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Basin Research. 2021;00:1–29.
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wileyonlinelibrary.com/journal/bre
Received: 29 March 2021
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Revised: 8 July 2021
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Accepted: 25 July 2021
DOI: 10.1111/bre.12599
RESEARCH ARTICLE
Integrated source rock evaluation along the maturation
gradient.Application to the Vaca Muerta Formation,
NeuquénBasin ofArgentina
J. B.Spacapan1
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M.Comerio1
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I.Brisson2
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E.Rocha3
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M.Cipollone1
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J.C.Hidalgo4
© 2021 International Association of Sedimentologists and European Association of Geoscientists and Engineers and John Wiley & Sons Ltd
1YPF- Tecnología S.A. (Y- TEC- CONICET),
Buenos Aires, Argentina
2YPF S.A., Buenos Aires, Argentina
3Pluspetrol S.A., Buenos Aires, Argentina
4Schulmberger GmbH, Aachen, Germany
Correspondence
J. B. Spacapan, YPF- Tecnología S.A.
(Y- TEC- CONICET), Av. del Petróleo
Argentino (RP10) S/N, Berisso (CP 1923),
Buenos Aires, Argentina.
Email: juan.b.spacapan@ypftecnologia.com
Abstract
The Vaca Muerta Formation (Tithonian– early Valanginian) is the main source rock
in the Neuquén Basin and the most important unconventional shale resource in South
America. In the present study, organic geochemistry, electron microscopy and basin
and petroleum system modelling (BPSM) were combined to evaluate source rock
properties and related processes along a transect from the early oil (east) to the dry
gas (west) window. The unit is characterized by high present- day (1%– 8% average)
and original (2%– 16% average) total organic carbon contents, which increase to-
wards the base of the unit and basinal (west) settings. Scanning electron micros-
copy shows that organic pores derived from the transformation of type II kerogen.
Isolated bubble pores are typical of the oil window, whereas bubble and densely
distributed spongy pores occur in the gas stage, indicating that the maturity gradient
exerts strong control on organic porosity. Organic geochemistry, pressure and poros-
ity data were incorporated into a 2D basin petroleum system model that includes the
sequential restoration of tectonic events and calculation of compaction trends, kero-
gen transformation, hydrocarbon generation and estimation of pore pressure through
geologic time. The W– E regional model extends from the Agrio Fold and Thrust
Belts to the basin border and allows us to evaluate the relationship between ther-
mal maturity and timing of hydrocarbon generation from highly deformed (west) to
undeformed (east) regions. Modelling results show a clear decrease in maturity and
organic matter (OM) transformation towards the eastern basin margin. Maximum
hydrocarbon generation occurred in the inner sectors of the belt, at ca. 120Ma; long
before the first Andean compression phase, which started during the Late Cretaceous
(ca. 70Ma). Miocene compression (15– 7Ma) promoted tectonic uplift of the inner
and outer sectors of the belt associated with a reduction in thermal stress and kerogen
cracking, as well as massive loss of retained fluids and a decrease in pore pressure.
The OM transformation impacted (a) the magnitude of effective porosity associated
with organic porosity development, and (b) the magnitude and distribution of pore
pressure within the unit controlled by hydrocarbon generation and compaction dis-
equilibrium. BPSM shows a progressive increase in effective porosity from the top
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SPACAPAN et Al.
1
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INTRODUCTION
Recognition of source rocks for oil and gas is the most criti-
cal risk element in petroleum exploration activities (Curiale
& Curtis,2016; Tissot & Welte,1984). Source rock evalua-
tion consists of assessing hydrocarbon generating potential,
organic matter (OM) type, hydrocarbons that might be gen-
erated and thermal maturity (Dembicki, 2009; Katz, 1995;
Tissot & Welte, 1984). Unconventional plays are usually
analysed in terms of average total organic carbon (TOC)
content, mineralogy, porosity, permeability, geomechanical
properties and pore pressure (Ejofodomi etal., 2011; Hazra
etal.,2019; Passey etal.,2010; Peters etal.,2017; Wang &
Gale,2009). At basin- scale, however, studies that focus on
the assessment and quantification of these parameters are still
scarce (Romero- Sarmiento etal.,2013).
Analytical techniques and numerical models including
basin and petroleum system modelling (BPSM) packages
are widely used tools to evaluate conventional and uncon-
ventional resources (Al- Hajeri et al., 2009; Hantschel &
Kauerauf, 2009; McCarthy etal., 2011; Mei etal., 2021;
Peters et al., 2017; Romero- Sarmiento et al., 2013). The
analysis of unconventional resources based on estimation
of burial temperature history and variations in maturity
gradients allows simulation of a wide variety of geological
processes through time, such as: (a) compaction trends, (b)
transformation of OM by thermal maturity, (c) generation–
retention– expulsion of hydrocarbons, (d) hydrocarbon
composition, (e) overpressure and fracturing mechanisms
and (f) preservation– development of porosity (Al- Hajeri
et al., 2009; Burgreen- Chan et al., 2015; Grohmann
etal.,2021; Hantschel & Kauerauf,2009; Mei etal.,2021;
Peters etal., 2017, 2018; Romero- Sarmiento et al., 2013;
Tissot & Welte, 1984). Recent studies integrate BPSM
tools with laboratory analysis to perform semi- quantitative
descriptions of processes that control hydrocarbon gener-
ation, expulsion and retention capacity (Mei etal., 2021;
Romero- Sarmiento etal.,2013, 2014). For instance, BPSM
of the Mississippian Barnett Shale (Fort Worth Basin,
USA) provided a quantitative means to estimate the total
volume of generated hydrocarbons and the distribution of
organic porosity at basin scale assuming that overpressure
accompanied by diagenetic precipitation of cements in-
hibited the effects of compaction (Romero- Sarmiento
etal.,2013). In that unit, model results and petrographic and
analytical studies indicated that organic pores are formed
by thermal stress and represent the main sites for hydrocar-
bon trapping (Loucks etal.,2009; Reed & Loucks,2015;
Romero- Sarmiento etal.,2014).
The Meso– Cenozoic Neuquén Basin in northern Patagonia
is one of the most important hydrocarbon basins in South
America (Legarreta etal.,2008; Uliana & Legarreta,1993;
Urien & Zambrano,1994; Veiga etal.,2020) and, in recent
years, it has become well known for its unconventional oil
and gas resources (e.g. Badessich etal., 2016; Legarreta &
Villar,2011; Sagasti et al., 2014). The basin has three ma-
rine organic- rich source rocks known as the Los Molles,
Vaca Muerta and Agrio formations (Fms). In particular, the
Vaca Muerta Fm (Tithonian– lower Valanginian) constitutes
a world- class source rock and an unconventional shale re-
source for both oil and gas (Brisson etal., 2020; Legarreta
& Uliana,1991; Legarreta etal., 2008; Veiga etal., 2020).
In recent years, a great number of sedimentological, palae-
ontological, geochemical and stratigraphic works have been
to the base and towards the west region related to the original organic carbon content
and maturity increasing along the same trend. Overpressure intervals with high or-
ganic carbon contents are the most prone to develop organic pores. The latter repre-
sent favourable sites for the storage of hydrocarbons in the Vaca Muerta Formation.
KEYWORDS
hydrocarbon generation, modelling, organic porosity, pore pressure, thermal maturation, Vaca
Muerta
Highlights
• Evaluation of the Vaca Muerta Fm based on or-
ganic geochemistry, petrography and petroleum
system modelling.
• Timing of hydrocarbon generation linked to tec-
tonic events and burial depth.
• TOC content increases towards the base of the
unit and basinal (west) settings.
• Organic pores developed from the early oil to the
dry gas window derived from the transformation
of type II kerogen.
• Hydrocarbon generation and compaction disequi-
librium are the main mechanisms that generate
pore pressure.
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SPACAPAN et Al.
reported for the unit (see Section 2). However, regional
basin- scale modelling integrated with scanning electron mi-
croscopy (SEM), organic geochemistry and pore pressure
measures has not been published.
In order to evaluate the source rock potential of the Vaca
Muerta Fm (VMFm) through geological time, a transect in the
central part of the Neuquén Basin (37° S) was analysed using
a regional 2D petroleum system model that extends from the
Agrio Fold and Thrust Belt in the west to the basin border in
the east (Figure1). BPSM involves sequential restoration of
the deformation, calibrated by published thermochronolog-
ical dating, which allowed us to integrate regional tectonic
events and processes that controlled the thermal maturity and
generation and expulsion of hydrocarbons. In addition, the
present work incorporated key parameters, such as original
total organic carbon (TOC0) content, porosity and pore pres-
sure conditions, in a basin simulator to test the magnitude
and distribution of organic porosity (Øorg) and evaluate the
causes of overpressure in the VMFm through the geological
evolution of the Neuquén Basin. The characterization of such
processes provides a partial evaluation of the unconventional
potential of the unit. Such characterization, integrated with
geomechanical properties, has a direct impact on the strate-
gies of hydraulic fracturing (Peters etal.,2017).
Thus, the aims of the present article are to: (a) establish
the original and present- day TOC distribution and transfor-
mation gradients for the VMFm at different basin positions
(from dry gas to the early oil window) using a robust Rock-
Eval® pyrolysis data set, (b) characterize the origin and types
of organic pores (Øorg) as function of thermal maturation via
high- resolution 2D- SEM, (c) obtain a semi- quantitative eval-
uation of the unit using 2D regional BPSM to test the timing
of hydrocarbon generation– expulsion from the Fold Belt in
the west to the basin border in the east and (d) test kerogen
transformation into hydrocarbons, porosity development and
the magnitude of pore pressure to evaluate the unconven-
tional potential of the Vaca Muerta source rock.
2
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GEOLOGICAL SETTING
The Meso- Cenozoic Neuquén Basin (Figure1), located in the
Northern Patagonian Andes, extends between 32° and 40° S
latitude, covering an area of 120,000km2 and includes parts
FIGURE 1 The Neuquén Basin of west-
central Argentina. Satellite image showing
the internal reference areas for the VMFm
(Brisson etal.,2020) and the positions of
analysed wells within the Agrio (Agrio-
Section) fold and thrust belt
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SPACAPAN et Al.
of the Mendoza, Neuquén, Rio Negro and La Pampa prov-
inces, Argentina (Howell etal.,2005; Vergani etal.,1995).
Three stages of basin infill are summarized in Figure2. The
rift basin stage was characterized by several NW– SE rift
depocentres formed during the Late Triassic– Early Jurassic
with continental and volcanic deposits of the Precuyo Group
(Franzese & Spalletti, 2001). A long thermal subsidence,
interrupted by localized tectonic events, characterizes the
retro- arc basin stage developed from the Early Jurassic to
Early Cretaceous with thick marine and continental succes-
sions composed of carbonate, siliciclastic and evaporite fa-
cies (Howell etal.,2005; Legarreta & Uliana,1991; Vergani
et al., 1995). The lithostratigraphic framework includes
the Cuyo, Lotena, Mendoza and Bajada del Agrio Groups
(Groeber, 1946; Leanza, 2003; Stipanicic et al., 1968;
Weaver,1931), where marine organic- rich source rocks re-
lated to long- term Palaeo- Pacific transgressions are recorded:
Los Molles, Vaca Muerta and Agrio Fms (Figure2). Finally,
the foreland basin stage in Late Cretaceous– Palaeocene
time was linked to contractional conditions and associated
with the Andean uplift (Horton, 2018). Sedimentation was
dominated by synorogenic red bed successions (Neuquén
Group) and the first shallow marine units (Malargüe Group)
from the Atlantic Ocean (Aguirre- Urreta etal.,2011; Tunik
et al., 2010). This stage was characterized by progressive
growth of S– N fold and thrust belts (e.g. Agrio, Chos Malal
and Malargüe) and reactivation of older extensional faults
(Horton etal.,2016; Rojas Vera etal.,2015).
The VMFm, the focus of this study, represents a widespread
marine transgression during the retro- arc stage, mainly com-
posed of organic- rich black shales, marls and limestones reach-
ing 800m thickness (Legarreta & Uliana,1991; Weaver,1931).
Based on ammonoid biozones, partially calibrated through
high- precision U- Pb ages, the unit ranged from Tithonian–
early Valanginian (e.g. Aguirre- Urreta et al., 2007; Naipauer
et al., 2020; Vennari et al., 2014). Along the S– N fold and
thrust belts, basinal- to- middle ramp deposits are well exposed
and have been studied by detail facies analysis (e.g. Kietzmann
etal.,2016; Otharán etal.,2020; Scasso etal.,2005; Spalletti
et al., 2000). In the subsurface of the Neuquén Embayment,
well logs, cores and seismic data provided additional infor-
mation on the unit (e.g. Desjardins et al., 2016; Dominguez
& Di Benedetto, 2019; Legarreta & Uliana, 1991; Mitchum
& Uliana,1985; Sagasti etal.,2014). Basin- scale stratigraphic
architecture shows that the unit comprises three to five pro-
gradational sequences with organic- rich transgressive inter-
vals composed of siliciclastic and carbonate- rich shales that
grade upward into highstands dominated by organic- lean
marls (Capelli etal.,2021; Dominguez etal.,2016; Kietzmann
etal.,2016; Legarreta & Villar,2015).
2.1
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Source rocks: An overview
Many studies have analysed the regional characteristics of the
petroleum systems in the Neuquén Basin (Boll etal., 2014;
Cruz et al., 1996, 2002; Karg & Littke, 2020; Kozlowski
FIGURE 2 The classic stratigraphic chart for the Neuquén Basin
(modified from Howell etal.,2005). The VMFm (Mendoza Group)
represents the main source rock/unconventional target in the basin
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SPACAPAN et Al.
etal.,1998; Legarreta etal.,2008; Mei etal.,2021; Rocha
etal.,2018; Uliana & Legarreta,1993; Vergani etal.,2011).
The three marine source units are the Los Molles, Vaca
Muerta and Agrio Fms, which differ in terms of organic
richness, OM type, maturity and distribution throughout
the basin. The oldest source rock was deposited during the
Pleinsbachian– Callovian and covers, in the same way as the
VMFm, almost the entire basin. The unit has present- day
TOC ranging from 1% to 5% with kerogen types II (algal/
amorphous macerals) and III (palynomorphs/phytoclasts
macerals), showing a transition from immature to overma-
ture stages (Jorgensen etal.,2013; Legarreta & Villar,2011;
Martínez etal.,2008). The thickness increases from approxi-
mately 500– 900 m following the main NW– SE axis of the
basin. However, important differences in thickness are re-
lated to inherited topography of the underlying rift depocent-
ers (Legarreta & Villar,2011; Olivera etal.,2020). Based on
TOC contents, the lowermost part (ca. 200m thick) shows
the most suitable characteristics for a possible unconven-
tional target (Jorgensen etal.,2013).
Based on organic geochemistry and petrological stud-
ies, the VMFm exhibits mainly amorphous (liptinitic mac-
erals) type II kerogen with TOC content between 3% and
8% (peak values of 12%– 20%) suitable for producing oil or
gas condensate, depending on position in the basin (Brisson
etal.,2020; Karg & Littke,2020; Legarreta & Villar,2011;
Sylwan,2014). The hydrocarbon yield expressed as original
hydrogen index (HI0) averages 680mgHC/gTOC based on the
analysis of immature samples (Brisson et al., 2020; Veiga
etal.,2020). This is representative of the organic- rich inter-
vals (30– 450 m thick) considered to be the unconventional
targets of the unit (Dominguez etal.,2016). Different patterns
of organic richness, hydrocarbon source quality, distribution
of free hydrocarbons and thermal maturity allowed Brisson
etal.(2020) to distinguish six reference areas for the VMFm
(Figure1). Moderate depth of 3,000m and overpressure con-
ditions also make the unit a prime target for drilling opera-
tions and stimulation treatments which favour development
and commercialization of this play (Badessich etal., 2016;
Veiga etal.,2020).
The Agrio Fm includes two organic- rich intervals of
late Valanginian and late Hauterivian age (e.g. Comerio
etal.,2018; Pazos etal.,2020; Uliana & Legarreta, 1993).
TOC content ranges from 1% to 5% with peak values of up to
16%, including type II and III kerogens (Comerio etal.,2018,
2020; Legarreta & Villar, 2012), with average measured
HI0 of 600 mgHC/gTOC for the type II intervals (Spacapan
etal.,2018). Carbonate- rich shales are more enriched in type
II kerogen than the siliciclastic shales, which are dominated
by type III kerogen (Comerio etal., 2018). Maturity maps
indicate that both intervals range in maturity from the oil
window to the gas window (Cruz etal., 1996; Legarreta &
Villar, 2012), reaching dry gas and overmature stages in areas
where intrusions are present (Spacapan etal., 2018, 2020).
Compared with VMFm, the Agrio Fm shows lower amounts
of OM, lower effective thickness (<100 m thick), and re-
duced regional distribution.
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METHODOLOGY
The VMFm was analysed using a W– E section (Figure 1)
along the Agrio fold and thrust belt (Agrio FTB). It includes
information from 27 wells distributed throughout the section
and available surface and seismic data. The present study
shows organic geochemistry results and scanning electron
microscopy images from cuttings and core samples from
Well A (2,312– 3,010m), Well B (2,610– 2,790m) and Well
C (2,270– 2,430 m) on the Dorso de Los Chihuidos– NE
Platform (Figure 1). We followed the stratigraphic scheme
of Legarreta and Villar (2015) that subdivided the VMFm
in lower, middle and upper VM to describe and interpret the
results.
3.1
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Organic geochemistry
A total of 220 cuttings and core samples were analysed for
present- day total organic carbon (TOC wt%) and Rock- Eval®
programmed pyrolysis following standard procedures from
the IFP Energies Nouvelles (Espitalié etal.,1986). Samples
were solvent extracted to remove oil mud residues. The use of
oil- based mud restricts the thorough evaluation of the unit be-
cause a quantitative measurement of free hydrocarbons (e.g.
pyrolysis S1 peak, mgHC/gROCK) is impossible, and many
ratios used to interpret and evaluate the source beds cannot
be employed in the analysis (Brisson etal.,2020). There are
many equations used to calculate the original TOC (TOC0) in
source rocks (e.g. Brisson etal.,2020; Chen & Jiang,2016;
Modica & Lapierre,2012; Peters etal.,2017). This study con-
siders the equation specific for the VMFm, which was calcu-
lated based on an extensive pyrolysis data from cores and
cutting samples from nearly 900 wells (see details in Brisson
et al., 2020). These authors indicated a homogenous char-
acter of the type II kerogen and obtained an average of HI0
of 680mgHC/gTOC based on measures of immature samples
(Brisson et al., 2020). The pyrolysis S2 (mgHC/gROCK) and
S3 (
mgCO2∕gTOC
) peaks allowed us to corroborate kerogen
types and thermal maturity based on the Tmax (Peters,1986).
Values of vitrinite reflectance (%Ro) were measured for Well
A and Well B; however, for Well C (early oil window), the
theoretical %Ro was calculated from Tmax values (Brisson
etal., 2020) due to the lack of vitrinite particles. The equa-
tion proposed by Brisson etal.(2020) is valid mainly for Tmax
between 410 and 470℃ and was derived from a strong data-
set. The usage of the equation in other source rocks should
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SPACAPAN et Al.
be tested first due to the relationship between Tmax and %Ro
appears to be kerogen- type dependent (Katz & Lin,2021). In
addition, measured %Ro data from proximal wells and ma-
turity maps were also considered to corroborate the maturity
trend of Well C. Transformation ratio (TR) was calculated
following the methodology of Waples and Tobey (2015),
which expresses the converted mass fraction of the initial re-
actant, that is, the ratio of petroleum formed from kerogen
in source rock to the total amount of petroleum that could
be formed from that kerogen (Peters etal., 2017; Tissot &
Welte,1984).
3.2
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Scanning electron microscopy analysis
To examine microtextural features and evaluate the ther-
mal transformation of OM, 22 core samples were prepared
on thin sections normal to bedding planes, mechanically
polished, ion- milled and analysed by field emission scan-
ning electronic microscope (FE- SEM) at the Laboratorio
de Analítica in YPF- Tecnología (Y- TEC) following in-
ternal procedures. Samples were coated with carbon and
studied at different magnifications (from 150× to up to
200,000×) under secondary electron (SE) and backscat-
tered diffraction (BSD) modes. Elemental composition
of mineral phases was determined by energy- dispersive
X- ray spectroscopy (EDS) microanalysis. Pore- size dis-
tribution was measured at different magnifications using
the JMicrovision© (Roduit,2008) program and consider-
ing OM pores as spherical to oval with bubble and spongy
morphologies (Ko etal.,2017; Löhr etal.,2015; Milliken
etal.,2013; Pommer & Milliken,2015). FE- SEM resolu-
tion is in the order of 10nm; and consequently, macropores
(>50nm) are well defined. However, part of the mesopores
(2– 50 nm) and micropores (<2 nm) are not measurable
(pore sizes as defined by Rouquerol etal.,1994). Elongate
pores with crack- like morphology were not considered
because of possible generation during sample preparation
(Katz & Arango,2018; Löhr etal.,2015; Schieber,2013).
4
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PETROLEUM SYSTEM
MODELLING
Schlumberger 2- D PetroMod® software allows full integra-
tion of tectonic events, structural restoration, facies variation
and source rock maturity through time. The software was
used for sequential restoration of the Agrio regional cross
section (Figures1 and 3). To calibrate the BPSM and evalu-
ate the history of hydrocarbon generation for the analysed
source rocks, organic geochemistry and %Ro data from the
VM, Los Molles and Agrio Fms were compiled (YPF data-
base). The age, erosion thickness, lithologies, unit thickness
and petroleum system elements for Well A and Well C are
included in Supplementary Material 1.
4.1
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Modelling input
One- dimensional (1- D) and 2D BPSMs were performed using
PetroMod® Teclink® software (Hantschel & Kauerauf,2009),
including coupled structural restoration and backstripping tools.
This technique integrates the structural and the petroleum sys-
tems model, which is essential for simulating hydrocarbon
generation, migration and accumulation in tectonically com-
plex areas. Software calculations in tectonically complex areas
are analysed in detail by Hantschel and Kauerauf (2009) and
Burgreen- Chan et al.(2015). PetroMod® software provides a
database to estimate the surface– water interface temperature
(SWIT). The upper boundary condition for temperature calcu-
lations is determined by the sediment– water surface (onshore)
temperatures (Hantschel & Kauerauf,2009; Peters etal.,2017).
In the model, SWIT data were corrected for present and past
water depth (Supplementary Material 2). It uses a global re-
construction of the palaeo- mean surface or air temperatures
and palaeobathymetry to estimate SWIT for a given latitude
(Wygrala,1989). The most important input for predicting hy-
drocarbon generation is the evolution of thermal heat flow
through geologic time, which together with the burial history,
controls the evolution of temperature and chemical reactions
during the generation, migration, accumulation and preservation
of petroleum. Thermal history of the Agrio section was recon-
structed assuming a constant heat flow of 60mW/m2 through
time (Supplementary Material 2). Heat flow was calibrated
with %Ro data and later cross- checked with Horner- corrected
bottom- hole temperature (Deming,1989). Similar constant heat
flow of 60 mW/m2 was assumed by Lampe et al.(2006) for
the Agrio FTB. The resulting temperature fields provided theo-
retical values for temperature, %Ro, TOC, Øorg and TR, and
were used to calculate the amount of cracked kerogen. Source
rock maturation assessed using the Easy %Ro equation from
Sweeney and Burnham (1990). Lithological properties were
based on Athy's compaction law (Athy,1930) and the multipoint
model (Hantschel & Kauerauf,2009). Athy's law is a traditional
porosity versus depth curve which predicts hydrostatic pressure
based on deposition of the entire column with various litholo-
gies. Additionally, the PetroMod® software allowed to simulate
effective and secondary porosity. Effective porosity is the pore
volume in a rock that contributes to the permeability and does
not include isolated vuggy porosity or water that is bound to
clay minerals (Hantschel & Kauerauf,2009). Secondary poros-
ity in a source rock is the additional porosity that can be gener-
ated by mineral transformations (inorganic secondary porosity)
or transformation of OM into hydrocarbons (organic secondary
porosity). PetroMod® software calculates the Øorg as the cumu-
lative amount of porosity generated during OM transformation.
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SPACAPAN et Al.
In addition, it predicts the proportion of gas adsorbed within
OM pores or on mineral surfaces versus free gas in pore spaces
or natural fractures (Peters etal., 2017). Furthermore, the evo-
lution of Øorg and its relationship with the burial history were
analysed through the effective porosity curve. Pore pressure pre-
diction is important for executing a safe drilling strategy and for
accurate production modelling (Couzens- Schultz et al.,2013).
Fluid pressure modelling can be used to improve pore pressure
prediction and reduce the drilling risk posed by unanticipated
overpressures (Peters etal.,2017). Diagnostic fracture injection
testing (DFIT) data obtained from the YPF database were used
to calibrate pressure conditions in the analysed wells.
4.2
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The Agrio Fold and Thrust Belt (FTB):
Balanced structural section
The Agrio FTB extends from the 38°50′ to 37°35′ S and is
characterized by two sectors with different structural styles
(Vergani etal., 1995; Zamora Valcarce et al.,2007; Zapata
& Folguera,2005). To the west, the inner sector shows base-
ment deformation and tectonic inversion of previous exten-
sional (Triassic) structures (Ramos et al., 2011; Rojas Vera
etal., 2010). The outer sector is dominated by thin- skinned
deformation showing basal detachments within Jurassic and
Lower Cretaceous evaporites and marine shales with a gen-
eral deformation sense to the east and several west- verging
backthrusts (Rojas Vera et al., 2015; Zamora Valcarce
etal.,2011). To the east, the Dorso de Los Chihuidos (DdLC)
is defined by an antiformal structure interpreted as the result
of tectonic inversion of basement involved normal faults
(Ramos et al., 2011). Such differences control the distribu-
tion of outcrops in the central part of the Neuquén Basin with
Jurassic sedimentary units (Cuyo and Lotena Groups) mainly
exposed in the inner sector and Upper Jurassic– Cretaceous
units (Mendoza, Bajada del Agrio and Neuquén Groups) to
the east in the outer sector (Leanza & Hugo,2001; Rojas Vera
etal., 2015; Zamora Valcarce et al.,2007, 2011). Balanced
structural section published by Rocha etal.(2018) was used in
this study, which extends from the Agrio FTB (inner and outer
FIGURE 3 Tectonic evolution for
the Agrio FTB cross section from the Late
Cretaceous to present day (see also Rocha
etal.,2018)
8
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SPACAPAN et Al.
sectors), the DdlC (Well A), external flank of the DdLC (Well
B) to the NE Platform (Well C) (see location in Figures1 and
3). This section was sequentially restored with the aim to rep-
resent the tectonical evolution based on available information.
Initial exhumation occurred in the Late Cretaceous (Rojas
Vera etal.,2015; Tunik etal.,2010), with two peaks of reacti-
vation in the Oligocene– Miocene and middle Miocene based
on apatite fission tracks (Rocha etal.,2018). The Agrio FTB
represents the most important depocentre during the Mesozoic
sedimentation and includes the embayment sector where the
VMFm reached highest maturity (Brisson etal., 2020). The
Mesozoic succession thins northward in the domain of Chos
Malal FTB, a sector known as Chihuido– Lomita as well as
to the basin margin (NE platform) characterized by shallower
burial and lower maturity levels.
5
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RESULTS
5.1
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Vaca Muerta organic geochemistry
The results from programmed pyrolysis are summarized in
Table1. The TOC content in all analysed wells is high with
mean values that range from 2.38% (Well A), 5% (Well B), to
3.21% (Well C) in the Agrio section (Figure4). The lower and
middle VM contain the highest TOC contents, with highest
values towards basinal (west) settings: 3.60% and 3.76% (Well
A), 8% and 4.83% (Well B) and 3.36% and 3.05% (Well C).
Well C shows Rock Eval®Tmax values that range from 429
to 443℃ (mean: 435℃) and calculated %Ro between 0.65
and 0.90 (mean value: 0.80), which is consistent with the
early oil window (Figure5a). %Ro measures indicate a range
from 1.60– 1.65 (wet gas, Well B) to 2.10– 2.33 (dry gas, Well
A) (Figure4). The S2 peak that coincides with the remaining
potential of hydrocarbon generation decreases towards high-
maturity zones ranging from 15.44mgHC/gROCK (1.34– 43.15
minimum and maximum values) in the early oil (Well C) to
0.68mgHC/gRO CK (0.21– 1.49) in the dry gas zone (Well A).
On the contrary, Tmax displays increased thermal maturity,
reaching mean values of 475℃ (460– 514℃ minimum and
maximum values) in the wet gas window (Well B). Tmax can-
not be measured in the dry gas window (Well A) due to very
low values of S2 indicating that hydrocarbon- generative ca-
pacity of the OM has been exhausted.
The mean values of HI also decrease as maturity increases
from 470mgHC/gTOC (238– 654 minimum and maximum val-
ues) in the early oil (Well C) to 41 mgHC/gTOC (6– 107) in
the dry gas window (Well A) for the Agrio section (Table1).
The oil- prone VMFm throughout the basin is supported by
the presence of bacterial/algae OM (Brisson et al., 2020;
Petersen etal., 2020) and is consistent with low values of
oxygen index (OI) in all analysed wells (mean values between
8 and 47
mgCO2∕gTOC
). However, the uppermost levels of the
upper VM at Well A record an increase in OI (Figure4). The
pseudo- van Krevelen diagram (hydrogen vs. oxygen index,
Figure5b) shows that most samples lie close to the HI- axis
and reflect increasing maturity of the analysed wells with HI
depletion from the early oil to dry gas windows. This explains
the type II kerogen identified in samples from the early- to-
peak oil window. More mature samples in the wet and dry gas
windows plot near the origin of the diagram.
The transformation ratio (TR = [HI0 − HIsample]/
HI0 × 100%, sensu Waples & Tobey,2015) increases with
maturity, showing mean values from 30% (3%– 64%) at Well
C, 97% (94%– 98%) at Well B to 93% (84%– 99%) at Well
A. The equation presented by Brisson etal.(2020) was used
to restore the original total organic carbon TOC0 content
(Table1). For the lower VM, average TOC0 contents range
from: 8.24% (1.10%– 15.50%) at Well A, 18.60% (7.29–
27.41) at Well B to 6.86% (0.56– 14.35) at Well C (Table1).
5.2
|
OM and its related pores under SEM
5.2.1
|
Oil window
Well C samples correspond to the early oil window and with re-
spect to OM two forms are documented (Figure6). Some samples
exhibit filament- like OM that defines a discontinuous wavy-
parallel lamination that is disposed between silt- size detrital
grains, calcareous debris and faecal pellets mainly composed of
calcareous coccoliths (Figure6a– c). These OM domains likely
represent relicts of marine type II kerogen compressed by me-
chanical compaction between rigid detrital grains. In such lev-
els, the OM does not show evidence of pores at SEM resolution.
Conversely, other samples show OM that is intimately bound to
the inorganic matrix composed of coccolith debris, illite/mica
phyllosilicates and quartz, plagioclase and carbonate fragments
(Figure6d,e). The OM mostly fills intergranular pore space and
lacks the filament- like structure. It occupies the interstices be-
tween those detrital components and within primary pores such
as those related to pressure shadows (Schieber,2010), and it
fills microfossil- related voids (Figure6f). Isolated, bubble pores
of variable size (40– 1,000nm, mean 200nm) are documented.
OM of detrital (terrigenous) origin occurs in few samples and in
minor amounts, which is consistent with little land- derived OM
in the VMFm (Brisson etal.,2020; Małachowska etal.,2019;
Petersen et al., 2020). Nonporous OM of terrigenous origin
(e.g. vitrinite and inertinite) is present as rigid grains with
discrete arcuate margins (Milliken et al., 2013; Pommer &
Milliken,2015). Phyllosilicate framework pores with triangu-
lar to elongated geometries (200– 1,400nm wide) are less com-
mon. Microfractures (6– 15µm thick by more than 600µm in
length, Figure 6f) oriented subparallel to bedding planes and
partially filled with secondary products (solid bitumen) are also
documented.
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TABLE 1 Summary with organic geochemistry results for the lower, middle and upper informal units of the Vaca Muerta Formation in the Agrio section (general includes all samples of the well)
Vaca
Muerta
units
TOC
%
S1
mg/g
S2
mg/g
S3
mg/g
Tmax
°C
HI=S2/TOC
mg/g
OI=S3/
TOC
mg/g
TR=HI0−HI/
HI0 %
Waples and
Tobey (2015)
TOC0 %
Brisson
etal.(2020)
Well C
(early
oil)
Middle 3.05 (0.44– 7.99) 0.15 (0.11– 0.35) 15.62 (1.34– 43.15) 0.52 (0.28– 1.06) 434 (429– 441) 497 (255– 654) 25 (4– 120) 26 (3– 62) 6.06 (0.42– 17.49)
Lower 3.36 (0.57– 6.39) 0.23 (0.06– 0.91) 15.28 (2.16– 40.18) 0.48 (0.19– 0.87) 437 (429– 443) 448 (238– 628) 17 (5– 45) 34 (7– 64) 6.86 (0.56– 14.35)
General 3.21 (0.44– 7.99) 0.19 (0.06– 0.91) 15.44 (1.34– 43.15) 0.50 (0.19– 1.06) 435 (429– 443) 470 (238– 654) 21 (4– 120) 30 (3– 64) 6.49 (0.42– 17.49)
Well B
(wet gas)
Upper 3.33 (0.40– 7.44) 0.10 (0.06– 0.16) 0.63 (0.13– 1.66) 0.27 (0.21– 0.50) 480 (460– 512) 21 (12– 38) 13 (4– 56) 96 (94– 98) 7.63 (0.87– 17.11)
Middle 4.83 (2.36– 7.10) 0.10 (0.07– 0.16) 0.81 (0.43– 1.26) 0.28 (0.22– 0.34) 466 (460– 476) 17 (12– 20) 6 (4– 11) 97 (97– 98) 11.21 (5.41– 15.90)
Lower 8 (3.18– 12) 0.10 (0.07– 0.15) 1.37 (0.52– 2.67) 0.26 (0.17– 0.33) 477 (466– 514) 17 (13– 24) 4 (2– 7) 97 (96– 98) 18.60 (7.29– 27.41)
General 5 (0.40– 12) 0.10 (0.06– 0.16) 0.87 (0.13– 2.67) 0.27 (0.17– 0.50) 475 (460– 514) 18 (12– 38) 8 (2– 56) 97 (94– 98) 11.50 (0.87– 27.41)
Well A
(dry gas)
Upper 1.75 (0.46– 4.50) 0.19 (0.10– 0.39) 0.71 (0.21– 1.49) 0.76 (0.45– 2.31) Unmeasurable
Tmax
51 (6– 107) 59 (11– 142) 92 (84– 99) 3.92 (0.97– 11.38)
Middle 3.76 (1.47– 5.0) 0.27 (0.16– 0.50) 0.61 (0.35– 0.84) 0.76 (0.53– 1.10) 17 (11– 28) 23 (11– 47) 97 (95– 98) 8.62 (3.32– 11.20)
Lower 3.60 (0.50– 6.74) 0.23 (0.10– 0.36) 0.60 (0.26– 0.91) 0.58 (0.32– 0.80) 28 (11– 60) 28 (11– 72) 95 (91– 98) 8.24 (1.10– 15.50)
General 2.38 (0.46– 6.74) 0.21 (0.10– 0.50) 0.68 (0.21– 1.49) 0.74 (0.32– 2.31) 41 (6– 107) 47 (11– 142) 93 (84– 99) 5.40 (0.97– 15.50)
Note: Minimum, maximum and mean values are presented.
Abbreviations: HI, hydrogen index; HI0, original hydrogen index; OI, oxygen index; S1, S2 and S3, peaks derived from the programed pyrolysis; Tmax, temperature reached in the S2 peak; TOC, total organic carbon; TOC0,
restoration of original TOC; TR, transformation ratio.
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5.2.2
|
Gas window
Samples of gas window maturity are dominated by OM of
secondary origin (see Mastalerz et al., 2018; Pommer &
Milliken,2015), which were identified as solid bitumen, the
dominant organic component in thermally mature samples
of the VMFm (Cavelan et al., 2019; Petersen et al., 2020;
Romero- Sarmiento et al., 2017). As mentioned previously,
OM is associated with the mineral matrix (intergranu-
lar space) and fills cavities within bioclasts and fractures
(Figures7 and 8). Compared with the oil window, however,
samples from the gas window show a larger range of pore
sizes. Wet gas samples (Well B) record large (2– 4µm) OM-
hosted bubble pores protected by rigid mineral phases as well
as calcite bioclasts (Figure7a– c). Nevertheless, some elon-
gated bubble pores suggest that compaction impacted OM
pores (Figure7e). OM pervasively fills intergranular spaces
and contains both spongy and bubble pores (Figure 7d–
f), which is typical of the gas window (Ko et al., 2017).
Equivalent samples from the gas window in the VMFm ana-
lysed by Cavelan etal.(2019) also show secondary solid bi-
tumen with bubble and spongy morphologies. In the present
study, SEM reveals that bubble and spongy morphologies
co- exist (Figure 7d– f), between diameters of 4µm– 800nm
(mean 500nm) and 10– 90nm (mean 55nm), respectively.
Samples from the dry gas window (Well A) also show
secondary OM products (solid bitumen) with spongy and
bubble pores (Figure8a– d). However, very small and widely
distributed spongy pores dominate (Figure8e,f). The OM is
confined within matrix cavities and is associated with both
detrital and authigenic clays as well as microcrystalline quartz
and calcite cement (Figure8b– e). In the case of the VMFm,
FIGURE 4 Organic geochemical logs for the analysed wells in the Agrio section. Blue stars (Wells A and B) represent vitrinite reflectance
(%Ro) values and pink stars (Well C) are theoretical %Ro values based on Brisson etal.(2020). TR and TOC0 were calculated following the
methodology of Waples and Tobey (2015) and Brisson etal.(2020)
FIGURE 5 Organic geochemical results for the lower, middle and upper VM (informal stratigraphic units defined by Legarreta &
Villar,2015) in the analysed wells along the Agrio (Well A, Well B and Well C) sections. (a) Hydrogen index (HI) versus calculated and measured
%Ro values. Calculated %Ro based on the equation of Brisson etal.(2020) for Well C (early oil window). Measured %Ro values are given for Well
A and Well B (gas window) and indicated with star markers. (b) HI versus oxygen index (OI) based on the pseudo- van Krevelen diagram
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FIGURE 6 SEM images of low- maturity samples (Well C). (a– c) Examples of nonporous organic matter (OM) (marine type II kerogen in the
VMFm). Note compactional features among rigid detrital grains, which in some cases are enclosed by a thin envelope of OM. Faecal pellets composed
of coccoliths and bioclasts (bc) filled with OM. (d, e) General and detail with the secondary organic matter (SOM) that hosts isolated bubble pores.
OM is distributed between detrital grains: Qz (quartz), illite/mica (red arrows) and carbonates (Cal). (f) SOM- filling microfractures and bioclasts (bc)
associated with spar calcite (Cal- s). The insert shows a detail image (scale bar=20µm)
FIGURE 7 SEM images of wet gas window samples (Well B). General (a) and detailed images (b, c) showing secondary organic matter
(SOM) filling matrix pores and bioclasts. The excellent preservation of bubble pores is linked with quartz (Qz) and calcite (Cal) cements and
calcite bioclasts (bc). (d) SOM shows both bubble and spongy pores. Note expanded mica (Mi), detrital (red arrows) and authigenic (yellow arrow)
illite. The insert shows detail of spongy pores (scale bar=2µm). (e) Elongate bubble pores (white arrows). (f) SOM- hosted spongy pores among
diagenetic microcrystalline quartz (Qz), pyrite framboids (Py) and calcite (Cal)
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siliceous and calcareous biogenic components are interpreted
to contribute to the precipitation of microquartz and calcite
(Milliken et al., 2019). There is also nonporous, elongate
OM interpreted of terrigenous origin (Figure 8a). Pores as-
sociated with the phyllosilicate framework are represented by
triangular- shaped openings (70– 1,200 nm wide, Figure 8b)
as was documented in overmature samples of the Middle
Devonian Geneseo Fm (Northern Appalachian Basin) by
Wilson and Schieber (2016). In the case of OM- hosted pores,
samples of the VMFm that experienced high- thermal maturity
range in size from 15 to 80nm (mean 40nm) for the spongy
and 100 to 700nm (mean 200nm) for the bubble pores.
6
|
BASIN AND PETROLEUM
SYSTEM MODELLING (BPSM)
The quantification of source rock maturity, hydrocarbon gen-
eration and expulsion, pore pressure distribution and porosity
(primary and secondary) was analysed in the regional 2- D
BPSM (Agrio section). BPSM fully integrated the main rock
parameters, such as kerogen type, TOC0, Øorg, TR, maturity
(%Ro) and tectonic events. The 2D modelling was conducted
for the three effective source rocks in the basin (Los Molles,
Vaca Muerta and Agrio Fms). In particular, this study pre-
sents data used to calibrate those parameters in the VMFm
because the study focuses on characterization of processes
within this unit through geological time.
6.1
|
Well calibration in the Agrio model
The conditions of temperature, OM content, maturity, po-
rosity and pore pressure were calibrated using a robust data
set from wells along the Agrio section (Figures 3 and 9).
Data presented correspond to Well A (DdLC) and Well C
(NE Platform), which represent different geological scenar-
ios, because they are located in different basin regions (see
FIGURE 8 SEM images of dry gas window samples (Well A). (a) Secondary organic matter (SOM)- hosted bubble pores and nonporous
terrigenous OM. (b, c) General and detailed images with SOM- filling pores between detrital (Pl=plagioclase; Qz- d=quartz) and diagenetic
quartz. Phyllosilicate pores (PF- pores) are also documented. In (c) note diagenetic quartz (Qz) and illite of detrital (red arrows) and diagenetic
(yellow arrow) origin. (d) SOM with bubble and spongy pores. The OM is associated with clay minerals of both detrital (red arrow) and diagenetic
(yellow arrows) origins. The insert shows spongy pores (scale bar=500nm). (e) SOM with spongy pores filling a cavity partially cemented
by calcite (Cal) and microcrystalline diagenetic quartz (Qz). There are illite/mica domains of detrital origin (red arrows) and authigenic crystals
(yellow arrows) that grew from detrital crystals. (f) Spongy pores. Note detail in the insert image (scale bar=200nm)
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Figure3). The thermal evolution of the model was calibrated
using Horner- corrected borehole temperature data (BHT),
whereas the TOC0 was calculated from pyrolysis data and
used to adjust the evolution of TOC0 for the lower, middle
and upper VM in the model (Figure9). Model and pyrolysis
results show an increase in the TOC0 content from the top
to the base of the unit. %Ro measures were used to calibrate
the thermal maturity, which indicates that the VMFm reached
the dry gas window (Well A, western flank of the Chihuidos
High) and the early oil window (Well C, NE Platform). In
order to calibrate pore pressure, we use data from DFIT.
DFIT is used as an indirect method to estimate pore pres-
sure in unconventional reservoirs (Bakar,2018). According
to DFIT data (red crosses in Figure9), overpressure increases
towards the foreland (west) region. A high pore pressure of
ca. 57MPa is registered at ca. 2,600m depth in Well A and
it is close to the lithostatic pressure, as was also documented
by Berthelon etal.(2021). Well C has a pore pressure of ca.
48 MPa at ca. 2,200 m depth. The effective porosity was
calibrated by using both well log (black crosses in Figure9)
and gas- filled porosity (red dots in Figure9) data (YPF data-
base). Results are consistent with previous studies (Askenazi
etal.,2013; Cuervo etal.,2016; Ortiz etal.,2020) and show
that the effective porosity increases towards the lower VM
(Figure 9). In Well A, this parameter ranges from 5.5% to
12.16% (9.1% average), whereas in Well C effective porosity
ranges from 3.24% to 8.44% (6.25% average).
6.2
|
Hydrocarbon generation in the
Agrio model
Evolution of the TR through time for the VMFm was com-
pared with the Los Molles and Agrio Fms and analysed in
four stages of sequential restoration (Figure 10). During
the Late Cretaceous (ca. 100Ma), TR of 95% suggests that
organic- rich deposits of the Los Molles Fm in the inner sector
reached the advanced dry gas window (Figure10a). From the
inner sector to the eastern flank of the DdLC, the lower VM
would have reached a TR average value of 95%. Expulsion
FIGURE 9 Well calibration of different parameters in the Agrio section for Well C (NE Platform) in (a) and Well A (DdLC) in (b). From left
to right: calculated temperature log (blue line). Black markers are Hornet- corrected borehole temperatures. TOC0 log showing the simulated organic
matter concentration (black curve). Green circles represent TOC0 values obtained from present- day TOC contents. Vitrinite log calculated with the
equation of Sweeney and Burnham (1990) Easy %Ro kinetic algorithm. %Ro vitrinite values (red markers) were used to calibrate the calculated
%Ro curve (black curve). Vertical profile showing the calculated pore pressure magnitude (black line), red crosses are the pore pressure determined
from DFIT tests. Calculated porosity (black curve) was calibrated using measures obtained from well logging (black cross) and gas- filled porosity
(red markers) from core samples. Depth is expressed in depth subsea
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SPACAPAN et Al.
started during the Early Cretaceous (ca. 130Ma) at a thermal
maturity of 0.82– 0.90 %Ro. Likewise, the western organic-
rich deposits of the Agrio Fm reached the early oil window,
with a TR of 15% approximately (Figure 10a). The model
predicts that large volumes of hydrocarbons were generated
and expelled from the Los Molles Fm and lower VM. Such
processes were synchronous with the deposition of the Bajada
del Agrio Group and before the formation of the main tectonic
structures in the inner sector of the belt. A marked thickness
increase in the Los Molles and VMFms was predicted in west-
ern areas where the beginning of hydrocarbon generation took
place between the Late Jurassic and Early Cretaceous. From
90 to 60Ma, more than 1,000m of sediments were deposited
(Neuquén and Malargüe Groups), which exhausted the gen-
eration capacity of the Los Molles and VMFms from the inner
sector to the DdLC. These results suggest that gas generation
related to secondary cracking reactions was a relevant factor
in the early development of overpressure in the VMFm.
The first compressional tectonic event started between 70
and 60Ma (Late Cretaceous– Palaeocene) and triggered base-
ment fault inversion in the Agrio FTB and uplifting of the
Cerro Mocho anticline in the inner (west) sector (Figure10b).
Shortening between the inner and outer sectors was accommo-
dated through a basal detachment in the Auquilco evaporites.
During this stage, the western organic- rich deposits of Los
Molles Fm and lower VM were thermally overmature, whereas
the kitchen of Agrio Fm would have reached a 45% transforma-
tion (Figure10b). To the NE platform, the base of the VMFm
would have reached more than 30% transformation (Figure10b).
During the middle Miocene (14 Ma), the model pre-
dicts that kerogens of the Los Molles Fm and lower VM
were fully transformed in the inner and outer sectors of
the belt (Figure10c). In those areas, the Los Molles source
rock reached the advanced dry gas window to overmature
(>4 %Ro). The VMFm source rock was in the gas win-
dow, whereas the Agrio Fm reached an average TR of 85%
(Figure10c). Miocene compression resulted in uplift of the
inner sector and the structural duplication of sedimentary
successions in the outer sector. The Miocene deformation
phase promoted uplift and cooling of the main source rocks
in the inner sector. Tectonic uplift temporally stopped ther-
mal maturation and secondary cracking, in conjunction with
FIGURE 10 Modelling of thermal
maturity based on transformation ratio
(TR%) in the Agrio cross section for the
three source rocks in the basin. Four stages
of sequential restoration are considered. (a)
Late Cretaceous, (b) Palaeocene, (c) middle
Miocene and (d) present day
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SPACAPAN et Al.
decreasing temperature and pressure. This process likely pro-
moted a reduction in pore pressure associated with the ex-
pulsion of large amounts of gas from the Jurassic and Lower
Cretaceous source rocks. The structural duplication in the
outer sector resulted in a component of structural thicken-
ing, which promoted thermal reactivation and, consequently,
increase in secondary cracking reactions and pore pressure.
Towards the structural heights of DdLC, the Los Molles
source rock was also overmature (>4 %Ro), and the lower
VM reached the gas window (2 %Ro).
Present- day maturity shows that the Los Molles and
VMFms are completely exhausted from the inner sector to the
eastern flank of the DdLC (Figure10d). Towards the DdLC
area, the calculated maturity trend for Well A shows that the
lower VM reached the dry gas window (Figures9b and 10d).
Furthermore, the model predicts that in the NE platform area,
the lower VM is in the early- to- peak oil window and reaches
a transformation ratio of 50% (Figure10d). Simulated and
calculated vitrinite reflectance values show a clear decrease
from the Agrio FTB to the foreland (east) region of the basin.
6.3
|
Time extractions for the lower Vaca
Muerta in the DdLC and NE Platform areas
The interplay of key processes related to regional tectonic
events and hydrocarbon generation, thermal stress, pore
pressure and porosity development was analysed in time
FIGURE 11 Time extractions for the lower VM in the Agrio model. (a) DdLC and (b) NE Platform areas. Curve references: Transformation
ratio (red), burial depth (brown), vitrinite reflectance (violet), total porosity (black), TOC (green), pore pressure (light blue) and secondary cracking
mass (dashed red). Present- day vitrinite reflectance values (black circles), pressure data derived from DFIT tests (blue stars) and the onset of
organic porosity (Øorg) development are included in both extractions
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extractions for the lower VM in the DdLC and NE Platform
areas of the Agrio section (Figure11).
The DdLC area shows that during the Early Cretaceous
the lower VM underwent a first phase of burial compaction
(brown curve in Figure11a), which reduced the effective
porosity from 60% to 13% (black curve in Figure11a). Pore
pressure increased up to 28MPa (blue curve in Figure11a)
interpreted to result from incomplete drainage of generated
fluids. From ca. 120 Ma, the unit reached a TR of 88%
(red curve in Figure11a), which induced an abrupt increase
in the porosity (black curve in Figure11a) related to the
growth of Øorg. The model also shows that the develop-
ment of Øorg added ca. 11% to the porosity and reduced
the TOC content to ca. 5% (green curve in Figure 11a).
Furthermore, continuous thermal cracking increased pore
pressure, which induced a first pulse of petroleum ex-
pulsion at thermal maturity of 0.82 %Ro (violet curve in
Figure 11a). A second phase of mechanical compaction
started at ca. 100 Ma and caused a reduction in porosity,
likely including both matrix and organic porosity (black
curve in Figure11a). At ca. 65Ma, the unit reached max-
imum burial (brown curve in Figure11a) and the effective
porosity was reduced to 10%. Secondary cracking reac-
tions, accompanied by gas generation (dashed red curve
in Figure11a), caused an increase in pore pressure of ca.
87MPa. From ca. 50Ma, progressive uplift of the DdLC
anticline started and continued during Palaeocene, Eocene
and Miocene times. Uplift and consequent erosion reduced
vertical stress, thereby reducing the required pore pressure
to maintain equilibrium with the overlying column. This
is demonstrated in the model between 50Ma and present-
day when about 500m of section was eroded, which led to
a decline in pore pressure (blue curve in Figure11a). By
present- day the pore pressure dropped to 57MPa, which is
consistent with DFIT values obtained in Well A (violet star
in Figure11a).
In the NE Platform, the lower VM underwent a contin-
uous decrease in effective porosity from 58% to 7% (black
curve in Figure11b) due to mechanical compaction that took
place between 150 and 60Ma. At 60Ma, TR of 45% (red
curve in Figure11b) shows that most of the unit was in the
main oil window during the maximum burial (brown curve
in Figure11b). The model shows that increased burial depth
and hydrocarbon generation increased the pore pressure
(blue curve in Figure11b) to ca. 62MPa. From ca. 22Ma to
present day, progressive uplift and erosion reduced the pore
pressure from 60 to 48MPa, which is comparable with DFIT
measures for Well C (violet star in Figure11b). Progressive
transformation of OM occurred in parallel with the reduction
in TOC contents (green curve in Figure11b) and increased
porosity (black curve in Figure11b), which is interpreted as
a product of Øorg development. The Øorg added 2.2% to the
effective porosity in the lower VM. The simulations allow us
to recognize significant differences in Øorg development be-
tween the DdLC (11%) and NE Platform (2.2%), which cor-
relate with TOC0 variations and transformation gradient. In
the DdLC area, the high TOC0 concentration associated with
a high transformation ratio promoted an increase in Øorg de-
velopment compared with the NE Platform.
7
|
DISCUSSION
7.1
|
Organic geochemical pattern in the
VMFm
Regional studies of the VMFm have examined the OM dis-
tribution, including richness (quantity), free hydrocarbons
FIGURE 12 Schematic evolution of
organic matter pore types with increased
thermal maturity based on SEM and
pyrolysis data for the VMFm. References:
np- OM (nonporous organic matter),
bc (bioclasts), fr (fracture) and SOM
(secondary organic matter)
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SPACAPAN et Al.
and thermal maturity (e.g. TR, %Ro) of the unit (e.g. Brisson
etal.,2020; Cruz etal.,1996, 2002; Legarreta & Villar,2011,
2015; Urien & Zambrano,1994; Veiga etal.,2020). In addi-
tion, there are many local contributions from outcrop sections
and the subsurface that include TOC and Rock- Eval® pyrolysis
analyses (e.g. Askenazi etal.,2013; Boll etal.,2014; Capelli
etal.,2021; Cavelan etal.,2019; Karg & Littke,2020; Krim
etal.,2019; Małachowska etal.,2019; Milliken etal.,2019;
Petersen etal.,2020; Romero- Sarmiento etal.,2017; Scasso
etal.,2005; Sylwan,2014). All those studies and the present
work indicate high present- day TOC values ranging from 1%
to 12% with maximum values towards the base of the unit in
the lower VM (Figure4). However, present- day TOC con-
tent may not reflect the loss of organic carbon during thermal
maturation. Thus, the original TOC0 based on the reconstruc-
tion of Brisson et al. (2020) is a suitable parameter to ex-
amine vertical and lateral richness distribution (Figure 4),
and it is applicable for the VMFm. In the Agrio section,
the lower VM shows an increase in TOC0 values from 6%
(east) to 8% (west). This observation is consistent with the
westward facies deepening of classic palaeogeographic
maps accompanied by restricted settings under low- oxygen
water conditions that favour preservation of OM (Legarreta
& Uliana,1991). The increase in TOC values from east to
west is associated with thickening of the VMFm between ca.
400 and 800m in the same trend (Dominguez et al.,2016),
which means a higher volume of generated hydrocarbons for
the same gradient of TR. Notably, Well B shows the high-
est present- day (mean 8%) and original TOC (mean 18% for
the lower VM) contents, which suggests that local effects
could have influenced these positive anomalies. As analysed
by Dominguez et al. (2016), organic- rich intervals in the
VMFm correspond to bottomset– distal foreset segments of
prograding clinoforms, conditioned by stratigraphic and in
some cases tectonic (differential subsidence and palaeo- arch
uplift) controls. The lower VM exhibits mostly stratigraphic
controls (Dominguez etal., 2016), and therefore, a position
close to the distal foreset is envisaged where optimal con-
ditions for the production and preservation of OM occurred
(Passey etal.,2010).
OM in the unit shows negligible compositional differ-
ences, both geographically and stratigraphically, and is
typically described as unstructured algal material (type II
kerogen) with very scarce land- derived (e.g. vitrinite) parti-
cles that yielded an estimated HI0 of 680mgHC/gTOC (Brisson
etal.,2020; Petersen etal.,2020; Veiga etal.,2020). As re-
corded in the Agrio section, the basin shows an E– W ther-
mal gradient, which is consistent with the decrease in HI
(Figure5) and increase in TR values to the west. The sample
set exhibits a gradual decrease in HI with increasing maturity
gradient from 470mgHC/gTOC (general average for the early
oil window, Well C) to 41mgHC/gTOC (general average for the
early oil window, Well A). This denotes the transformation
of type II kerogen into hydrocarbons and the concomitant re-
duction in HI (Hazra etal.,2019; Peters & Cassa,1994).
Some samples from the upper VM show an increase in
OI, which could suggest some terrigenous OM input; how-
ever, it may be better to interpret it as the result of OM ox-
idation during transport and deposition (Peters, 1986). In
the case of the upper VM, that increase is accompanied by
a decline in TOC content related to the shallowing upward
tendency of this interval. As the upper VM shows an increase
in the carbonate content (Capelli et al., 2021; Legarreta &
Villar,2015), impure calcite could also generate some CO2
upon pyrolysis and, as a consequence, an increase in the S3
peak and OI parameter (Peters,1986).
7.2
|
Evolution of OM across the
maturation gradient
The importance of shale reservoirs as sources of oil and gas
has motivated numerous studies that focus on parameters that
control the development and preservation of pores (Katz &
Arango,2018; Ko etal.,2017; Liu etal.,2017; Löhr etal.,2015;
Milliken et al., 2013; Reed & Loucks, 2015). The regional
analysis of the VMFm presented in this work demonstrates that
maturity is an important factor that impacts the development
of Øorg. The early and rapid changes in TR that characterize
type II kerogen from the VMFm (Brisson et al., 2020) sug-
gest that OM- hosted pores are associated with partially and ex-
hausted OM generated during primary and secondary cracking
reactions. As also documented by Tomassini etal.(2019), the
general high TOC content of the unit indicates that OM- hosted
pores are the main storage of potential fluids.
In the oil window and based on TR and SEM data, the OM
that hosts pores is partially transformed and occupies spaces
between detrital grains, the internal structure of bioclasts and
fractures (Figure12). Interestingly, some samples from the
early oil window (Well C) lack OM- hosted pores and have
the lowest values of TR (mean 30%, Table1). Filament- like
organic particles resemble those liptinite macerals identified
under optical petrography in immature to low mature sam-
ples (Brisson etal.,2020; Małachowska etal.,2019; Petersen
etal., 2020). The type II sapropelic kerogen that prevailed
during sedimentation of the VMFm (Brisson et al., 2020;
Legarreta & Villar, 2015) is prone to ductile compaction
(Figure6a– c) and loss of primary porosity (Löhr etal.,2015;
Milliken et al., 2014). In analogous shale units at low ther-
mal maturity, type II kerogen is nonporous and highly af-
fected by mechanical compaction (Comerio et al., 2020;
Schieber,2013). This observation indicates that the poten-
tial infill of pores in this early- generation stage with heavy,
bitumen- like petroleum (Petersen etal.,2020) could explain
why liptinite macerals do not show evidence of pores at
SEM resolution (Löhr etal.,2015). However, at some rock
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SPACAPAN et Al.
intervals in the early oil window, isolated bubble pores occur
in secondary OM products (e.g. solid bitumen), suggesting
that other processes were involved in the development of
Øorg. As was pointed out by Brisson etal.(2020), variations
in depositional conditions could have influenced the final
composition of oil- prone organofacies (e.g. sulphur- rich vs.
sulphur- depleted). These diagenetic differences could affect
the onset of primary cracking reactions and the generation of
liquid hydrocarbons and bitumen (Hackley & Cardott,2016).
Thus, decomposition of kinetically distinct kerogens at dif-
ferent rates might explain why that some strata at the same
thermal maturity preserve nonporous liptinite macerals,
whereas in others Øorg is associated with secondary OM
products such as the solid bitumen.
OM- hosted pores in the gas window are interpreted to
develop in secondary, highly transformed (TR> 90%) OM
and show both the bubble and spongy morphologies (Ko
et al., 2017; Milliken et al., 2013). The wet gas window
(Well B) exhibits the largest bubble pores (2– 4 µm) asso-
ciated with development of highly concentrated spongy
pores that are absent in the early oil window but become
more abundant in the dry gas window (Figure 12). Large
bubble pores occur in ‘shelter’ pores (Figure7a– c), such as
in the interior of bioclasts and around diagenetic products
(calcite cement) indicating that some lithologies (Milliken
etal.,2019) favoured their preservation. They likely formed
in the oil window as was interpreted for the Eagle Ford Fm
(Cenomanian– Turonian, Maverick Basin of south Texas),
where bubble pores include hydrocarbon liquids that were left
behind or migrated following petroleum generation (Schieber
etal., 2016). Consequently, we interpret that spongy pores
started to grow during secondary cracking due to decom-
position of partially transformed OM by thermal maturity.
Some bubble pores appear to form due to coalescence of
spongy pores (Figure8c,d) and were, therefore, also gener-
ated during the dry gas window (Cavelan etal.,2019). The
bubble geometry is mainly represented by macropores (pore
sizes >50nm) and well documented with SEM resolution.
On the contrary, spongy pores include a part of mesopores
(2– 50 nm) and presumably micropores (<2 nm), the latter
measured through nitrogen adsorption analysis by Cavelan
etal.(2019) for the VMFm. For terrigenous OM, SEM does
FIGURE 13 (A) Present- day maturity (%Ro) of the VMFm along the Agrio section. (B) Thermal maturity based on transformation ratio
(TR%) for the lower VM is presented in four areas: (a) Cerro Mocho, (b) DdLC, (c) East of DdLC and (d) NE Platform
20
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SPACAPAN et Al.
not show pores at any maturity, the same observations apply
for the New Albany Shale (Devonian– Mississippian, Illinois
Basin at USA), where vitrinite and inertinite macerals may
not contribute to additional Øorg (Liu etal.,2017).
SEM images do not show clear evidence of deformed
organic pores; except for some examples in Well B where
OM- hosted pores within a clay- rich matrix exhibit elongated
(flattened) forms interpreted as the product of mechanical
compaction (Figure7e). Previous studies documented that or-
ganic pores can survive mechanical compaction but preserve
features of OM deformation (Wang,2020). As documented
for the VMFm, most organic pores are preserved showing
circular forms, which implies that rigid components such as
microfossils and diagenetic products (microcrystalline quartz
and calcite cement) inhibit the effects of compaction. In
addition, the analysed samples are far from intensively de-
formed areas (e.g. outcrops in the internal belts) where OM-
hosted pores could be deformed. The OM- hosted pores are
interpreted to result from kerogen and bitumen cracking to
oil and gas, presumably in equilibrium between lithostatic
pressure and pore pressure within the unit (Ko etal.,2017).
Accordingly, overpressure- related processes could represent
important mechanisms that inhibit the effects of compaction
and contributed to preservation of Øorg (see Section7.3.3).
7.3
|
BPSM in the Agrio cross section
The 2D modelled section presented in this work reproduces
the decrease in maturity and OM transformation from west
(fold and thrust belt) to east (basin margin) for the main
source rocks in the Neuquén Basin (see Section6). For the
VMFm, the models predict temporal and spatial variations in
the timing of hydrocarbon generation– expulsion controlled
by tectonic events, burial depth and differences in thick-
ness of the Mesozoic sedimentary overburden. Model results
show that OM transformation impacted on the magnitude of
(a) the effective porosity associated with Øorg development,
and (b) the distribution of pore pressure within the unit.
7.3.1
|
Timing of hydrocarbon generation
Based on present- day %Ro values, maturity windows of the
VMFm along the Agrio section are presented in Figure 13.
Temporal and spatial variations in the timing of kerogen trans-
formation are documented between the inner sector and the
NE Platform. From the fold belt (Cerro Mocho– Pichi Mula)
to the DdLC structure, the lower VM reached the dry gas win-
dow, and according to the modelling, the maximum transfor-
mation occurred at ca. 120Ma in the inner sector (A- curve in
Figure13b) before the Late Cretaceous Andean deformation
phase that affected the western part of the belt (Cobbold &
Rossello,2003; Rojas Vera etal.,2015; Sánchez etal., 2018;
Zamora Valcarce et al., 2011; Zapata & Folguera, 2005).
Modelling results indicate that hydrocarbon generation and ex-
pulsion preceded the growth of main structures in the inner and
outer sectors of the Agrio FTB and would have been favoured
by the increase in the Mesozoic sedimentary cover towards the
inner and outer sectors (ca. 4– 5km burial depth). Nevertheless,
tectonic uplift and cooling of both sectors correlate with the
Miocene contractional pulse. As a consequence, thermal stress
and secondary cracking stopped, and pore pressure decreased,
since remnant fluids (mainly gas) were expelled from the unit.
Such interpretations were previously inferred by Gómez Omil
et al. (2014), indicating that intensely deformed areas in the
Neuquén Basin are at present day inactive and incapable of
generating hydrocarbons.
For the DdLC structure, TR of 99% shows that the lower
VM was already in the dry gas window at ca. 98Ma (B-
curve in Figure13b), whereas in the external flank of this
structure full transformation conditions were reached at ca.
80 Ma (C- curve in Figure 13b). Compressive deformation
and uplift/regional erosion promoted the exhumation of the
unit associated with expulsion of fluids as well as hydrocar-
bon migration and trapping in previously generated struc-
tures (Rocha etal.,2018). This observation is consistent with
our modelling because the dissipation of pore pressure (blue
curve in Figure11a) and fluid expulsion are linked to exhu-
mation events that occurred mainly between Palaeocene and
Miocene time. The NE Platform shows that the unit reached
the early- to- peak oil window with a TR of 40%– 50%, indi-
cating that hydrocarbons generation started from ca. 60Ma
(D- curve in Figure13b).
The model indicates that hydrocarbon generation and
expulsion started in the western VMFm before the Late
Cretaceous Andean deformation, which controlled the uplift
of inner sectors within the Agrio FTB. In the undeformed
scenario (Figure10a), hydrocarbons were able to migrate up
to 70 km through the main carrier beds in the basin (Cruz
etal., 2002; Rocha etal.,2018). At present day, the VMFm
is totally exhausted in the intensely deformed regions of the
belt, with full kerogen transformation into hydrocarbons at ca.
120Ma. At the basin scale, the Agrio model shows a clear
eastward decrease in maturity and transformation gradient as-
sociated with changes in the sedimentary column thickness
that led to differential maximum burial before the Miocene
deformation pulse. Similar interpretations were documented
along the Chos Malal FTB, where thermal maturity and
transformation also decrease eastward linked to differences
in thickness of the sedimentary overburden (Cruz etal.,1996;
Karg & Littke,2020). In the inner sector of the Agrio FTB,
the Miocene uplift caused present- day source rocks to show
relict maturity reached at deeper burial depths in the past. In
addition, there is an increase in the thermal stress and trans-
formation of the OM from north to south, mainly controlled
|
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SPACAPAN et Al.
increased sedimentary thickness in the same trend (Gómez
Omil etal.,2014; Legarreta etal.,2008). These observations
indicate that the effects of thermal maturity follow a N– S trend
controlled by a general thickness increase in the source rocks
of the Mendoza Group towards the area of the Agrio FTB, to
the north of the Huincul Arch (see location in Figure1).
7.3.2
|
Organic porosity estimation
The integrated modelling results and SEM images indicate
that the development of Øorg is a typical feature of the
VMFm. Petromod® software calculates Øorg as the result of
OM transformation from solid immature kerogen to less dense
fluid hydrocarbons during thermal maturation (Hantschel &
Kauerauf, 2009). Time extractions show an increase in ef-
fective porosity, interpreted as the result of Øorg linked to
the transformation of OM into hydrocarbons (Figure 14a).
The simulations are comparable with those of Modica and
Lapierre (2012): Øorg tends to increase with burial depth and
thermal transformation. Accordingly, Øorg differences for
the lower VM between the DdLC (11%) and NE Platform
(2.2%) correspond to an increase in TR values to the west in
the basin. Such observations are consistent with basin- scale
modelling of Øorg in the Mississippian Barnett Shale that al-
lowed Romero- Sarmiento etal.(2013) to estimate from 0%
(immature zones) to 4% Øorg (mature zones) of rock volume.
However, as for the Upper Devonian Duvernay Formation
in the Western Canada Basin (Chen & Jiang,2016), the de-
velopment of Øorg is also a function of TOC0 and kerogen
type, since type I kerogen generates more Øorg than type III
kerogen (Chen etal.,2015).
Time extractions show variations in the effective po-
rosity through time for the lower, middle and upper VM in
Well A (Figure14a). From 120 Ma, the lower VM (TOC0
11% average) increased its porosity by ca. 11%, which is
interpreted as a response to Øorg development. The curve
obtained by Mei etal. (2021) for the VMFm also shows a
considerable increase in porosity due to Øorg development
associated with the onset of hydrocarbon generation. To the
contrary, the upper VM (TOC0 2% average) would have de-
veloped only 1.95% of Øorg at full transformation, a value
that does not considerably affect the evolution of the poros-
ity curve (Figure14a). Time extractions indicate progressive
increase in porosity from the top to the base of the unit re-
lated to TOC0 and thermal maturity and, therefore, with the
FIGURE 14 (a) Effective porosity
curves through geologic time for the lower,
middle and upper VM in DdLC (Well A).
Simulated porosity increases as a response
to organic porosity (Øorg) development and
the porosity difference between upper and
lower VM is expressed as ΔØ. Modelling
indicates a progressive increase in porosity
from the top to the base of the unit related
to TOC0 and thermal maturity increase
and, therefore, with increase in Øorg
in the same trend. The insert shows the
calculated porosity (black curve) and data
obtained from well logging (black cross)
and gas- filled porosity (red circles) from
core samples. (b) Distribution of present- day
pore pressure in the VMFm. Pore pressure
modelling for the lower VM in Well A with
(black curve) and without hydrocarbon
generation (dashed black curve)
22
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SPACAPAN et Al.
increased in Øorg in the same trend. This observation agrees
with SEM analysis, which found that OM- hosted pores are
dominant in organic- rich intervals of the unit (Tomassini
etal., 2019). Although it is beyond the scope of this study
to quantify the porosity, our results suggest that organic- rich
intervals of the VMFm and associated OM pores control the
hydrocarbon storage capacity. Similar results have been doc-
umented in other worldwide class unconventional resources,
as in the Barnett (Texas) and Haynesville (Texas, Arkansas,
Louisiana) Fms, where much of the petroleum is trapped
in organic pores (Passey et al., 2010; Peters et al., 2017;
Romero- Sarmiento etal.,2013).
It is important to highlight that the constructed model
incorporates bulk kinetics specific for the VMFm (Brisson
etal., 2020), which provided accurate information on ther-
mal evolution of the OM, Øorg and timing of hydrocarbon
generation. Future investigations should incorporate detailed
compositional kinetic schemes to optimize the evolution of
TOC, Øorg and hydrocarbon retention and expulsion in the
VMFm (see Mei et al., 2021).
7.3.3
|
Pore pressure related to
hydrocarbon generation
2D basin modelling suggests that hydrocarbon genera-
tion represents an important mechanism that controls the
magnitude and distribution of pore pressure in the VMFm.
Simulations and DFIT data indicate that the unit is an over-
pressured system at different basin positions. Previous studies
proposed that the transformation of kerogen into oil and gas
represents the main mechanism for overpressure generation
in the VMFm (Badessich etal.,2016; Cobbold etal.,2013;
Rocha etal.,2018; Rodrigues etal.,2009; Veiga etal.,2020;
Zanella etal.,2015). The volume expansion associated with
hydrocarbon generation has been implicated as a cause of
overpressure in different sedimentary basins (Osborne &
Swarbrick,1997; Swarbrick etal.,2002). Hydrocarbon gen-
eration can be a cause for overpressure if the rate of volume
increase due to kerogen transformation exceeds the rate
of volume loss by fluid expulsion and migration (Berg &
Gangi,1999). Bredehoeft et al. (1994) proposed that if the
liquid generated during thermal cracking is less dense than
the solid kerogen, then there will be more liquid than created
pores and, thus, the pore pressure will increase. This over-
pressure mechanism depends upon kerogen type, abundance
of OM, thermal history and rock permeability (Osborne &
Swarbrick, 1997). For the VMFm, modelling results show
that pore pressure magnitude was influenced by abundance
of OM and generated fluids, both parameters controlled by
the position in the basin and thermal history. The highest
pore pressures coincide with the western part of the basin,
where the VMFm shows highest TOC0 contents and where
the unit reached the gas window. Osborne and Swarbrick
(1997) suggested that changes in overpressure gradients re-
lated to volume expansion after hydrocarbon generation are
controlled by two main reactions: (1) low- temperature reac-
tion rate for primary cracking of kerogen into oil and gas, and
(2) high- temperature reaction rate for secondary cracking of
oil and bitumen into gas. In particular, secondary cracking
reactions induce a significant overpressure within low per-
meability source rocks (Osborne & Swarbrick,1997). High
pressures are more readily developed by gas generation than
by oil generation because of the much lower density of gas
(Barker, 1990). Different case studies documented that the
generation of gas resulted in conditions of overpressure within
source rocks (Carcione & Gangi, 2000; Gao et al., 2019;
Hao et al., 1996; Hunt,1990; McPeek, 1981; Nunn, 2012;
Ramdhan & Goulty, 2010; Swarbrick et al., 2002; Tingay
etal.,2009). Cracking of 1 vol% of oil would generate over-
pressures close to the magnitude of the lithostatic gradient
in confined rocks (Barker,1990). The relationship between
pore pressure and maturity windows for the VMFm along the
Agrio FTB is shown in Figure14b. Well A (DdLC) in the gas
window at present day reaches 57MPa, whereas towards the
oil window (Well C), the pore pressure reaches 48MPa. The
volume expansion related to primary and secondary cracking
would have controlled such differences in pore pressure of
the VMFm between different maturity stages. These results
indicate that secondary cracking of retained hydrocarbons in
VMFm produced a significant increase in pore pressure in
western areas of the Neuquén Basin.
The Petromod® software calculates the pore pressure
caused by primary and secondary cracking reactions consid-
ering different parameters such as kerogen reduction, poros-
ity, density of hydrocarbons and compressibility (Hantschel
& Kauerauf,2009). The magnitude of fluid expansion on pore
pressure was also evaluated in a model excluding hydrocar-
bon generation in pore pressure calculations for the VMFm
in the DdLC area (Figure14b). Interestingly, the two models
show discrepancies in the magnitude of pore pressure, con-
firming that hydrocarbon generation, especially gas, plays a
significant role in pressure generation. In the second model,
pore pressure generation was related to disequilibrium com-
paction and pore pressure magnitude is lower than the model
with hydrocarbon generation. In particular, during the peak
of gas generation (ca. 50Ma), the pore pressure difference is
ca. 30% on average between both models (Figure14b). Our
results suggest that both disequilibrium compaction and hy-
drocarbon generation could act as coupled processes contrib-
uting to pore pressure generation within the VMFm.
On the other hand, the present- day distribution of pore
pressure (Figure14b) depends on the magnitude of different
processes that reduce pore pressure such as fracturing, uplift
and erosion (Doré & Jensen,1996; Law & Dickinson,1985;
Law & Spencer, 1998; Neuzil & Pollock, 1983). Such
|
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SPACAPAN et Al.
processes reduce vertical stress, thereby reducing the re-
quired pore pressure to maintain equilibrium with the over-
lying column (Burgreen- Chan et al., 2015). Pore pressure
reduction is recorded in the time extraction for DdLC when
ca. 1,000m of sedimentary rocks were eroded from 65Ma
to present day. The pore pressure in the unit decreases from
87MPa (50Ma) to 57MPa (present day), demonstrating the
capacity of fracturing, uplift and erosion to reduce pressure
and promote late expulsion and migration of hydrocarbons
into potential traps. The amount of pore pressure reduction
appears to be a consequence of the permeability increase
triggered by fracturing, uplift and erosion associated with
a decrease in lithostatic load. In the same way, the Miocene
tectonic uplift stopped the thermal stress and secondary
cracking, thus promoting a substantial pore pressure reduc-
tion in the Agrio Fold belt. The reduction in pore pressure in
the VMFm associated with those processes is in agreement
with observations and modelling from other studies in the
unit (Mei etal.,2021). We consider that tectonic uplift could
be an important process for redistribution of hydrocarbons
within the basin and individual traps because of changes
in structural configuration (e.g. Shanley & Cluff,2015). In
the model, the faults were assumed to be closed (i.e. im-
permeable) for the simulated steps. Compartmentalization
due to faults is a common feature in petroleum systems and,
in many cases, is identified by laterally different pressure
regimens (Borge, 2002; Borge & Sylta, 1998; Gibson &
Bentham,2003; Williams & Madatov,2005). This is doc-
umented in the Pichi Mula triangular zone, where closed
faults inhibited the drainage of fluids and resulted in high
present- day pressure (Figure14b).
Finally, 2D basin modelling by Berthelon et al. (2021)
suggested that horizontal (tectonic) compression related
to Andean deformation could increase overpressure in the
VMFm. However, the authors mentioned that their proposed
model does not integrate horizontal stress with hydrocarbon
generation in the calculation of the overpressure. The model-
ling in our study shows that generation of hydrocarbons and
compaction disequilibrium represents the main mechanisms
controlling overpressure in the VMFm. However, we do not
rule out the possibility that compressional stress related to
Andean deformation may have also influenced the distribu-
tion and magnitude of pore pressure. This proposal should be
modelled in detail considering the magnitudes and temporal
relationships among maximum burial, hydrocarbon genera-
tion and horizontal stress.
8
|
CONCLUSIONS
This study analyses the unconventional petroleum potential
of the VMFm source rock at different thermal maturities
based on organic geochemistry, electron microscopy and
a regional BPSM from the Agrio FTB to the basin border.
A robust data set was incorporated into the model with the
purpose of integrating regional tectonic events and processes
that controlled the generation and expulsion of hydrocarbons,
organic porosity development and pore pressure mechanisms
through geologic time.
In the Agrio FTB, the lower Vaca Muerta shows an
increase in TOC0 towards the west from 4% to 8% mean
values. The increase in TOC0 from east to west is associ-
ated with thickening of the unit, which suggests the po-
tential larger volumes of generated hydrocarbons for the
same thermal gradient. Thermal maturity based on the
transformation ratio (TR) controlled the development of
organic pores. TR increases westward, indicating that in
conjunction with increased TOC0, organic pores represent
the main control on total porosity in organic- rich intervals
of the unit. Along the Agrio FTB, ca. 11% of organic po-
rosity was reached in the DdLC (gas window), whereas
only ca. 2% was reached in the NE Platform (early oil) for
the lower Vaca Muerta. Organic geochemistry and elec-
tron microscopy demonstrate that OM- hosted pores are
related to thermal degradation of oil- prone type II kerogen
into partially (TR ca. 3%– 60%) nearly completely (TR ca.
80%– 99%) transformed OM. Based on SEM images, iso-
lated bubble pores are typical of the oil window, whereas
bubble and densely distributed spongy pores occur in the
gas window.
BPSM shows that temporal and spatial variations in the
timing of hydrocarbon generation are linked to tectonic
events, burial depth and differences in thickness of the
Mesozoic sedimentary overburden. The model shows a clear
decrease in maturity and OM transformation to the east (basin
margin) for the main source rocks in the Neuquén Basin. 2D
modelling predicts that large volumes of hydrocarbons were
generated and expelled from VMFm during the Early and
Late Cretaceous in western sectors of the basin.
The VMFm is an overpressure cell at different basin po-
sitions. BPSM indicates that hydrocarbon generation and
compaction disequilibrium were main mechanisms that
controlled magnitude and distribution of pore pressure.
The volume expansion associated with hydrocarbon gen-
eration reached maximum values from secondary cracking
(transformation of oil and bitumen into gas) during the Late
Cretaceous– Palaeocene.
The distribution of OM and mechanisms that control pres-
sure and porosity along the maturity gradient represent key
parameters to evaluate unconventional plays in the context
of basin evolution. In the Vaca Muerta Formation, overpres-
sure intervals with high organic carbon contents are the most
prone to develop organic pores, which represent favourable
sites for the storage of hydrocarbons.
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SPACAPAN et Al.
ACKNOWLEDGEMENTS
This study is published with the permission of YPF and
YTEC. We are especially grateful to L. Monti, G. Sagasti
and R. Manoni (YPF), C. Smal and J.P. Alvarez (Y- TEC)
for allowing us to publish the present data. To M. Fasola,
for his review and constructive comments. Special thanks
to A. Floridia, N. Jausoro and F. Medina (Laboratorio de
Microscopía in Y- TEC) for SEM analysis. H. Villar (GeoLab
Sur) is thanked for pyrolysis analysis and vitrinite determina-
tions. Special thanks to M.F. Romero- Sarmiento and B. Katz
who provided thoughtful comments and further improved
this article. We also express our gratitude to K. Peters for
his useful edits, suggestions and ideas. We acknowledge C.
Jhonson (Asociate Editor of BR) for constructive comments
on the original version of the manuscript.
PEER REVIEW
The peer review history for this article is available at https://
publo ns.com/publo n/10.1111/bre.12599.
DATA AVAILABILITY STATEMENT
The data that support the findings of this study are available
from the corresponding author upon reasonable request.
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the Supporting Information section.
How to cite this article: Spacapan, J. B., Comerio,
M., Brisson, I., Rocha, E., Cipollone, M., & Hidalgo,
J. C. (2021). Integrated source rock evaluation along
the maturation gradient. Application to the Vaca
Muerta Formation, Neuquén Basin of Argentina.
Basin Research, 00, 1– 29. https://doi.org/10.1111/
bre.12599
