Organic petrology of the Aptian-age section in the downdip Mississippi Interior Salt Basin, Mississippi, USA: Observations and preliminary implications for thermal maturation history

International Journal of Coal Geology 131 (2014) 378–391

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International Journal of Coal Geology journal homepage: www.elsevier.com/locate/ijcoalgeo

Organic petrology of the Aptian-age section in the downdip Mississippi Interior Salt Basin, Mississippi, USA: Observations and preliminary implications for thermal maturation history Brett J. Valentine ⁎, Paul C. Hackley, Catherine B. Enomoto, Alana M. Bove, Frank T. Dulong, Celeste D. Lohr, Krystina R. Scott U.S. Geological Survey, MS 956 National Center, Reston, VA 20192, United States

a r t i c l e

i n f o

Article history: Received 30 January 2014 Received in revised form 30 June 2014 Accepted 1 July 2014 Available online 14 July 2014 Keywords: Solid bitumen Organic petrology Thermal maturity Mississippi Interior Salt Basin Aptian

a b s t r a c t This study identifies a thermal maturity anomaly within the downdip Mississippi Interior Salt Basin (MISB) of southern Mississippi, USA, through examination of bitumen reflectance data from Aptian-age strata (Sligo Formation, Pine Island Shale, James Limestone, and Rodessa Formation). U.S. Geological Survey (USGS) reconnaissance investigations conducted in 2011–2012 examined Aptian-age thermal maturity trends across the onshore northern Gulf of Mexico region and indicated that the section in the downdip MISB is approaching the wet gas/condensate window (Ro ~1.2%). A focused study in 2012–2013 used 6 whole core, one sidewall core, and 49 high-graded cutting samples (depth range of 13,000–16,500 ft [3962.4–5029.2 m] below surface) collected from 15 downdip MISB wells for mineralogy, fluid inclusion, organic geochemistry, and organic petrographic analysis. Based on native solid bitumen reflectance (Ro generally N 0.8%; interpreted to be post-oil indigenous bitumens matured in situ), Ro values increase regionally across the MISB from the southeast to the northwest. Thermal maturity in the eastern half of the basin (Ro range 1.0 to 1.25%) appears to be related to present-day burial depth and shows a gradual increase with respect to depth. To the west, thermal maturity continues to increase even as the Aptian section shallows structurally on the Adams County High (Ro range 1.4 to N1.8%). After evaluating the possible thermal agents responsible for increasing maturity at shallower depths (i.e., igneous activity, proximity to salt, variations in regional heat flux, and uplift), we tentatively propose that either greater paleoheat flow or deeper burial coupled with uplift in the western part of the MISB could be responsible for the thermal maturity anomaly. Further research and additional data are needed to determine the cause(s) of the thermal anomaly. Published by Elsevier B.V.

1. Introduction Production of gas from shale reservoirs is expected to supply 50% of total U.S. natural gas production by 2040 (U.S. Energy Information Administration, 2013), an increase made possible by the application of horizontal drilling and fracture stimulation technologies (Alexander et al., 2011). The U.S. Geological Survey (USGS) is tasked with the estimation of undiscovered domestic and worldwide shale gas resources and is engaged in research efforts to support this mission (U.S. Geological Survey, 2007). Determination of the geologic controls on shale gas resources requires basic rock-focused information, including the key parameters of thermal maturity, organic richness, and reservoir thickness (Curtis, 2002). However, these types of data are sparse or unavailable in many areas now being explored. Lower Cretaceous Aptian-age strata in the Gulf of Mexico Basin are current industry targets for development as unconventional ‘shale gas’ ⁎ Corresponding author. E-mail address: [email protected] (B.J. Valentine).

http://dx.doi.org/10.1016/j.coal.2014.07.001 0166-5162/Published by Elsevier B.V.

reservoirs. The Aptian-age Pearsall Formation in the Maverick Basin of south Texas (Fig. 1), for example contains a USGS estimated mean undiscovered gas resource of 8.8 TCF with thermal maturity in the dry gas window (Dubiel et al., 2011; Hackley, 2012). Reconnaissance studies outside of the Maverick Basin show that thermal maturity of the Aptian-age section is lower northeast of the San Marcos Arch in Texas (Fig. 1) and eastward toward Florida with the exception of the downdip portion of the Mississippi Interior Salt Basin (MISB) (Enomoto et al., 2012). Enomoto et al. (2012) determined that the Aptian-age section in downdip areas of the MISB is approaching the wet gas condensate stage (vitrinite and solid bitumen Ro values of up to ~1.2%), suggesting that this area may have potential shale gas resources. Petroleum system modeling by Mancini et al. (2008a) indicated that the Mesozoic section in the central and eastern Gulf Coastal Plain has high potential for gas resources and recent horizontal development of the Upper Cretaceous Tuscaloosa Marine Shale as a liquids play (Barrell, 2013) in central Louisiana and southern Mississippi demonstrates potential for development of unconventional petroleum systems in the study area. The current paper evaluates thermal maturity of the Aptian-age section in

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Fig. 1. Map of the Mississippi Interior Salt Basin (MISB) showing 2012–2013 well sample locations, well sample locations from Enomoto et al. (2012), salt domes and structures (modified from Ewing and Lopez, 1991; Geomap® Company, 2012; Lopez and Orgeron, 1995), faults (modified from Ewing and Lopez, 1991; Geomap® Company, 2012), terrigenous sediment sources, Adams County High (modified from Gazzier and Bograd, 1988) and major geologic structures within the region.

the downdip MISB in the context of shale gas potential through focused organic petrographic analyses. 2. Geologic setting and stratigraphy The MISB extends from southwestern Alabama to northeastern Louisiana and contains numerous salt diapir and pillow structures formed from the underlying Jurassic Louann Salt (Fig. 1). Major geologic structures bounding the MISB include the Monroe Uplift and the Jackson Dome to the north, and the La Salle Arch to the west. The Wiggins Uplift, a relict mass of continental crust of Paleozoic age left behind during Late-Triassic–Jurassic rifting of Pangaea, occurs south of the basin from the southeast to northwest (Dallmeyer, 1989; Ewing, 1991; Mancini and Puckett, 2002). In the southwestern corner and extending downdip of the MISB is a region known as the Adams County High. An area that is relatively void of faulting except where a few relatively high relief anticlinal structures occur (Meylan, 1997). The Lower Cretaceous Aptian-age section evaluated in this study includes the Sligo Formation (Hauterivian-age at base), Pine Island Shale, James Limestone, and the Rodessa Formation (Albian-age at top) (Fig. 2). In the Early Cretaceous, the northern Gulf of Mexico experienced relative tectonic quiescence (Yurewicz et al., 1993) and a stable rimmed carbonate platform extending from south Texas to Florida developed. This platform was the site for N 10,000 ft (N 3000 m) of Lower Cretaceous carbonate and evaporite deposition (McFarlan, 1977; McFarlan and

Menes, 1991). In Mississippi, sediment influx diluted the carbonate system and proximal clastic rocks grade downdip basinward into carbonates on the outer shelf (Yurewicz et al., 1993). The lowermost unit in the studied section, the Sligo Formation, consists of fine to medium grained shallow marine sandstones with red and gray shales deposited in shoreface and proximal shelf environments (Devery, 1982). Finegrained terrigenous sediment, draining from the Appalachian and Ouachita mountains, the U.S. continental interior, and adjacent coastal plain sediments during the mid-Aptian-age, put an end to the carbonate dominated system forming the dark gray and black shales interbedded with minor limestone that comprise the Pine Island Shale (Goddard, 2001; Salvador, 1991). Dinkins (1969) placed the Sligo Formation-Pine Island Shale contact at the first occurrence of limestone or interbedded limestone and sandstone in the basal Pine Island. The James Limestone, a fossiliferous limestone (shelf) and dense micrite (deeper waters) formed during recommencement of carbonate deposition over the Pine Island Shale (Forgotson, 1963). Increased rates of subsidence and a supply of fine-grained clastic sediments returned during the Upper Aptian-age, resulting in the deposition of the overlying Rodessa Formation, primarily in semi-restricted lagoonal environments (Forgotson, 1963). The Rodessa Formation is comprised of interbedded clastics and limestone with some anhydrite (Dinkins, 1969; Nunnally and Fowler, 1954). The James Limestone and Pine Island Shale are not continuously present in Mississippi and in some locations the Rodessa Formation directly overlies the Sligo Formation (Dockery, 1996).

B.J. Valentine et al. / International Journal of Coal Geology 131 (2014) 378–391

Epoch Upper (in part)

Period

Chronostratigraphic Units

Gulf Coast Provincial Stages

Age

Local Time Scale (Ma)

380

Mississippi Interior Salt Basin

Updip

95 Cenomanian (lower part)

Downdip

Tuscaloosa Formation Tuscaloosa Formation mid-Cenomanian unconformity

Gulfian

100 WashitaFredericksburg undiff.

Dantzler Formation

Paluxy Formation Mooringsport Fm.

Comanchean

Cretaceous Lower

Albian

113

Ferry Lake Anhydrite

Rodessa Fm.

Stuart CityEdwardsGlen Rose reef

115 Aptian James Ls.

120

Pine Island Shale

Sligo Formation 126 Barremian

131

Hosston Formation Coahuilan

Hauterivian

134

Valanginian

139

Unconformity

Cotton Valley Formation

Berriasian (upper part)

EXPLANATION Conformable

Transitional

Unconformable

Dominant Lithology Shale, Mudstone Siltstone

Evaporite

Carbonate

Sandstone

Fig. 2. Lower Cretaceous stratigraphic column for the southern Mississippi Interior Salt Basin (MISB). Modified from Dockery (1996), Mancini and Puckett (2000), American Association of Petroleum Geologists (2002), and Mancini et al. (2008b). Numerical time scale for global chronostratigraphic units from Gradstein et al. (2012); local numerical time scale from Dockery (1996), Shreveport Geological Society (1987), and Mancini et al. (2008a, 2008b).

3. Methodology Fifteen wells transecting the southern MISB from southeastnorthwest were selected for sampling (Table 1; Fig. 1). These 15 wells were correlated to a cross section of 36 previously-studied wells (Enomoto et al., 2012) using IHS Kingdom® software. Well log ASCII and image files were purchased from commercial libraries. Top picks were evaluated based on well log character and comparison to top picks contained in the proprietary IHS Energy Group wells database (IHS Energy Group, 2012a). Using the model framework that high spontaneous potential (SP) values and low resistivity values were indicative

of shales with potentially high organic content, sample depths in wells with available cuttings in the Aptian-age section were selected based on the log curve values. Fifty-six samples (primarily cuttings) were collected from the Aptian-age section at the Mississippi Core Repository in Jackson, MS. Samples ranged in depth from 13,320–16,440 ft (4060– 5011 m). Cuttings samples were sub-sampled to select the darker, more organic-rich fragments. Core from the James Limestone in the Pennzoil 1 Piazza Heirs well also was selectively sampled to target shaley intervals. Samples were analyzed by Rock-Eval pyrolysis (RockEval II™) and for total organic carbon (TOC via Leco™) in a commercial laboratory (Weatherford Laboratories) according to the methods described in Barker (1974) and Espitalié et al. (1977). X-ray diffraction (XRD) of low temperature ash residues was performed at USGS via techniques described in Hosterman and Dulong (1989). Three core samples were evaluated via fluid inclusion petrography with one also examined via microthermometry in a commercial laboratory (Fluid Inclusion Technologies, Inc.) using standard techniques (e.g., Sheperd et al., 1985). Fifty-three samples for organic petrographic analysis were prepared by crushing to ~1 mm top size and embedding in thermoplastic mounts. The mounts were then ground and polished following ASTM D2797 (ASTM, 2013a). A photographic grid of the examination surface was captured using a Leica DM4000 M with a white LED light source and a 10× air objective with the computer program DISKUS-FOSSIL by Hilgers Technisches Buero. This technique aids in navigation between rock fragments and in re-locating important characteristics found during analysis. Reflectance measurements were completed with a 50× oil objective and the DISKUS-FOSSIL program, which uses a low-resolution monochromatic digital camera as a detector. Since most samples contained little or no vitrinite, native solid bitumen was selected to quantify mean random reflectance (Ro) values in this study. Due to overlap of maceral-type reflectance ranges, macerals were identified during analysis as migrated solid bitumen [Ro generally b0.8%; thought to represent recently migrated and cracked oil(?), that did not experience maximum burial], native solid bitumen [Ro generally N 0.8%; thought to represent indigenous solid hydrocarbons that matured in situ(?), experiencing maximum burial], vitrinite or inertinite. If a maceral could not be positively identified using reflectance, form (e.g., presence of void-filling texture, or cellular structure), and relief, the maceral was recorded as “Solid Bitumen/Inert” and its reflectance was not included in the calculation of the mean Ro value. Random reflectance measurements were determined according to ASTM D7708, with the exception that some samples yielded less than the 20 measurements required for compliance (ASTM, 2013b).

4. Results 4.1. X-ray diffraction mineralogy Twenty-five cuttings and core samples analyzed by semiquantitative X-ray diffraction mineralogy show a general overlap between the shale and limestone units in the Aptian-age section (Table 2). Normalizing quartz, carbonate and clays to 100 wt.% results in average normalized quartz content of Pine Island Shale and Rodessa Formation of 29 wt.% (Fig. 3) compared to 20 wt.% in the James Limestone. Normalized carbonate averages 46 wt.% in the James Limestone compared to 18 wt.% in Pine Island and Rodessa with normalized clay averages of 34 wt.% in James Limestone compared to 53 wt.% in Pine Island Shale and Rodessa Formation samples. Other minerals (e.g., pyrite b10 wt.%; feldspar b5 wt.%) generally are present only in minor concentrations and the average sum of clays plus carbonate plus quartz was 94 wt.% (non-normalized). A general overlap of shale/limestone distinction in the average normalized compositions does occur with the exception of two James Limestone samples that are dominated by carbonates. (N80 wt.%). Clay mineral composition is dominated by illite

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Table 1 List of sample well locations. Well Name

API No.

County

Latitude†

Longitude†

Geologic Unit(s)

Sample Type

Pennzoil 1 Piazza Heirs Chevron 32 Cranfield Unit INEXCO Oil Co. 1 Sarah G. Cupit et al. ADCO Prod. 1 Brookhaven BK & TR Watson Oil Corp. 1 H.L. Watson et al. INEXCO 1 Selman Smith Estate Systems Fuels Inc. 1 Polk Berry 17-6 South LA Prod. 1 Bowie Creek Unit 11-6 ANR Prod. 1 Branch Lee et al. Tomlinson Int. Inc. 1 Tatum LBR 27-11 Shell Oil 1 Tatum et al. California Oil Co. 1 Walley VR Forest Oil Corp. 1 Emerald Mobil Expl. Co. 1 International Paper Co. 27-10 Amoco Prod. 1 Cumbest Unit 13-11

23063201560000 23001032510000 23063202160000 23037209010000 23085200350000 23077200330000 23065200550000 23031200330000 23147201380000 23073202520000 23035200200000 23111000020000 23035200640000 23131200090000

Jefferson Adams Jefferson Franklin Lincoln Lawrence Jefferson Davis Covington Walthall Lamar Forrest Perry Forrest Stone

31.8404 31.5440 31.6903 31.5149* 31.5785* 31.5861 31.5745 31.5022 31.1224 31.1019 31.2792* 31.4244 31.0170* 30.7544

−91.2003 −91.1760 −90.7727 −90.7295* −90.3343* −90.0992 −89.9355 −89.5812 −89.9417 −89.5981 −89.3199* −88.8651 −89.2056* −89.1769

James Ls., Pine Island Sh. and Sligo Fm. James Ls. and Pine Island Sh. James Ls. and Pine Island Sh. James Ls., Pine Island Sh. Rodessa Fm., James Ls. and Pine Island Sh. James Ls., Pine Island Sh. and Sligo Fm. James Ls., Pine Island Sh. James Ls. Pine Island Sh. Pine Island Sh. and Sligo Fm. James Ls. and Pine Island Sh. James Ls. and Pine Island Sh. James Ls., Pine Island Sh. and Sligo Fm. Pine Island Sh.

Core and cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Core chips and cuttings Cuttings Cuttings

23059200030000

Jackson

30.6098

−88.5407

Pine Island Sh. and Sligo Fm.

Cuttings

† Location information gathered from the Mississippi Dept. of Environmental Quality Office of Geology website * Latitude and longitude converted from township and range coordinates; Ls. = Limestone; Sh. = Shale; Fm. = Formation.

with minor contributions from chlorite, kaolinite and traces of a mixed layer illite/smectite clay in 3 samples. 4.2. Fluid inclusion petrography and microthermometry No petroleum inclusions were identified in the three argillaceous carbonate core samples from the Pennzoil 1 Piazza Heirs core, presumably due to elevated burial temperatures observed in the western end of the study area, as determined by high native solid bitumen reflectance values (Ro 1.7–2.0%, described below). Homogenization temperatures (Th; n = 41) of primary aqueous inclusions in calcite cements (sample from 13,909.5 ft [4239.6 m]) were in the range of 115–140 °C with the majority of values occurring between 120–135 °C, (Table 3), similar to present-day bottom-hole temperatures as determined during wireline logging (125–130 °C uncorrected, at depth of sampling). Salinities of aqueous inclusions were consistently high, at 20–24.4 wt.% salt. 4.3. Organic geochemistry Total organic carbon (TOC) content ranges from 0.01–1.21 wt.% and averages 0.5 wt.% (n = 51) (Table 4; Fig. 4A). Overall low TOC suggests that the pyrolyzate adsorbs to the mineral matrix during combustion, resulting in a reduced S2 peak and HI value, and an increased Tmax and OI value (e.g., Peters, 1986; Fig. 4B,C,D and E). The S2 peaks range from 0.14 to 2.33 mg HC/g rock, averaging 0.40, indicating that there is little present-day hydrocarbon generative potential. More than 70% of the S2 peak values are N 0.2 mg HC/g rock (Fig. 4B), suggesting that Tmax values should be reliable. However, of the 51 pyrolysis analyses in the current study, only 11 had reasonable Tmax values (~ 430– 530 °C, which converts to ~ 0.6–2.2% Ro according to the empirical formula calculated Ro = 0.0180 × Tmax – 7.16; Jarvie et al., 2001), presumably due to the low TOC content and high thermal maturity of the organic material. Pyrolyzable carbon is interpreted to occur almost exclusively in solid bitumens, based on organic petrographic analysis (described below). Supported by the reflectance values and petrographic analyses (Fig. 4C, E, and F), the organic carbon is presumed to be relatively insoluble native pyrobitumen, which would thermally decompose upon pyrolysis to non-volatile chars that contribute little to the FID signal. No relationships were observed between TOC or S2 with respect to migrated solid bitumens (low Ro, fluorescent solid bitumen), which are presumed to have higher H concentrations. Because Tmax is unreliable, we suggest the pyrolysis approach to characterizing kerogen type (Fig. 4D) and thermal maturity (Fig. 4C and E) in these mature–overmature organic-lean rocks should be discounted in favor of organic petrographic analysis and reflectance measurements.

4.4. Organic petrography Despite being organic-lean, all samples (n = 53) contained post-oil solid bitumens and inertinite (e.g., fusinite, inertodetrinite). Only two samples contained fragments of vitrinite. Low-reflecting, fluorescent migrated solid bitumen (emplaced post-maximum burial) was observed in 22 samples and was difficult to measure due to its narrow morphology along mineral grains and fractures (Fig. 5A, B and C). Migrated solid bitumen did not occur with other organic material and was observed adjacent to native solid bitumen (experienced maximum burial) only once. Using Jacobs (1989) classification, migrated solid bitumen is classified as grahamite to epi-impsonite based solely on reflectance values. Native solid bitumen occurred most commonly as discrete, wispy, homogeneous organic masses found in and along carbonate grains (Fig. 5B,D, E, F and G) but in some samples large (N50 μm) native solid bitumen masses were found (Fig. 5H). Based exclusively from reflectance measurements using Jacobs (1989) nomenclature, native solid bitumen is classified as epi-impsonite to meso-imsonite. In a few instances, a fine granular texture was observed in the center of homogenous native solid bitumen (Fig. 5I and J); in these cases, Ro was determined on the outer homogenous material. Reflectance values of native solid bitumens tended to have a wide reflectance range with standard deviations of 0.14–0.28. Multiple peaks can be observed in the reflectance histograms (Fig. 6). In all samples, native solid bitumen reflectance partially overlapped with inertinite macerals, making identification difficult and distinction of native solid bitumen from inertinite was accomplished primarily by visual observation of morphology (e.g., void-filling or cellular structure) and relief (Fig. 5K). Based on native solid bitumen reflectance, Ro values increase regionally across the MISB from the southeast to the northwest (Table 5; Fig. 7). Thermal maturity in the eastern half of the basin (Ro range 1.0 to 1.25%) appears to be related to present-day burial depth, showing a gradual increase with respect to depth. Continuing to the west, the deepest wells along the transect (ADCO Prod. 1 Brookhaven BK&TR and Watson Oil Corp. 1H.L. Watson et al. at depths of 15,940–16,460 ft [4858.5–5017 m]) had Ro values of 1.31–1.68%. However, thermal maturity continues to increase (Ro range 1.71 to 2.0%) as the Aptian-age section shallows (depths of ~ 14,000 ft [4267.2 m]) structurally across the Adams County High toward the western margin of the basin. 5. Discussion 5.1. Bitumen reflectance and thermal history Vitrinite and solid bitumen reflectance measurements from Enomoto et al. (2012) ranged 0.6–1.2% in the MISB, indicating that

382

Table 2 X-ray diffraction mineralogy data in percent. Total⁎

0.0 0.0

0.0 12.3

94.7 103.7

6.5 2.0 8.1 1.2 5.7 10.2

0.0 5.8 12.1 3.7 0.0 11.4

41.8 49.3 53.7 31.0 29.0 57.3

101.8 100.2 100.0 97.4 101.4 100.0

4.5

1.3

9.6

28.9

96.8

12.7

4.7

1.3

8.7

27.4

102.3

0.0

23.0

0.0

2.8

11.2

37.0

97.6

1.0

2.8

37.0

0.0

9.6

9.9

56.5

99.5

12.7

1.5

0.0

35.0

0.0

9.1

10.4

54.5

99.3

1.8

5.4

0.0

0.1

39.9

0.0

9.6

11.6

61.1

96.2

24.1

1.3

20.5

1.5

0.5

36.9

0.0

5.0

9.0

50.9

98.8

0.511

33.9

3.0

21.1

0.0

2.7

25.2

0.0

4.6

8.1

37.9

98.6

Jame Ls./Pine Island Sh. contact

0.455

28.2

2.6

16.5

2.1

0.1

33.9

2.6

5.6

8.5

50.6

100.1

Jame Ls./Pine Island Sh. contact

0.360

22.1

1.5

5.0

2.1

0.8

54.1

0.0

6.8

7.5

68.4

99.9

Sligo Fm.

0.892

26.0

2.2

1.5

3.3

0.5

47.9

0.0

8.0

9.9

65.8

99.3

Pine Island Sh.

0.359

16.7

1.4

22.4

0.0

0.0

37.4

0.0

4.9

12.7

55.0

95.5

Pine Island Sh.

0.451

16.3

1.0

28.1

0.6

0.0

37.1

0.0

2.9

12.2

52.2

98.2

Sligo Fm.

0.471

19.1

1.1

12.7

2.6

0.0

46.1

0.0

4.4

13.5

64.0

99.5

Pine Island Sh.

0.175

24.0

3.2

7.2

2.1

1.1

46.9

0.0

7.4

6.8

61.1

98.7

Pine Island Sh.

0.071

59.1

3.5

7.3

1.0

0.0

18.8

0.0

6.8

3.0

28.6

99.5

Pine Island Sh.

0.213

54.9

3.2

5.2

0.0

0.8

23.5

0.0

9.1

3.3

35.9

100.0

Sample depth

Geologic unit(s)

LOI

Quartz

Feldspar

Carbonate

Pyrite

Other Minerals

Pennzoil 1 Piazza Heirs Pennzoil 1 Piazza Heirs

13,909.5 ft (4239.6 m) 13,950–13,980 ft (4252.0–4261.1 m) 13,950.5 ft (4252.1 m) 13,952 ft (4252.6 m) 13,959 ft (4254.7 m) 13,965 ft (4256.5 m) 13,966 ft (4256.8 m) 14,430–14,460 ft (4398.3–4407.4 m) 15,320–15,330 ft (4669.5–4672.6 m) 15,350–15,360 ft (4678.7–4681.7 m) 15,430–15,440 ft (4703.1–4706.1 m) 16,000–16,010 ft (4876.8–4879.8 m) 16,250–16,260 ft (4953.0–4956.1 m) 16,320–16,330 ft (4974.3–4977.4 m) 16,100–16,120 ft (4907.3–4913.4 m) 16,260–16,280 ft (4956.1–4986.5 m) 16,340–16,360 ft (4980.4–4986.5 m) 15,370–15,380 ft (4684.8–4687.8 m) 15,490–15,500 ft (4721.4–4724.4 m) 15,430–15,440 ft (4703.1–4706.1 m) 15,500–15,510 ft (4724.4–4727.4 m) 15,530–15,540 ft (4733.5–4736.6 m) 14,300–14,310 ft (4358.6–4361.7 m) 13,230–13,234 ft (4032.5–4033.7 m) 13,260–13,261 ft (4041.6–4042.0 m)

James Ls. James Ls.

0.000 0.153

1.6 11.8

0.0 0.3

93.1 71.1

0.0 3.7

0.0 4.5

0.0 7.7

0.0 0.0

0.0 4.6

James Ls. James Ls. James Ls. James Ls. James Ls. Sligo Fm.

0.125 0.152 n.d. n.d. n.d. 0.376

16.5 26.6 39.0 19.4 15.7 29.6

0.4 1.8 1.2 1.4 0.4 1.8

33.5 13.0 2.1 34.2 48.9 7.7

6.9 9.0 1.6 6.7 4.9 1.5

2.7 0.5 2.4 4.7 2.5 2.1

35.3 41.5 33.5 26.1 23.3 35.7

0.0 0.0 0.0 0.0 0.0 0.0

Jame Ls./Pine Island Sh. contact

0.102

15.1

0.5

52.3

0.0

0.0

13.5

Pine Island Sh.

0.060

18.2

0.9

49.8

3.0

3.0

Pine Island Sh.

0.264

17.4

1.0

41.6

0.6

James Ls.

1.257

27.6

2.4

9.2

Pine Island Sh.

0.301

29.7

0.9

Pine Island Sh.

0.435

27.8

Rodessa Fm./James Ls. contact

0.524

James Ls.

Pennzoil 1 Piazza Heirs Pennzoil 1 Piazza Heirs Pennzoil 1 Piazza Heirs Pennzoil 1Piazza Heirs Pennzoil 1 Piazza Heirs Pennzoil 1 Piazza Heirs Chevron 32 Cranfield Unit Chevron 32 Cranfield Unit Chevron 32 Cranfield Unit ADCO Prod. 1 Brookhaven BK & TR ADCO Prod. 1 Brookhaven BK & TR ADCO Prod. 1 Brookhaven BK & TR Watson Oil Corp. 1 H.L. Watson et al. Watson Oil Corp. 1 H.L. Watson et al. Watson Oil Corp. 1 H.L. Watson et al. INEXCO 1 Selman Smith Estate INEXCO 1 Selman Smith Estate Tomlinson Int. Inc. 1 Tatum LBR 27-11 Tomlinson Int. Inc. 1 Tatum LBR 27-11 Tomlinson Int. Inc. 1 Tatum LBR 27-11 Shell Oil 1 Tatum et al. California Oil Co. 1 Walley VR California Oil Co. 1 Walley VR

Illite

Illite/Smectite

Kaolinite

⁎ Totals do not add to 100% due to semi-qualitative library peak matching iterations of raw data; LOI = loss on ignition in %; Fm. = Formation; Ls. = Limestone; n.d. = not determined; Sh. = Shale.

Chlorite

B.J. Valentine et al. / International Journal of Coal Geology 131 (2014) 378–391

Total clays

Well name

B.J. Valentine et al. / International Journal of Coal Geology 131 (2014) 378–391

383

EXPLANATION Pine Island Shale/Rodessa Formation (n=19)

0 100 10

Pine Island Shale/Rodessa Formation mean

90

James Limestone (n=7) 20

80

40

60

50

50

60

) (%

Qu art

James Limestone mean 70

ys Cla

z (% )

30

40

70

30

80

20

90 100

0

10

10

20

30

40

50

60

70

80

90

0 100

Carbonate (%) Fig. 3. Ternary plot showing normalized quartz-clay-carbonate mineralogy for the samples analyzed in this study. Larger data points show mean of all values.

thermal maturities are in the oil window and approaching condensate/ wet gas generation. Our new results from measurement of native solid bitumen reflectance indicate somewhat higher maturity and suggest a complex petroleum generation and expulsion history. In particular, the presence of a wide range of solid bitumen populations, including native bitumens with high reflectance and recently migrated fluorescent bitumens with lower reflectance suggests multiple processes are contributing to bitumen formation, potentially including episodic hydrocarbon charging, devolatilization, thermochemical sulfate reduction, and thermochemical maturation. The presence of multiple source rocks in the basin (e.g., Echols et al., 1994; Evans, 1987; Sassen, 1990; Sassen et al., 1988; Walters and Dusang, 1988) also may contribute to

Table 3 Fluid inclusion microthermometry data for Pennzoil 1 Piazza Heirs 13,909.5 ft (4239.6 m) sample. Population

Th aq (°C)

Tm aq (°C)

Sal (wt.%)

pr; cal cmt pr; cal cmt pr; cal cmt pr; cal cmt pr; cal cmt pr; cal cmt pr/sec; cal cmt pr/sec; cal cmt pr/sec; cal cmt pr/sec; cal cmt pr/sec; cal cmt pr/sec; cal cmt pr/sec; cal cmt pr/sec; cal cmt

120–125 (6) 126–128 (5) 115–120 (5) 127–130 (2) 128–133 (6) 135–137 (2) 135–140 (3) too high (1) 125–130 (3) 131 (1) too high (1) 115–116 (2) 124–126 (6) N/A (1)

−18.0 to −22.0 −18.0 to −22.0 −18.0 to −21.0 −18.0 to −23.0 −18.0 to −22.0 −17.0 to −19.0 −19.0 to −20.0 −19.0 to −20.0 −19.0 to −24.0 −19.0 −18.0 −18.0 to −23.0 −17.0 to −21.5 −20.0

21.0–23.7 21.0–23.7 21.0–23.0 21.0–24.4 21.0–23.7 20.2–21.7 21.7–22.4 21.7–22.4 21.7–25.1 21.7 21.0 21.0–24.4 20.2–23.3 22.4

Th aq: homogenization temperature of aqueous inclusions. Tm aq: final melting temperature of aqueous inclusions. Sal (wt.%): salinity computed from NaCl-H2O system. Number in parentheses: number of inclusions measured. N/A: could not be determined. pr: primary inclusions. sec: secondary inclusions. cal cmt: calcite cement.

solid bitumen heterogeneity. We did not observe any spatial or stratigraphic relationships between relative quantities of higher vs. lower reflectance native solid bitumens in individual samples, nor did we observe spatial/stratigraphic concentrations of recently migrated solid bitumens with the possible exception that lower maturity fluorescent bitumens may be qualitatively more abundant in the Shell 1 Tatum well. Bitumen reflectance values from our study are generally consistent with previous documentation of thermal maturity in the MISB. Mancini et al. (2003) presented approximate Ro values for the Jurassic Oxfordian Smackover Formation calculated from TAI determinations. Their well B' (API #23-049-20032) in southern Hinds County is located approximately 40 miles (64.4 km) updip from the western end of our study area and has a present-day modeling-based Ro for the Smackover Formation of ~2.2%, consistent with our measured values of 1.5–2.0% at the western end of the study area. Price and Barker (1985) also reported Ro measurements from Hinds County of approximately 1.5% for the Aptian-age section. Ro measurements from the Upper Cretaceous-age Tuscaloosa Formation approximately 20 miles (32.2 km) downdip from the western end of our study area were much lower at 0.94– 0.98% (Dennen et al., 2010). Other nearby studies also have documented lower thermal maturity organic matter (Ro 0.64%) in the Upper Cretaceous section (Miranda and Walters, 1992). This discrepancy in thermal maturity between the Lower and Upper Cretaceous strata could be due to the presence of the mid-Cenomanian unconformity (see Mancini et al., 2006) which may have caused significant uplift of the Lower Cretaceous section, higher heat flux during the Early Cretaceous, and/or greater burial depth of the Lower Cretaceous section. Slightly east and updip from the eastern end of our study area, Sassen and Moore (1988) documented thermal maturity of the Smackover section through TAI measurements which convert to Ro values ranging between 0.6 and 3.0%. Carroll (1999) measured vitrinite reflectance on the Cretaceous-age section in the same area as Sassen and Moore (1988) in order to model thermal maturity of the Smackover; his study confirmed the earlier results with Ro values of 0.31–0.42% in the Cretaceous-age section projected to a thermal maturity of 0.7% at the top of the Smackover Formation. Both studies contoured present-day thermal maturity at the top of the Smackover Formation, showing it entering the gas/condensate window 15–30 miles (24.1–48.3 km) updip of our samples where we measured 1.0–1.1% Ro. Our earlier results

384

Table 4 Organic geochemistry data. Sample depth

Geologic unit(s)

Sample

TOC

S1

S2

S3

Tmax

HI

OI

PI

13,909.5 ft (4239.6 m) 13,950.5 ft (4252.1 m) 13,952 ft (4252.6 m) 13,959 ft (4254.7 m) 13,965 ft (4256.5 m) 13,966 ft (4256.8 m) 14,370–14,400 ft (4380.0–4389.1 14,430–14,460 ft (4398.3–4407.4 15,320–15,330 ft (4669.5–4672.6 15,350–15,360 ft (4678.7–4681.7 15,430–15,440 ft (4703.1–4706.1 15,722–15,730 ft (4792.1–4794.5 15,820–15,830 ft (4821.9–4825.0 15,940–15,950 ft (4858.5–4861.6 16,000–16,010 ft (4876.8–4879.8 16,130–16,140 ft (4916.4–4919.5 16,320–16,330 ft (4974.3–4977.4 16,100–16,120 ft (4907.3–4913.4 16,260–16,280 ft (4956.1–4986.5 16,340–16,360 ft (4980.4–4986.5 16,440–16,460 ft (5010.9–5017.0 15,340–15,350 ft (4675.6–4678.7 15,370–15,380 ft (4684.8–4687.8 15,450–15,460 ft (4709.2–4712.2 15,490–15,500 ft (4721.4–4724.4 14,980–14,990 ft (4565.9–4569.0 14,840–14,860 ft (4523.2–4529.3 14,880–14,900 ft (4535.4–4541.5 15,380–15,400 ft (4687.8–4693.9 15,440–15,460 ft (4706.1–4712.2 15,430–15,440 ft (4703.1–4706.1 15,500–15,510 ft (4724.4–4727.4 15,530–15,540 ft (4733.5–4736.6 14,180–14,190 ft (4322.1–4325.1 13,140–13,150 ft (4005.1–4008.1 13,230–13,234 ft (4032.5–4033.7 13,990–14,000 ft (4264.2–4267.2 13,690–13,700 ft (4172.7–4175.8 13,820–13,830 ft (4212.3–4215.4 13,320–13,330 ft (4059.9–4063.0

James Ls. James Ls. James Ls. James Ls. James Ls. James Ls. Pine Island Sh./Sligo Fm. contact Sligo Fm. James Ls./Pine Island Sh. contact Pine Island Sh. Pine Island Sh. Pine Island Sh. Pine Island Sh. James Ls. James Ls. James Ls. Pine Island Sh. Rodessa Fm./James Ls. contact James Ls. James Ls./Pine Island Sh. contact Pine Island Sh. James Ls. James Ls./Pine Island Sh. contact Pine Island Sh. Sligo Fm. Pine Island Sh. James Ls. James Ls. Pine Island Sh. Pine Island Sh. Pine Island Sh. Pine Island Sh. Sligo Fm. James Ls. James Ls. Pine Island Sh. James Ls. Pine Island Sh. Pine Island Sh. Pine Island Sh.

Core Core Core Core Core Core Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Core chips Cuttings Cuttings Cuttings Cuttings

0.44 0.35 0.54 0.48 0.46 0.43 0.39 0.36 0.35 0.27 0.32 0.12 0.31 1.05 1.08 0.12 1.21 0.46 0.50 0.57 0.40 0.64 0.43 0.34 0.49 0.89 0.48 0.56 0.01 0.26 1.21 0.42 0.49 0.20 0.48 0.39 0.32 0.15 0.28 0.19

0.10 0.10 0.09 0.07 0.08 0.07 0.07 0.06 0.19 0.14 0.21 0.10 0.09 0.07 0.21 0.07 0.13 0.08 0.12 0.13 0.06 0.07 0.10 0.07 0.07 0.10 0.07 0.07 0.04 0.08 0.14 0.13 0.08 0.08 0.09 0.09 0.14 0.09 0.09 0.10

0.18 0.15 0.24 0.18 0.22 0.18 0.30 0.20 0.59 0.38 0.59 0.26 0.28 0.41 0.90 0.19 1.05 0.38 0.43 0.48 0.31 0.22 0.20 0.14 0.14 0.32 0.27 0.25 0.14 0.17 0.70 0.28 0.23 0.20 0.26 0.24 0.49 0.22 0.32 0.37

0.47 0.51 0.48 0.45 0.35 0.43 0.37 0.40 0.40 0.38 0.36 0.33 0.49 1.09 0.31 0.34 1.55 0.37 0.59 0.53 0.34 0.51 0.41 0.44 0.36 0.25 0.37 0.42 0.23 0.33 1.50 0.56 0.46 0.36 0.40 0.48 0.34 0.53 0.46 0.40

309 309 343 339 329 328 441 440 361 350 369 341 352 442 440 332 415 433 423 425 423 323 320 322 327 336 438 338 428 345 427 430 338 346 365 344 371 343 351 433

40.91 42.98 44.53 37.42 47.83 42.35 76.53 56.34 169.05 141.79 185.53 209.68 89.46 39.01 83.72 165.22 87.14 82.43 86.87 84.36 77.69 34.59 47.06 40.82 28.51 36.08 56.02 44.48 −1.00 65.89 57.95 66.67 46.75 102.56 54.51 62.34 154.57 143.79 114.70 190.72

106.82 146.13 89.05 93.56 76.09 101.18 94.39 112.68 114.61 141.79 113.21 266.13 156.55 103.71 28.84 295.65 128.63 80.26 119.19 93.15 85.21 80.19 96.47 128.28 73.32 28.18 76.76 74.73 −1.00 127.91 124.17 133.33 93.50 184.62 83.86 124.68 107.26 346.41 164.87 206.19

0.36 0.40 0.27 0.28 0.27 0.28 0.19 0.23 0.24 0.27 0.26 0.28 0.24 0.15 0.19 0.27 0.11 0.17 0.22 0.21 0.16 0.24 0.33 0.33 0.33 0.24 0.21 0.22 −1.00 0.32 0.17 0.32 0.26 0.29 0.26 0.27 0.22 0.29 0.22 0.21

m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m)

Fm. = Formation; HI = hydrogen index (S2 x 100/TOC); Ls. = Limestone; OI = oxygen index (S3 × 100/TOC); PI = production index (S1/[S1 + S2]); S1,S2 = mg hydrocarbons/g rock; S3 = mg CO2/g rock; Sh. = Shale; Tmax in °C; TOC = wt. % total organic carbon.

B.J. Valentine et al. / International Journal of Coal Geology 131 (2014) 378–391

Well name Pennzoil 1 Piazza Heirs Pennzoil 1 Piazza Heirs Pennzoil 1Piazza Heirs Pennzoil 1 Piazza Heirs Pennzoil 1 Piazza Heirs Pennzoil 1 Piazza Heirs Pennzoil 1 Piazza Heirs Pennzoil 1 Piazza Heirs Chevron 32 Cranfield Unit Chevron 32 Cranfield Unit Chevron 32 Cranfield Unit INEXCO Oil Co. 1 Sarah G. Cupit et al. INEXCO Oil Co. 1 Sarah G. Cupit et al. ADCO Prod. 1 Brookhaven BK & TR ADCO Prod. 1 Brookhaven BK & TR ADCO Prod. 1 Brookhaven BK & TR ADCO Prod. 1 Brookhaven BK & TR Watson Oil Corp. 1 H.L. Watson et al. Watson Oil Corp. 1 H.L. Watson et al. Watson Oil Corp. 1 H.L. Watson et al. Watson Oil Corp. 1 H.L. Watson et al. INEXCO 1 Selman Smith Estate INEXCO 1 Selman Smith Estate INEXCO 1 Selman Smith Estate INEXCO 1 Selman Smith Estate Systems Fuels Inc. 1 Polk Berry 17-6 South LA Prod. 1 Bowie Creek Unit 11-6 South LA Prod. 1 Bowie Creek Unit 11-6 ANR Prod. 1 Branch Lee et al. ANR Prod. 1 Branch Lee et al. Tomlinson Int. Inc. 1 Tatum LBR 27-11 Tomlinson Int. Inc. 1 Tatum LBR 27-11 Tomlinson Int. Inc. 1 Tatum LBR 27-11 Shell Oil 1 Tatum et al. California Oil Co. 1 Walley VR California Oil Co. 1 Walley VR Forest Oil Corp. 1 Emerald Mobil Expl. Co. 1 International Paper Co. 27-10 Mobil Expl. Co. 1 International Paper Co. 27-10 Amoco Prod. 1 Cumbest Unit 13-11

B.J. Valentine et al. / International Journal of Coal Geology 131 (2014) 378–391

n = 51

10 5

0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1 1.2 1.3 1.4

TOTAL ORGANIC CARBON (TOC, wt.%)

TYPE I oil-prone usually lacustrine

8 7

Organic Lean

6 5

Mixed TYPE II-III oil-gas-prone

4 3

TYPE III gas-prone

2 1 0 0

D

0.2

0.4

0.6

0.8

1.0

TYPE IV inert 1.4 1.6 1.8

1.2

2.0

TOTAL ORGANIC CARBON (TOC, wt.%)

1000

n = 50 l

TYPE II

500 400 300

Oil Window

PRODUCTION INDEX (PI)

600

Immature Intensive Generation, Expulsion

0.8 0.7 0.6 Stained or Contaminated

0.5 0.4

100

100

150

200

250

300

350

OXYGEN INDEX (OI, mg CO2/g TOC)

F

14

n = 53 12

Frequency

10 8

PRODUCTION INDEX (PI)

50

325

Immature

350

Overmature

375 400 425 450 475 MATURITY (based on Tmax, °C)

Oil Window

Condensate Wet Gas Zone

Intensive Generation, Expulsion

0.8

500

525

550

Dry Gas Window

vitrinite reflectance (n=8) solid bitumen reflectance (n=29)

0.7

Stained or 0.6 Contaminated

0.5 High Level Conversion

0.4

2

375

Dry Gas Window

TYPE IV inert 400 425 450

Mature

475 500

525 550

Postmature

Oil Window

700 TYPE II 600 oil-prone usually marine 500

400

vitrinite Ro (n=8) solid bitumen Ro (n=28)

TYPE II-III oil-gas-prone

300 Dry Gas Window 200

0.2

TYPE III gas-prone

100 Low Level Conversion

0.2

325 350

TYPE I oil-prone usually 800 lacustrine

0.3

0

4

TYPE III gas-prone

900

0.1

6

TYPE II-III oil-gas-prone

300

Immature

Low Level Conversion

0.9 0

400

Tmax (°C)

0.2

1.0

0

500

1000

0.3

0 300

TYPE III IV TYPE IV

TYPE II oil-prone usually marine

600

0 300

High Level Conversion

III

700

Dry Gas Window

0.1

200

800

Postmature

100

n = 50

0.9 II

Mature

Condensate-Wet Gas Zone

HYDROGEN INDEX (HI, mg HC/g TOC)

1.0

700

Immature

TYPE I oil-prone usually lacustrine

200

E

TYPE I 800

Condensate -Wet Gas Zone

900

n = 50

900

TYPE II oil-prone usually marine

HYDROGEN INDEX ( HI, mg HC/g TOC)

0

9

Condensate - Wet Gas Zone

15

1000 n = 51

Oil Window

Frequency

20

C

10

HYDROGEN INDEX ( HI, mg HC/g TOC)

B

REMAINING HYDROCARBON POTENTIAL (S2, mg HC/g rock)

A

385

0.4

0.6

0.8

TYPE IV inert

Overmature

1.0

1.2

1.4

1.6

1.8

MATURITY (measured reflectance in oil, % Ro)

2.0

2.2

0 0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

2.2

MEASURED REFLECTANCE in oil (% Ro)

0

0.9

1.1

1.3 1.5 1.7 1.9 Native Solid Bitumen Ro (%)

2.1

2.3

Fig. 4. Geochemistry graphs (A) Histogram of TOC values from this study and from MISB samples in Enomoto et al. (2012). (B) S2 plotted vs. TOC showing organic lean character and primarily inert nature (pyrobitumen) of pyrolyzed organic matter. (C) Comparison of HI vs. Tmax and HI vs. measured Ro, showing unreliable thermal maturity results from pyrolysis compared to petrographic analysis. (D) HI vs. OI illustrating primarily inert nature (pyrobitumen) of pyrolyzed organic matter. (E) Comparison of PI vs. Tmax and PI vs. measured Ro, showing unreliable thermal maturity results from pyrolysis compared to petrographic analysis. (F) Histogram of Ro values from this study.

(Enomoto et al., 2012) included minimally constrained (low numbers of individual reflectance measurements) Ro values of 0.6–1.2% measured on vitrinite and solid bitumen. The lower reflectance values in our earlier work (Enomoto et al., 2012) may represent the migrated solid bitumens reported in this study, or represent degraded organic matter (scratched, pitted, etc.). As documented herein, reflectance values increase southeast to northwest across the basin. Thermal maturity in the eastern half of the basin appears to be related to present-day burial depth, showing a gradual increase with respect to depth (Fig. 7) (e.g., Koons et al., 1974). However, thermal maturity continues to increase even as the Aptian-age section shallows structurally on the Adams County High toward the western margin of the basin. The empirical bitumen reflectance geothermometer calibration of Barker and Bone (1995) indicates a peak temperature of 136.6 °C (Ro 1.78% for native solid bitumen) for the Pennzoil 1 Piazza Heirs 13,909.5' sample, generally consistent with the higher Th values determined from fluid inclusions (Table 3). All samples from this well (n = 11, Table 5; depth range of 13,910– 14,460 ft [4240–4407 m]) give an average Ro of 1.80%, converting to 137.7 °C, also consistent with the higher homogenization temperatures. The similarity of aqueous inclusion homogenization temperatures (minimum entrapment temperatures) to present-day down-hole

temperatures (uncorrected) of 125–130 °C and peak temperatures calculated from bitumen reflectance may suggest that the Lower Cretaceous strata in this area currently are at or slightly shallower than maximum burial depths. Consistency of salinity and Th values suggests entrapment at elevated temperature from a homogeneous fluid phase. However, limited fluid inclusion data from one sample precludes definitive conclusions regarding thermal history. Possible explanations for higher peak temperatures (as recorded by bitumen reflectance), in the western part of the basin as compared to the east, include agents such as igneous activity or proximity to salt, differences in regional crustal heat flux, or differences in burial depth and erosion. Salt structures do provide a path of low resistance for thermal conduction and can cause local thermal anomalies within close proximity to salt (e.g., Yu et al., 1992). High aqueous inclusion salinities (Table 3) suggest interaction of pore fluids with salt. However, based on the location and analyses of our samples, when compared to known salt structures (Ewing and Lopez, 1991; Geomap® Company, 2012; Lopez and Orgeron, 1995), there does not seem to be a connection to the rise in thermal maturity in the western part of the basin. In addition, numerous samples adjacent to salt from the central and eastern parts of the basin do not display elevated bitumen reflectance values in this study (Fig. 1). Proximity to Upper Cretaceous hypabyssal/

386

B.J. Valentine et al. / International Journal of Coal Geology 131 (2014) 378–391

A

C

B

msb

msb

msb

w w

b

msb

D

b E

nsb

msb

nsb

F

G

nsb nsb nsb

H K

fg

h

h

nsb nsb fg I

Inertinite

J

Fig. 5. Reflected light photomicrographs of organic material in Aptian-age strata of the MISB. All photomicrographs were taken in reflected white light under oil immersion at 500× magnification. The white bar in each image is 10 μm in length. (A) Migrated(?) solid bitumen (msb) in micrite matrix, INEXCO 1 Selman Smith Estate 15,370–15,380 ft (4684.8–4687.8 m). (B) Migrated(?) solid bitumen (msb) under white light (w) and blue light (b) illumination, Systems Fuel Inc. 1 Polk Berry 17-6 14,980–14,990 ft (4565.9–4568.9 m). (C) Void-filling migrated(?) solid bitumen (msb) in carbonate matrix under white light (w) and blue light (b) illumination, Mobil Expl. Co. 1 International Paper Co. 27-10 13,820–13,830 ft (4212.3– 4215.4 m). (D) Void-filling native solid bitumen (nsb) in a carbonate matrix, INEXCO 1 Sarah G. Cupit 15,600–15,610 ft (4754.9–4757.9 m). (E) Void-filling native solid bitumen (nsb) in a micrite matrix, Pennzoil 1 Piazza Heirs 13,959 ft (4254.7 m). (F) Void-filling native solid bitumen in a micrite matrix, Systems Fuel Inc. 1 Polk Berry 17-6 15,070–15,080 ft (4593.3–4596.4 m). (G) Native solid bitumen (nsb) along carbonate grains in a carbonate-rich matrix, Amoco Prod. 1 Cumbest Unit 13-11 13,320–13,330 ft (4059.9–4063 m). (H) Large native solid bitumen in clay/carbonate-rich matrix, California Oil Co. 1 Walley VR 13,140–13,150 ft (4005.1–4008.1 m). (I) Large native solid bitumen (nsb) exhibiting homogenous (h) and fine grained (fg) texture, California Oil Co. 1 Walley VR 13,140–13,150 ft (4005.1–4008.1 m). (J) Native solid bitumen (nsb) exhibiting homogenous (h) and fine grained (fg) texture, California Oil Co. 1 Walley VR 13,140–13,150 ft (4005.1–4008.1 m). (K) Inertinite in micrite matrix, ANR Prod. 1 Branch Lee et al. 15,440–15,460 ft (4706.1– 4712.2 m).

volcanic rocks on the Monroe Uplift (Byerly, 1991; Moody, 1949) or Jackson Dome (Byerly, 1991; Monroe, 1954) is a possible thermal agent; however, our samples are N35 miles (56 km) distant from the locations of known igneous emplacement.

Blackwell and Richards (2004) show heat flow gradients of 55– 59 mW/m2 over most of the basin with the exceptions of the Wiggins Uplift and the western edge of the MISB which show a slight increase to 60–64 mW/m2. Lewan (2002) cited a higher present-day thermal

16 14 12 10 8 6 4 2 0 Ro (%)

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 2 2.2 2.4 2.6 2.8 3 3.2 3.4 3.6 3.8

16 14 12 10 8 6 4 2 0

16 14 12 10 8 6 4 2 0

Ro (%)

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 2 2.2 2.4 2.6 2.8 3 3.2 3.4 3.6 3.8

Mobil Expl.Co. 1 International Paper Co. 27-10 13820-13830’ Frequency

Systems Fuels Inc. 1 Polk Berry 17-6 15070-15080’ Frequency

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 2 2.2 2.4 2.6 2.8 3 3.2 3.4 3.6 3.8

Pennzoil 1 Piazza Heirs 13950-13980’ Frequency

B.J. Valentine et al. / International Journal of Coal Geology 131 (2014) 378–391

Ro (%) EXPLANATION Migrated solid bitumen Native solid bitumen Inertinite Solid bitumen/Inert (?)

Fig. 6. Representative reflectance histograms for three samples.

gradient in the northwestern Mississippi Salt Basin as the agent for higher thermal maturity in the Turonian-age section, relative to elsewhere in the central onshore Gulf Coast. Koons et al. (1974) also noted that the present-day thermal gradient was higher in the western part of the salt basin. Neither Koons et al. (1974) nor Lewan (2002) addressed reasons for a higher thermal gradient; it is implicit in the modeling study of Lewan (2002) that the higher thermal gradient also was present in the geologic past. To calculate the present-day thermal gradients, we performed a limited evaluation of down-hole temperature data (uncorrected) from the wireline log headers used in this study. Thermal gradients are highest in the two wells on the Adams County High, which have the highest bitumen reflectance values (Fig. 7). Thermal gradients are lower to the northwest in Louisiana, and also to the southeast across the central and eastern MISB. This preliminary result suggests that higher thermal maturity on the Adams County High may be related to greater heat flux. However, this observation is preliminary and based only on the limited data from the wells used in this study. To attempt a more regional scale evaluation for this study, we compiled bottom-hole temperature data from IHS Energy Group (2012b) from two counties in our study area (Jefferson County in the west and Perry County in the east). Average thermal gradients calculated from this larger dataset (Perry County, n = 30; Jefferson County, n = 114) were similar at 22.6 °C/km and 20.9 °C/km, respectively, conflicting with the higher thermal gradient calculated for the Adams County High from individual log headers. However, until a systematic heat flow study is completed, we suggest that higher presentday and paleo-thermal gradients on the Adams County High may in part be responsible for increased thermal maturity as documented by higher bitumen reflectance values.

387

The cause of anomalous present-day and/or paleo-heat flow at the Adams County High is not well understood but is presumed related to igneous activity and crustal uplift associated with the Monroe Uplift and Jackson Dome. Salvador (1991) proposed reactivation of an ancient plate boundary or graben due to rapid subsidence of the Gulf of Mexico basin whereas Cox and Van Arsdale (2002) suggested continental passage over the Bermuda hotspot was responsible for vertical crustal movement and igneous emplacement. Until additional information can be applied to further constrain thermal history, we propose two possible scenarios or a combination of the two based on the evidence presented herein: 1) the western end of the MISB has experienced greater heat flux than the central and eastern parts of our study transect, and/or 2) deeper burial of sediments in the west coupled with differential uplift and erosion. 5.2. Potential shale gas resources Critical geological parameters for considerations of shale gas potential include thermal maturity, organic richness, mineralogy and reservoir thickness, among others (Curtis, 2002). Our work demonstrates that the observed thermal maturity is appropriate for shale gas resources, with Ro values of 0.93–2.00% (Table 5) indicating that the Aptian-age section is in the peak oil to dry gas window in the downdip MISB. In this sense, it is similar to other shale plays in the Gulf of Mexico Basin, such as the Eagle Ford, Haynesville and Pearsall Formations. Organic richness (0.5 wt.% average, Table 4) is low compared to other shale plays; for example, Hammes et al. (2011) indicated an average TOC content of 2.8 wt.% in the Haynesville play. Gross thickness of the base of Pine Island Shale to the top of the Rodessa Formation section in our study area (Fig. 7) ranges 640–1262 ft (195–385 m) and averages 902 ft (274 m) (n = 19 interpreted wells), which is similar to other shale plays (National Energy Technology Laboratory, 2013). Another consideration that is important to unconventional reservoir potential is shale mineralogy. Average clay content (53 wt.%) of Pine Island Shale and Rodessa Formation samples in this study (Table 2) is higher than other Gulf of Mexico unconventional plays and may negatively impact artificial stimulation techniques, which work best in more brittle quartz and carbonate-rich rocks (Passey et al., 2010). Evaluated spatially, the mineralogy of Pine Island Shale and Rodessa Formation samples show a relationship to southwestward-directed clastic influx, with carbonate concentration generally increasing downdip and westward at the expense of quartz and clay, suggesting that the shales may be more brittle downdip. Reservoir pressures in the Aptian-age interval appear to be variable based on evaluation of mud weights available for 11 of the 15 sampled wells. Considering a standard hydrostatic pressure of 0.465 psi/ft for saline water, 4 wells were slightly overpressured at ~0.54 psi/ft and the INEXCO Oil Co. 1 Sarah G. Cupit et al. well in Jefferson Co. registered the highest pressure gradient at 0.75 psi/ft. Overall, results from this work indicate generally poor shale gas potential for the Aptian-age section based on low organic and high clay content. However, the thermal maturity is appropriate and petroleum system modeling by others has indicated high undiscovered gas potential for the basin as a whole. 6. Summary and conclusions Organic petrographic data summarized in this paper show that maturity in the downdip MISB Aptian-age section ranges from 1.2% Ro in the southeast, increases with depth to the west to 1.4–1.6% Ro, and continues to increase to 1.7–2.0% Ro as the section shallows on the Adams County High on the western edge of the basin. Two scenarios or their combination are tentatively proposed as possible causes for higher peak temperatures recorded at shallower depths at the western margin of the basin: 1) greater present-day and paleoheat flux, and/or 2) deeper burial and differential uplift and erosion. Analytical results from the present work indicate low organic (avg. 0.5 wt.%) and high

388

Table 5 Native solid bitumen reflectance data. Sample depth

Sample type

Geologic unit(s)

Native SB† Ro

s.d.

n

Pennzoil 1 Piazza Heirs Pennzoil 1 Piazza Heirs Pennzoil 1 Piazza Heirs Pennzoil 1 Piazza Heirs Pennzoil 1 Piazza Heirs Pennzoil 1 Piazza Heirs Pennzoil 1 Piazza Heirs Pennzoil 1 Piazza Heirs Pennzoil 1 Piazza Heirs Pennzoil 1 Piazza Heirs Pennzoil 1 Piazza Heirs Chevron 32 Cranfield Unit Chevron 32 Cranfield Unit Chevron 32 Cranfield Unit INEXCO Oil Co. 1 Sarah G. Cupit et al. INEXCO Oil Co. 1 Sarah G. Cupit et al. INEXCO Oil Co. 1 Sarah G. Cupit et al. ADCO Prod. 1 Brookhaven BK & TR ADCO Prod. 1 Brookhaven BK & TR ADCO Prod. 1 Brookhaven BK & TR ADCO Prod. 1 Brookhaven BK & TR Watson Oil Corp. 1 H.L. Watson et al. Watson Oil Corp. 1 H.L. Watson et al. Watson Oil Corp. 1 H.L. Watson et al. Watson Oil Corp. 1 H.L. Watson et al. INEXCO 1 Selman Smith Estate INEXCO 1 Selman Smith Estate INEXCO 1 Selman Smith Estate INEXCO 1 Selman Smith Estate Systems Fuels Inc. 1 Polk Berry 17-6 Systems Fuels Inc. 1 Polk Berry 17-6 Systems Fuels Inc. 1 Polk Berry 17-6 South LA Prod. 1 Bowie Creek Unit 11-6 ANR Prod. 1 Branch Lee et al. ANR Prod. 1 Branch Lee et al. Tomlinson Int. Inc. 1 Tatum LBR 27-11 Tomlinson Int. Inc. 1 Tatum LBR 27-11 Tomlinson Int. Inc. 1 Tatum LBR 27-11 Shell Oil 1 Tatum et al. Shell Oil 1 Tatum et al. Shell Oil 1 Tatum et al. Shell Oil 1 Tatum et al. California Oil Co. 1 Walley VR California Oil Co. 1 Walley VR Forest Oil Corp. 1 Emerald Forest Oil Corp. 1 Emerald Forest Oil Corp. 1 Emerald Forest Oil Corp. 1 Emerald Mobil Expl. Co. 1 International Paper Co. 27-10 Mobil Expl. Co. 1 International Paper Co. 27-10 Amoco Prod. 1 Cumbest Unit 13-11 Amoco Prod. 1 Cumbest Unit 13-11 Amoco Prod. 1 Cumbest Unit 13-11

13,909.5 ft (4239.6 m) 13,950–13,980 ft (4252.0–4261.1 13,950.5 ft (4252.1 m) 13,952 ft (4252.6 m) 13,959 ft (4254.7 m) 13,965 ft (4256.5 m) 13,966 ft (4256.8 m) 14,100–14,130 ft (4297.7–4306.8 14,280–14,310 ft (4352.5–4361.7 14,370–14,400 ft (4380.0–4389.1 14,430–14,460 ft (4398.3–4407.4 15,320–15,330 ft (4669.5–4672.6 15,350–15,360 ft (4678.7–4681.7 15,430–15,440 ft (4703.1–4706.1 15,600–15,610 ft (4754.9–4757.9 15,722–15,730 ft (4792.1–4794.5 15,820–15,830 ft (4821.9–4825.0 15,940–15,950 ft (4858.5–4861.6 16,000–16,010 ft (4876.8–4879.8 16,130–16,140 ft (4916.4–4919.5 16,320–16,330 ft (4974.3–4977.4 16,100–16,120 ft (4907.3–4913.4 16,260–16,280 ft (4956.1–4986.5 16,340–16,360 ft (4980.4–4986.5 16,440–16,460 ft (5010.9–5017.0 15,340–15,350 ft (4675.6–4678.7 15,370–15,380 ft (4684.8–4687.8 15,450–15,460 ft (4709.2–4712.2 15,490–15,500 ft (4721.4–4724.4 14,960–14,970 ft (4559.8–4562.9 14,980–14,990 ft (4565.9–4569.0 15,070–15,080 ft (4593.3–4596.4 14,840–14,860 ft (4523.2–4529.3 15,380–15,400 ft (4687.8–4693.9 15,440–15,460 ft (4706.1–4712.2 15,430–15,440 ft (4703.1–4706.1 15,500–15,510 ft (4724.4–4727.4 15,530–15,540 ft (4733.5–4736.6 14,140–14,150 ft (4309.9–4312.9 14,180–14,190 ft (4322.1–4325.1 14,240–14,246 ft (4340.4–4342.2 14,300–14,310 ft (4358.6–4361.7 13,140–13,150 ft (4005.1–4008.1 13,230–13,234 ft (4032.5–4033.7 13,990–14,000 ft (4264.2–4267.2 14,020–14,030 ft (4273.3–4276.3 14,100–14,110 ft (4297.7–4300.7 14,220–14,230 ft (4334.3–4337.3 13,690–13,700 ft (4172.7–4175.8 13,820–13,830 ft (4212.3–4215.4 13,320–13,330 ft (4059.9–4063.0 13,420–13,430 ft (4090.4–4093.5 13,560–13,570 ft (4133.1–4136.1

Core Cuttings Core Core Core Core Core Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Core chips Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings

James Ls. James Ls. James Ls. James Ls. James Ls. James Ls. James Ls. James Ls. Pine Island Sh. Pine Island Sh./Sligo Fm. contact Sligo Fm. James Ls./Pine Island Sh. contact Pine Island Sh. Pine Island Sh. James Ls. Pine Island Sh. Pine Island Sh. James Ls. James Ls. James Ls. Pine Island Sh. Rodessa Fm./James Ls. contact James Ls. James Ls./Pine Island Sh. Contact Pine Island Sh. James Ls. James Ls./Pine Island Sh. contact Pine Island Sh. Sligo Fm. James Ls./Pine Island Sh. contact Pine Island Sh. Pine Island Sh. James Ls. Pine Island Sh. Pine Island Sh. Pine Island Sh. Pine Island Sh. Sligo Fm. James Ls. James Ls. James Ls. Pine Island Sh. James Ls. Pine Island Sh. James Ls. Pine Island Sh. Pine Island Sh. Sligo Fm. Pine Island Sh. Pine Island Sh. Pine Island Sh. Sligo Fm. Sligo Fm.

1.78 1.70 1.71 1.83 1.85 1.76 1.79 1.72 1.89 2.00 1.80 1.79 1.93 1.82 1.59 1.47 1.60 1.53 1.57 1.65 1.60 1.47 1.31 1.68 1.66 1.44 1.37 1.34 1.51 1.15 1.22 1.18 1.18 1.30 1.45 1.25 1.26 1.21 1.04 1.12 0.93 1.10 1.01 1.27 1.23 1.22 n.d. 1.30 1.12 1.30 1.22 1.25 1.27

0.19 0.17 0.26 0.19 0.19 0.21 0.19 0.21 0.16 0.15 0.20 0.16 0.17 0.20 0.16 0.14 0.23 0.17 0.21 0.19 0.14 0.25 0.23 0.22 0.17 0.19 0.15 0.19 0.24 0.24 0.25 0.22 0.16 0.16 0.19 0.22 0.24 0.24 0.24 0.28 0.22 0.28 0.15 0.14 0.26 0.20 n.d. 0.22 0.19 0.22 0.18 0.17 0.17

76 58 76 63 72 69 79 48 31 37 20 11* 26 35 71 24 30 45 33 44 12* 26 19* 31 25 40 32 23 21 10* 58 47 11* 31 43 56 32 25 21 32 42 42 64 24 49 32 n.d. 38 17* 41 36 25 12*

m)

m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m) m)

Comments Migrated SB present (0.66, 0.75, 1.0%, 3 measurements).

Migrated SB present (0.35, 0.39%, 2 measurements).

Migrated SB present (0.7–1.0%, 5 measurements). Migrated SB present (1.1%, 1 measurement). Vitrinite fragment found (1.44%, 1 measurement). Migrated SB present (0.85%, 1 measurement). Vitrinite fragment found (1.38%, 1.63%, 2 measurements). Migrated SB present (0.89, 0.96, 0.99%, 3 measurements). Migrated SB present (0.69–0.95%, 6 measurements).

Migrated SB present (0.66%, 1 measurement).

Migrated SB present (0.40%, 1 measurement). Migrated SB present (0.27, 0.34, 0.52%, 3 measurements). Migrated SB present (0.31–0.77%, 4 measurements).

Migrated SB present (0.60%, 1 measurement).

Migrated SB present (0.33–0.55%, 6 measurements). Migrated SB present (0.47–0.6%, 9 measurements). Migrated SB present (0.29–0.58%, 4 measurements). Migrated SB present (0.36%, 1 measurement). Migrated SB present (0.39%, 1 measurement). Migrated SB present (0.67%, 1 measurement). No organic matter measured due to insufficent sample material. Migrated SB present (0.67%, 1 measurement). Migrated SB present (0.69%, 1 measurement). Migrated SB present (0.64%, 1 measurement).

† = indigenous solid hydrocarbons matured in situ(?); * = insufficent number of measurements (ASTM, 2013a, 2013b); Fm. = Formation; Ls. = Limestone; n.d. = not determined; SB = solid bitumen; s.d. = standard deviation; Sh. = Shale.

B.J. Valentine et al. / International Journal of Coal Geology 131 (2014) 378–391

Well name

A

389

Fig. 7. MISB structural cross-section of Aptian-age strata. (A) Cross-section with native solid bitumen reflectance (Ro;%) measurements, generalized iso-reflectance contours, and calculated thermal gradients (°C/km; based on uncorrected temperatures from wireline log headers). (B) Map of the top of the James Limestone with cross-section transect, average reflectance values for each well, and generalized iso-reflectance contours.

B.J. Valentine et al. / International Journal of Coal Geology 131 (2014) 378–391

B

390

B.J. Valentine et al. / International Journal of Coal Geology 131 (2014) 378–391

clay (avg. 53 wt.%) content are present in Rodessa and Pine Island shales in the downdip MISB, suggesting generally poor shale gas potential. However, the thermal maturity is appropriate (Ro 0.93–2.00% from native solid bitumen) and the gross thickness of the examined section (avg. 902 ft; 274 m) is similar to that of other North American shale plays. The data contained herein will be useful in the context of shale gas exploration in the downdip MISB and will support future USGS assessments of undiscovered energy resources. Acknowledgments Reviews by Neely Bostick, Brian Cardott, David Dockery, Jen O'Keefe, Magdalena Misz-Kennan, Peter Warwick and an unidentified journal reviewer improved this manuscript. We would like to thank James Coleman for his guidance and assistance on this project. We also would like to thank Robert Ervin and Michael Pippins at the Mississippi Office of Geology Core Repository for their tremendous help in procuring samples for this study. 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