Eagle Ford Basin

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This page is currently being authored by a student at the University of Oklahoma. This page will be complete by May 6, 2020.

Eagle Ford Basin

Intro

Eagle Ford Basin (also known as the Eagle Ford Shale) is a Sedimentary Rock Formation that was deposited in the Cenomanian and Turonian ages of the Late Cretaceous Period. The late Cretaceous Period was estimated to have lasted for around 89-95 million years old This Basin covers the Southwest area of Texas to just North of Austin, Texas. This basin was deposited in an inland sea that would cover modern-day Texas. This basin is known to be more of a carbonate than a shale, this high carbonate content and lower clay content make the Eagle Ford more brittle, making hydraulic fracturing easier. The formation lies in the middle of the Austin Chalk (above) and the Buda Limestone (Below).

[1]A map laying out all the production wells within the Eagle Ford Basin region in Southeast Texas.

History of the basin

Eagle Ford takes its name after a town called Eagle Ford, Texas where shale is outcropped at the surface in clay form making this basin one of the most active shale play in the entire world. Ranging in depths of 4,000 to 14,000 feet and a dimension of 50 miles in width and 400 miles in length the Eagle Ford basin contains around 3.4 billion barrels of recoverable oil and about 20.8 trillion cubic feet of recoverable natural gas. With the basin stretching from the border of Mexico, across the South and into portions of East Texas, many rigs and potential drill wells have been founded for the production and excavation of oil and gas.    

Eagle Ford first started development on October 21, 2008 with its first drill site owned by Petrohawk Energy, eventually totaling 87 horizontal drilling sites with 0 vertical drilling sites. These sites benefited from the source rock from beneath the city of Austin referred to as the Austin Chalk.[2] Due to the basin having a high concentration of carbonate shale, over 70%, the basin had an increase in drilling permits in 2010 and continued to grow. This increase resulted in the basin’s peak, where production boomed in 2015 with oil productivity at 1,188,418 Bbl (middle), natural gas productivity at 6,079 million cubic feet per day (bottom right), and condensate at 309,838 barrels per day (bottom left). After 2015, production began to decline and overall level out.

Texas Eagle Ford Basin's natural gas production from 2009 through December 2019.[3]
Texas Eagle Ford Basin's condensate production from 2009 through December 2019.[4]
Texas Eagle Ford Basin oil production from 2009 through December 2019.[5]

Primary risks and uncertainties

Eagle Ford basin is divided into three sections based on the hydrocarbon contents: Oil, gas-condensate, and dry gas. From Northwest to Southeast, the play ranges from 30 SG(API) all the way to around 63.6 SG(API), the northern sector being the lowest and southern the highest. From an economic standpoint, not all of the Eagle Ford basin can produce high oil yields

Eagle Ford Shale Play

Due to steep decline curves and production replacement, well returns can be affected. Long-term production can vary based on parent-child well interference, caused by reservoir depletion, and reservoir total/effective stress changes.

Some uncertainties include the possibility of over drilling. As shown in the figure, the Eagle Ford rig count does not increase, and substantially decreases 2014-2016. Players in the basin have utilized refracturing to increase production rate but uncertainties still stand because of the application to only a subset of wells. Stimulation of wells through enhanced oil recovery has been used before putting the wells back into production.

Petroleum Geology

Trap

The traps found in the Eagle Ford are both structural and stratigraphic. Since the Eagle Ford has the stratigraphic trapping it requires hydraulic fracturing in order for the well to be profitable. The way the rocks are breaking (faulting) also leads toward some lateral trapping. Some migration to the north has caused hydrocarbons to become trapped in the Austin Chalk area of this basin.

Seal

The seal that is found in this basin is the Carbonate Seal, this is because the basin has a lot of limestone throughout. The Austin Chalk (above) and the Buda Limestone (below) have low permeability and porosities, as seen on figure ___. Since the rock is has limestone it is considered a good cap rock as its easily broken and altered pores develop. The Eagle Ford Shale is said to have permeabilities in the range of 50-1500 nano-darcys. Since it is so low it will need a large demand of freshwater in order to fracture.

Source Rock

A Source Rock is a rock that the hydrocarbons are contained in. The source rock for this basin has many different sources ranging from mud rock to clay stone. The Eagle Ford Shale is a Cretaceous Sediment located in South and South East Texas. This provides the source rock for the Austin Chalk oil.  The low clay content and high carbonate content (up tp 70%) makes the Eagle Ford more brittle. This basin dips toward the Gulf of Mexico and is considered to be an unconventional play. Within this basin there are many other plays/formations for example the South Bosque Formation, the Maverick Basin, and the Pepper Shale.

Reservoir

This basins Reservoir is defined by the differences in both physical and organic characteristics that give the basin a high diversity level. Many things that effect the hydrocarbon storage zones within this basin can depend on the deposition environment, mineralogy, and kerosene type. The 2 most important things that control a reservoir are porosity and permeability, these processes control the pores and their connectivity. This basin has very low levels of both causing it to be a great reservoir type.

Future/Current Assessment of Eagle Ford Basin

Improving the field through EOR

Enhanced Oil Recovery methods have been used to improve or maintain production from unconventional plays and wells and have been wildly successful and popular of late.

Rig Count of the Eagle Ford Basin

One method for this is the “refracturing” of hydraulically fractured wells for increased production. Over time, as technology is developed and improved, steps are taken and methods are learned, leading to increased production and efficiency in practices. By delving back into these “legacy” wells that have already been produced, operators in the play were able to produce at a higher rate without having to dig a new hole. Once these “old” wells are reopened and analyzed, they are stimulated through the new technology to lead to higher production.

The other method mentioned was the injection of natural gas or other gasses into the oil after initial production to exponentially better the recovery rate for the well. This practice of gas injection is often referred to as the “huff and puff” method and has grown to be very popular across the nation and globe in recent years. Through this method alone, production in the Eagle Ford play has been raised by 30-40% alone.

Risks

Eagle Ford basin is divided into three sections based on the hydrocarbon contents: Oil, gas-condensate, and dry gas. From Northwest to Southeast, the play ranges from 30 SG(API) all the way to around 63.6 SG(API), the northern sector being the lowest and southern the highest. From an economic standpoint, not all of the Eagle Ford basin can produce high oil yields

Due to steep decline curves and production replacement, well returns can be affected. Long-term production can vary based on parent-child well interference, caused by reservoir depletion, and reservoir total/effective stress changes.

Some uncertainties include the possibility of over drilling. As shown in figure _, the Eagle Ford rig count does not increase, and substantially decreases 2014-2016. Players in the basin have utilized refracturing to increase production rate but uncertainties still stand because of the application to only a subset of wells. Stimulation of wells through enhanced oil recovery has been used before putting the wells back into production.

References

  1. https://www.forbes.com/sites/davidblackmon/2016/09/06/whats-wrong-with-the-eagle-ford-shale/#6f1d0bdc53a7
  2. Blackmon, David. “Happy 10th Anniversary To The Eagle Ford Shale.” Forbes, Forbes Magazine, 22 Oct. 2018, www.forbes.com/sites/davidblackmon/2018/10/21/happy-10th-anniversary-to-the-eagle-ford-shale/#f6352039abb1.
  3. “About Us.” Texas RRC, Railroad Commission of Texas, www.rrc.state.tx.us/oil-gas/major-oil-and-gas-formations/eagle-ford-shale-information/.
  4. “About Us.” Texas RRC, Railroad Commission of Texas, www.rrc.state.tx.us/oil-gas/major-oil-and-gas-formations/eagle-ford-shale-information/.
  5. “About Us.” Texas RRC, Railroad Commission of Texas, www.rrc.state.tx.us/oil-gas/major-oil-and-gas-formations/eagle-ford-shale-information/.
    • Research, F. (2017, May 01). The Eagle Ford SHALE basin is roaring back. Retrieved May 05, 2020, from https://seekingalpha.com/article/4067408-eagle-ford-shale-basin-is-roaring-back
    • King M., H. (2018). Eagle Ford Shale. Retrieved May 05, 2020, from https://geology.com/articles/eagle-ford/
    • Hill, D. (2018). The Eagle Ford shale laboratory: A field study of the STIMULATED Reservoir volume, detailed Fracture characteristics, AND EOR POTENTIAL. Retrieved May 05, 2020, from https://netl.doe.gov/node/5906
    • Jacobs, T. (2020, May 04). Shale EOR delivers, so Why won't the sector go big? Retrieved May 05, 2020, from https://pubs.spe.org/en/jpt/jpt-article-detail/?art=5360