Eagle Ford Shale Part A: Geological Review
The Eagle Ford Play in the Center South of Texas is the largest tight oil producer and the second largest shale gas producer in the United States. Initially the Eagle Ford formation was known as the mother rock of the gas and petroleum conventional reservoirs produced from the Austin Chalck formation and it has been studied since the year 1887 by Hill, who gave it his name, from outcrops of surface along the state. Railroad Commission of Texas qualified the Eagle Ford Play as the best shale play in the United States due to its relatively shallow depths in the oil window, high percentage of carbonate makes it easier to fracture, and large lateral extent and thickness (Railroad Commission of Texas, 2011).
The first unconventional well in the formation was carried out in the Hawkville Field (La Salle County) by the company Petrohawk in the year 2008 with an initial gas production of 7,5mmft3 and since then, its growth has been vertiginous positioning itself as the more active formation in the country, with an areal extension of 11500mi2, along 26 counties from where it produces petroleum, gas and condensate and dry gas.
Figure 1: Eagle Ford Play in Texas showing the three hydrocarbons windows of the Play and the Western part of the gulf Basin. Source: US Energy Information Administration.
The maximum oil production in the field was reached in March 2015 with a flow rate of 1,63MMbbl/d and the maximum gas production was achieved in October of the same year with a flow rate of 5,15Bcf/d from which they have begun to decline due to the strong disinvestment produced in the drilling of new wells.
The formation Eagle Ford is located in the western part of the Gulf of Mexico Basin in the Southwest of Texas.
Gulf of Mexico Basin
The Gulf of Mexico Basin is a small ocean basin that is home to a great number of conventional and unconventional reservoirs along the south of the United States and east of Mexico among which is found the Eagle Ford Field. It stands out for being the more fruitful sedimentary basin in the hydrocarbon production of the planet, having reached in the year 2015 reserves produced and confirmed by a volume of 21,91 billion barrels of oil and 192.4 trillion cubic feet of gas (Kazanis et al., 2014).
The basin is located adjacent to the Caribbean Sea and is surrounded by the east of Mexico, Texas, the southeast Gulf states of the United States and Cuba. Its geography is the result of the break-up (separation) of the Pangea and tectonic movements associated with the Mesozoic Era (Galloway, 2008; Hudec et al., 2013b).
Figure 2: Map of the Gulf Mexico Basin showing the Basin edges and the Western Gulf Province where is located the Eagle Ford Shale. Source Salvador (1987).
Currently it’s characterized by a inactive rift that divided the preexisting stratigraphy and formed the oceanic crust, allowing the deposition, thermal subsidence and subsequent accumulation of sediments during 65 million years generating the current hydrocarbon systems (Galloway, 2008). Subsequent sedimentation and tectonic activity resulted in the migration of these deposits and the deformation of the associated sediment layers forming folds, faults and other structures which work as traps of hydrocarbons in the north-west and north-center of the GOM.
Structural and tectonic features
There are several structural features in the western part of the GOM province and adjacent to it which have influenced the depositional extension, thickness and depth of the Eagle Ford formation. Among them we can highlight the Llano Uplift, Ouachita Orogenic Belt, San Marcos Arch, Rio Grande Embayment, Maverick Basin, Edwards And Sligo Reef Margins, Houston Embayment, Anticlinal Pearsall, Zavala Syncline, Chittum Anticline, Balcones Fault, Luiling Fault and Charlotte_Jourdanton Fault.
Figure 3: Map of the Western Gulf Province showing the main structural features. Source: Condon and Dyman 2003.
- The Llano uplift is located in the north-west border of the Gulf Province and it’s an area of Proterozoic rocks outcrop. Apparently this acted as a support during the Ouachito Orogeny tectonic compression in the Pennsylcanian and Permian time and as a source of clastic sediments in the Maverik Basin during the Cretaceous (Goldhammer and Johnson, 2001).
- OUACHITA Orogenic BELT is located along the sides south and east of the Llano Uplift and is an area of raise that were formed when the continents Africa, North and South America collided to make up the Pangea (Condon and Dyman, 2006) consisting of a group of folded and failed rocks of the Paleozoic time.
- San Marcos Arch is a subsurface extension of the Llano Uplift which was formed during the Permian Pennsylvanian compression producing a broad regional arch (anticline) which extends in a south-easterly direction toward the Gulf separating the Maverik Basin and the Rio Grande Embayment of the East Texas Basin (Dravis, 1980). Many units are thin on the Arch or are absent indicating a period of uplift during the Jurasico and Cretaceous(Condon and Dyman, 2006).
Figure 4: Southwest-northeast cross-section showing the Eagle Ford formation over the San Marcos Arch. Source: Hentz and Ruppel (2010).
- The Rio Grande embayment is found southwest of the San Marcos Arch, which extends into northeastern Mexico (Ewing, 1991) and is generally aligned with the northwest-trending Precambrian Texas lineament along the Rio Grande River. (Condon and Dyman, 2006).
- The Maverik Basin is located in the southwest of the Texas State and is originated from basement structures developed during the failed Rio Grande rift (Rose, 1972, Donovan and Staerker, 2010) forming a depocenter during the Laramide Tectonism in the Late Cretaceous to early Tertiary.
- The Edwards And Sligo Reef Margins are Early Cretaceous continental shelf edge reefs formed during fast levels of marine trangression (Condon and Dyman, 2006) that characterize the region more prospective of the Eagle Ford formation. The Sligo Reef Margin is considered the southern limit of the Eagle Ford Play.
- The Houston Embayment is a low structure similar to that of the Rio Grande Embayment that is located on the northwest side of the San Marcos Arch and it is the southern extension of the East Texas Basin whose generation was influenced by the lineament Precambrain Wichita.
- The Pearsall Anticline is located in the south west of San Antonio and is sub parallel to other failure areas in the region, its origin has been estimated in the Jurasico (Ewing 1987) being older than other folds in the Maverik Basin.
- Faults are common in the study area and are grouped in several major zones that parallel the Ouachita Orogeneic Belt (Weeks, 1945):The Balcones fault zone is located in the North-West of the Maverik Basin, (Gulf Province)it marks the craton margin of the central United States, it's constituted by normal faults with displacements which may exceed the 1600ft in the southeast. The Luling fault area is parallel to the area of the Balcones Fault and is located to the southeast of the same.They are normal faults whose movements are opposite to the Balcone Fault , with displacements that reach 1000 to 2000 ft, forming between the both a wide graben. The Charlotte-Jourdanton fault zone is extended to the south-east of the Frio County through Atascosa and it's of a smaller size. The region is composed of a set of normal faults along which the movements in opposite direction have occurred to form a graben that reaches displacements of 500 to 700 ft.
The Eagle Ford formation was deposited during the Middle Cenomanian to Turonian stages of the Upper Cretaceous, during an interval of approximately 9 million years consisting of an organic-rich calcareous mudrock. This is located in unconformity under the Austin Chalck formation and lies over Buda formation in the west of the San Marcos Arch and over it to the north of the Stuart City Margin; to the south of the same it lies over the georgewton formation. To the Northeast of the San Marcos Arch the lower Eagle Ford grades into the Pepper Shale formation.
From logs responses the Eagle Ford formation is divided in an upper member and a lower member:
- The lower Eagle Ford was deposited during a second order transgressive system being constituted mainly by a dark gray mudrock well laminated with oil-prone organic matter exhibiting normally a high response to the gamma ray logs (typically between 90 API to 135 API units). As the Eagle Ford formation is transgressive, the formation is older close to Sligo Shell Margin and younger northward (Adams and Carr, 2010).
- The upper Eagle Ford was deposited during a marine regression (Dawson, 2000) and consists predominantly of a calcareous mudrocks of light gray color with a low organic matter content and a low activity in the gamma ray log (between 45 to 60API units, Hentz and Ruppel, 2010). There are also present thin beds of organic, dark-gray noncalcareous mudrocks with a high activity in the gamma ray log (120 API units Harbor, 2010).
Figure 5: Cross section A-A' showing the Lower and Upper Eagle Ford members across the Maverick Basin to San Marcos Arch. Source: Hentz and Ruppel 2010.
Figure 6: Cross section B-B' showing the Eagle Ford formation in the part Northeast of the San Marcos Arch and how the Lower Eagle Ford grade into the Pepper Shale formation Source: Hentz and Ruppel 2010.
Figure 7: Cross section 1-1' showing the Lower and Upper Eagle Ford members across the Maverick Basin to the Sligo Shelf Margin. Source: Hentz and Ruppel 2010.
As we can see in the isopachs map the thickness of the Eagle Ford formation varies widely throughout the Play. Above the San Marcos Arch and to the east of the same the reservoir has an average thickness of 75ft with small local spots that can overcome the 200ft. In the west region of the San Marcos Arch the formation enjoys the greatest thicknesses starting from 200ft in the edges of the Maverick Basin up to overcome the 550ft toward the center of the same.
Figure 8: Map of the thickness contours of the Eagle Ford formation (isopachs), also showing the outcrops of the formation in the north of the same. Source: U.S. Energy Information Administration.
The formation depth varies drastically throughout the play going usually from surface outcrops in the North of the reservoir to reach depths of 14000ft in the region of Sligo Reef Margin. The reservoir productive area is found mainly located between the 4000ft to the 12000ft. This pronounced increase in the depth brings with it important changes in the type of hydrocarbons generated and stored from oil, gas and condensate to dry gas (as can be seen in figure 1) together with an increase in the pore pressure, and the costs associated with the drilling and well completions.
Figure 9: Map showing the elevation of the Top of the Eagle Ford formation. Source: U.S. Energy Information Administration.
Mineralogical Composition and Petrophysical properties:
The mineralogical composition of the formation is one of its most distinctive features as its high content of carbonate minerals (between 40 and 90%) and low clay content (15-20%) make the reservoir a formation easy to fracture, a high rate of brittles and as a result with an excellent response to the hydraulic fracture treatment. The total content of organic matter (TOC) is between 2 to 12%, the porosity is quite high for a shale ranging from 8 to 12%, the thermal maturity (%R0) is located between 0.45 to 1.4%, the API gravity varies between 20° to 62° and the pressure gradient goes from 0.5 to 0.8 (psi/ft) (Za Za Energy, 2013).
Table 1: shows the Reservoir Characteristics providing by Za Za Energy (2013) and Chesapeake (2010). It's a core sample image of the Upper Eagle Ford member and the picture B is a core sample of the Lower Eagle Ford member.
The Eagle Ford formation has been divided into different numbers of facies from studies carried out by some researchers: Donovan and Staerker (2010) divided the formation in 5 facies by the analysis conducted in surface outcrops, Workman (2013) and MCGarity (2013) divided it in 8 facies through the analysis of well cores and profiles from different wells and Harbor (2011) has divided it into 9 facies by analysis of well cores, cutting of drilling and logs obtained from 27 wells along13 counties.
In this work we’re going to adopt the classification of Harbor for the division of facies to be based on the largest number of samples from different counties, which has allowed him obtained a better correlation and compression of the formation.
Facies 1: Massive Argillaceous Mudrock is dark green to grey, fissile, and massive bedded with a mineral composition of 42% of Clay, 23% of quartz and an average TOC content of 5,1% from 8 samples. It occurs as a relatively thick succession in the basal lower Eagle Ford. (Harbor, 2011).
Facies 2: Laminated Calcareous Foraminiferal Mudrock is the most abundant facies within the Eagle Ford. It’s characterized by brown to dark grey, mixed calcite and clay mineral matrix with millimeter (mm) scale planar laminations. The average TOC is 5% from 68 samples, with an average content of 54% of calcite and 25% of clay. (Harbor, 2011).
Facies 3: Laminated Fossiliferous Wackestone/Packstone is located stratigraphically above Facies 1 and it’s characterized by organic-rich clay- and silt- sized matrix with abundant whole and fragmented skeletal material. The average TOC is 7,2% (two samples) and the XRD analyses shows a composition in average of 55% of calcite with 30% of clay. Small fining upward sequences are common and composed of medium grey (silt-sized) to brown (clay-sized) couplets. (Harbor, 2011).
Facies 4: Laminated Foraminiferal and Peloidal Packstone is composed of two subfacies, is characterized by light grey, ripple and low angle cross laminated limestone beds within dark grey, organic-rich peloidal packstone matrix. It’s located in both the upper and lower Eagle Ford with an average TOC of 4.6% (six samples), 69% of carbonate and 18% of clay. (Harbor, 2011).
Facies 5: Massive to Bioturbated Kaolinitic Claystone represent diagenetically altered volcanic ash that were deposited in open marine settings with light green to grey color and the average clay mineral content is 91%. It’s commonly found interstratified with laminated calcareous foraminiferal mudrocks in the lower and upper Eagle Ford. (Harbor, 2011).
Facies 6: Laminated Wackestone is characterized by well-sorted clay-sized matrix with mm scale ripple laminations of globigerinid foraminifera, phosphatic bioclasts, disaggregated inoceramid bivalve shells, and peloids. The color of this facies ranges from brown to medium grey with an average of 66% carbonate, 19% of clay and 1,6% of TOC (six samples) (Harbor, 2011).
Facies 7: Disrupted Bedded Foraminiferal Packstone consisting of two subfacies, are characterized by white to light grey colored, cm scale, discontinuous bedded and starved ripple laminae within a brown, mixed skeletal and mud matrix. It has an average composition of 59% carbonate, 29% of clay and 8,1% of TOC from two samples) with abundant slumped and folded structures. (Harbor, 2011).
Facies 8: Massive Inoceramid Packstone is characterized by brown, massively bedded, coarse-grained skeletal debris in a mixed micrite and clay mineral matrix. It has an average of 70% carbonate, 25% clay and 1,3% TOC from one sample.It’s found in upper Eagle Ford rocks along the axis of the San Marcos Arch (Harbor, 2011).
Facies 9: Bioturbated Lime Wackestone is characterized by white to light gray massive, highly bioturbated, micritic calcite matrix with planktonic foraminifera tests and inoceramid bivalve shells. It has an average content of 90% carbonate and 0,88% Toc (two samples) and it’s widespread in the Maverick Basin region. (Harbor, 2011).
In the part B of "EAGLE FORD SHALE" we'll develop: WELL TYPE, AVERAGE PRODUCTION PER WELL, DECLINATION CURVE, CUMULATIVE PRODUCTION, ESTIMATED ULTIMATE RECOVERY PER WELL (EUR), FIELD DECLINE, PRODUCTION FORESCAT, PRACTICAL RECOMMENDATIONS. and a general conclusion.
Written by the author:
- BARNETT TECHNICAL INFORMATION
- Eagle Ford Geological Review
- WHAT IS HYDRAULIC FRACTURING?
- WHERE IS THE GAS STORED?
- HOW TO EVALUATE A SHALE PLAY?
- FLOW MECHANICS IN SHALE GAS
- EXCEL WORKSHEET TO CALCULATE THE PERMEABILITY IN SHALE GAS FIELDS
- BEHAVIOR OF ARPS EQUATION IN SHALE PLAYS
- U.S. Dry Shale Gas Production
- U.S. Tight Oil Production
- Argentina Shale Production
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Author: Emanuel Omar Martin, Petroleum Engineer