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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. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

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 multi-

client study, the authors have greatly expanded the geologic

and reservoir data set we developed during an earlier scoping-

level 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, Burro-

Picachos, 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

SPE 177139

Evaluation of Mexico’s Shale Oil and Gas Potential

Scott H. Stevens, SPE, and Keith D. Moodhe, SPE

Advanced Resources International, Inc.

2 [177139]

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 low-

cost 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.

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).

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. Translate nearly 500 mostly Spanish language technical

articles and develop a GIS data base of geologic and

reservoir properties.

2. Characterize the geologic and reservoir properties of each

shale basin and formation.

3. Establish the areal extent of the shale gas and shale oil

formations.

4. Define and characterize the prospective area for each

shale gas and shale oil formation based on thickness,

depth, TOC, and thermal maturity.

5. 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.

6. 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] 3

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 Haynesville-

Bossier 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.

Burgos Basin CNH plans to offer 124 blocks totaling 14,406 km

2 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.

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

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.

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 organic-

rich 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).

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

4 [177139]

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).

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 Tampico-

Misantla 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] 5

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

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 two-

thirds 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 salt-

withdrawal 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 3,330-

3,390 m.

6 [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. 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.

3. 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.

4. 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%).

5. 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 (10

9) 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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8 [165832]

Figure 1: Shale Basins in Northeast Mexico, Showing Unconventional Exploration Blocks Scheduled for Rounds 1-4.

[177139] 9

Tith

onia

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10,0

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mal

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0.90

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Low

Low

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Low

Low

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Low

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/Med

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954

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Tuxp

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(2,8

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Dep

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Env

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(9,0

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Shal

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rmat

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hale

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trata

Mar

ine

U. C

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Bur

gos

(24,

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mi2 )

Sabi

nas

(35,

700

mi2 )

Tam

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(26,

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mi2 )

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Reservoir Properties

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(wt.

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Physical Extent

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th (f

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logi

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Are

a

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Gas

Pha

se

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Con

cent

ratio

n (B

cf/m

i2 )

Ris

ked

GIP

(Tcf

)

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ked

Rec

over

able

(Tcf

)

Vera

cru

z

(9,0

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aulip

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Org

an

ically

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h200

200

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Net

160

160

200

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210

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150

Inte

rval

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4,0

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ress

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Norm

al

5.0

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0.8

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5%

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%0.8

5%0.9

0%

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Low

Low

Low

Low

Low

Low

Low

/Med

ium

Oil

Conden

sate

Oil

Conde

nsa

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ilO

il

43.9

15.0

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36.4

33.

023.5

To

tal

15.8

89.8

119.4

18.5

12.7

11.

56.

92

75

0.9

55.3

94.

780.7

40.

51

0.4

60.2

81

3

Tu

xpan

(2,8

10 m

i2)

Sh

ale

Fo

rmatio

nE

ag

le F

ord

Sh

ale

Pim

ien

ta

Geo

log

ic A

ge

M.

- U

. C

reta

ceous

Jura

ssic

Dep

osi

tio

nal E

nvir

on

men

tM

arin

eM

arin

ePhysical Extent

Pro

sp

ectiv

e A

rea (

mi2

)

Th

ickn

ess (

ft)

Dep

th (

ft)

Basic Data

Basin

/Gro

ss A

rea

Bu

rgo

s

(24,2

00 m

i2)

Tam

pic

o

(26,9

00 m

i2)

Resource

Oil

Ph

ase

OIP

Co

ncen

tratio

n (

MM

bb

l/m

i2)

Ris

ked

OIP

(B

bb

l)

Ris

ked

Reco

vera

ble

(B

bb

l)

Reservoir

Properties

Reser

vo

ir P

ressu

re

Aver

age

TO

C (

wt.

%)

Th

erm

al M

atu

rity

(%

Ro

)

Cla

y C

on

ten

t

Tab

le 1

: E

sti

mate

d S

hale

Gas a

nd

Sh

ale

Oil R

eso

urc

es i

n M

exic

o

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