The Eagle Ford Shale play is of Cretaceous origin and is located in Southeast Texas, covering 30 counties across the state. Petroleum exploration in the Eagle Ford unconventional play first began in October of 2008. Since then development into the formation has identified three primary zones corresponding to lateral changes in the position of wells; Northwest to the Southeast, and their produced fluids; oil, gas-condensate, and gas. The formation itself consists primarily of mudrock and claystones and is divided into seven members. Hydrocarbons generate and undergo primary migration within the source rock, which constitutes the main reservoir unit of the formation. Difficulties revolving around the heterogeneity of the petroleum system add to the uncertainty of the formation’s development, but also create a wide variety of problems that can be studied to develop the industry's understanding of unconventional shale plays. The uniqueness of this play combined with its prolific reserves has made it a prime candidate for the study of stimulation methods and enhanced oil recovery methods (EOR), such as Huff-n-Puff.
- 1 History of the Basin
- 2 Primary Geologic Risks
- 3 Petroleum System
- 4 HC type and Maturation
- 5 Analysis Geological Uncertainties and Challenges
- 6 Current and Future Assessment
- 7 Further Reading
- 8 References
History of the Basin
STS#1 is the very first discovery well in the Eagle Ford Play drilled in October 2008 with 0.6-mile lateral length and 9.7 Mscf/d of production rate. After the very first well, STS#1 in La Salle county, Texas, the play extended from the Sligo shelf edge to the Maverick basin in the west side. The trend extended further to the eastern border of Lavaca and Gonzales counties with 60-miles in width and 102-miles in length on average as of 2011 . In the present day, exploration has reached to the northeastern border of Leon, Madison, and Walker counties covering 400-miles in length, 50-miles in width and 250-ft in thickness on average (Figure 1).
The history of Eagle Ford in terms of production rate and rig count is showing that the play has pasted the glory days. Since the discovery well was drilled in 2008, the production rate kept increasing tremendously and it was the peak in 2015 with 1,196,974 bbl/day of production rate (Figure 2). After the peak in 2015, the producing rate decreased and it seems to become constant. As shown on Figure 3, the rig count has been decreased since 2015 as well, and seems to be constant since 2017 with about 90 rigs. As the production rate decreased since the peak, many operators are leaving Eagle Ford Play such as Encana, Pioneer Resources, Earthstone Energy, and Sanchez Energy with having hard time to manage their economics .
Primary Geologic Risks
As shown in Figure 4, the Eagle Ford Play is broken into three regions; Oil, gas-condensate and dry gas from Northwest to Southeast. This implies that not all region of Eagle Ford Play is economic because you might not want to produce dry gas during whole well life.
The Eagle Ford Play also contains seven different facies:
1) massive argillaceous mudrock
2) massive foraminiferal calcareous mudrock
3) laminated calcareous foraminiferal lime mudstone
4) laminated foraminiferal wackestone
5) cross-laminated foraminiferal packastone-grainstone
6) massive benetonitic claystone
7) nodular foraminiferal packstone-grainstone
As shown, much variability of Eagle Ford facies is observed even at a small lateral spacing (50 ft), so the formation is highly heterogeneous and stratigraphers and explorationists often over-looks the variability of facies. In addition, mudrock deposition is complex and it involves the interplay of many controlling processes and nodular facies, ash beds, and other heterogeneities can dramatically influence correlatability, so caution must be employed when evaluating mudrock systems like Eagle Ford Play.
The eagle ford exhibits self-sealing overlying and underlying carbonate seals with mostly about 2-3% porosities. The Austin chalk, which is the overlying limestone along with Buda Limestone which is the underlying seal has quite low permeabilities and porosities (Figure 5). Although varies significantly, operators and reports have shown the permeability of Eagle Ford formation to be within the nanodarcy range. The ultralow permeability forces operators to hydraulic fracture the formation intensely, which brought up the issue of frac hits. The Austin chalk, which serves as both top and lateral seal requires large, connected fracture systems to store and produce hydrocarbons and only requires upward migration.
The Eagle Ford Group source rock is characterized by large variations in lithology. The group can be divided into seven distinct lithologies ranging from argillaceous mudrock to massive bentonic claystone. The large variations in lithology makes correlation of geological data difficult to perform at scales beyond the coreface. Accuracy in correlation over lateral distances of 500-ft can be as high as 73% but this number decreases to 16% over the scale of 10-miles. Difficulties in defining the high level of heterogeneity in the Eagle Ford group is made difficult due to the depositional history of the source rock. To make this easier, the Eagle Ford is typically divided into four primary stratigraphic units; The Pepper Shale, an unnamed unit (commonly called the Waller Member), the Bouldin Member, and the South Bosque Formation.
The Pepper Shale and the Waller Members contain the highest Total Organic Content (TOC) while TOC across the entire Eagle Ford sporadically changes in value between 0.1 - 8.4% by weight with an average of 2.4%. Correlation between API Gamma Ray (GR) response and TOC does not appear to consistently exist between each group and is due to variations in carbonite and Uranium (U) concentration (Figure 6). This makes lithofacies classification based on GR response unreliable without additional information available. Identification of source rock facies within the Eagle Ford is crucial for optimization of zonal selection and completion design, as this formation is an unconventional play.
In the Eagle Ford shale play, both structural and stratigraphic traps are found. The Eagle Ford, with its stratigraphic trapping nature, requires hydraulic fracturing to be economical. The faults in Eagle ford provide lateral trapping where the sweet spots down dip form and are adjacent to major faults. The Northward migration along bedding planes from the Eagle Ford has caused hydrocarbons to become trapped in the fractured Austin Chalk, where the presence of gas cap is observed. Better initial production rates have been noticed at the down thrown side of the faults.
Primary and Secondary Reservoirs
The Eagle Ford reservoir is characterized by drastic variations in lithofacies which contributes to the high degree of heterogeneity that can be observed regarding its reservoir characteristics. Mineralogy, depositional processes, kerogen type, burial depth, and diagenetic processes all effect the potential hydrocarbon storage for zones within the Eagle Ford. These processes control the distribution of pores and their connectivity; the two most important parameters of porosity and permeability. The zones of interest in the Eagle Ford are primarily fine-grained mudstones, which are difficult to build accurate reservoir flow models.
A study performed using over 3,600 producing wells across the Eagle Ford found the following average reservoir properties based upon production data (Table 1).
HC type and Maturation
The hydrocarbon type in the Eagle Ford formation varies with depth, ranging from black oil at the shallowest and gas condensate at the deepest interval. A comprehensive fluid characterization based on type is shown in Table 2 below .
This strong fluid type dependency on depth is mainly due to thermal maturation: as the depth increases, high geothermal gradient cause the temperature to increase quite significantly. The geothermal gradient in Eagle Ford is approximately 3.75ºF/100 ft, which is comparatively large against the typical assumed value of 1.43ºF/100ft.
Table 2 also reveals the increasing bubble point with depth. This agrees with theoretical reservoir fluid characterization. Due to the ultra-low permeability of shale formations, matured gas tends to over-pressure the interval of interest. Moreover, the increasing gas content in the fluid also shifts the phase curve and raises the bubble point. Hence, the difference between the static reservoir pressure and the bubble point decreases. This motivates earlier phase change to gas from oil as the deeper part of the reservoir is being depleted.
Analysis Geological Uncertainties and Challenges
There was a study  done to determine the petrophysical properties of Eagle Ford Play including lithology, pore volume, water saturation, organic richness, and productivity correlations. One of the examples is porosity map shown in Figure 7. When the porosity was calculated, there were uncertainties due to sources such as possible errors in porosity-log normalization and undetected wellbore rugosity. Additonally, uncertainty of connate water salinity and water resistivity created uncertainty in the water saturation of the formation. However, the study overcame these uncertainties by using the relative uncertainty in water saturation and water resistivity, thus reducing the porosity value into half of the original porosity.
It is also a problem that there are already too many producing wells in Eagle Ford, so it is hard to drill new wells and that is also why the rig count does not increase anymore as shown on Figure 3. However, many operators have overcome this problem with refracturing since it increases production rate a lot as shown on Figure 8. To increase the production rate up to 20% using refracturing, more proppant volume per cluster can be injected.
Current and Future Assessment
Enhanced Oil Recovery (EOR)
Enhanced Oil Recovery (EOR) implementation in the Eagle Ford formation has been gaining appreciable momentum. A popular EOR technique that has been implemented and being intensely studied is huff-n-puff. The principle of huff-n-puff utilizes the periodic injection of gas followed by a soaking period using a lateral injection well. A high API gravity gas is injected, and the well is shut-in during the soaking period. The injection of gas lowers the gravity of the overall fluid, establishing greater mobility. This technique is beneficial for the shallower portion of the Eagle Ford where the API gravity is relatively lower.
Numerous huff-n-puff studies have been conducted such as one that utilizes numerical simulation to estimate the recovery improvement generated by a huff-n-puff technique. Figure 9 compares the cumulative oil production with 10 cycle of huff-n-puff and without any EOR treatment. It is observed that cumulative oil production for black oil window in the Eagle Ford is appreciably boosted by the presence of huff-n-puff, quantitatively by 30-40%. Slightly lower improvement is apparent for lighter fluids.
"Frac hits" is a newly emerged industry term describing the interference between hydraulic fractures. The intense short spacing of hydraulic fractures and the close distance between wells were believed to have caused fractures to communicate, both through pressure or physical crosscut . This problem is apparent in infill drilling, where the "child" well is drilled in close proximity from the main or "parent" well. Consequently, the production from the parent well impairs when the child well starts producing, which makes the investment for drilling a child well futile.
Frac hits is a rampant issues among hot shale plays including the Eagle Ford. In the Eagle Ford, average well spacing averages around 250-ft with aggressive hydraulic fracturing. Typical wells are stimulated by 30-60 clusters to maximize reservoir contact. The implication of small well spacing is apparent in the production data: the shorter the spacing, the greater the production decline rate. A number of studies have attempted to study the optimal spacing between wells. Nonetheless, this topic is difficult to solve for a multitudes of reasons. First, shale plays tend to be extremely heterogeneous, which adds a level of complexity that numerical simulation is unable to account for. Furthermore, the science of hydraulic fracture propagation remains stead-fast in the vertical transverse isotropic assumption. These two points combined make the prediction of fracture mechanics susceptible to large degree of uncertainties. Nonetheless, a study by Statoil (now Equinor) suggests 400-ft to be an optimal spacing for wells within their stake/working interest. Although frac hits have yet to be understood fully, a number of techniques to mitigate the damages have been tested, including scheduled shut-in's and pre-loading.
- Martin, R., Baihly, J., and Malpani, R. 2011. Understanding Production from Eagle Ford-–Austin Chalk System. Presented at the SPE Annual Technical Conference and Exhibition held in Denver,Colorado, USA, 30 October–2 November. SPE-145117-MS. http://dx.doi.org/10.2118/145117-MS.
- Rairoad Commission of Texas. 2019. Eagle Ford Shale Information. https://www.rrc.state.tx.us/oil-gas/major-oil-and-gas-formations/eagle-ford-shale-information/ (accessed on October 2019)
- EIA. “Drilling Productivity Report.” Eagle Ford Region. 2019. www.eia.gov/petroleum/drilling/pdf/eagleford.pdf. (accessed on November 2019)
- Erickson, B. 2019. 2019 Eagle Ford Shale Economics: Challenging For Valuation Title Belt.Fores, 23 April 2019, https://www.forbes.com/sites/bryceerickson1/2019/04/23/2019-eagle-ford-shale-economics-challenging-for-valuation-title-belt/#530cf07ad036 (accessed on November 2019).
- Railroad Commission of Texas. 2019. Eagle Ford Production History.https://www.rrc.state.tx.us/media/51509/eagle-ford-oil.pdf (accessed on November 2019)
- Gherabati, S. A., Hammes, U., Male, F., and Browning, J. 2018. Assessment of Hydrocarbon in Place and Recovery Factors in the Eagle Ford Shale Play. Society of Petroleum Engineers. doi:10.2118/189982-PA http://energentgroup.com/a-tale-of-two-plays-the-eagle-ford-basin-and-the-austin-chalk/
- Fairbanks, M.D., Ruppel, S.G., and Rowe, H. 2016. High-resolution stratigraphy and facies architecture of the Upper Cretaceous (Cenomanian-Turonian) Eagle Ford Group, Central Texas. AAPG Bulletin 3:379-403.
- Ko, L., Loucks, R., Ruppel, S., et. al. 2017. Origin and Characterization of Eagle Ford Pore Networks in the South Texas Upper Cretaceous Shelf. AAPG Bulletin, V. 101, NO. 3 (March 2017). https://pubs.geoscienceworld.org/aapgbull/article/101/3/387/295140/origin-and-characterization-of-eagle-ford-pore
- Luo, G., Tian, Y., Sharma, A., et al. 2019. Eagle Ford Well Insights Using Data-Driven Approaches. Presented at the International Petroleum Technology Conference, Beijing, China, 26-28 March. IPTC-19260-MS. https://doi.org/10.2523/IPTC-19260-MS
- Ganjdanesh, R., Yu, W., Fiallos, M. et al. 2019. Gas Injection EOR in Eagle Ford Shale Gas Condensate Reservoirs. Presented at the SPE/AAPG/SEG Unconventional Resources Technology Conference, Denver, Colorado, USA, 22-24 July. SPE-urtec-2019-987. https://doi.org/10.15530/urtec-2019-987
- Hammes, U. et al. 2016. Regional assessment of the Eagle Ford Group of South Texas, USA: Insights from lithology, pore volume, water saturation, organic richness, and productivity correlations. Interpretation 4: 1 http://dx.doi.org/10.1190/INT-2015-0099.1.
- Lindsay, G. J., White, D. J., Miller, G. A., Baihly, J. D., & Sinosic, B. (2016, February 1). Understanding the Applicability and Economic Viability of Refracturing Horizontal Wells in Unconventional Plays. Presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 9&-11 February. SPE-179113-MS. http://dx.doi.org/10.2118/179113-MS.
- Jaripatke, O., and Pandya, N. 2013. Eagle Ford Completions Optimization – An Operator’s Approach. Presented at the Unconventional Resources Technology Conference, Denver, Colorado, USA 12-14 August. URTeC 1581757. https://doi.org/10.1190/urtec2013-072.
- Jacobs, T. 2017. The implication of small well spacing is apparent in the production data: shorter the spacing, greater decline rate. JPT vol 69 issue 11. SPE-1117-0035-JPT https://doi.org/10.2118/1117-0035-JPT