SPE 177139 Evaluation of Mexico`s Shale Oil and Gas Potential

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[165832]
SPE 177139
Evaluation of Mexico’s Shale Oil and Gas Potential
Scott H. Stevens, SPE, and Keith D. Moodhe, SPE
Advanced Resources International, Inc.
Copyright 2015, Society of Petroleum Engineers Inc.
This paper was prepared for presentation at SPE Latin America and Caribbean Petroleum
Engineering Conference (LACPEC) held in Quito, Equador, 18-20 November, 2015.
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Abstract
Mexico has significant oil and gas resource potential in
Jurassic and Cretaceous age shale formations. These shale
deposits -- which correlate with productive shale plays in the
USA -- appear prospective but are still in the early stage of
exploration and thus remain poorly characterized. Early shale
exploration wells tested mostly low rates, but a recent oil well
made 500 bopd while a shale gas well reached 10.9 MMcfd.
The Mexican government plans to offer shale exploration
blocks through an international auction. As part of a multiclient study, the authors have greatly expanded the geologic
and reservoir data set we developed during an earlier scopinglevel study conducted for the US Energy Information
Administration (EIA). The additional geologic data support
our initial view that Mexico has some of the largest and best
quality shale potential outside the US and Canada. Risked,
technically recoverable resources were estimated in the
EIA/ARI study at 13.1 BBO of oil and 545 Tcf of natural gas.
Detailed geologic mapping and analysis indicates the two
most prospective liquids-rich shale areas in Mexico occur
within onshore portions of the Burgos and Tampico-Misantla
basins, which have transport infrastructure and well services.
Significant potential also exists in the Veracruz, Macuspana,
Sabinas, and other onshore basins, but those areas tend to be
structurally more complex and/or are mostly in the dry gas
window.
The U. Cretaceous Eagle Ford Shale (in the Burgos) and
correlative Agua Nueva Formation (in the Tampico-Misantla)
have high TOC and brittle carbonate-rich mineralogy, but their
net prospective area is reduced due to often shallow burial
depth and low thermal maturity. A better target appears to be
the U. Jurassic Pimienta and La Casita formations, which can
be thick (~200 m), at prospective depth over much larger
areas, are in the volatile oil to wet gas windows, and
frequently overpressured, although TOC is lower than in the
Agua Nueva.
Introduction
The greater Gulf of Mexico Basin extends south from the
onshore Gulf Coast of the US into northeastern Mexico (Fig.
1). Equivalent shale formations, such as the Eagle Ford and
Haynesville/Bossier shale plays in the US, also are present
south of the international border, where they are considered
important source rocks for conventional oil and gas deposits.
As such, Mexico offers relatively low-risk shale exploration
targets compared with other countries, such as China and
Australia, which have entirely different geologic histories and
present-day settings.
Our previous scoping-level study for the US Department
of Energy’s Energy Information Administration (EIA)
documented that shale oil and gas resources in northeast
Mexico are large and prospective (EIA/ARI, 2013). At that
time, with limited geologic data, we estimated risked,
technically recoverable resources in Mexico to be
approximately 13.1 BBO of oil and 545 Tcf of natural gas
(104 BBOE; Table 1). Our recent more detailed work, based
on a much larger public data set that we compiled, generally
supports this analysis, while providing more granularity on the
geologic variability and prospectivity of individual basins.
Mexico’s national oil company Pemex recently published
its own estimates of shale oil and gas resources in Mexico,
although their methodology and assumptions have not been
disclosed. Pemex’ most recent estimate for shale resources in
Mexico is 60.2 BBOE, comprising 31.9 BBO of oil, 36.8 Tcf
of wet natural gas, and 104.1 Tcf of dry natural gas (Pemex,
2014a). These estimates include both the U. Cretaceous and
U. Jurassic shales in the Tampico-Misantla, Burgos, BurroPicachos, and other basins. The US Geological Survey
independently estimated much smaller resources of 0.776
BBO, 23.474 Tcf, and 0.883 BB of natural gas liquids (mean
estimates), but did not release its geologic maps (USGS,
2014).
Pemex initiated shale exploration drilling in 2010 and to
date has completed over 30 horizontal test wells treated with
large hydraulic stimulations. A further 29 shale wells are
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planned during 2015-2019. Drilling has been concentrated in
the Burgos Basin south of Texas, along with several wells in
the Tampico-Misantla and Sabinas basins. The initial wells
have tested mostly low rates but a few recent wells were more
productive, particularly in the Pimienta Fm of the southern
Burgos Basin.
Note that these early horizontal test wells were relatively
shallow, targeting shale formations at depths of 1,000 to 2,500
m. In contrast, many shale plays in the US target deeper areas,
such as the Bakken Shale in the Williston Basin, where
horizontal development is focused at depths of about 3,300 m
with greater reservoir pressure. Despite the slow start, it
appears likely that once geologic sweet spots are defined and
well completion practices refined, shale resources could play a
major role in Mexico’s plans to boost natural gas output,
reduce gas imports from the US, and maintain or even grow its
recently declining oil output.
As part of Mexico’s ongoing major reforms of the
petroleum industry, the Comisión Nacional de Hidrocarburos
(CNH) plans to hold a series of international auction rounds of
blocks with unconventional oil and gas potential. CNH has
identified an estimated 21.642 BBOE of potential in 291
blocks totaling 33,959 km2 in the Burgos, Burro-Picachos,
Tampico-Misantla and other onshore basins (SENER, 2015).
Mexico’s shale resource potential is significant, but numerous
challenges remain, including security, the availability of lowcost well services, and a scarcity of geologic and reservoir
data on shale rock properties. On the other hand, the close
proximity to shale services, expertise, and funding sources in
the US and Canada gives Mexico a leg up over other countries
which are seeking to jump start their shale industries.
[177139]
With a total 5,000+ mapped shale geologic and reservoir
data points, we had reasonably good control of thickness,
depth, structure, lithology, and thermal maturity for the
principal U. Cretaceous and U. Jurassic shale targets across
northeast Mexico. Geochemical data such as TOC and HI
control were less abundant. Published log and seismic images
were mostly of poor quality and not suitable for petrophysical
analysis, though still useful for correlation and defining
general shale characteristics. We found limited data on
subsurface hydrology and shale physical properties, notably
mineralogy which was rarely of interest prior to the advent of
shale exploration.
Our methodology for assessing Mexico’s shale resources
was described in further detail in EIA/ARI, 2013. We applied
typical screening criteria of shale thickness, minimum and
maximum depth, total organic carbon content (TOC), thermal
maturity indicated by vitrinite reflectance (Ro), and
mineralogy. High-graded areas within the basins considered
prospective for shale gas and shale oil exploration were
mapped and characterized. We then estimated technically
recoverable resources (TRR) from the original oil (or gas) in
place (OOIP or OGIP) based on the range of actual recovery
factors currently achieved in North American shale plays.
Finally, we applied risk factors commonly employed by shale
operators. However, the economic viability of the TRR was
not assessed in our study.
The discrete steps in the EIA/ARI evaluation were:
1.
2.
Mexico’s shale service sector is gradually building the
necessary capability for large-scale horizontal drilling
combined with massive multi-stage hydraulic stimulation.
Only a small number of horizontal shale gas and oil wells have
been tested thus far, with generally low but still encouraging
production rates. Large-scale commercial production appears
to be some years in the future. Considerable work is needed to
define the geologic “sweet spots”, develop the service sector’s
capacity to effectively and economically drill and stimulate
modern horizontal shale wells, and install the extensive
surface infrastructure needed to transport product to market.
Data Control and Methodology
A significant challenge in assessing Mexico’s shale
resources is data availability. Much of the basic geologic and
well data that is publicly available in other countries is
confidential in Mexico. However, a wealth of geologic data on
source rock shales has been published over the years in
various Mexican journals and university theses. We utilized
these public sources to develop a proprietary GIS data base of
shale geology in Mexico, compiled from nearly 500 Spanish
and English language technical articles, most of which were
written “pre-shale” and concerned conventional source rock
geology. Data locations plotted on our Mexico maps provide
an indication of geologic control (Fig. 2).
3.
4.
5.
6.
Translate nearly 500 mostly Spanish language technical
articles and develop a GIS data base of geologic and
reservoir properties.
Characterize the geologic and reservoir properties of each
shale basin and formation.
Establish the areal extent of the shale gas and shale oil
formations.
Define and characterize the prospective area for each
shale gas and shale oil formation based on thickness,
depth, TOC, and thermal maturity.
Estimate the risked shale gas and shale oil in-place based
on a) overall play probability of success and b) play area
probability of success.
Using recovery factors from similar shales in the US
estimate the technically recoverable shale gas and shale
oil resource.
Shale Basins and Formations in Mexico
Large sedimentary basins extend across onshore northeast
Mexico, containing rich petroleum source rocks with suitable
thickness, depth, organic content, and thermal maturity for
shale gas/oil exploration. The two most prospective basins
appear to be the Burgos Basin, extending south of Texas, and
the smaller Tampico-Misantla Basin further to the southeast in
Veracruz and adjoining states.
Other basins (Sabinas,
Veracruz, Macuspana) also have shale potential, but overall
they tend to be structurally more complex and/or in the dry gas
window and are presented in less detail here.
[177139]
Two principal marine-deposited shale exploration targets
are present in northeast Mexico, each one considered an
important source rock for the conventional oil and gas fields
which have been discovered in the region (Fig. 3). The Upper
Cretaceous Eagle Ford, Agua Nueva and equivalent
formations may perhaps be more familiar to US
explorationists. This shale formation has been intensively
developed in South Texas, making its direct extension into
northern Coahuila State an obvious target. But after data
gathering and analysis, we were surprised at how relatively
limited the Eagle Ford prospective area is in Mexico, due to
structural trends, insufficient burial depth, and low or high
thermal maturity.
The more prospective target appears to be the Upper
Jurassic (Tithonian) Pimienta, La Casita, and equivalent
formations. These organic-rich black shale to shaly limestone
deposits, which are near time-equivalent with the HaynesvilleBossier Shale in Louisiana, were deposited in a broad marine
basin under anoxic conditions. Lithologies range from shales,
argillaceous limestones, to thin-bedded lime mudstone with
chert layers. While the Tithonian generally has somewhat less
TOC than the U. Cretaceous (2-3% vs 4-5% in the richer
zones), it occurs at suitable burial depth over much larger
areas, and more often is in the optimal wet gas to volatile oil
thermal maturity windows.
Furthermore, additional shale targets directly underlie the
Pimienta, such as the Taman, San Andres, Santiago and
equivalent formations of Oxfordian to Kimmeridgian age.
While not as laterally persistent as the Tithonian, these units
can be equally or more organic-rich and offer secondary shale
completion zones. An analogy could be the Three Forks and
Mid-Bakken units in the Williston Basin, now a “two-fer”
play with optionality. The Oxfordian in Mexico is about 500
m deeper than the Tithonian, giving it higher reservoir
pressure and thermal maturity, although our data control was
weaker.
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imports from the US, which currently exceed 2 Bcfd and are
increasing quickly as major pipeline infrastructure expansions
are completed, to a reported 8 Bcfd capacity by the end of
2015 (Seelke et al., 2015).
Data availability for the Burgos Basin overall was good,
comprising over 2,000 data points (well logs, cross-section
control points, outcrop samples) extracted from more than 250
published articles and university theses, mostly in Spanish.
Basic data on depth, thickness, thermal maturity, and other
shale properties were abundant for both U. Cretaceous Eagle
Ford and U. Jurassic Pimienta formations, but the data were
not suitable for advanced petrophysical or seismic analysis.
The Burgos Basin is located south of the Rio Grande
Embayment, east of the Burro Salado Arch, north of the
Tampico-Misantla Basin (which contains similar Mesozoic
shale targets), and northeast of the Sierra Madre Oriental
thrust belt. The basin extends offshore but our shale study
was limited to onshore. It formed by extension associated
with salt deposition during the Jurassic to Early Cretaceous.
Later on it was affected by Laramide (late Cretaceous)
compression, followed by strike slip faulting during the
Oligocene along the Rio Bravo left-lateral fault zone (Flotte et
al., 2008). The Burgos contains a thick Tertiary sequence
which hosts numerous mostly small conventional and tight
natural gas fields.
Closely spaced mostly normal faults associated with folds
deform the Tertiary sequence and form conventional
hydrocarbon traps (Hernandez-Mendoza et al., 2008).
Fortunately, most of these faults flatten into a detachment
surface near or above the Cretaceous-Tertiary boundary and
do not appear to cut the shale-prospective Mesozoic section
(Fig. 4; Ortiz-Ubilla and Tolson, 2014). Thus the geologic
structure of the Burgos may be favorable for the deeper shale
targets.
Burgos Basin
CNH plans to offer 124 blocks totaling 14,406 km2 in the
Burgos Basin under Bid Rounds 2-4, with an estimated 6.486
BBOE of unconventional resources. Stretching south from the
Texas border, the Burgos has been the focus of Pemex’ initial
shale exploration activity. Two main shale targets are present:
the U. Cretaceous Eagle Ford Shale in the north Burgos, with
a relatively small prospective area just south of the Texas
border; and the U. Jurassic Pimienta and La Casita formations
in the south Burgos, extending over a much larger prospective
area and probably with greater resource potential. Mexico’s
best horizontal shale well to date, the 750-boepd Anhelido-1,
was completed here in the Pimienta Fm.
Pemex began its shale exploration program targeting the
Eagle Ford Shale and later extended to the Pimienta Fm. The
company’s first shale exploration well, the Emergente-1 well
drilled in 2010, is located just south of the Texas border. The
4,071-m well (measured depth) targeted the 175-m thick Eagle
Ford Shale at subsurface depths of 2350-2525 m. Its 1300-m
lateral was oriented due south and positioned in the organicrich lower Eagle Ford zone, where TOC reaches 4.5%. As the
first of its type the Emergente-1 took five months to drill,
whereas recent comparable wells in Mexico can now be
drilled in about one month. Following a 17-stage frac
employing 8 million gallons of slickwater and 42,563 sacks of
quartz sand proppant, the well produced an initial gas rate of
2.8 MMcfd (Zavala-Torres, 2014).
Production of natural gas from conventional sandstone
reservoirs began in the Burgos Basin as early as 1945. Gas
output peaked in 2010 and has since declined to the current
1.2 Bcfd. Condensate production associated with natural gas
also peaked in 2010, and currently is about 18,000 bbl/d and
declining (Pemex, 2014b). Shale gas development in the
Burgos could help stem the rise of, or even reduce, gas
The Eagle Ford Shale in the nearby Habano-1 shale test
well had micritic matrix with detrital clay, planktonic
foraminifera, sealed with calcite and authigenic clay,
occasional pyrite. Samples measured 54% calcite, 18%
quartz, and 19% clay (type not noted), with 9% other minerals
(Martinez Contreras, 2015). The Montañés-1 well measured
1.95% average TOC in the upper Eagle Ford Shale, increasing
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to 2.71% average in the lower zone. Subsequent Eagle Ford
Shale wells in the northern Burgos all tested low-moderate oil
and gas rates, much lower than from the Pimienta Fm in the
southern Burgos, but it is not clear whether due to rock quality
or perhaps fracture stimulation design.
As of mid-2014 Pemex had completed three horizontal
large-frac wells targeting the more promising Pimienta Fm in
the southern Burgos Basin; three others were undergoing
completion (Araujo et al., 2014). In 2012 the Anhelido-1 well
was completed in the Pimienta Fm at a mean measured depth
of 2,111 m. The Pimienta here consists of marine-deposited
black shale and shaly limestone containing Type II/III
kerogen, divided into four intervals with varying concentration
of carbonate mineralogy and TOC richness, which ranged up
to 4%. Tmax of 450-454°C indicates condensate to wet gas
thermal maturity. XRD measured favorably brittle mineralogy:
70% calcite, 1% dolomite, 10% quartz, and 11% illite clay.
Porosity was estimated at 7%. The fracture gradient was a
moderate 0.92 – 1.02 psi/ft. The nearby Arbolero-1 shale well
tested 0.55 psi/ft reservoir pressure gradient.
The Anhelido-1 lateral was landed just above the peak
radioactivity zone, where clay content was lower, TOC higher,
and the formation considered more brittle. They conducted a
17-stage hydraulic stimulation, employing 5.1 million lbs sand
proppant and 12 million gallons of frac fluid. Each stage
utilized five 1-m long frac clusters, with 20 shots/meter that
were deep penetrating and 60° phased. Formation brittleness
was homogeneous along the lateral, and the evenly spaced
stages received uniform stimulation based on radioactive
tracers. This stimulation resulted in estimated 133-m propped
fracture length and 95-m propped fracture height.
The Anhelido-1 well was the first horizontal frac shale
well to produce oil from the Pimienta Fm, and achieved a
production rate higher than any of the Eagle Ford wells up to
that time. Initial production was about 500 bopd of 37° API
oil with 1.5 MMcfd of wet gas (24-hour rate). Production
dropped rapidly but stabilized at 80-90 bopd with 0.6 MMcfd
of gas after one year on line. Pemex reported cumulative
production of about 40,000 bbl of oil during the first year,
with estimated ultimate recovery (EUR) of over 100,000 bbl
(cumulative gas was not reported). Such an early test well,
while probably not economic, would be considered promising
in any new shale basin. There appears to be good potential to
further increase productivity by optimizing the stratigraphic
landing zone, well and frac design, and other parameters.
Another well, the Tangram-1 encountered 215 m thick
Pimienta Fm in a thermally more mature dry gas window.
The well tested 10.9 MMcfd of dry gas, the highest rate for a
shale gas well in Mexico thus far.
In-situ stress data on the shale targets are not available in
the Burgos, but the overlying Eocene tight sandstones have
tested low stress. For example, one well measured 6,150 psi
closure stress at a depth of 3,217 m., for a favorably low 0.58
psi/ft frac gradient (Medina Eleno and Valenzuela, 2010).
[177139]
This suggests that hydraulic stimulation of shale targets in the
basin could be effective.
The very large Burgos Basin faces certain operational
challenges compared with similar basins in the US and
Canada, due to limited pipeline infrastructure and local
security issues. On the other hand, hydraulic stimulation has
been applied for some years in tight gas development,
providing a certain degree of local well service capability.
Whereas the Burgos is an arid area compared with coastal
Tampico-Misantla, extensive ground water resources are
present in the Cretaceous Agua Nueva and Cupido formations.
For example, the latter is about 200 m thick, with fresh to
brackish conditions 380-1,350 ppm TDS at 600-700 m depth
(Conagua, 2009). Groundwater could provide a source of
fluid for hydraulic stimulation in the basin.
Tampico-Misantla Basin
Somewhat smaller than the Burgos Basin, but with
sizeable prospective liquids-rich windows, the TampicoMisantla Basin (TMB) is the primary focus of CNH’s
upcoming Round 1 unconventional license auction. CNH
plans to offer a total 158 license blocks covering 17,625 km2
and with an estimated 17.625 BBOE of resource potential
under Bid Rounds 1 through 4 (Fig. 5). This does not include
Round 0 areas retained by Pemex, mostly in the southern half
of the basin, which also may have good shale potential.
The southern portion of the TMB hosts the well-known
Chicontepec complex, a series of conventional oil fields which
since discovery in 1904 have produced a cumulative 5.5 BBO
and 7.5 Tcf from over 20,000 wells. Production is mainly
from Tertiary conventional and tight sandstones and naturally
fractured Cretaceous carbonates in structural traps (Fig. 6).
These conventional oil fields produce 15-35° API gravity
crude from 1,500-2,500 m depth. Underlying Cretaceous and
Jurassic shale reservoirs are likely to produce higher gravity
oil. Sulfur content can be high (5%) in biodegraded shallow
conventional fields but is lower (<1%) in deeper fields.
Pemex estimates 18.9 Bboe of remaining conventional
reserves in the TMB, but notes that low permeability results in
poor recovery factors (~2%) and high full-cycle costs (Pemex,
2013).
Topography within the TMB is mostly flat coastal plain to
rolling hills, considered favorable for shale development. The
rugged Sierra Madre Oriental mountains rise rapidly in the
west, reaching 4,000 m elevation outside the basin. The
largest city is Poza Rica (193,000), otherwise surface
conditions are mostly rural. The climate is tropical, with
moderate 14-24°C temperatures and 1.2 m/yr average rainfall,
concentrated during June-October.
Data availability for the TMB overall generally was good,
comprising over 2,000 data points (well logs, cross-section
control points, outcrop samples) from more than 1,500 unique
mapped locations, extracted from nearly 150 published
articles, mostly in Spanish. Of this total, 763 data points
penetrated just down to the Cretaceous strata, 946 penetrated
both the Cretaceous and Jurassic, and 398 points were
[177139]
specifically on the U. Jurassic Tithonian Pimienta Fm. We
recorded 211 partial well log images, of which 150 penetrated
the Jurassic.
Initiated in the late Triassic as a pull-apart basin, the
NNW-SSE trending Tampico-Misantla Basin (TMB)
transitioned to foreland basin by the Paleocene. The basin is
bounded on the east by the Tuxpan Uplift and Caribbean
coastline. The west is bounded by thrusting and folding
related to the Laramide-age Sierra Madre Oriental range.
Note that we extended the basin several kilometers to the west
beyond the traditional Cretaceous-Tertiary boundary, where
Jurassic shale can still occur at prospective depth. Faulting
inside the basin is relatively minor, mostly high-angle normal
faults with h<50 m. Structural dip is gentle, mostly flat lying
to about 5° (Fig. 7; Pemex, 2012). Overall, structure appears
favorable for shale development using horizontal drilling.
The Upper Cretaceous Agua Nueva Fm is an organic-rich
shaly carbonate which has produced oil in naturally fractured,
anticlinal fields within the TMB. Our mapping indicates this
unit is too shallow and thermally immature for economic shale
exploration in most of the basin. Instead, we regard the
underlying Upper Jurassic Pimienta Formation as the primary
shale target in the TMB: it is depositionally more widespread,
less eroded by the Paleochannel, deeper and at higher
pressure, and thermally more mature. The Pimienta also is
considered the main source rock in the TMB.
The Pimienta Fm is an organic-rich black shale to shaly
limestone unit that ranges up to 350 m thick, averaging 150 to
200 m in basinal depositional settings, 50-100 m on slope
settings, and thinning to zero over paleo highs. Note the
Pimienta is 2-3 times thicker than the Eagle Ford Shale in
South Texas. During the Tithonian, high evaporation in
restricted basins resulted in lower clay and Type III kerogen
than in the preceding Oxfordian stage. Oils generated from
the Tithonian are subtly differentiated from the Oxfordian by
C26 character (Guzman-Vega et al., 2010).
The top of the Pimienta Fm varies from 500 to 4,000 m
deep across the TMB. To the east the Pimienta deepens
rapidly offshore to below 5 km. The Tamaulipus Arch
uplifted the Pimienta, bifurcating the prospective area into
south and north halves. Note that the underlying Taman,
Santiago, and related U. Jurassic shale targets are an additional
~500 m below the Pimienta and could be secondary targets, or
perhaps primary targets where the Pimienta is too shallow and
immature.
We mapped well-defined black oil, volatile oil, wet gas,
and dry gas windows for the Pimienta Fm across the TMB
based on Tmax and Ro data. Thermal maturity increases
regionally towards the Sierra Madre Oriental in the west, and
also increases gradually with depth. Much of the onshore
basin is in the black to volatile oil windows, with a smaller
wet gas and tiny dry gas window in the west.
Microseismic monitoring of the Tertiary at Chicontepec
shows that maximum principal horizontal stress is oriented
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NE-SW, consistent with regional tectonics, with 40-250 m
fracture length (average 130 m). Stress magnitude is uncertain
but fracture height growth of around 90 m in the Tertiary
sandstone reservoirs indicates favorably moderate stress
(Gutiérrez et al., 2014).
The TMB differs from US shale plays in that significant
relatively recent (Miocene-Quaternary) igneous activity has
occurred, particularly in the south, which could negatively
impact the shale potential (Ferrari et al., 2005). Fortunately,
most of this igneous activity, part of the Trans-Mexican Faja
Volcanic Belt, consisted of shallow extrusive lava flows that
followed paleotopography from elevated source areas in the
eastern Sierra Madre Orientale downhill some 90 km across
the TMB to the coast.
After screening for depth, thickness, Ro, and igneous
intrusions and lava flows, the net high-graded prospective
thermal maturity windows for the U. Jurassic Pimienta Fm
that we identified in the TMB are comparable in size to those
of the South Texas Eagle Ford Shale play (>12,000 mi2),
although the northern TMB region is poorly constrained.
Pemex has drilled, cored, and hydraulically fractured three
horizontal wells in the southern TMB, landing in the Pimienta
Formation which is 92 to 200 m thick and 2,327 to 2,920 m
deep (below sea level) in these penetrations. Data on rock
properties and production have not yet been released.
In 2013 Pemex estimated the TMB has 34.8 BBOE of
unconventional shale resources from both U. Cretaceous and
U. Jurassic formations, comprising mainly oil (30.7 BBO)
with some wet gas (20.7 Tcf) but no dry gas. EIA/ARI’s 2013
estimate for the Pimienta Fm alone was 10.6 BBOE of risked,
technically recoverable resources, comprising a more balanced
blend of 6.5 BBO of oil and 24.7 Tcf of mainly wet natural
gas, including a small amount of dry gas.
In 2014 the USGS estimated a much smaller resource of
0.6 BBO and 0.4 Tcf for the TMB (mean estimate), about twothirds from the U. Cretaceous Agua Nueva Fm and the balance
from the U. Jurassic Pimienta Fm. The USGS reported
screening out 79% of the otherwise prospective Pimienta Fm
area based on a Pemex contour map indicating TOC of less
than 2%. However, core data we located indicates this map
may be underestimating actual TOC. In our view the
Pimienta’s greater depth, reservoir pressure, and thermal
maturity make it the more prospective target in the TMB,
despite lower overall TOC than in the Agua Nueva Fm.
Other Basins
Several other basins in Mexico have shale potential. Just
west of the Burgos Basin in the Sabinas Basin, with similar U.
Cretaceous and U. Jurassic shale targets that are entirely in the
dry gas window, but significantly folded due to thrusting from
the Sierra Madre Oriental mountains as well as local saltwithdrawal tectonics (Soegaard et al., 2003). A shale gas
exploration well (Percutor-1) produced 2.17 MMcfd of dry gas
from the Eagle Ford Shale at a sub-surface depth of 3,3303,390 m.
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[177139]
In the Veracruz and Macuspana basins of southeast
Mexico, the U. Cretaceous (Turonian) Maltrata Formation is a
significant source rock, with about 100 m of shaly marine
limestone and an average 3% TOC (Type II). Thermal
maturity ranges from oil-prone (Ro averaging 0.85%) within
the oil window at depths of less than 11,000 ft, to gas-prone
(Ro averaging 1.4%) within the gas window at average depths
below 11,500 ft. The dip angle is relatively steep, thus
prospective area appears to be limited to a relatively long,
narrow belt. These other basins are the focus of our
continuing evaluation of Mexico’s shale oil and gas potential.
Conclusions
1. Our GIS-based data base of shale geologic and
reservoir properties, built with data published in
nearly 500 mostly Spanish language technical articles
and university theses, helped us to identify and
characterize the prospective areas within Mexico’s
shale basins. In all, over 5,000 shale data points were
mapped, including depth, thickness, Ro, and TOC.
2.
3.
4.
5.
The new data generally confirms our earlier estimate
for EIA that Mexico has approximately 13.1 BBO
and 545 Tcf of risked, technically recoverable shale
oil and gas resources, while providing more
granularity on where potential sweet spots may be
located.
The structurally simple southern flank of the Burgos
Basin has large shale oil and gas resources in the U.
Jurassic Pimienta Formation. A horizontal shale well
here produced 500 bopd of 37° API crude and 1.5
MMcfd of wet gas. We mapped a large area in the
southern Burgos high-graded for thickness, depth, Ro,
and structural simplicity.
The Tampico-Misantla Basin has liquids-rich shale
potential, particularly for the U. Jurassic Pimienta
Fm. High-graded areas have 100-300 m thick
Pimienta shale at a depth of 2 to 4 km deep, with
large areas in the volatile oil to wet gas thermal
maturity windows (Ro 0.7 to 1.3%).
Other basins (Sabinas, Veracruz, Macuspana) also
may be prospective but initial review shows then to
be structurally more complex. The Sabinas Basin is
entirely in the dry gas window, while the Veracruz
and Macuspana basins have exceptionally thick
source rocks of liquids-rich maturity, but also are
significantly faulted. While CNH has not announced
license blocks, these basins could have good local
potential and warrant further study.
Acknowledgments
The authors wish to thank the Energy Information
Administration, Chesapeake Energy, ConocoPhillips, and
eight other oil company clients for financial support
provided in conducting this study. Vello A. Kuuskraa
contributed to the resource methodology used in this
study.
Nomenclature
Bcf
billion (109) cubic feet
bopd
barrels of oil per day
BBO
billion (109) barrels of oil
BBOE
billion (109) barrels of oil equivalent
C
centigrade
CNH
Comisión Nacional de Hidrocarburos
g/cc
grams per cubic centimeter
GIS
geographic information system
km
kilometer
km2
square kilometer
m
meter
m3
cubic meters
MMcfd
million (106) cubic feet per day
ppm TDS
parts per million total dissolved solids
psi/ft
pounds per square inch per foot of depth
Ro
vitrinite reflectance
Tcf
trillion (1012) cubic feet
TOC
total organic carbon
TRR
technically recoverable resources
XRD
x-ray diffraction
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7
8
[165832]
Figure 1: Shale Basins in Northeast Mexico, Showing Unconventional Exploration Blocks Scheduled for Rounds 1-4.
B a sic D a ta
P h y sica l E xte n t
R e servo ir
P ro p erties
R e so u rce
Basic Data
Physical Extent
Reservoir
Properties
6,700
3,500
Average
7,500
4,000 - 16,400
160
200
10,500
6,500 - 16,400
210
300
11,500
7,500 - 16,400
200
500
Low
Low
Assoc. Gas
Thermal Maturity (% Ro)
Clay Content
Gas Phase
446.4
7.8
0.9
Risked GIP (Tcf)
Risked Recoverable (Tcf)
111.6
74.4
21.7
GIP Concentration (Bcf/mi )
Wet Gas
5.0%
1.15%
5.0%
0.85%
Average TOC (wt. %)
5.0%
230.2
767.5
190.9
Dry Gas
Low
1.60%
3.0%
4.0%
100.2
501.0
131.9
Dry Gas
Low
1.50%
Pimienta
Jurassic
Marine
4.78
119.4
37.9
Oil
3.0%
0.85%
Low
Normal
23.6
118.1
69.1
Dry Gas
Low
2.50%
2.0%
Underpress.
11,500
9,800 - 13,100
240
800
9,500
Marine
U. Jurassic
4.7
58.5
18.6
Assoc. Gas
Low
0.85%
3.0%
Normal
5,500
3,300 - 8,500
200
500
9,000
Tampico
9.5
47.7
44.7
Wet Gas
Low
1.15%
3.0%
Normal
6,200
4,000 - 8,500
200
500
3,050
Marine
Jurassic
Pimienta
(26,900 mi )
0.74
18.5
17.3
Condensate
3.0%
1.15%
Low
Normal
9.0
45.0
83.0
Dry Gas
Low
1.40%
3.0%
Normal
8,000
7,000 - 9,000
200
500
1,550
0.51
12.7
36.4
Oil
3.0%
0.85%
Low
Normal
Maltrata
U. Cretaceous
Marine
2
Veracruz
(9,030 mi )
Tamaulipas
0.7
8.9
25.5
Assoc. Gas
Low
0.85%
3.0%
Normal
7,900
6,000 - 9,500
210
300
1,000
Marine
Jurassic
Pimienta
200
500
1,000
Marine
0.8
9.5
27.2
Assoc. Gas
Low
0.90%
3.0%
Normal
8,500
Normal
150
300
560
11,000
0.5
6.6
22.4
Assoc. Gas
Low/Medium
0.85%
3.0%
Normal
400
150
300
2.9
14.7
70.0
Dry Gas
Low/Medium
1.40%
3.0%
Normal
11,500
10,000 - 12,500
Marine
U. Cretaceous
Maltrata
2
Veracruz
13
275
Total
(9,030 mi )
9,800 - 12,000
0.28
6.9
23.5
Oil
3.0%
0.85%
Low/Medium
6,600 - 10,000
2
(2,810 mi )
Tuxpan
0.46
11.5
33.0
Oil
3.0%
0.90%
Low
Normal
1,000
560
500
300
200
150
6,600 - 10,000 9,800 - 12,000
8,500
11,000
Pimienta
Jurassic
Marine
L. - M. Cretaceous
1,000
300
210
6,000 - 9,500
7,900
Tamaulipas
L. - M. Cretaceous
Marine
Table 1: Estimated Shale Gas and Shale Oil Resources in Mexico
50.4
201.6
100.3
Dry Gas
Low
1.70%
Underpress.
9,000
5,000 - 12,500
400
500
9,500
Marine
Marine
6,700
M. - U. Cretaceous
U. Jurassic
2
2
Tuxpan
2
(2,810 mi )
Tampico
(26,900 mi )
9,000
3,050
500
500
200
200
3,300 - 8,500 4,000 - 8,500
5,500
6,200
Tithonian Shales Eagle Ford Shale Tithonian La Casita
Highly Overpress. Highly Overpress. Highly Overpress. Highly Overpress.
3,300 - 4,000
Interval
2
160
Net
Reservoir Pressure
Depth (ft)
Thickness (ft)
200
Organically Rich
10,000
Marine
600
Depositional Environment
2
Eagle Ford Shale
M. - U. Cretaceous
Geologic Age
Prospective Area (mi )
2
Sabinas
5.39
(35,700 mi )
0.95
Risked Recoverable (B bbl)
89.8
15.0
Condensate
5.0%
1.15%
Low
Highly Overpress.
10,000
200
160
4,000 - 16,400
7,500
Burgos
15.8
Risked OIP (B bbl)
2
2
(24,200 mi )
Oil
43.9
5.0%
0.85%
Low
Highly Overpress.
600
200
160
3,300 - 4,000
3,500
OIP Concentration (MMbbl/mi )
2
Burgos
(24,200 mi )
Eagle Ford Shale
M. - U. Cretaceous
Marine
Oil Phase
Average TOC (wt. %)
Thermal Maturity (% Ro)
Clay Content
Reservoir Pressure
Prospective Area (mi )
Organically Rich
Thickness (ft)
Net
Interval
Depth (ft)
Average
2
Shale Formation
Geologic Age
Depositional Environment
Shale Formation
Basin/Gross Area
Resource
Basin/Gross Area
545
2,233
Total
[177139]
9
10
[177139]
Figure 2: The Shale Trend in Northeast Mexico is Significantly Larger than the
South Texas Eagle Ford Shale Play; Data Locations for Study are Indicated
[177139]
11
Figure 3: Stratigraphy of the Burgos Basin Showing U. Cretaceous Agua Nueva (Eagle Ford) Fm and U. Jurassic Pimienta (La Casita) Fm.
Note Listric Normal Faults Cutting Tertiary Section Flatten into Detachment Surface and Don’t Affect Mesozoic Section.
Figure 4: West-East Cross Section of Burgos Basin Showing Tertiary Detachment Faults Underlain by Less Deformed Mesozoic Shales
12
[177139]
Figure 5: Unconventional Oil and Gas Exploration Blocks Planned for the Tampico-Misantla Basin (CNH)
Figure 6: Stratigraphy of Source Rock Shale Targets in the Tampico-Misantla Basin Include the U. Cretaceous
[177139]
13
U JURASSIC
PIMIENTA FM
Figure 7: Seismic Time Section Showing Generally Simple Structure of the U. Jurassic Pimienta Fm in the Tampico-Misantla Basin