Estimates of Maturation and TOC from Log Data in the Eagle Ford Shale, Maverick Basin of South Texas

Austin Cardneaux and Jeffrey A. Nunn

Department of Geology and Geophysics, Louisiana State University, E235 Howe-Russell Bldg., Baton Rouge, Louisiana 70803

ABSTRACT

The Eagle Ford Formation in South Texas has been an established hydrocarbon play since 2008. This study uses geohistory and thermal modeling analysis to map the boundary between the oil window and immature areas in the Maverick Basin. The up-dip limit of the oil window of the Eagle Ford Formation is present as far north as the uppermost parts of Maverick, Zavala, and Frio counties based on estimated vitrinite reflectance (%Ro). This limit correlates to a subsea structure depth of ~650 ft (198 m) in Maverick county, ~2900 ft (884 m) in Zavala county and ~3650 ft (1113 m) in Frio coun-ty. The change in depth in relation to maturity reflects the amount of burial and subse-quent uplift and erosion along the Chittim Anticline. %Ro estimated from geohistory and thermal modeling are consistent with published studies of cores and cuttings and correlate well with published %Ro maps. Total organic carbon (TOC) was calculated using a well log overlay analysis technique. TOC varies laterally and stratigraphically throughout the study area. TOC is higher in the lower Eagle Ford compared to the up-per Eagle Ford. An area of high TOC (>10%) is noted in the lower Eagle Ford near the center of the Maverick Basin. The log overlay analysis technique for calculating TOC shows reasonable results when compared to actual measurements from cores and cut-tings. These techniques can provide a quick look to define the petroleum potential in frontier areas where data are limited.

INTRODUCTION In 2010, the United States (U.S.) was the third largest crude oil producer in the world, but almost half of the

19.1 MMbopd used in the U.S. was imported (EIA, 2011). Full development of shale plays within the U.S. can allow this country to be more energy self-sufficient. The Eagle Ford Formation in south and central Texas is arguably one of the best shale plays within the U.S. because of its: 1) relatively shallow depths; 2) the presence of liquid hydrocarbons; 3) high percentage of carbonate content which makes it easier to fracture; and 4) large lateral extent and thickness (Railroad Commission of Texas, 2011).

The Eagle Ford has been studied for over 120 years and was named from outcrops around Dallas, Texas (Hill, 1887). The term shale play is relative considering that many of these resource shale plays are not 100% shale as the term implies. Variable rock properties in shale plays require different techniques to extract the oil and gas. Methods like hydraulic fracturing and horizontal drilling had to be implemented to extract this natural resource. The Eagle Ford play was initially discovered as dry gas, and later wet gas and oil were discovered up-dip. The northern part of the play is the updip oil window with lower pore pressure and higher oil volumes, the southern part of the play is the downdip dry gas window with higher pore pressure, and in the middle is the wet gas or condensate window (DrillingInfo, 2010).

The Eagle Ford play area is growing. Large and small companies are working to delineate the spatial and stratigraphic extent of the oil window of the play due to currently higher oil prices as compared to lower gas pric-es. Many interpretations have been released on limits of this play (e.g., EIA, 2011; Chesapeake Energy, 2012), but the data and technique behind those interpretations are proprietary. This study was conducted to demonstrate

Cardneaux, A., and J. A. Nunn, 2013, Estimates of maturation and TOC from log data in the Eagle Ford Shale, Maverick Basin of South Texas: Gulf Coast Association of Geological Societies Transactions, v. 63, p. 111124.

111

Copyright 2013 by The Gulf Coast Association of Geological Societies

Cardneaux and Nunn

techniques for defining the northern limits of the oil window of the South Texas Eagle Ford shale play using pub-lic data. These techniques can be applied to the entire Eagle Ford shale play as well as other shale plays. Well logs were used to determine the thickness of the Eagle Ford and the overburden formations for geohistory model-ing. The modeling was used to estimate vitrinite reflectance (%Ro) values, which gave a basis for defining lim-its. Well logs also were used to estimate spatial variations in total organic carbon (TOC) using an overlay analy-sis (Passey et al., 1990). A Masters thesis by Harbor (2011) performed detailed geochemistry on a group of Ea-gle Ford wells, and data from nine of Harbors wells have been used to calibrate the models (Cardneaux, 2012, Appendix A). Geochemical calibration allowed for wells with only log data to be used.

The study area is within the following counties in Texas: Kinney, Maverick, Uvalde, Zavala, Medina, and Frio (Fig. 1), which are part of the Maverick Basin. The Eagle Ford outcrops in the study area within Kinney, Uvalde, and Medina counties. This area was chosen for this study because of the variability in published maps of the Eagle Ford oil window and also drilling is moving farther north to test and define the limits of the oil window.

GEOLOGIC SETTING The opening of the Gulf of Mexico and the rotation of the Yucatan Block caused a half-graben to form dur-

ing Triassic time in what is now Maverick County, Texas (Ewing, 2003; Scott, 2003). Salt was deposited in the Late Triassic and Jurassic time (Salvador, 1991). Thermal subsidence was amplified by the evacuation of as much as 1000 m (3281 ft) of salt (Salvador, 1991).

In South Texas, the Ouachita basement provided a stable topography for the development of coastlines and carbonate platforms, like the Stuart City and Sligo reef margins (Goldhammer and Johnson, 2001). Southern movement of the Laramide Uplift filled the Cretaceous foreland basin and caused sediment to be deposited into intrashelf depocenters such as the Maverick Basin (Galloway, 2008). During the Cretaceous, Precambrian highs, including the Llano Uplift in Central Texas and the Coahuila Block in northeast Mexico were the source of clas-tic sediment into the Maverick Basin (Goldhammer and Johnson, 2001). The southeast-northwest trending San Marcos Arch, an extension of the Llano Uplift, separates the Maverick Basin and the East Texas Basin (Loucks, 1976). Laramide compression inverted the Triassic half-graben and formed the Chittim Arch in the western por-tion of the Maverick Basin (Ewing, 2003) (Fig.1). Uplift may have caused 12 km (0.61.2 mi) of erosion (Ewing, 2003).

The Eagle Ford Formation was deposited during the Middle Cenomanian to Turonian stages of the Upper Cretaceous, an interval of approximately 9 million years. In South Texas, the Eagle Ford lies unconformably below the Austin Chalk Formation and above the Buda Formation. The unconformable surfaces between the upper Eagle Ford and Austin Chalk as well as the lower Eagle Ford and Buda can be clearly seen in the type log (Fig. 2). The Eagle Ford can be divided into an upper and a lower unit that can be distinguished by changes in log response (Fig. 2). Donovan and Staerker (2010) and Lock et al., (2010) have identified further subdivisions within the Eagle Ford based on outcrop studies, but those boundaries are not consistently recognized in log data. The upper Eagle Ford is interpreted to be progradational within a highstand systems tract and the lower Eagle Ford is interpreted to be retrogradational within a transgressive systems tract (Donovan and Staerker, 2010). Because the Eagle Ford is transgressive, the formation is older near the Sligo shelf margin and younger towards the north (Adams and Carr, 2010). Some workers interpret the Eagle Ford as a continuous transgressive systems tract (Adams and Carr, 2010; Dawson and Almon, 2010), and others interpret alternating transgressive/regressive sequences (Donovan and Staerker, 2010; Harbor, 2011; Lock et.al., 2010). Eagle Ford units thin from the Maver-ick Basin to the San Marcos Arch in the subsurface (Hentz and Ruppel, 2010).

The upper Eagle Ford consists of interbedded dark and light gray calcareous mudrock, while the lower Eagle Ford unit consists of mostly dark gray mudrock (Hentz and Ruppel, 2010). Cardneaux (2012) described different facies interpretations from the literature. Gas-prone organic material is typical of the upper Eagle Ford and more oil-prone organic material is found within the lower Eagle Ford interval (Dawson and Almon, 2010). Regional lithofacies patterns and fossil content indicate a marginal to open marine depositional setting for the Eagle Ford Formation (Dawson and Almon, 2010). Eagle Ford strata show a mixed siliciclastic-bioclastic sediment mix that accumulated near and below storm wavebase on a relatively shallow shelf to the northwest and in deeper settings to the south and southwest (Dawson and Almon, 2010).

DATA AND METHODS Wireline logs from 84 wells with spontaneous potential (SP) and resistivity (RES) curves were used in this

study (Fig. 1). Some wells also had gamma ray (GR), sonic (DT), and neutron-density (ND) curves. A list of

112

Estimates of Maturation and TOC from Log Data in the Eagle Ford Shale, Maverick Basin of South Texas

wells and associated logs are provided in Cardneaux (2012). The wireline logs for the study area were obtained from: DrillingInfo, TGS-NOPEC Geophysical Company, Texas Bureau of Economic Geology, and the Texas Railroad Commission. Wells are concentrated in Kinney, Uvalde, Medina, Frio, Zavala, and Maverick counties, with a few outliers which were used for correlation (Fig. 1).

Mapping Using GeoGraphix Data for the 84 wells were imported into Landmark/Halliburtons GeoGraphix software, and plotted using

latitude and longitude positions of each well. A shape file for Texas and Texas counties was downloaded from the U.S. Census Bureau TIGER/Line website and imported into GeoGraphix. Also in GeoGraphix, tiff image files for the wireline logs were depth registered. Formations were correlated based on lithologies within the Maverick Basin and their respective wireline curve responses. The Del Rio Formation has high gamma ray values of ~90 API units and resistivity values of ~8 ohm-m. The Buda Formation is characterized by a blocky signature with low gamma ray values of ~15 API units and resistivity values of ~15 ohm-m. The lower Eagle Ford has gamma ray values of 90 to 135 API units and the upper Eagle Ford has gamma ray values of 45 to 60 API units (Hentz and Ruppel, 2010). The lower Eagle Ford also has resistivity values of ~60 ohm-m and the upper Eagle Ford has resistivity values of ~10 ohm-m. The tran-sition between Upper Eagle Ford and the Austin Chalk Formation shows short zones of fluctuating readings for gamma ray and resistivity. The Austin Chalk has gamma ray values of ~30 API units and resistivity values of ~10 ohm-m. Figure 2 shows the type log. Younger units are described in Cardneaux (2012).

Geohistory/Maturation Calculations Using PetroMod

Using Schlumbergers IES GmbH PetroMod 2011 software, 1D models were created for temperature history to calculate %Ro for each well in the study area. Input information required by PetroMod included thickness, deposition ages, and lithology for every distinguishable formation (Table 1). Lithology and geologic time period

Figure 1. Map of study area in south Texas with county boundaries. Wells used in this study are shown as black dots. Red dots are wells also used by Harbor (2011). Chittim Anticline is shown as a heavy line with orthogonal double arrowhead line. The Maverick Basin is outlined by a dashed line.

113

Cardneaux and Nunn

Figure 2. Type log for study area. Unit subdivisions are from Donovan and Staerker (2010).

are defined using the descriptions available on the U.S. Geological Survey website . International Union of Geological Sciences geologic time scale was used to get the approximate ages in million years ago (Ma) for each formation. Geohistory plots in PetroMod use the Easy %Ro method for computing maturation (Burnham and Sweeney, 1990).

PetroMod also requires heat flow, water depth, and surface temperature to calculate the thermal history. Basal heat flow through time is derived from the McKenzie Model for lithospheric stretching (McKenzie, 1978). The model is based on two periods: an initial stretching period with constant thinning of the lithosphere and a cooling period with rebuilding of the original thermal thickness of the lithosphere (Hantschel and Kauerauf, 2009). With a lack of structural history on the Maverick Basin, basal heat flow settings are based on Gulf of Mexico rifting and subsidence. Rifting in the Gulf of Mexico occurred in Late Triassic to Middle Jurassic, and subsidence occurred in the Late Jurassic to Early Cretaceous (Buffler and Sawyer, 1985). Rifting ages from 225 to 160 Ma and subsidence ages from 160 to 135 Ma were used in the McKenzie model. Basal heat flow was estimated from the models to be 63 mW/m2 from 135 Ma to present, which correlates to SMU (2011) heat flow maps for present day. The heat flow is constant for over 40 Ma before Eagle Ford deposition thus model assump-tions regarding rifting do not significantly affect results for the Eagle Ford. The Eagle Ford was deposited on a relatively shallow shelf (Dawson and Almon, 2010). Pinet (1996) describes a continental shelf to be less than 150 m (~492 ft). Paleowater depth (PWD) was estimated in this study to be 450 ft (137 m) for the Eagle Ford zone in the study area. Water depths in the Hawkville trough to the south may have been greater. PetroMod uses a Sediment Water Interface Temperature (SWIT) model based on Wygrala (1989) to get an average air surface temperature history which varies with latitude and changes in global temperatures throughout geological time, and is necessary to constrain the upper boundary condition on heat transport (Hantschel and Kauerauf, 2009).

114

Estimates of Maturation and TOC from Log Data in the Eagle Ford Shale, Maverick Basin of South Texas

Maturity in %Ro from PetroMod was recorded for both the upper and lower Eagle Ford zones. The model-ing results were correlated to %Ro results from core analysis by Harbor (2011). Harbor (2011) estimated %Ro from Tmax values using %Ro = 0.0180 * Tmax 7.16 (Jarvie, 2001). This relationship had an R2 value of 0.79 using the data available to Jarvie (2001). %Ro values are reviewed in the Results and Discussion section.

Delta Log R and TOC A log overlay analysis to determine mature source zones was used (Fig. 3) (Passey et al., 1990). Porosity

logs respond to organic matter type and in a probable source rock there is a high transit time or low bulk density coupled with a high resistivity caused by the presence of non-conducting hydrocarbons (Passey et al., 1990). If a porosity curve and a resistivity curve are in the same log tract the curves will overlay in a non-source rock (baseline), a separation caused by resistivity will occur in a reservoir, a separation caused by the sonic curve will occur in an immature source, and a separation of both curves will occur in a mature source. A gamma-ray log is used to determine lithology. The separation in a mature source can be quantified to give a value known as Delta Log R (Fig. 3).

Quantifying Delta Log R is necessary to solve for TOC in this technique and is represented by: Delta Log R = log10 (R / Rbaseline) + 0.02 * (t tbaseline). Resistivity baseline and DT baseline values were averaged for wells with the Del Rio shale formation present. The average was 5 ohm*m (RES) and 86 s/ft (DT). Resistivity val-ues used in the Delta Log R formula were the average of the highest and lowest resistivity value within the upper and lower Eagle Ford interval. %Ro values from modeling were transformed into level of maturity (LOM) by re-arranging LeCompte and Hursans (2010) formula. The Delta Log R value was used along with LOM to estimate TOC:

TOC = ( log R) * 10 (2.297 0.1688 * LOM). Most wells in the study area do not have sonic (DT) curves on the wireline logs, so a cross-plot method was

implemented to empirically solve for DT if resistivity is known. The type log was digitized to be used in the cross-plot function of Prizm in GeoGraphix. A cross-plot of the Eagle Ford resulted in a linear line fit equation of:

Upper Eagle Ford (Fig. 4a): DT = 92.101860 1.488029 * (RES) and Lower Eagle Ford (Fig. 4b): DT = 74.632980 + 0.091947 * (RES). The correlation between crossplot DT values and log DT values are discussed further in the Results and Dis-

cussion section. Using the two cross-plot equations, DT can be calculated for both the upper and lower Eagle Ford intervals in every well. TOC can now be solved for all wells in the study area using the Delta Log R meth-od.

Table 1. Example input values for PetroMod calculations.

Layer Top, ft Age, Ma Lithology Sparta 0 39 Sandstone Cane River 360 42 Shale Wilcox 542 45 Sandstone (typical) Midway 5773 59 Siltstone (organic lean) Navarro 6210 65 Siltstone (organic lean) Olmos 6900 70 Sand and Shale San Miguel 7440 74 Shale Anacacho 9712 79 Limestone Austin 10278 85 Limestone (chalk, typical) Upper Eagle Ford 10420 88 Marl Lower Eagle Ford 10522 90 Marl Buda 10683 96 Limestone (micrite) Base of Buda 10804 100

115

Cardneaux and Nunn

RESULTS AND DISCUSSION Figure 5 contains a structure map on the top of the Eagle Ford. The Eagle Ford has a regional dip to the

southeast. The Chittim Anticline can be seen within the structural map by a plunging anticlinal pattern in the contours in Maverick and Zavala counties. Structural contours in Figure 5 compare well with Petrohawks re-sults (EIA, 2011). Martin et al. (2011) analyzed production from the Eagle Ford and developed an isochore map along with production figures. Their isochore map of the Eagle Ford correlates to the isochore map created in this study (Fig. 5) showing that the formation identifications are consistent between the two studies.

In both isochore maps, a thick section of Eagle Ford Formation is seen within Maverick County and extends east into Zavala County within the basin. Another high is present in southern La Salle and McMullen counties. A thin section is seen on the east side of Dimmit County and in the northwest of La Salle County as well as Frio County. Differences between isochore maps are most likely due to well control.

A strong correlation outside of the Maverick Basin (Fig. 1) was established between model %Ro results and %Ro measured from core samples (Harbor, 2011) (Table 2). However, initial results within the basin and espe-cially in Maverick County were lower than the data from Harbor (2011) because erosion on the Chittim Anticline was not taken into account. Formation of the Chittim Anticline took place from late Late Cretaceous until late Eocene time (~70 Ma to ~39 Ma) (Fowler, 1956). The Eocene Sparta Formation, deposited ~39 Ma, is the youngest interval seen in the wells in the study area. In the base case model, deposition was assumed to be con-stant throughout the area and the thicknesses of formations present in the A. M. Foerster well in east-central La Salle County (Fig. 1) were assumed to be the original formation thicknesses since all formations are present in this well because tectonic events have not caused erosion. Erosion estimates varied from well to well based on the youngest formation in each well as compared to the thicknesses of the formations in the A.M. Foerster well. For example, based on the Wilcox thickness in the A. M. Foerster well, the Halff well in west-central Frio Coun-ty (Figs. 6 and 7) experienced 2400 ft (730 m) of sedimentation followed by erosion which increases estimated %Ro of the Eagle Ford from 0.63 without erosion to 0.71 with erosion. Erosion is presumed to start after deposi-tion and continued at a constant rate until present, since the surface Eocene rocks conform to the plunging anticli-nal outcrop pattern of the Chittim Anticline. Other deposition and erosion possibilities are discussed in the sensi-tivity analysis.

Figure 3. Resistivity and sonic log response to types of source rocks and reservoir rocks (modified after Passey et al., 1990).

116

Estimates of Maturation and TOC from Log Data in the Eagle Ford Shale, Maverick Basin of South Texas

An independent way of estimating the amount of erosion that took place in the study area is the relationship of porosity to depth. Sclater and Cristie (1980) described how porosity changes with depth for different litholo-gies. Porosity values from neutron/density porosity logs and from PetroMod calculated porosity were sampled every 100 ft (30 m) for the length of three wells. Porosity values were plotted against the compaction curves of Sclater and Cristie (1980) for shale, shaly sand, sand, and chalk. Well log porosity and PetroMod porosity values are much smaller than porosity estimated from compaction curves assuming that present depth is maximum depth of burial. However, when estimated erosion is included, well log porosity and PetroMod porosity plot very close to the compaction curve for chalk. The close relationship to the chalk compaction curve is understandable since most of the Cretaceous section in the Maverick Basin is calcareous. Ewing (2003) estimated 12 km (0.61.2 mi) of erosion on the Chittim Anticline, which is consistent with estimates from wells in this study near the anti-cline. Another technique to estimate the amount of erosion is moisture content of coal. The moisture content of coal decreases with burial depth and moisture content has a direct relationship to the type of coal and also %Ro (Hacquebard, 1977). Scott and Gose (2002) noted two types of coals in the Maverick Basin: bituminous high-volatile C in the Olmos formation and lignite within the Wilcox formation. Hacquebard (1977) showed the range of %Ro for bituminous high-volatile C to be ~0.52 to ~0.65 and the range of %Ro for lignite to be ~0.35 to ~0.41. For the Halff well, the %Ro values with estimated erosion are in the range for coal in relationship to depth of burial. For the L. O. Travis well in southwest Zavala County, %Ro values with estimated erosion for the Ol-mos formations are less than the range for coal moisture content, but %Ro values for the Wilcox formation are in the range for coal in relationship to depth of burial. Cardneaux (2012) contained a complete discussion of ero-sion estimates.

Figure 8 shows %Ro estimated from PetroMod results in this study versus %Ro from Harbor (2011). Model results and Harbor (2011) results are within +/- 0.08 %Ro (Fig. 8). For both the upper and lower Eagle Ford units in all wells, DT values were computed using the crossplot equation and resistivity values from the log, Delta Log R using the resistivity and DT values for the Eagle Ford and Del Rio, LOM using the model %Ro, and TOC us-ing Delta Log R and LOM. The resistivity values from the log were average values, so TOC calculations were based on average values. %Ro values were taken from the middle of each of the Eagle Ford units.

Figure 9 shows a %Ro map for the lower Eagle Ford in the Maverick Basin. Results are consistent with %Ro maps constructed using proprietary data (e.g., online maps by EIA and Chesapeake Energy). In general, esti-mated %Ro increases from immature in the north to dry gas in the south due to greater depth of burial (Figs. 5 and 9). In the northern portion of the Maverick Basin, the Eagle Ford is immature but in most of Maverick, Zavala, and Frio counties the Eagle Ford should be in the oil window.

LOM maps can be combined with Delta Log R values to estimate TOC. As most wells in this study area did not have sonic logs, Delta Log R was estimated empirically using a crossplot of DT values with resistivity values as explained in the Data and Methods section. Sondhi (2011) showed that in the Eagle Ford, sediment with high-er clay content has a higher porosity and lower velocity (higher DT) and sediment with higher carbonate content

Figure 4. Resistivity/DT cross-plots: (left) upper Eagle Ford and (right) lower Eagle Ford. Linear trend line in blue. Depths are color coded as shown in the legend.

117

Cardneaux and Nunn

Figure 5. (Top) Subsea depth structural contour map on the top of the Eagle Ford Formation. Con-tour interval is 750 ft (9229 m). (Bottom) Top of Eagle Ford to Top of Buda isochore map. Contour interval is 50 ft (15 m). Open circles are well locations. Chittim Anticline is shown as a heavy line with orthogonal double arrowhead line. The Maverick Basin is outlined by a dashed line. Minimum curva-ture gridding algorithm with a smallest feature radius of 50,000 ft (15,240 m) and a radius of influence of 750,000 ft (230,000 m) was used. See Cardneaux (2012) for values at each well location.

has a lower porosity and increased velocity (lower DT). Also, velocity decreases (higher DT) when TOC increas-es. Therefore, the upper Eagle Ford should have a lower DT than the lower Eagle Ford due to lithology, porosity, and TOC. However, the crossplot and the sonic logs show a higher DT in the upper Eagle Ford and a lower DT in the lower Eagle Ford. This opposite response could be explained by fractures in the upper Eagle Ford that create secondary porosity and increase DT. The upper Eagle Ford lithology is more brittle compared to the lower Eagle Ford. Estimates of DT from the resistivity crossplot method compared to actual DT values measured by the sonic log for three wells in the study area and crossplot estimates are within +/- 10 s/ft from log values. The SP log also was investigated to determine its potential in estimating DT using the crossplot method because it is a

118

Estimates of Maturation and TOC from Log Data in the Eagle Ford Shale, Maverick Basin of South Texas

common and widely available log. The results were not as accurate as crossplotting DT versus resistivity, but show a relationship between the two well logs (Cardneaux, 2012).

Figure 9 shows TOC maps for the upper and lower Eagle Ford units, respectively. Estimated TOC values are much lower for the upper Eagle Ford unit and higher for the lower Eagle Ford unit, which is consistent with Harbor (2011) and Lock et al. (2010). A high TOC zone of the lower Eagle Ford in Zavala County (Fig. 9) is inferred by high resistivity values (100+ ohm-m). Literature was investigated for paleostructure, water chemis-try, or any other possibility to explain this high TOC zone, but definitive information was not found.

Figure 10 shows a comparison between TOC for the lower Eagle Ford from Harbor (2011) and estimated TOC for six wells. The estimated TOC in this study, referred to herein as the Delta Log R TOC technique, is from using the Passey et al. (1990) TOC equation described in the Data and Methods section. The high/low val-ues for the estimated Delta Log R TOC technique are from using maximum and minimum resistivity values from the well logs. The high/low values for Harbor (2011) are either from core or cuttings taken over the interval. In some cases, TOC is highly variable within a small stratigraphic interval. Figure 10 shows the Delta Log R TOC technique accurately predicts within the range of measured values from Harbor (2011) for the Hendershot, Schau-ers, Gise, and Chittim wells. The Delta Log R TOC technique for the Halff and Calvert wells underestimates TOC by less than 1 wt.%. In Harbor (2011), the Gise well has TOC measurements that are very close to each other (within the thickness of the symbols), so the error bar is not shown.

SUMMARY AND CONCLUSIONS

The potential limit of the oil window of the Eagle Ford Formation in South Texas defined in this study is present as far north as the uppermost parts of Maverick, Zavala, and Frio counties based on %Ro. This limit cor-relates to a subsea structure depth of ~ 200 m (650 ft) in Maverick County, ~880 m (2900 ft) in Zavala County, and ~1110 m (3650 ft) in Frio County. The change in depth in relation to maturity reflects the amount of subsid-ence within the Maverick Basin and subsequent uplift and erosion along the Chittim Anticline.

%Ro estimated from geohistory and thermal modeling used in this study are consistent with core/cuttings (Harbor, 2011) and correlate well with published %Ro maps. This technique could be applied in other shale plays to understand fully the geologic history, thermal regime, and how all the aspects of the petroleum system tie to current data.

TOC varies laterally and stratigraphically throughout the study area. However, TOC is higher in the lower Eagle Ford compared to the upper Eagle Ford. A high TOC area is noted in the lower Eagle Ford on the contour map. The log overlay analysis technique for calculating TOC (Passey et al., 1990) shows reasonable results when compared to actual measurements, and can give a quick look to define the petroleum potential of a prospect.

The structure map shows the location of the Chittim Anticline and the regional southeast dip of the Eagle Ford. %Ro is affected by depth of burial and the structural contours have a similar trend as the %Ro maps. The isochore map shows the Eagle Ford depositional structure and correlates to the thicknesses of Martin et al. (2011) isochore map.

ACKNOWLEDGMENTS

We thank Stephen Sears and Art Donovan for helpful comments and advice during this research. The De-partment of Geology and Geophysics of Louisiana State University provided financial support for AC. Land-mark and Schlumberger donated the software used in this research.

Table 2. Estimated %Ro from thermal modeling and %Ro from core data (Harbor, 2011).

Well Name Depth, ft Model %Ro (this study) Core %Ro (Harbor, 2011)

Hendershot 4745 0.54 0.56

Benbele 7987.5 0.73 0.73

Schauers 8122 0.76 0.72

Triple Bar Ranch 10780 1.32 1.32

119

Cardneaux and Nunn

REFERENCES CITED

Adams, R. L., and J. P. Carr, 2010, Regional depositional systems of the Woodbine, Eagle Ford, and Tuscaloosa of the U.S. Gulf Coast: Gulf Coast Association of Geological Societies Transactions, v. 60, p. 327.

Buffler, R. T., and D. S. Sawyer, 1985, Distribution of crust and early history, Gulf of Mexico Basin: Gulf Coast Asso-

ciation of Geological Societies Transactions, v. 35, p. 333344. Cardneaux, A. P., 2012, Mapping of the oil window in the Eagle Ford Shale Play of Southwest Texas using thermal

modeling and log overlay analysis: Masters thesis, Louisiana State University, Baton Rouge, 83 p. Chesapeake Energy, 2012, May 2012 investor presentation, p. 10 of 31, Accessed July 22, 2013. Dawson, W. C., and W. R. Almon, 2010, Eagle Ford Shale variability: Sedimentologic influences on source and reser-

voir character in an unconventional resource unit: Gulf Coast Association of Geological Societies Transactions, v. 60, p. 181190.

Donovan, A. D., and T. S. Staerker, 2010, Sequence stratigraphy of the Eagle Ford (Boquillas) Formation in the

subsurface of South Texas and outcrops of West Texas: Gulf Coast Association of Geological Societies Transactions, v. 60, p. 861899.

DrillingInfo, 2011, Eagle Ford Shale overview: DrillingInfo, Inc., Austin, Texas. EIA (U.S. Energy Information Administration), 2010, Eagle Ford Shale play map, Accessed June 22,

2013. Ewing, T. E., 2003, Review of the tectonic history of the Lower Rio Grande border region, South Texas and Mexico,

and implications for hydrocarbon exploration: Society of Independent Professional Earth Scientists Newsletter, v. 40, p. 1621.

Fowler, P., 1956, Faults and folds of south-central Texas: Gulf Coast Association of Geological Societies Transactions,

v. 6, p. 3742.

Figure 6. Burial history curve for the Halff well in west-central Frio County computed from Petro-Mod, assuming uniform erosion from 39 Ma to present.

120

Estimates of Maturation and TOC from Log Data in the Eagle Ford Shale, Maverick Basin of South Texas

Figure 7. %Ro values for the Eagle Ford formation for nine wells in the study area (red dots in Figure 1): (red bars) estimated from PetroMod, and (blue bars) measured from core data by Harbor (2011). Hassett is in Zavala County, Triple Bar Ranch is in La Salle County, and Benbele is in south-east Frio County. Henderson and Schauers are in Gonzales County, Lawrence Gise is in Dimmit County, Calvert and Halff are in Frio County, and Chittim, J. M. is in Maverick County.

Galloway, W. E., 2008, Depositional evolution of the Gulf of Mexico Sedimentary Basin, in A. D. Miall, ed., The sedi-mentary basins of the United States and Canada: Elsevier, New York, New York, 610 p.

Goldhammer, R. K., and C. A. Johnson, 2001, Middle JurassicUpper Cretaceous paleogeographic evolution and se-

quence-stratigraphic framework of the northwest Gulf of Mexico Rim, in C. Bartolini, R. T. Buffler, and A. Cantu-Chapa, eds., The western Gulf of Mexico Basin; tectonics, sedimentary basins, and petroleum systems: American Association of Petroleum Geologists Memoir 75, Tulsa, Oklahoma, p. 4581.

Hacquebard, P. A., 1977, Rank of coal as an index of organic metamorphism for oil and gas in Alberta, in G. Deroo,

T. G. Powell, B. Tissot, and R.G. McGrossan, eds., The origin and migration of petroleum in the Western Canadi-an Sedimentary Basin, Alberta: Bulletin of Geologic Society of Canada, v. 262, p. 1122.

Hantschel, T., and A. I. Kauerauf, 2009, Fundamentals of basin and petroleum systems modeling: Springer, Berlin,

Germany, p. 131148.

121

Cardneaux and Nunn

Harbor, R., 2011, Facies characterization and stratigraphic architecture of organic-rich mudrocks, Upper Cretaceous Eagle Ford Formation, South Texas: Masters thesis, University of Texas at Austin, 195 p.

Hentz, T. F., and S. C. Ruppel, 2010, Regional lithostratigraphy of the Eagle Ford Shale: Maverick Basin to East Texas

Basin: Gulf Coast Association of Geological Societies Transactions, v. 60, p. 325337. Hill, R. T., 1887a, The topography and geology of the Cross Timbers and surrounding regions in northern Texas:

American Journal of Science, 3rd series, v. 33, p. 291303. Jarvie, D., B. Claxton, B. Henk, and J. Breyer, 2001. Barnett Shale with Tmax to Ro correlation equation, Accessed June 22, 2013. Lecompte, B., and G. Hursan, 2010, Quantifying source rock maturity from logs: How to get more than TOC from

Delta Log R: Society of Petroleum Engineers Paper 133128, Richardson, Texas, 10 p. Lock, B. E., L. Peschier, and N. Whitcomb, 2010, The Eagle Ford (Boquillas Formation) of Val Verde County, Texas

A window on the South Texas play: Gulf Coast Association of Geological Societies Transactions, v. 60, p. 419434.

Loucks, R. G., 1976, Pearsall Formation, Lower Cretaceous, South Texas: Depositional facies and carbonate diagenesis

and their relationship to porosity: Ph.D. dissertation, University of Texas at Austin, 362 p. Martin, R., J. Baihly, R. Malpani, G. Lindsay, and K. Atwood, 2011, Understanding production from Eagle Ford

Austin Chalk System: Society of Petroleum Engineers Paper 145117, Richardson, Texas, 28 p. Mckenzie, D., 1978, Some remarks on the development of sedimentary basins: Earth and Planetary Science Letters,

v. 40, p. 2532.

Figure 8. %Ro map for Lower Eagle Ford. Contour interval is 0.05 %Ro. Open circles are well loca-tions. Legend bar shows interpreted petroleum generation windows. Chittim Anticline is shown as a heavy line with orthogonal double arrowhead line. The Maverick Basin is outlined by a dashed line. Minimum curvature gridding algorithm with a smallest feature radius of 50,000 ft (15,000 m) and a radius of influence of 750,000 ft (230,000 m) was used. See Cardneaux (2012) for values at each well location.

122

Estimates of Maturation and TOC from Log Data in the Eagle Ford Shale, Maverick Basin of South Texas

Passey, Q., S. Creaney, J. Kulla, F. Moretti, and J. Stroud, 1990, A practical model for organic richness from porosity and resistivity logs: American Association Petroleum Geologists Bulletin, v. 74, p. 17771794.

Pinet, P. R., 1996, Invitation to oceanography, 3rd ed.: West Publishing Co., St. Paul, Minnesota.

Railroad Commission of Texas, 2011, Eagle Ford information, Accessed December 5, 2011.

Salvador, A., 1991, Triassic-Jurassic, in A. Salvador, ed., The geology of North America, v. J: The Gulf of Mexico Basin: Geologic Society of America, Boulder, Colorado, p. 131180.

Figure 9. Eagle Ford TOC maps. (Top) Upper Eagle Ford and (Bottom) Lower Eagle Ford. Contour interval is 0.5 and 1 wt.% TOC, respectively. Open circles are well locations. Minimum curvature gridding algorithm with a smallest feature radius of 50,000 ft (15,240 m) and a radius of influence of 750,000 ft (230,000 m) was used. See Cardneaux (2012) for values at each well location.

123

Cardneaux and Nunn

Sclater, J. G., and P. A. F. Christie, 1980, Continental stretching: An explanation of the post-Mid-Cretaceous subsid-

ence of the Central North Sea Basin: Journal of Geophysical Research, v. 85, p. 37113739. Scott, R. J., 2003, The Maverick Basin: New technologyNew success, in N. C. Rosen, ed., Structure and stratigraphy

of South Texas and Northeast Mexico: Applications to Exploration: Gulf Coast Section of the Society of Eco-nomic Paleontologists and Mineralogists Foundation, Houston, Texas, and South Texas Geological Society, San Antonio, Texas, p. 18.

Scott, R. J., and M. Gose, 2002, Maverick Basin/Sacatosa Field coalbed methane project: American Association of

Petroleum Geologists Search and Discovery Paper 90023, Tulsa, Oklahoma. Sondhi, N., 2011, Petrophysical characterization of the Eagle Ford Shale: Masters thesis, University of Oklahoma,

Norman, 197 p. Sweeney, J. J., and A. K. Burnham, 1990, Evaluation of a simple model of vitrinite reflectance based on chemical kinet-

ics: American Association of Petroleum Geologists Bulletin, v. 74, p. 15591570. Wygrala, B. P., 1989, Integrated study of an oil field in the southern Po Basin, northern Italy: Ph.D. thesis, University

of Cologne, Germany, 217 p.

Figure 10. TOC for lower Eagle Ford estimated from log response (Delta Log R) compared to meas-ured TOC from Harbor (2011). Henderson and Schauers are in Gonzales County, Lawrence Gise is in Dimmit County, Calvert and Halff are in Frio County, and Chittim, J. M. is in Maverick County. See red dots in Figure 1.

124