Geology and Resource Assessments
The Eagle Ford
Shale Play in South Texas is one of the biggest U.S. shale plays. Just above
the Eagle Ford is the Austin Chalk, a 100-600ft thick zone of chalk and marl (carbonate-rich
mudstone). There are also multiple layers of volcanic ash from a series of
submarine volcanoes that were active when the chalk was deposited. They are
associated with the Laramide orogeny. Chalk is a type of soft, white, porous limestone
composed mainly of calcite and originally formed deep under the sea by the
compression of microscopic plankton that had settled to the sea floor. The
Austin Chalk is primarily composed of microscopic shell fragments from floating
sea organisms known as "coccolithophores" (the same organisms that
contributed to the White Cliffs of Dover, on the south coast of England). The
Austin Chalk is a tight argillaceous limestone, a brittle carbonate with
vertical fracturing that allowed oil and gas to migrate up from its source in
the Eagle Ford, which is the next formation below it. Sometimes it is recrystallized.
It has been producing oil and gas for a hundred years, with several successful revitalizations
as extraction technologies and geological understanding improved. The chalk is
porous with matrix porosity ranging up to 10% but permeability is low. It is a
brittle rock that tends to fracture. Early wells in the play, including early
horizontal wells were not hydraulically fractured but produced from natural
fractures. Some wells were phenomenally productive but were required to access
fractures, later typically identified on seismic lines. According to a December
2021 paper in Marine and Petroleum Geology about matrix reservoir quality in
the Austin Chalk by Robert Loucks and Sheng Peng: “The depositional
environment of the chalk is interpreted to have been a deeper-water (below
storm wave base) setting on a drowned shelf where bottom waters and sediments
varied between oxic and anoxic.”
According to an
October 2018 article in American Oil & Gas Reporter: “According to a
newly revised U.S. Geological Survey assessment, undiscovered and
technically recoverable Eagle Ford resources are pegged at 8.5 billion barrels
of oil, 66 trillion cubic feet of natural gas, and 1.9 billion barrels of
natural gas liquids. It has been a while since USGS assessed the Austin Chalk,
but it has estimated 900 million barrels of oil in only the Giddings Field, the
play’s largest field, spanning parts of seven counties in South-Central Texas,
which already has produced 526 million barrels of oil and 4.7 Tcf of gas.”
No doubt, the Austin Chalk reserves will exceed the early USGS reserves assessment.
The Eagle Ford
can be thick where produced and wells can be drilled and spaced in the Upper
Eagle Ford and Lower Eagle Ford. According to a 2014 EIA assessment: “The formation
is divided into two units: an upper unit, characterized by interlayered light
and dark gray calcareous mudrock deposited during a regressive interval (sea
level falling), and a lower unit of mostly dark gray mudstone deposited during
a transgressive interval (from rises in sea levels).” Depths to reach the
Eagle Ford vary from about 6500 ft in Southwest Texas to over 11,000 ft in productive
areas in Southeast Texas to over 17,000 ft further south into the basin where
it is less likely to be developed due to those depths and leaking seals. Depths
to the Austin Chalk are similar being just above the Eagle Ford but the chalk wells
in Louisiana can be quite deep at over 14,000 ft. The Eagle Ford is one of the
four big shale oil plays in the U.S. as well as a significant gas play. The continuous
gas deposit in the Eagle Ford and Austin Chalk is downdip from the continuous
oil deposit due to thermal maturity dynamics. The deeper gas window is favorably
situated near U.S. LNG export terminals on the Southeast coast of Texas. The
Eagle Ford and Austin Chalk trends no doubt extend into Mexico from Southwest
Texas.
Eagle Ford Hydrocarbon Fairways
A 2021 case
study of the Lower Eagle Ford to determine key geological factors controlling estimated
ultimate recovery (EUR) of wells concluded that the four major factors are:
reservoir capacity, resources, flow capacity, and fracability. Total porosity
and hydrocarbon-bearing porosity directly determine reservoir storage capacity
but total organic content (TOC) and vitrinite reflectance are indirect
determinants. The resources of shale hydrocarbons are determined by
hydrocarbon-bearing porosity and effective shale thickness. Flow capacity is
controlled by effective permeability, crude oil density, gas-oil ratio,
condensate oil-gas ratio, formation pressure gradient, and R0.
Fracability is controlled directly by brittleness index and indirectly
controlled by clay content in volume.
Geological Factors Affecting EURs, Source: Quantitative assessment of the sweet spot in marine shale oil and gas based on geology, engineering, and economics: A case study from the Eagle Ford Shale, USA. Energy Strategy Reviews. Volume 38, November 2021, 100713. Lianhua Hou, Caineng Zou, Zhichao Yu, Xia Luo, Songtao Wu, Zhongying Zhao, Senhu Lin, Zhi Yang, Lijun Zhang, Dingwei Wen, Jingwei Cui. Quantitative assessment of the sweet spot in marine shale oil and gas based on geology, engineering, and economics: A case study from the Eagle Ford Shale, USA - ScienceDirect
Eagle Ford Sweet Spot Reservoir Analysis. Source: Quantitative assessment of the sweet spot in marine shale oil and gas based on geology, engineering, and economics: A case study from the Eagle Ford Shale, USA. Energy Strategy Reviews. Volume 38, November 2021, 100713. Lianhua Hou, Caineng Zou, Zhichao Yu, Xia Luo, Songtao Wu, Zhongying Zhao, Senhu Lin, Zhi Yang, Lijun Zhang, Dingwei Wen, Jingwei Cui. Quantitative assessment of the sweet spot in marine shale oil and gas based on geology, engineering, and economics: A case study from the Eagle Ford Shale, USA - ScienceDirect
The Eagle Ford
thins to the north and does not thicken into the East Texas Basin like the
rocks below it. Its productive fairway and hydrocarbon windows are well
established. The shale extends into northern Mexico and is very prospective
there as is likely the Austin Chalk. Shale gas and oil reserves analysis suggests
that Mexican shale gas (545 Tcf) is the 6th largest such gas resource in the world,
most of which is in the Eagle Ford. The Burgos Basin in Mexico, a southern
extension of the Western Gulf Basin of South Texas is a main area of prospectivity.
Development has been slow in Mexico hampered by government issues and early poor
results, but the hydrocarbons are there and should be comparable to the high reserves
just across the border.
Gen 1: Austin Chalk Natural Fracture Porosity Play
Traditionally,
Austin Chalk wells were drilled to access gas and oil filled natural fractures.
In the late 1980’s the Austin Chalk began to be explored more resulting in some
large vertical wells although there were also many dry holes. It was hit or
miss. Seismically identified fractures and small faults were the targets. The
play reached from South Texas into South-Central Louisiana where it is deeper. With
the advent of horizontal well drilling in the 1990’s it was postulated that these
lateral wells could access more of these vertical fractures and thus more oil
and gas reserves, and this turned out to be true. There were also fewer dry
holes. The legacy fracture porosity drilling trend is generally just slightly up-dip
from the more recent matrix porosity trend. The early active parts of the play
were towards Central Texas. The Giddings Field there is the largest Austin
Chalk fracture porosity field developed.
Gen 2: Austin Chalk in Early Horizontal Drilling, High-Volume
Hydraulic Fracturing, and Geosteering
The Austin
Chalk was one of the first widely successful horizontal gas plays and initial production
in these wells often exceeded 50MMCF/day in-line. It was once thought that the
source rock of Austin Chalk was the organic carbon in the chalk itself but
later it was realized that the Eagle Ford shale was the source rock. The Austin
Chalk horizontals led to a more integrated horizontal drilling industry with
the development of logging-while-drilling (LWD) or measurement-while-drilling
(MWD) with gamma ray logging tools and to geosteering wells with that gamma ray.
By the mid-1990’s new companies like Horizontal Solutions International (HSI) emerged
that were devoted to geosteering horizontal wells. The new horizontals in the
chalk also spurred George Mitchell and Mitchell Energy to test the Barnett
Shale with horizontal drilling and high-volume hydraulic fracturing in the 90’s
which led to new shale gas plays like the Marcellus, Fayetteville, and
Haynesville Shales which would be followed by new horizontal oil plays from
shales in the Bakken, Eagle Ford, Niobrara, and in the Permian shales of West
Texas. Other horizontal plays like the Bossier Limestone which sits above the
Haynesville Shale were developed in Northeast Texas in the early 2000’s and are
now being successfully revisited today. The wells targeting fractures only were
not hydraulically fractured but produced naturally with some huge wells. This is
a huge cost savings over wells that need to be fracked.
Gen 3: The Austin Chalk Matrix Porosity Play
In the
mid-2010’s some companies began exploring the Austin Chalk away from the highly
fractured areas, instead targeting the higher matrix porosity zones in less
fractured areas. The results were very good. Importantly, they were more
repeatable than in the fractured play where results were often inconsistent. New
3D seismic data also showed more fractures that were untapped so that in some areas
both matrix and fracture porosity can be targeted. This happened in the
Giddings Field where there were multiple 20-30 BCF wells in the 1990’s that
were produced naturally without fracs. Areas with over 6% matrix porosity are targeted
to be fracked and have been showing very good results. The Giddings Field had
been assumed to be depleted but new wells have shown strong results and good
long-term performance targeting matrix porosity. Wells have responded well to
increased proppant loading with the goal of producing from the induced
fractures. Thus, results are more consistent than wells targeting natural fractures.
Wells have responded very well to Eagle Ford style fracs. Clay-control
chemicals have also been helpful in increasing connectivity and preventing the
volcanic ash from sealing fractures. Operators have also noted that determining
permeability and calculating water saturation in the play can be tricky. Determining
storage capacity in a mixed lithology fractured limestone can also be tricky.
Fortunately, results have often been better than predicted.
Robert Loucks
and Sheng Peng in 2021 identified five lithofacies in the Austin Chalk that positively
affect reservoir quality. Here they mention the most important 4 of them: “Burrowed
marly chalk (lithofacies 1) has the best reservoir quality, with a mean
porosity of 6.2% and a geometric mean permeability of 351 nd. Burrowed chalky
marl to marly chalk (lithofacies 2) has the second-best reservoir quality, with
mean porosity being 5.5% and geometric mean permeability being 214 nd. Slightly
burrowed laminated marly chalk (lithofacies 3) has a mean porosity of 4.5% and
a geometric mean permeability of 101 nd. Well-laminated chalky marl to marly
chalk (lithofacies 4) has the poorest reservoir quality, with a mean porosity
of 3.5% and geometric mean permeability of 25 nd.”
Revival in Austin Chalk Production Beginning in mid-2010's. Source:
Troughs or Sub-Basins with Thick Rock Sections and
High Reserves
The Karnes Trough
area has a thickened Lower Cretaceous section of dolomitic limestones which
includes locally slightly thicker Austin Chalk and Eagle Ford. From 2015 Austin
Chalk production increased from about 24 MBOPD and 200 MMCFGPD to about 75
MBOPD and 320 MMCFGPD by the end of 2017. This is mainly attributed to new chalk
wells in the trough and platform/monocline areas of Karnes County, Texas. The
Maverick Basin in Maverick and Dimmit Counties in South-Southwest Texas is another
area of thickened Eagle Ford that is continuing development in Dimmit County. Here
the drilling depths are shallower which helps with well costs. It is mainly the
Austin Chalk and the Upper Eagle Ford that are thickened in the Maverick Basin.
EOG’s Dorado discovery in nearby but deeper Webb County has been described as a
sub-basin. Successful very high reserve wells have been drilled here over the
last few years.
Austin Chalk, Eagle Ford, Buda Combo Plays
The Eagle Ford prospective
fairway is large, and the Austin Chalk prospective fairway overlaps it in many
counties from East-Central Texas to South-Southwest Texas. The Buda Limestone,
a dolomitic limestone, lies below the Eagle Ford. It is developed as a
fractured carbonate reservoir in a few areas overlapping Austin Chalk and Eagle
Ford. Other combo plays include formations just above the Austin Chalk, the San
Miguel and the Olmos, to the west in the Rio Grande Embayment area. The Hearne
area in the northern part of the play in Burleson, Milam, and Robertson Counties
is prospective in the Austin Chalk, Eagle Ford, and Buda. This area is up on
the platform where the production is oil. In that area some of the nearby older
wells have also experienced increased production as a result of fracking of new
wells.
EOG’s Dorado Discovery Area
In November 2020
EOG Resources unveiled their Dorado discovery in Webb County, Texas in an area
of thick Austin Chalk (~400ft) and thick Eagle Ford (~ 300ft) with high reserve
potential. In their 163,000 net acres they estimated gas reserves of 21 TCF from
1250 potential net locations in both formations, 9.5 TCF in the Austin Chalk
from 530 locations and 11.5 TCF in the Eagle Ford from 720 locations. In the past few years, they have been drilling
the area successfully but have recently in 2023 decided to temporarily defer
completing 2023 wells due to low gas prices, leaving them as DUCs. EOG drilled
17 Austin Chalk wells in Dorado in 2019 then paused drilling in 2020 to evaluate
production while analyzing the field with cores, petrophysical logs, and 3D
seismic. According to EOG’s E.V.P. of Exploration and Production, Ken Boedeker
from a February 2021 article in American Oil & Gas Reporter: “With a
break-even cost of less than $1.25 per Mcf, we believe this play represents the
lowest cost supply of natural gas in the United States. At Henry Hub prices of
$2.50 per Mcf, Dorado competes directly with our premium oil plays. We are
leveraging our proprietary knowledge built from prior plays to move quickly
down the cost curve with our initial development. We currently estimate a
finding cost of $0.39 per Mcf in the Austin Chalk and $0.41 per Mcf in the
Eagle Ford.” Following a year of production, by early 2021, EOG became
confident in their reservoir model and reserves estimates and I believe drilled
another 15 wells in the field that year. The play also benefits from abundant
infrastructure availability with access to LNG export terminals, pipelines
selling to Mexico, and local sales points. It also gives EOG optionality when
oil prices are low and gas prices are more favorable.
Austin Chalk Exploration Failures in East Louisiana
and Mississippi: Deep, Expensive, and Often Wet
The Austin Chalk
has also had some success in Western Louisiana with some developed fields and several
periods of waxing and waning interest there and to the east. EOG made a
discovery further east in 2017 and drilled about 6 wells I believe but by Sept.
2019 decided to abandon the area due to increased water production. Another of
the downsides is that it is deeper there. EOG, Marathon, Conoco Phillips, and
others made a run for acreage and drilled test wells in Eastern Louisiana and
Mississippi but poor results and water seem to be an insurmountable problem so most
companies have pulled out. While the Eagle Ford Shale is below the Austin Chalk
in Texas, another source rock, the Tuscaloosa Marine Shale (TMS) is below the
chalk in Louisiana and Mississippi. Australian company Australis Oil and Gas
drilled some very deep 15,000 -20,000 ft wells in the TMS in 2019 that were pretty
good wells, but the TMS has been challenging as a whole with the play all but
abandoned. The company does worry about rapid decline which they have seen in
the Austin Chalk wells in the area, and which is known in the low permeability
TMS.
Drilling Issues in the Austin Chalk and Eagle Ford
The presence of
some small offsetting faults and fractures combined with high formation pressures
and possible interference from nearby wells has led to some drilling issues in both
formations. Lost circulation and mud loss can be issues. Managed pressure
drilling, including drilling on mudcap with no cuttings returning to the
surface is not uncommon in some areas. Differential sticking, when the drill
string sticks to the side of the well bore can occur when pressures drop away
from the wellbore due to intersecting open fractures. These South Texas plays
are also deep, with high pressures and fairly high temperatures, which can
contribute to variations in well bore integrity. The Eagle Ford drills fast
like most shales. The Austin Chalk drills a little slower than the Eagle Ford but
still pretty fast. Small faults can complicate geosteering in some areas. The
volcanic ash layers can also be hazardous as they fall in and as they have a
tendency to keep the bit in them if drilled horizontally close to formation
dip. That also results in more ash in the cuttings and a higher potential for
plugging fractures. Thus, wells may be steered away from the known ash layers.
The Eaglebine is
a name given to the combo play of Eagle Ford and Woodbine formations in the
East Texas Basin. The north and east of the main Eagle Ford fairway in the Western
Gulf Coast Basin is bounded by the San Marcos Arch. On the northeast side of
the arch is the East Texas Basin where these rock formations again thicken but
have different facies and lithologies. The Eagle Ford is mainly the upper Eagle
Ford equivalent and is less calcareous than in the main producing area and less
prospective. However, below the Eagle Ford is the Woodbine Sandstone which is a
major oil and gas producer in the East Texas Basin at depths greater than 12,000
ft. The Woodbine is age equivalent to the Tuscaloosa Marine Shale (TMS) further
East beyond the Sabin Uplift which bounds the East Texas Basin to its
northeast. The Woodbine organic shale below the sands is also an important target at shallower depths The Lower Eagle Ford intertongues with the Maness Shale and the
Pepper Shale that underlies the Eagle Ford in South Texas intertongues with the
Woodbine Sandstone. The Woodbine facies include incised valley fills to the
northeast and fluvial-deltaic sandstones to the southwest. These reservoirs as
such can be more heterogenous and reservoir quality can be more difficult to
predict and less consistent for horizontal drilling. Still, production has been
very good in some of these zones, with EURs sometimes exceeding 30-40 BCF in
vertical wells but with wells nearby having much lower production. The Woodbine
is “highly stratified and diagenetically complex.” The history of cement
diagenesis is thought to be a key factor in preserving porosity and
corresponding high hydrocarbon production. These are monster wells but with
drilling depths up to 15,000 ft they are also costly.
Eaglebine Play Regional Stratigraphy. Source:Stratigraphic and Depositional Context of the Eaglebine Play: Upper Cretaceous Woodbine and Eagle Ford Groups, Southwestern East Texas Basin. Tucker F. Hentz and William A. Ambrose. AAPG. Search and Discovery Article #51094. June 22, 2015. View PDF (searchanddiscovery.com)
Woodbine Reservoir and Diagenesis. Source: Woodbine Formation Sandstone Reservoir Prediction and Variability, Polk and Tyler Counties, Texas. Robert J. Bunge. AAPG. Search and Discovery Article #10331. June 25, 2011. Woodbine Formation Sandstone Reservoir Prediction and Variability, Polk and Tyler Counties, Texas; #10331 (2011) (searchanddiscovery.com)
References:
Austin
Chalk Revival: New Oil and Gas from an Old Trend. (2018?). Austin Chalk RevivalAustin Chalk Revival
(austinchalkoilgas.com)
East
Texas Chalk: It’s The Matrix. Nissa Darbonne. Oil and Gas Investor. Hart
Energy. January 24, 2020. East
Texas Chalk: It’s The Matrix | Hart Energy
Austin
Chalk Revived: An Emerging Unconventional Play. Laurentian Research. March 7,
2019. Seeking Alpha. Austin
Chalk Revived: An Emerging Unconventional Play | Seeking Alpha
The
Eagle Ford and Austin Chalk: Better Operating Practices and New Approaches Keep
South Texas Humming. Al Pickett. American Oil and Gas Reporter. October 2018. Better
Operating Practices And New Approaches Keep South Texas Humming (aogr.com)
Matrix
reservoir quality of the Upper Cretaceous Austin Chalk Group and evaluation of
reservoir-quality analysis methods; northern onshore Gulf of Mexico, U.S.A. Robert
G. Loucks and Sheng Peng. Marine and Petroleum Geology. Volume 134, December
2021. Matrix
reservoir quality of the Upper Cretaceous Austin Chalk Group and evaluation of
reservoir-quality analysis methods; northern onshore Gulf of Mexico, U.S.A. -
ScienceDirect
Louisiana
Austin Chalk: Hundreds of Millions Down the Drain? Matt Zbrowski. Journal of
Petroleum Technology. September 29, 2019. Louisiana
Austin Chalk: Hundreds of Millions Down the Drain? (spe.org)
Haynesville,
TMS and the Austin Chalk: Louisiana’s place in the Lower 48 supply stack. Brandon
Myers. Wood Mackenzie. January 2020. General
template rules (planoweb.org)
Quiet
for decades, Austin Chalk oil and gas play attracting new interest. Mark
Passwaters. S&P Global Market Intelligence. June 8, 2018. Quiet
for decades, Austin Chalk oil and gas play attracting new interest | S&P
Global Market Intelligence (spglobal.com)
Key
geological factors controlling the estimated ultimate recovery of shale oil and
gas: A case study of the Eagle Ford shale, Gulf Coast Basin, USA. Lianhua Hou,
Zhichao Yu, and Senhu Lin. June 2021. Petroleum Exploration and Development
48(3):762-774. (PDF)
Key geological factors controlling the estimated ultimate recovery of shale oil
and gas: A case study of the Eagle Ford shale, Gulf Coast Basin, USA
(researchgate.net)
Quantitative
assessment of the sweet spot in marine shale oil and gas based on geology,
engineering, and economics: A case study from the Eagle Ford Shale, USA.
Energy Strategy Reviews. Volume
38, November 2021, 100713. Lianhua Hou, Caineng Zou, Zhichao Yu, Xia Luo,
Songtao Wu, Zhongying Zhao, Senhu Lin, Zhi Yang, Lijun Zhang, Dingwei Wen,
Jingwei Cui. Quantitative
assessment of the sweet spot in marine shale oil and gas based on geology,
engineering, and economics: A case study from the Eagle Ford Shale, USA -
ScienceDirect
Eagle
Ford Shale play economics: U.S. versus Mexico. Ruud Weijermars, Nadav Sorek,
Deepthi Sen, Walter B. Ayers. Journal of Natural Gas Science and Engineering. Volume
38, February 2017, Pages 345-372. Eagle
Ford Shale play economics: U.S. versus Mexico - ScienceDirect
Woodbine
Formation Sandstone Reservoir Prediction and Variability, Polk and Tyler
Counties, Texas. Robert J. Bunge. AAPG. Search and Discovery Article #10331. June
25, 2011. Woodbine
Formation Sandstone Reservoir Prediction and Variability, Polk and Tyler
Counties, Texas; #10331 (2011) (searchanddiscovery.com)
Stratigraphic
and Depositional Context of the Eaglebine Play: Upper Cretaceous Woodbine and
Eagle Ford Groups, Southwestern East Texas Basin. Tucker F. Hentz and William
A. Ambrose. AAPG. Search and Discovery Article #51094. June 22, 2015. View
PDF (searchanddiscovery.com)
No comments:
Post a Comment