.

Table 4.

Selected diamondoids and biomarker concentration in ppm together with C7 maturity ratios.

Sample ID1 + 2-Methylada mantane1 + 2-Ethyladam antane3 + 4-Methyldia mantaneC29ααα 20R steraneHeptane Ratio*Isoheptane Ratio*
West of Nemaha Uplift (Anadarko Shelf)
Da-Wo-177.841.94.253.757.21.7
Ka-Al-198.446.95.121.750.31.5
Ri-Wo-1121.686.43.685.545.31.3
St-Al-163.438.43.340.834.00.9
East of Nemaha Uplift
Ad-Lo-54629.72.311
Ad-Lo-640.220.92.314.527.90.7
El-Py-331.320.81.749.231.50.7
Je-Py-143.224.81.729.530.10.7
Me-Py-147.623.7226.833.20.8
To-Py-139.119.51.438.628.80.7
Wd-Py-143.4301.310.5
Wh-Lo-132.924.42.240.527.40.5
Wh-Lo-234.8292.138.626.50.5
Wi-Py-13729.21.714.3
Wi-Py-630.920.71.513.831.40.8
Sample ID1 + 2-Methylada mantane1 + 2-Ethyladam antane3 + 4-Methyldia mantaneC29ααα 20R steraneHeptane Ratio*Isoheptane Ratio*
West of Nemaha Uplift (Anadarko Shelf)
Da-Wo-177.841.94.253.757.21.7
Ka-Al-198.446.95.121.750.31.5
Ri-Wo-1121.686.43.685.545.31.3
St-Al-163.438.43.340.834.00.9
East of Nemaha Uplift
Ad-Lo-54629.72.311
Ad-Lo-640.220.92.314.527.90.7
El-Py-331.320.81.749.231.50.7
Je-Py-143.224.81.729.530.10.7
Me-Py-147.623.7226.833.20.8
To-Py-139.119.51.438.628.80.7
Wd-Py-143.4301.310.5
Wh-Lo-132.924.42.240.527.40.5
Wh-Lo-234.8292.138.626.50.5
Wi-Py-13729.21.714.3
Wi-Py-630.920.71.513.831.40.8
*

Heptane Ratio: (100 × n-heptane/cyclohexane + 2-methylhexane + 1,1-dimethylcyclopentane (DMCP)) + 3-methylhexane + 1-cis/s-3-DMCP + 1-trans-3-DMCP + 1-trans-2-DMCP + n-heptane + methylcyclohexane); Isoheptane Ratio: (2-methylhexane + 3-methylhexane/1-cis/s-3-DMCP + 1-trans-3-DMCP + 1-trans-2-DMCP).

The mixed maturity oils west of Nemaha uplift appear to be largely sourced from the Woodford Shale. This observation is supported by the overall biomarkers distribution and ratios shown in Table 3 (Figure 9). However, biomarkers only capture the contribution of low to peak oil maturity hydrocarbons; therefore, the cracked hydrocarbon contribution could have been derived from different source in these oil samples. The cracked hydrocarbon input to west of Nemaha uplift oils remains to be investigated. Particularly, at high-thermal maturity, stage biomarkers are not stable; therefore, the cracked hydrocarbons would not contain any biomarkers to infer their source rock. Hence, using compound-specific isotope analysis of diamondoid (CSIA-D) could provide further insight into the source of the cracked hydrocarbons in oils west of the Nemaha uplift (Moldowan et al., 2015).

Implications to Hydrocarbon Charge History

A long-distance oil migration model out of the Anadarko Basin has been proposed on the basis of light hydrocarbons (Burruss and Hatch, 1989). Moreover, the decrease in toluene of C7 hydrocarbons away from the Anadarko Basin has been attributed to long-distance oil migration (Burruss and Hatch, 1989). Similarly, our data support the long-distance migration hypothesis. However, diamondoids and biomarkers in samples from the Anadarko shelf suggest a more complex hydrocarbon charge history. The latter we hypothesize is due to episodic hydrocarbon charge, which includes an early maturity hydrocarbon charge followed by a later and more mature charge expelled as the Anadarko Basin continued to subside. Additionally, the long migration is supported by %VRo maps, which suggests that the Woodford is immature to generate hydrocarbons within the Anadarko shelf at Woods and Alfalfa counties (Cardott, 1989). Unlike the long-distance component to the migration system that charged the Mississippian of the Anadarko shelf, oil samples from Payne and Logan counties east of the Nemaha uplift appear to result from a relatively isolated charge system with short migration distances. This relatively closed system was dominated by in situ generation under much lower thermal stress as indicated by low diamondoid concentrations and low heptane and isoheptane ratios together with measured values of vitrinite and solid bitumen reflectance (Table 2).

The Nemaha uplift is a Late Mississippian or Early Pennsylvanian paleostructural feature extending from southeastern Nebraska to central Oklahoma. This structurally high feature separates the Cherokee platform in northeastern Oklahoma from the Anadarko Basin and shelf (Dolton and Finn, 1989). The Mississippian section is absent or thin along the Nemaha uplift (Figure 14), thereby restricting its usefulness as a carrier bed for oil migrating northward from the Anadarko Basin. In this tectonic context, occurrence of oil within north–central Oklahoma (i.e., Payne and Logan counties) is likely to be of localized origin with very minimal if any contribution from the Anadarko Basin. Localization is further enhanced by facies change within the Mississippian section from clean carbonate to the north to argillaceous mudrocks to the south (Figure 14), which provided a low-permeability barrier between the Cherokee platform and Arkoma Basin (Andrews, 2007). This interpretation is supported by the low maturity of recovered fluids and rock samples from the Cherokee platform. Any contribution from deeper basins (i.e., Anadarko and Arkoma) would have generated a high-maturity signature with high concentrations of diamondoids. Additionally, because of low permeability in the Woodford Shale, it seems reasonable to expect the oil in the Woodford Shale east of the Nemaha uplift (i.e., Payne and Logan counties) to be generated locally and not the result of long-distance migration.

Figure 14.

Map of Oklahoma showing the absence of Mississippian section in central Oklahoma that resulted from erosion during the Carboniferous, as well as the distribution of the Caney Shale. We propose that erosion of Mississippian carbonate carrier beds along the Nemaha uplift impeded migration of more mature cracked oil from the Anadarko Basin to the Cherokee platform. Likewise, the low-permeability facies of the Caney Shale impeded migration of mature and cracked oil from the Arkoma Basin to the Cherokee platform.

Figure 14.

Map of Oklahoma showing the absence of Mississippian section in central Oklahoma that resulted from erosion during the Carboniferous, as well as the distribution of the Caney Shale. We propose that erosion of Mississippian carbonate carrier beds along the Nemaha uplift impeded migration of more mature cracked oil from the Anadarko Basin to the Cherokee platform. Likewise, the low-permeability facies of the Caney Shale impeded migration of mature and cracked oil from the Arkoma Basin to the Cherokee platform.

CONCLUSIONS

The Devonian–Mississippian Woodford Shale and Lower Mississippian carbonates are important sources of hydrocarbons within north–central Oklahoma. Pyrolysis and reflected light microscopy suggest that, in addition to the well-known potential of the Woodford Shale, organic-rich Lower Mississippian carbonates exhibit good to fair generation potential and have reached the early oil window. Furthermore, hydrocarbon contribution from Lower Mississippian carbonates was revealed by the similar molecular characteristics that Mississippian rock extracts share with some produced oils. The diagnostic biomarker of Lower Mississippian-source rocks is the presence of extended tricyclic terpane homologs up to C35. Such variations in fingerprints we believe reflect both organic matter type and depositional setting.

Mississippian and Woodford oils within the Anadarko shelf and east of Nemaha uplift appear to exhibit different charging histories. Diamondoid concentrations combined with biomarker ratios are indicative of a mixed source for oils recovered from the Anadarko shelf. These reservoirs contain noncracked oils mixed with cracked oil that migrated long distance from the Anadarko Basin. In contrast, samples collected from the Cherokee platform east of the Nemaha uplift (i.e., Payne and Logan counties) are relatively depleted in diamondoids and display unique biomarker characteristics, hence indicating a localized source rock subjected to lower maturation levels. We speculate that erosion of the Mississippian section from the Nemaha uplift (Figure 14) during the Carboniferous contributed to the separation of the Cherokee platform petroleum systems from the Anadarko Basin systems. Facies change within the Mississippian section in eastern Oklahoma facilitated isolation of the Cherokee platform from the Arkoma Basin and thereby blocked the northward migration of more mature cracked oils.

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Figures & Tables

Figure 1.

Major Mississippian oil and gas fields across Oklahoma and Kansas. Contour lines represent Mississippian (pre-Chester) thickness. Modified from Adler et al. (1987).

Figure 1.

Major Mississippian oil and gas fields across Oklahoma and Kansas. Contour lines represent Mississippian (pre-Chester) thickness. Modified from Adler et al. (1987).

Figure 2.

Map of study area showing approximate locations and county names where core and oil samples were collected for this study, including east of Nemaha uplift (Payne and Logan counties) and west of Nemaha uplift (Woods and Alfalfa counties).

Figure 2.

Map of study area showing approximate locations and county names where core and oil samples were collected for this study, including east of Nemaha uplift (Payne and Logan counties) and west of Nemaha uplift (Woods and Alfalfa counties).

Figure 3.

Proposed depositional model of the midcontinent region during Early Mississippian, modified from Lane and De Keyser (1980).

Figure 3.

Proposed depositional model of the midcontinent region during Early Mississippian, modified from Lane and De Keyser (1980).

Figure 4.

Generalized stratigraphy column of northern Oklahoma showing oil and source rock sampling intervals.

Figure 4.

Generalized stratigraphy column of northern Oklahoma showing oil and source rock sampling intervals.

Figure 5.

Schematic workflow of the laboratory analysis. TOC = total organic carbon; GC-FID = gas chromatography flame ionization detector; GC-MS = gas chromatography-mass spectrometry; GC-MS-MS = gas chromatography equipped with triple quadrupole spectrometer.

Figure 5.

Schematic workflow of the laboratory analysis. TOC = total organic carbon; GC-FID = gas chromatography flame ionization detector; GC-MS = gas chromatography-mass spectrometry; GC-MS-MS = gas chromatography equipped with triple quadrupole spectrometer.

Figure 6.

(A) Modified Van Krevelen diagram showing kerogen type of potential Mississippian source rock and Woodford Shale samples. (B) Kerogen conversion measured from plotting Rock–Eval parameters (i.e., production index (S1/(S1 + S2)) vs. Tmax).

Figure 6.

(A) Modified Van Krevelen diagram showing kerogen type of potential Mississippian source rock and Woodford Shale samples. (B) Kerogen conversion measured from plotting Rock–Eval parameters (i.e., production index (S1/(S1 + S2)) vs. Tmax).

Figure 7.

Photomicrographs of macerals in both organic-rich Mississippian carbonate and Woodford Shale, examined under reflected white light and fluorescence light (UV) with oil immersion; scale bar is 25 μm. Am = Amamorphous organic matter fused with the rock matrix; SB = solid bitumen filling microfracture network; Alg = alginite (possibly prasinophyte alginate); T = telalginite (Tasmanites).

Figure 7.

Photomicrographs of macerals in both organic-rich Mississippian carbonate and Woodford Shale, examined under reflected white light and fluorescence light (UV) with oil immersion; scale bar is 25 μm. Am = Amamorphous organic matter fused with the rock matrix; SB = solid bitumen filling microfracture network; Alg = alginite (possibly prasinophyte alginate); T = telalginite (Tasmanites).

Figure 8.

Ternary diagram of relative concentrations of ααα-C27, C28, and C29 regular steranes of Woodford Shale and Mississippian carbonate as measured by GC-MS-MS. Plot modified from Moldowan et al. (1985).

Figure 8.

Ternary diagram of relative concentrations of ααα-C27, C28, and C29 regular steranes of Woodford Shale and Mississippian carbonate as measured by GC-MS-MS. Plot modified from Moldowan et al. (1985).

Figure 9.

GC-MS-MS of C27–30 steranes composite mass fragmentogram showing end-members of both Woodford and Mississippian oils. The Woodford end-member oil can be identified by having abundance in both C29ααα 20R biomarkers relative to the rest ααα 20R steranes.

Figure 9.

GC-MS-MS of C27–30 steranes composite mass fragmentogram showing end-members of both Woodford and Mississippian oils. The Woodford end-member oil can be identified by having abundance in both C29ααα 20R biomarkers relative to the rest ααα 20R steranes.

Figure 10.

Mass chromatogram (m/z 191) of saturate hydrocarbons comparing end-members of Woodford Shale oil and rock samples with Mississippian oil and rock (* is depicting extended tricyclic terpanes).

Figure 10.

Mass chromatogram (m/z 191) of saturate hydrocarbons comparing end-members of Woodford Shale oil and rock samples with Mississippian oil and rock (* is depicting extended tricyclic terpanes).

Figure 11.

Maturity ratios of Mississippian and Woodford oil samples: (A) C29 20S/(20S + 20R) = C29 aa stigmastane 20S/(20S + 20R), C29ββ/(ββ + αα) C29 stigmastane ββ S/(ββS + ααR); (B) TA(I)/TA(II) = triaromatic steroid ratio (C21 + C22)/(C21 + C22 + C26 + C27 + C28), MA(I)/MA(I + II) = (C) MDR = (4-/4- + 1-methyldibenzothiophene), DMDBTs = (2,6 + 3,6)/(1,4) dimethyldibenzothiophenes; (D) MPI-1 = 1.89 × (2- + 3-) methylphenanthrene/(phenanthrene + 1.26 × (1- + 9-) methylphenanthrene), PP-1 modified = (1- + 9-) methylphenanthrene/(2- + 3-) methylphenanthrene. The ratios of C29 epimers together with monoaromatic steroids indicate these samples reached a maturity equivalent to 0.7–0.9 %Ro (Peters and Moldowan, 1993).

Figure 11.

Maturity ratios of Mississippian and Woodford oil samples: (A) C29 20S/(20S + 20R) = C29 aa stigmastane 20S/(20S + 20R), C29ββ/(ββ + αα) C29 stigmastane ββ S/(ββS + ααR); (B) TA(I)/TA(II) = triaromatic steroid ratio (C21 + C22)/(C21 + C22 + C26 + C27 + C28), MA(I)/MA(I + II) = (C) MDR = (4-/4- + 1-methyldibenzothiophene), DMDBTs = (2,6 + 3,6)/(1,4) dimethyldibenzothiophenes; (D) MPI-1 = 1.89 × (2- + 3-) methylphenanthrene/(phenanthrene + 1.26 × (1- + 9-) methylphenanthrene), PP-1 modified = (1- + 9-) methylphenanthrene/(2- + 3-) methylphenanthrene. The ratios of C29 epimers together with monoaromatic steroids indicate these samples reached a maturity equivalent to 0.7–0.9 %Ro (Peters and Moldowan, 1993).

Figure 12.

Whole-oil chromatogram showing n-alkanes distribution of sample Ri-Wo-1 (west of Nemaha uplift) and Ad-Lo-6 (east of Nemaha uplift). Note the bimodal distribution of n-alkanes in the sample located west of Nemaha uplift and the unimodal distribution of n-alkanes in sample east of the Nemaha uplift.

Figure 12.

Whole-oil chromatogram showing n-alkanes distribution of sample Ri-Wo-1 (west of Nemaha uplift) and Ad-Lo-6 (east of Nemaha uplift). Note the bimodal distribution of n-alkanes in the sample located west of Nemaha uplift and the unimodal distribution of n-alkanes in sample east of the Nemaha uplift.

Figure 13.

Extent of cracking determined by comparing concentration of ααα-C29 sterane and 3,4-3 +4-methyldiamantane. Mississippian oil samples collected west of the Nemaha uplift are a mixture of cracked and uncracked oils with an average diamondoid concentration of 4.1 ppm and C29 sterane concentration of 50.4 ppm. Woodford Shale oil samples from east of the Nemaha uplift have an average diamondoid concentration of 1.8 ppm and average C29 sterane concentration of 26.1 ppm.

Figure 13.

Extent of cracking determined by comparing concentration of ααα-C29 sterane and 3,4-3 +4-methyldiamantane. Mississippian oil samples collected west of the Nemaha uplift are a mixture of cracked and uncracked oils with an average diamondoid concentration of 4.1 ppm and C29 sterane concentration of 50.4 ppm. Woodford Shale oil samples from east of the Nemaha uplift have an average diamondoid concentration of 1.8 ppm and average C29 sterane concentration of 26.1 ppm.

Figure 14.

Map of Oklahoma showing the absence of Mississippian section in central Oklahoma that resulted from erosion during the Carboniferous, as well as the distribution of the Caney Shale. We propose that erosion of Mississippian carbonate carrier beds along the Nemaha uplift impeded migration of more mature cracked oil from the Anadarko Basin to the Cherokee platform. Likewise, the low-permeability facies of the Caney Shale impeded migration of mature and cracked oil from the Arkoma Basin to the Cherokee platform.

Figure 14.

Map of Oklahoma showing the absence of Mississippian section in central Oklahoma that resulted from erosion during the Carboniferous, as well as the distribution of the Caney Shale. We propose that erosion of Mississippian carbonate carrier beds along the Nemaha uplift impeded migration of more mature cracked oil from the Anadarko Basin to the Cherokee platform. Likewise, the low-permeability facies of the Caney Shale impeded migration of mature and cracked oil from the Arkoma Basin to the Cherokee platform.

Table 1.

Details of both rock and oil samples used in this study.

Sample IDSample TypeCountyFormationDepth (ft)
Ad-Lo-1CoreLoganLower Mississippian5570
Ad-Lo-2CoreLoganLower Mississippian5589
Ad-Lo-3CoreLoganLower Mississippian5633
Ad-Lo-4CoreLoganLower Mississippian5701
Ad-Lo-5CoreLoganLower Mississippian5820
Ad-Lo-6OilLoganLower Mississippian6250
Da-Wo-1OilWoodsMississippian (Meramec)5565
El-Py-1CorePayneLower Mississippian4365
El-Py-2CorePayneLower Mississippian4462
El-Py-3OilPayneLower Mississippian4829
Ho-Py-1CuttingPayneWoodford Shale5155
Ho-Py-2CuttingPayneWoodford Shale5160
Ho-Py-3CuttingPayneWoodford Shale5165
Ho-Py-4CuttingPayneWoodford Shale5170
Je-Py-1OilPayneLower Mississippian3280
Ka-Al-1OilAlfalfaMississippian (Meramec)5924
Me-Py-1OilPayneWoodford Shale3450
Ri-Wo-1OilWoodsMississippian (Osage)5307
St-Al-1OilAlfalfaMiddle Mississippian5670
To-Py-1OilPayneLower Mississippian3900
Wd-Py-1CorePayneWoodford Shale3367
Wd-Py-2CorePayneWoodford Shale3381
Wh-Lo-1OilLoganLower Mississippian5632
Wh-Lo-2OilLoganWoodford Shale5785
Wi-Py-1CorePayneLower Mississippian5144
Wi-Py-2CorePayneLower Mississippian5157
Wi-Py-3CorePayneLower Mississippian5162
Wi-Py-4CorePayneLower Mississippian5185
Wi-Py-5CorePayneLower Mississippian5281
Wi-Py-6OilPayneLower Mississippian5656
Sample IDSample TypeCountyFormationDepth (ft)
Ad-Lo-1CoreLoganLower Mississippian5570
Ad-Lo-2CoreLoganLower Mississippian5589
Ad-Lo-3CoreLoganLower Mississippian5633
Ad-Lo-4CoreLoganLower Mississippian5701
Ad-Lo-5CoreLoganLower Mississippian5820
Ad-Lo-6OilLoganLower Mississippian6250
Da-Wo-1OilWoodsMississippian (Meramec)5565
El-Py-1CorePayneLower Mississippian4365
El-Py-2CorePayneLower Mississippian4462
El-Py-3OilPayneLower Mississippian4829
Ho-Py-1CuttingPayneWoodford Shale5155
Ho-Py-2CuttingPayneWoodford Shale5160
Ho-Py-3CuttingPayneWoodford Shale5165
Ho-Py-4CuttingPayneWoodford Shale5170
Je-Py-1OilPayneLower Mississippian3280
Ka-Al-1OilAlfalfaMississippian (Meramec)5924
Me-Py-1OilPayneWoodford Shale3450
Ri-Wo-1OilWoodsMississippian (Osage)5307
St-Al-1OilAlfalfaMiddle Mississippian5670
To-Py-1OilPayneLower Mississippian3900
Wd-Py-1CorePayneWoodford Shale3367
Wd-Py-2CorePayneWoodford Shale3381
Wh-Lo-1OilLoganLower Mississippian5632
Wh-Lo-2OilLoganWoodford Shale5785
Wi-Py-1CorePayneLower Mississippian5144
Wi-Py-2CorePayneLower Mississippian5157
Wi-Py-3CorePayneLower Mississippian5162
Wi-Py-4CorePayneLower Mississippian5185
Wi-Py-5CorePayneLower Mississippian5281
Wi-Py-6OilPayneLower Mississippian5656
Table 2.

Carbon analysis, Rock–Eval pyrolysis and vitrinite reflectance data of rock samples.

Sample IDCarbonate (wt. %)TOC (wt. %)S1 (mg HC/g)S2 (mg HC/g)Tmax (°C)Measured %Ro*Calculated %Ro**Hydrogen Index (S2× 100/TOC)Oxygen Index (S3× 100/TOC)Production Index (S1/S1+S2)
Ad-Lo-134.061.331.153.064430.770.81230380.27
Ad-Lo-242.420.990.582.464450.840.85249420.19
Ad-Lo-336.591.171.092.974440.810.83254400.27
Ad-Lo-439.501.290.823.274400.820.76253330.20
Ad-Lo-538.042.581.2711.734410.860.78455220.10
El-Py-144.502.070.8310.234310.750.60494220.08
El-Py-255.070.870.673.014400.810.76348530.18
Ho-Py-18.365.0733.644380.710.7240260.13
Ho-Py-24.372.6420.694370.710.71474110.11
Ho-Py-35.483.1725.944330.710.6347390.11
Ho-Py-45.262.3924.794370.720.7147180.09
Wd-Py-13.857.413.9744.454420.820.8060060.08
Wd-Py-26.308.343.2342.464360.810.6950950.07
Wi-Py-122.141.930.717.304370.740.71378180.09
Wi-Py-246.061.250.594.194420.780.80335300.12
Wi-Py-321.361.030.292.164350.730.67210490.12
Wi-Py-435.890.830.432.394430.790.81287580.15
Wi-Py-540.211.300.773.854440.820.83296360.17
Sample IDCarbonate (wt. %)TOC (wt. %)S1 (mg HC/g)S2 (mg HC/g)Tmax (°C)Measured %Ro*Calculated %Ro**Hydrogen Index (S2× 100/TOC)Oxygen Index (S3× 100/TOC)Production Index (S1/S1+S2)
Ad-Lo-134.061.331.153.064430.770.81230380.27
Ad-Lo-242.420.990.582.464450.840.85249420.19
Ad-Lo-336.591.171.092.974440.810.83254400.27
Ad-Lo-439.501.290.823.274400.820.76253330.20
Ad-Lo-538.042.581.2711.734410.860.78455220.10
El-Py-144.502.070.8310.234310.750.60494220.08
El-Py-255.070.870.673.014400.810.76348530.18
Ho-Py-18.365.0733.644380.710.7240260.13
Ho-Py-24.372.6420.694370.710.71474110.11
Ho-Py-35.483.1725.944330.710.6347390.11
Ho-Py-45.262.3924.794370.720.7147180.09
Wd-Py-13.857.413.9744.454420.820.8060060.08
Wd-Py-26.308.343.2342.464360.810.6950950.07
Wi-Py-122.141.930.717.304370.740.71378180.09
Wi-Py-246.061.250.594.194420.780.80335300.12
Wi-Py-321.361.030.292.164350.730.67210490.12
Wi-Py-435.890.830.432.394430.790.81287580.15
Wi-Py-540.211.300.773.854440.820.83296360.17
*

This represent both vitrinite reflectance and corrected solid bitumen reflectance using Landis and Castaño (1995) calibration.

**

Calculated vitrinite reflectance equivalent using Tmax formula: (0.018 × Tmax) – 7.16.

Table 3.

Selected molecular markers and ratios of rock extracts and oil samples.*

     TerpaneSteraneAromatic Steroids
Sample IDOEP*Pr/PhPr/n-C17Ph/n-C18TetC24/HopBisnorh op/HopExtended TTC21/(C21 + C22)C22/(C22 + C27)Dia/RegC27/S29MA(I)/M A(I + II)TA(I)/TA(II)
Ad-Lo-50.941.241.241.240.350.570.960.230.390.351.320.190.54
Ad-Lo-60.981.461.461.460.340.470.910.260.380.301.190.230.52
Da-Wo-10.961.571.571.570.170.060.500.420.530.270.680.190.33
El-Py-31.040.770.770.770.250.390.820.310.340.460.980.160.27
Je-Py-11.021.651.651.650.160.110.730.400.440.280.870.200.34
Ka-Al-10.961.501.501.500.190.130.710.410.530.270.690.270.49
Me-Py-11.011.661.661.660.160.120.680.420.490.260.540.220.38
Ri-Wo-11.011.401.401.400.140.070.430.450.450.240.660.170.25
St-Al-10.991.611.611.610.190.070.630.440.500.240.790.240.45
To-Py-10.981.651.651.650.150.120.660.400.340.241.060.170.31
Wd-Py-11.021.391.391.390.220.150.600.460.600.350.320.240.54
Wh-Lo-10.951.531.531.530.130.100.720.430.440.240.750.200.39
Wh-Lo-21.031.481.481.480.160.100.730.390.450.260.840.210.38
Wi-Py-10.971.251.251.250.250.260.780.330.540.261.000.210.36
Wi-Py-61.001.631.631.630.290.090.850.130.320.311.240.270.35
     TerpaneSteraneAromatic Steroids
Sample IDOEP*Pr/PhPr/n-C17Ph/n-C18TetC24/HopBisnorh op/HopExtended TTC21/(C21 + C22)C22/(C22 + C27)Dia/RegC27/S29MA(I)/M A(I + II)TA(I)/TA(II)
Ad-Lo-50.941.241.241.240.350.570.960.230.390.351.320.190.54
Ad-Lo-60.981.461.461.460.340.470.910.260.380.301.190.230.52
Da-Wo-10.961.571.571.570.170.060.500.420.530.270.680.190.33
El-Py-31.040.770.770.770.250.390.820.310.340.460.980.160.27
Je-Py-11.021.651.651.650.160.110.730.400.440.280.870.200.34
Ka-Al-10.961.501.501.500.190.130.710.410.530.270.690.270.49
Me-Py-11.011.661.661.660.160.120.680.420.490.260.540.220.38
Ri-Wo-11.011.401.401.400.140.070.430.450.450.240.660.170.25
St-Al-10.991.611.611.610.190.070.630.440.500.240.790.240.45
To-Py-10.981.651.651.650.150.120.660.400.340.241.060.170.31
Wd-Py-11.021.391.391.390.220.150.600.460.600.350.320.240.54
Wh-Lo-10.951.531.531.530.130.100.720.430.440.240.750.200.39
Wh-Lo-21.031.481.481.480.160.100.730.390.450.260.840.210.38
Wi-Py-10.971.251.251.250.250.260.780.330.540.261.000.210.36
Wi-Py-61.001.631.631.630.290.090.850.130.320.311.240.270.35
*

OEP, odd-to-even predominance (Scalan and Smith, 1970); Pr/Ph, pristine/phytane ratio; TetC24/Hop, C24H42 tetracyclic terpane/hopane ratio; Gam/Hop, gammacerane/hopane ratio; Bisnorhop/Hop, 17α(H), 21β(H)-28,30-bisnorhopane/hopane ratio; HHI, homohopane index = C35αβ(S + R)/(ΣC31 – C35αβ + R); Extended TT, extended tricyclic terpane = extended trycyclic ΣC28–40(S + R)/(ΣC28–40(S + R) + hopane); C21/(C21 + C22), C21αβ sterane/(C21αβ sterane + C22αβ sterane); C22/C22 + C27, C22αβ sterane/(C22αβ steranes + C27αα20R sterane); Dia/Reg, C27βα20S + R diasterane/(C27βα20S + R diasterane/(C27βα20S + R diasterane + C27αα20[S + R] + C27ββ20[S + R] regular steranes); C27/C29, C27αα20R sterane/C29αα20R sterane.

Table 4.

Selected diamondoids and biomarker concentration in ppm together with C7 maturity ratios.

Sample ID1 + 2-Methylada mantane1 + 2-Ethyladam antane3 + 4-Methyldia mantaneC29ααα 20R steraneHeptane Ratio*Isoheptane Ratio*
West of Nemaha Uplift (Anadarko Shelf)
Da-Wo-177.841.94.253.757.21.7
Ka-Al-198.446.95.121.750.31.5
Ri-Wo-1121.686.43.685.545.31.3
St-Al-163.438.43.340.834.00.9
East of Nemaha Uplift
Ad-Lo-54629.72.311
Ad-Lo-640.220.92.314.527.90.7
El-Py-331.320.81.749.231.50.7
Je-Py-143.224.81.729.530.10.7
Me-Py-147.623.7226.833.20.8
To-Py-139.119.51.438.628.80.7
Wd-Py-143.4301.310.5
Wh-Lo-132.924.42.240.527.40.5
Wh-Lo-234.8292.138.626.50.5
Wi-Py-13729.21.714.3
Wi-Py-630.920.71.513.831.40.8
Sample ID1 + 2-Methylada mantane1 + 2-Ethyladam antane3 + 4-Methyldia mantaneC29ααα 20R steraneHeptane Ratio*Isoheptane Ratio*
West of Nemaha Uplift (Anadarko Shelf)
Da-Wo-177.841.94.253.757.21.7
Ka-Al-198.446.95.121.750.31.5
Ri-Wo-1121.686.43.685.545.31.3
St-Al-163.438.43.340.834.00.9
East of Nemaha Uplift
Ad-Lo-54629.72.311
Ad-Lo-640.220.92.314.527.90.7
El-Py-331.320.81.749.231.50.7
Je-Py-143.224.81.729.530.10.7
Me-Py-147.623.7226.833.20.8
To-Py-139.119.51.438.628.80.7
Wd-Py-143.4301.310.5
Wh-Lo-132.924.42.240.527.40.5
Wh-Lo-234.8292.138.626.50.5
Wi-Py-13729.21.714.3
Wi-Py-630.920.71.513.831.40.8
*

Heptane Ratio: (100 × n-heptane/cyclohexane + 2-methylhexane + 1,1-dimethylcyclopentane (DMCP)) + 3-methylhexane + 1-cis/s-3-DMCP + 1-trans-3-DMCP + 1-trans-2-DMCP + n-heptane + methylcyclohexane); Isoheptane Ratio: (2-methylhexane + 3-methylhexane/1-cis/s-3-DMCP + 1-trans-3-DMCP + 1-trans-2-DMCP).

Contents

GeoRef

References

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