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Sandstone diagenesis and reservoir quality prediction: Models, Myths, and reality


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Models and concepts of sandstone diagenesis developed over the past two decades are currently employed with variable success to predict reservoir quality in hydrocarbon exploration. Not all of these are equally supported by quantitative data, observations, and rigorous hypothesis testing. Simple plots of sandstone porosity versus extrinsic parameters such as current subsurface depth or temperature are commonly extrapolated but rarely yield accurate predictions for lithified sandstones. Calibrated numerical models that simulate compaction and quartz cementation, when linked to basin models, have proven successful in predicting sandstone porosity and permeability where sufficient analog information regarding sandstone texture, composition, and quartz surface area is available. Analysis of global, regional, and local data sets indicates the following regarding contemporary diagenetic models used to predict reservoir quality. (1) The effectiveness of grain coatings on quartz grains (e.g., chlorite, microquartz) as an inhibitor of quartz cementation is supported by abundant empirical data and recent experimental results. (2) Vertical effective stress, although a fundamental factor in compaction, cannot be used alone as an accurate predictor of porosity for lithified sandstones. (3) Secondary porosity related to dissolution of framework grains and/or cements is most commonly volumetrically minor (<2%). Exceptions are rare and not easily predicted with current models. (4) The hypothesis and widely held belief that hydrocarbon pore fluids suppress porosity loss due to quartz cementation is not supported by detailed data and does not represent a viable predictive model. (5) Heat-flow perturbations associated with allochthonous salt bodies can result in suppressed thermal exposure, thereby slowing the rate of quartz cementation in some subsalt sands.
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Sandstone diagenesis and
reservoir quality prediction:
Models, myths, and reality
Thomas R. Taylor, Melvyn R. Giles, Lori A. Hathon,
Timothy N. Diggs, Neil R. Braunsdorf, Gino V. Birbiglia,
Mark G. Kittridge, Calum I. Macaulay, and
Irene S. Espejo
Models and concepts of sandstone diagenesis developed over
the past two decades are currently employed with variable suc-
cess to predict reservoir quality in hydrocarbon exploration.
Not all of these are equally supported by quantitative data, ob-
servations, and rigorous hypothesis testing. Simple plots of sand-
stone porosity versus extrinsic parameters such as current sub-
surface depth or temperature are commonly extrapolated but
rarely yield accurate predictions for lithified sandstones. Cali-
brated numerical models that simulate compaction and quartz
cementation, when linked to basin models, have proven suc-
cessful in predicting sandstone porosity and permeability where
sufficient analog information regarding sandstone texture, com-
position, and quartz surface area is available.
Analysis of global, regional, and local data sets indicates the
following regarding contemporary diagenetic models used to
predict reservoir quality. (1) The effectiveness of grain coatings
on quartz grains (e.g., chlorite, microquartz) as an inhibitor of
quartz cementation is supported by abundant empirical data
and recent experimental results. (2) Vertical effective stress, al-
though a fundamental factor in compaction, cannot be used
alone as an accurate predictor of porosity for lithified sand-
stones. (3) Secondary porosity related to dissolution of frame-
work grains and/or cements is most commonly volumetrically
minor (<2%). Exceptions are rare and not easily predicted with
current models. (4) The hypothesis and widely held belief
that hydrocarbon pore fluids suppress porosity loss due to
quartz cementation is not supported by detailed data and does
Thomas R. Taylor Shell International Ex-
ploration and Production, Projects and Technol-
ogy, 3737 Bellaire Boulevard, Houston, Texas
Tom Taylor has worked at Shells Bellaire Tech-
nology Center since 1982 in research and ap-
plications related to reservoir quality, diagenesis,
and rock properties. He holds a B.S. degree
from Winona State University and a Ph.D. from
Michigan State University.
Melvyn R. Giles Shell International Ex-
ploration and Production, 200 North Dairy
Ashford, Houston, Texas 77079-1197;
Melvyn R. Giles has a B.Sc. (honors) degree in
geology and chemistry from the University of
Bristol and a Ph.D. from the University of Glasgow.
He joined Shells Koninklijke/Shell Exploratie En
Produktie Laboratorium research center in 1980,
where he has been active in diagenesis, basin
modeling, overpressure, rock property, and geo-
physical research. He is currently the global theme
leader for unconventional gas.
Lori A. Hathon Shell International Ex-
ploration and Production, Projects and Tech-
nology, 3737 Bellaire Boulevard, Houston,
Texas 77025;
Lori Hathon worked in exploration and regional
studies for Amoco Production Company prior
to joining Shell International Exploration and
Production, Inc. in 1997. At Shell, she has per-
formed research in reservoir quality and physical
rock properties modeling. She holds a B.S. de-
gree from Michigan State University and a Ph.D.
from the University of Missouri.
Timothy N. Diggs Shell International Ex-
ploration and Production, 200 North Dairy Ash-
ford, Houston, Texas 77079-1197;
Tim Diggs holds undergraduate and graduate
degrees from the University of Virginia and the
University of Texas at Austin. He has more than
24 years of experience in clastic and carbonate
petrology, with more than 20 years at Shell work-
ing on field- to regional-scale reservoir charac-
terization. He has also worked extensively with
numerous types of unconventional reservoirs,
including HPHT, oil shales, and fractured reservoirs.
Copyright ©2010. The American Association of Petroleum Geologists. All rights reserved.
Manuscript received July 13, 2009; provisional acceptance December 4, 2009; revised manuscript
received January 25, 2010; final acceptance April 21, 2010.
AAPG Bulletin, v. 94, no. 8 (August 2010), pp. 10931132 1093
not represent a viable predictive model. (5) Heat-flow pertur-
bations associated with allochthonous salt bodies can result in
suppressed thermal exposure, thereby slowing the rate of quartz
cementation in some subsalt sands.
The success of many hydrocarbon exploration efforts depends
in large part on finding sandstone reservoirs with sufficient
porosity and permeability to support commercial develop-
ment. Assessing reservoir quality risk is especially important
in plays and prospects where objective sandstones have been
exposed to elevated temperatures (>100°C) and/or high ef-
fective stresses for significant periods of geologic time.
The detection of seismic bright spots and other direct hy-
drocarbon indicators led to a boom in deep-water exploration
in Tertiary basins worldwide in the 1980s and early 1990s.
However, direct seismic detection of reservoir sandstones and
differentiation of pore-fluid type are made problematic as a re-
sult of changes in acoustic rock properties associated with pro-
gressive diagenesis. In most of the cases involving highly lithified
sandstones and bounding mudrocks, confidently distinguishing
seismic impedance response associated with contrasting fluid
types (brine, oil, or gas) from that attributable to variable sand-
stone porosity is not possible (Kittridge et al., 2004a, b). Fur-
thermore, seismic differentiation of sandstone reservoirs con-
taining low-saturation gas from those with pore systems highly
saturated with oil becomes increasingly difficult as sandstone
porosity decreases. These factors, coupled with the degradation
of seismic resolution with depth, make assessment of reservoir
quality risk from seismic attributes alone highly suspect.
As a general rule, in first-cycle basins, sandstone porosity
decreases with increasing depth (Figures 1,2), giving rise to re-
gional porosity-depth or porosity-temperature curves that have
commonly been applied in hydrocarbon exploration (Schmoker
and Gautier, 1988; Schmoker and Schenk, 1994, Ehrenberg
et al., 2008). Occurrences of high-quality reservoir sandstones
that deviate from normal porosity-depth trends are attributed
to processes or conditions that have limited compaction and/
or cementation, or to porosity enhancement by dissolution of
grains or preexisting cements. Bloch et al. (2002, p. 301) defined
anomalous porosity or permeability as “…statistically higher
than the values in typical sandstone reservoirs of a given li-
thology, age, and burial/temperature. In sandstones contain-
ing anomalous porosities, such porosities exceed the maximum
Neil R. Braunsdorf Shell International
Exploration and Production, Projects and Tech-
nology, 3737 Bellaire Boulevard, Houston,
Texas 77025;
Neil Braunsdorf holds undergraduate and grad-
uate degrees from Stony Brook University and
the University of Michigan. He has more than
25 years of experience in exploration and ex-
ploration research with Shell, investigating varied
aspects of rock and fluid properties and pore-
pressure prediction. His current research inter-
ests include unconventional reservoirs and
predrill rock property prediction in complex
geological settings.
Gino V. Birbiglia Sarawak Shell Berhad,
Locked Bag No.1, Miri, Sarawak, Malaysia
Gino Birbiglia joined Shell in 1997. He has a
broad technical background, including previous
roles as a development geologist, exploration
geophysicist, and regional exploration geologist.
He has worked in deep-water, shelf, and on-
shore environments, primarily in the United States
and Southeast Asia. Presently, he is living and
working in Malaysia evaluating new exploration
opportunities in Southeast Asia.
Mark G. Kittridge Shell International Ex-
ploration and Production, 200 North Dairy
Ashford, Houston, Texas 77079-1197;
Mark G. Kittridge is a principal technical expert
(quantitative interpretation) and a regional dis-
cipline lead in petrophysics with Shell Interna-
tional EP Inc. He joined Shell in 1988 after earning
B.Sc. and professional degrees in geological en-
gineering from the Colorado School of Mines
and an M.Sc. degree in petroleum engineering
from the University of Texas.
Calum I. Macaulay Shell International
Exploration and Production, Projects and Tech-
nology, 3737 Bellaire Boulevard, Houston,
Texas 77025;
Calum Macaulay is a sedimentary petrologist.
He holds a B.Sc. degree in geology and miner-
alogy from the University of Aberdeen and a
Ph.D. in applied geology from the University of
Strathclyde. As a postdoc at the Scottish Uni-
versities Research and Reactor Center and the
Universities of Glasgow and Edinburgh, he in-
vestigated diagenetic processes for 10 years
before joining Shell in 2001.
1094 Sandstone Reservoir Quality Prediction
porosity of the typical sandstone subpopulation.By this defi-
nition, the term anomalous porosity could be applied, for
example, to sandstones with 25, 15, or 6% porosity depending
on the background porosity typically encountered. For exam-
ple, in Miocene sandstones of offshore Texas (Figure 2), one
might consider porosities of about 22% or more at depths
greater than 4000 m (13,000 ft) to be anomalous.
The complex and variable interplay of factors such as sand
composition, texture, and fluid chemistry under conditions of
variably increasing temperature and effective stress through
time yields a wide range of potential outcomes with respect to
reservoir porosity and permeability. The high-reservoir-quality
end of this range is not in the strict sense anomalous but rep-
resents the reasonable consequence of a specific combination
of geologic factors.
Given the task of evaluating reservoir quality risk with little
or no data, the explorationist is forced to rely on geologic models
and concepts. Selecting the appropriate model or analog is
not always straightforward, especially in true frontier settings.
Some models are supported by empirical and/or theoretical
evidence and have the potential to be applied in a predictive
manner. Others, although conceptually plausible, do not with-
stand rigorous testing against geological and petrophysical data
yet are widely accepted by exploration geoscientists within the
Significant progress has been made in recent years toward
the successful application of calibrated numerical models (e.g.,
Exemplar, Touchstone) that forecast sandstone porosity and
permeability by modeling mechanical compaction and quartz
cementation as a function of thermal and effective stress histo-
ries (Lander and Walderhaug, 1999; Walderhaug, 2000; Lander
et al., 2008). However, many of the key factors that influence
the modeled evolution of porosity and permeability (e.g., sand
texture, grain coats, carbonate cements, authigenic clays) are im-
portant model inputs (Panda and Lake, 1994, 1995) that must
be constrained via use of analog data or diagenetic models and
In this article, we critically evaluate existing methods and
diagenetic concepts that are commonly invoked to explain the
occurrence of anomalous, high-quality sandstone reservoirs at
relatively high temperatures and effective stresses. These in-
clude (1) porosity-versus-depth trends, (2) influence of over-
pressure on sandstone compaction and cementation, (3) inhibi-
tion of quartz cement precipitation by grain coatings, (4) porosity
enhancement by dissolution of framework grains or cements,
(5) preservation of porosity due to emplacement of hydro-
carbon pore fluids and, (6) suppression of quartz cementation
Irene S. Espejo Shell International Ex-
ploration and Production, 200 North Dairy
Ashford, Houston, Texas 77079-1197;
Irene Espejo has more than 18 years of industry
experience, having joined Shell in 2001. Her
work involves upscaling properties among thin
section, core, log, and subseismic scales, relat-
ing them to depositional environments, prove-
nance, rock properties, and reservoir quality
modeling. Previous experience includes a research
associate appointment at Rice University. She
holds a doctorate degree from the University of
Buenos Aires.
The authors gratefully acknowledge Shell In-
ternational Exploration and Production for the
permission to publish this article. Numerous
Shell colleagues have contributed to the ideas
and analysis presented in this article by means
of spirited critical discussions. We also thank
R. H. Lander, L. M. Bonnell, and R. E. Larese for
the permission to include data and illustrations
from their work. Editorial comments by L. I.
Summa, L. M. Bonnell, K. Bjørlykke, and R. H.
Lander are acknowledged and greatly appreciated.
The AAPG Editor thanks the following reviewers
for their work on this article: Knut Bjørlykke,
Linda Bonnell, and Lori Summa.
Taylor et al. 1095
in subsalt settings. We then review the appropriate
functions of these concepts in prospect and play risk
Porosity-versus-depth curves are routinely employed
to estimate sandstone porosity. Although instruc-
tive in some respects, this approach is not a partic-
ularly robust way of predicting reservoir quality for
sandstones. These trends have proven useful in un-
lithified sands with limited textural and mineral-
ogic variability where mechanical compaction is the
dominant porosity-reducing mechanism (e.g., Gulf
of Mexico deep-water Tertiary turbidites). How-
ever, simple extrapolation of compaction trends to
greater depths where cementation rates increase is
prone to significant error.
In the Gulf of Mexico, PliocenePleistocene to
late Miocene sands are dominantly unlithified, and
porosity tends to decline with burial depth (Figure 1).
Several factors contribute to the existence of this
straightforward relationship. The data were derived
from clean sands with a relatively narrow range in
grain size and sorting (mean grain size 80120 mm,
moderately well sorted). The sands are dominantly
composed of rigid framework grains of similar com-
position and roughly similar mechanical properties.
In the northern Gulf of Mexico deep-water region,
overpressures related to compaction disequilibrium
are established at relatively shallow depths and
tend to increase in a predictable manner with depth
(Ostermeier, 1995; Kittridge et al., 2004a). Depth
below sea floor in this case is a proxy for system-
atically increasing the vertical effective stress (VES).
Because of the generally low thermal gradients in
the deep-water Gulf of Mexico region, the sands in
the data set are currently at less than 80°C and al-
most entirely unaffected by quartz or other volu-
metrically significant cementation. As such, from
sea bottom to approximately 4500 m (14,750 ft),
mechanical compaction as a function of VES is the
dominant control on sand porosity (Figure 1).
At greater depths (45007500 m [14,750
24,600 ft]) and higher temperatures, porosity in
deep-water Gulf of Mexico sandstones is much more
variable and no longer follows a simple depth trend
(Figure 1). This reflects the onset of significant quartz
cementation (temperature >100°C) and, in some
cases, greater porosity loss caused by mechanical
compaction. Also plotted are data from two Gulf of
Figure 1. Porosity-versus-depth trends
for sands from two Tertiary offshore
deep-water basins: the Gulf of Mexico
(GOM) and offshore Niger Delta. Data
are derived from core and wireline log
measurements. Gulf of Mexico wet-sand
log data (solid gray squares) represent
unlithified deep-water sands currently
at their maximum burial depths and at
temperatures less than 80°C. Log data
from four deep Gulf of Mexico wells
(solid black circles) correspond to deep-
water Miocene sands at maximum burial
depths with temperatures greater than
80°C. Core-porosity data from two Gulf
of Mexico shelf wells (open triangles) are
also from Miocene sands with present-
day temperatures in excess of 80°C.
Offshore Niger Delta log porosity data
(solid gray triangles) define a trend
(dotted line) that provides a very poor
match to core-porosity data from a
nearby well (light-gray diamonds).
1096 Sandstone Reservoir Quality Prediction
Mexico Basin shelf wells where higher thermal
gradients push the onset of quartz cementation to
shallower depths than observed in the deep-water
region. Clearly, we can conclude from these data
that extrapolation of simple porosity-depth trends
into the realm of high-temperature diagenesis is
fraught with errors.
An additional pitfall associated with using
porosity-depth trends for reservoir quality predic-
tion is the inappropriate application of trends de-
rived from one basin to another basin. Data from a
single deep-water lease block, offshore Nigeria, are
plotted along with Gulf of Mexico data in Figure 1.
The Nigeria wireline-log data define a trend with a
greater porosity decline with depth than observed
in the Gulf of Mexico data set. When core data from
the same block are plotted, they define an even
greater rate of decline with depth. Several factors
are at play here. Sediments in offshore Nigeria are
characteristically at hydrostatic or only mildly over-
pressured conditions and are therefore exposed
to much greater VES at a given depth than deep-
water Gulf of Mexico sediments. In addition, Ni-
ger Delta sands are characterized by a much greater
range of grain size and sorting (mean grain size
120500 mm; well to poorly sorted) resulting
in a much greater span of initial depositional po-
rosities than Gulf of Mexico sands. Furthermore,
within areas like offshore Nigeria where widely
variable sand textures are the norm, a single porosity
Figure 2. Compilation of petrophysical
(core and wireline log) data for middle
Miocene sandstones from 37 wells in the
Brazos, Mustang Island, and Matagorda
Island areas of the Corsair trend, offshore
Texas. Extensive petrographic study has
shown that variable calcite cement abun-
dance is the primary control on porosity
variation. Anomalously high porosity values
occur locally in some deeply buried sand-
stones at Picaroon field (Brazos A-19, A-20).
Taylor et al. 1097
trend for all sands does a very poor job of describing
In extreme cases, porosity-versus-depth plots
are essentially useless for accurate predrill predic-
tion (Figure 2). Middle Miocene (15 Ma) sand-
stones from the offshore Texas continental shelf
exhibit a broad range in porosity over the depth
range of approximately 20006000 m (6500
19,700 ft). Petrographic and log analyses indicate
that varying quantities of pore-filling calcite cement
is the main reason for such widely variable poros-
ities (Vogler and Robison, 1987; Taylor, 1990; Taylor
and Land, 1996). The mean porosity trend for this
data set is meaningless with regard to predicting
porosity for a given well or prospect.
Increasing effective stress caused by sediment load-
ing is the major physical force driving the reduction
in porosity of sandstones by compaction. Mechan-
ical compaction is the dominant process by which
sand porosity is reduced from surface depositional
values of 4050% to typical values of 2532% prior
to lithification (Houseknecht, 1987; Paxton et al.,
2002). The development of fluid overpressures less-
ens the VES, thereby reducing the load borne by
intergranular and cement-grain contacts within bur-
ied sand. Overpressures can slow the rate of com-
paction but do not result in a bulk-rock volume (i.e.,
porosity) increase. Both experimental and empirical
evidence indicates that compaction of sand is an
irreversible process (Giles, 1997).
Significant porosity preservation is commonly
suggested to occur as a result of fluid overpressures
in sandstones (Ramm and Bjørlykke, 1994; Wilson,
1994; Osborne and Swarbrick, 1999). This hy-
pothesis is taken further in most basin modeling
programs that assume that a simple dependence
of porosity on effective stress exists (Schneider
and Hay, 2001). An exploration strategy based on
overpressuring would thus predict more favorable
reservoir quality in overpressured intervals than
in equivalent, normally pressured reservoirs. Two
mechanisms have been proposed. First, porosity that
would otherwise be lost to compaction is held open
by overpressures, resulting in anomalously porous
sandstones at significant burial depths. Second,
overpressures have been suggested to limit or pre-
vent significant quartz cementation by forestalling
the onset of intergranular pressure solution, there-
by eliminating a presumed primary source of silica
(Osborne and Swarbrick, 1999; Walgenwitz and
Whonham, 2003).
Effective Stress, Sand Composition, and
Porosity Data
Sandstone compaction is dependent not only on
effective stress history, but also on the mechanical
properties of the sand. The mechanical strengths
of the various individual detrital components and
authigenic cements combine to determine the bulk
mechanical strength of a sediment, which deter-
mines how a given sand will respond to increasing
effective stress.
Bloch et al. (2002) examined relationships among
effective stress history, detrital grain ductility, and
the onset of quartz cementation using numerical
compaction and cementation models. The models
contrast hypothetical end-member quartz-rich (rigid)
and lithic-rich (ductile) sands. For both lithic-rich
and quartz-rich sands, early overpressures provide
a depth window of potential porosity preservation
until temperatures reach the point where signifi-
cant quartz cementation can occur (>90°C). Late
development of overpressures has a much smaller
or negligible effect on porosity. Given sufficient time
and increasing temperature due to increasing burial,
the models predict that, in the absence of robust grain
coats, intergranular porosity preserved by inhibition
of compaction will be filled with quartz cement
negating the positive effects of fluid overpressure.
Given the natural range of sand composition,
one should clearly not expect a global VES-porosity
relationship to exist. Nonetheless, unlithified sands
of generally similar framework-grain composition fol-
low fairly consistent local or regional VES-porosity
trends (Giles, 1997). In these examples, present-day
VES represents the maximum historical effective
stress. Geologic situations in which present-day VES
1098 Sandstone Reservoir Quality Prediction
does not represent the historical maximum may in-
volve uplift and/or late development of overpres-
sures. In compressional settings, the maximum prin-
cipal stress may not be the vertical component, and
in such cases, one would not expect VES to be
related to sandstone porosity in any meaningful way.
Examination of internally consistent, quanti-
tative petrographic data collected by the authors
illustrates the difficulties of relating present-day
VES to reservoir properties in sandstones that have
been subjected to various degrees of diagenesis.
The data set consists of 645 analyses of sandstones
ranging in age from Miocene to Permian and cov-
ering a broad range in framework composition
(Figure 3). All the sandstones included in the data
set have less than 5% detrital matrix clay, with most
containing less than 1%. A plot of intergranular
volume (IGV), a parameter used to gauge com-
paction state (IGV = intergranular porosity + S
pore-filling cements + matrix; expressed in terms of
the percentage of bulk-rock volume) versus VES,
shows a high degree of scatter with a general weak
trend of decreasing average IGV with increasing
stress (Figure 4A). An analogous plot of VES ver-
sus thin-section porosity reveals no discernable
trend, only a tendency for maximum porosity to
decline with increasing VES (Figure 4B). The large
overall scatter observed is attributable to differences
in sand texture, composition, and cementation.
If the generation of dissolved silica by pressure
solution is a significant control on sandstone res-
ervoir quality, a systematic trend toward increased
compaction and quartz cement abundance with
increasing VES should be evident. Moreover, an
inverse correlation between IGV and quartz ce-
ment volume would be expected if the bulk vol-
ume is reduced via dissolution at grain contacts
and quartz cement is precipitated within the ad-
jacent intergranular pore space. In the global data
set presented here, the volume of quartz cement
shows no correlation with VES (Figure 5), suggest-
ing that overpressured sands have had equal access
to sources of silica for quartz cementation. Clearly,
VES alone does not provide the level of precision
required to assess reservoir quality risk for diage-
netically modified sandstones prior to drilling.
Figure 3. Standard quartz,
feldspar, and rock fragment plot
for global sandstone data set
used in subsequent plots and
discussions (Folk, 1974). GOM =
Gulf of Mexico.
Taylor et al. 1099
In most sandstone reservoirs with quartz cement,
the cement crystals nucleate on detrital quartz grains.
These overgrowth crystals have the same crystal-
lographic orientation as their grain substrates.
Authigenic quartz crystals of this type grow into the
adjacent pore space and commonly result in signif-
icant progressive loss of intergranular porosity with
increasing temperature (Bjørlykke and Egeberg,
1993; Giles et al., 2000; Walderhaug, 2000). Em-
pirical and theoretical studies have shown that
quartz cementation in sandstones is controlled by
the rate of precipitation, which is highly sensitive
to temperature (Oelkers et al., 1996; Walderhaug,
1996). Experimental and empirical evidence in-
dicates that precipitation rate is also influenced by
the grain size of the quartz substrates (Lander et al.,
2008). The volume of quartz cement can therefore
be directly related to an integrated time and tem-
perature function, the size distribution of potential
quartz substrates, and the quartz surface area avail-
able for precipitation (Walderhaug, 1996, 2000;
Lander and Walderhaug, 1999; Lander et al., 2008).
The formation of grain coats on the surface of de-
trital quartz grains prior to the onset of significant
quartz precipitation is thought to inhibit cementa-
tion by forming a barrier that prevents widespread
nucleation of quartz. The most effective types of
grain coats observed in sandstones are clay minerals
and microcrystalline quartz. Other less effective
types of grain coats include detrital clay rims and
fine crystalline carbonates (e.g., siderite).
Clay Coats
The importance of clay mineral coats in preserving
porosity in sandstones has been recognized in nu-
merous studies (Heald and Larese, 1974; Thomson,
1979; Pittman et al., 1992; Ehrenberg, 1993; Bloch
et al., 2002; Anjos et al., 2003; Taylor et al., 2004).
Figure 4. Thin-section data versus present-day vertical effective stress (VES) for the global sandstone data set. (A) Intergranular
volume (IGV) versus VES. (B) Thin-section porosity versus VES.
1100 Sandstone Reservoir Quality Prediction
These reports present examples in which sand-
stones that lack or have poorly developed clay coats
are highly cemented with authigenic quartz, whereas
identical sands with robust grain coats contain much
lower volumes of quartz cement. Authigenic chlorite
is the most important and effective grain-coating
mineral in terms of limiting extensive quartz ce-
mentation in sandstones. This is in large part due to
the strong tendency of chlorite to form continuous
layers that line the interface between detrital grains
and intergranular pore space (Figure 6). Authigenic
illite and mixed-layer clays are less frequently re-
ported as grain coatings (Storvoll et al., 2002). In
general, detrital clay rims, formed by processes
such as mechanical infiltration, are less continuous
than authigenic coatings and therefore less effec-
tive in inhibiting quartz cement nucleation (Wilson
and Pittman, 1977; Bloch et al., 2002) although
authigenic clay coats may form in part from detrital
A prime example of the effectiveness of con-
tinuous chlorite coats is the Jurassic Norphlet For-
mation in Mobile Bay, offshore Alabama (Dixon
et al., 1989; Taylor et al., 2004; Ajdukiewicz et al.,
2010, this issue). At this location, the eolian Norphlet
is an excellent gas reservoir with porosities com-
monly in the range of 1520% at depths of 6600
7000 m (21,60023,000 ft) below the sea floor.
Most detrital grain surfaces are coated with chlo-
rite, and only minor amounts of quartz cement are
found (Figure 7A). Where small discontinuities in
the chlorite rims occur in the uppermost part of the
Figure 5. Volume of authigenic quartz
cement from thin-section versus present-
day vertical effective stress for the global
sandstone data set.
Taylor et al. 1101
section, authigenic quartz has nucleated on the un-
coated surface and filled the adjacent intergranular
pore space (Figure 7B).
Quantitative data confirm the observations as
to the importance of clay coats in limiting porosity
loss due to quartz cementation. For example, an
inverse relationship exists between the volume of
quartz cement and the percentage of detrital quartz-
grain surface coated with clay in Jurassic and Triassic
sandstones from the North Sea (Figure 8). These
reservoirs are currently at their historical maximum
temperatures of approximately 130160°C. The
scatter in the data is attributed to natural variations
in composition, texture, and local burial histories.
In comparison, data from the Norphlet Formation
follow a much steeper trend (Figure 8). Norphlet
reservoirs at this location are currently at temper-
atures greater than 200°C and have been hotter
than 100°C for approximately 100 m.y. (Taylor
et al., 2004). This comparison illustrates the strong
temperature dependence of quartz precipitation
rate. Furthermore, it is evident that, for higher tem-
perature reservoirs, much greater grain-coat cov-
erage is required to preserve significant amounts of
porosity. Numerical models for quartz cementa-
tion also predict that increasingly complete grain
coats are needed to preserve porosity given high
thermal exposures (Bloch et al., 2002; Lander et al.,
Chlorite has been the subject of many diage-
netic studies; however, no proven method of pre-
dicting chlorite coats in data-poor frontier settings
exists (Bloch et al., 2002). In more mature settings
where core data are available, the probability of
chlorite coatings can be assessed using sedimento-
logical and petrographic analog data. Further study,
more data from modern analogs, and experiments
are needed to decipher the mechanisms of chlorite
authigenesis, including the potential impact of bio-
logical controls (Needham et al., 2005).
Several of the most important examples of chlo-
rite coatings preserving economic reservoir quality
are from deltaic and near-shore marine sandstone
facies (Ehrenberg, 1993; Hillier, 1994; Grigsby,
Figure 6. Scanning electron
microscope photomicrographs of
grain-coating authigenic chlo-
rite in a Miocene sandstone from
the Gulf of Mexico. (A) Low-
magnification view reveals nearly
continuous chlorite coats on de-
trital quartz grains. (B) Higher
magnification view correspond-
ing to the box in panel A.
Figure 7. Thin-section photo-
micrographs of eolian sandstone
from the Jurassic Norphlet For-
mation, offshore Alabama, Gulf of
Mexico. (A) Detrital grains are
lined with highly continuous
chlorite rims. Only minor amounts
of quartz cement are present.
(B) A small discontinuity in the
chlorite coating (arrow) allows
authigenic quartz to nucleate and
develop a syntaxial overgrowth.
1102 Sandstone Reservoir Quality Prediction
2001). These are typically iron-rich varieties of chlo-
rite and are associated with areas of river discharge
into marine environments. Examples of deeply bur-
ied, porous eolian sand reservoirs with highly con-
tinuous, Mg-rich chlorite grain coats (e.g., Norphlet,
Rotliegend) are found in association with evaporite
deposits (Kugler and McHugh, 1990; Hillier et al.,
1996). The alteration of volcanic rock fragments
and glass provides internal sources for the elemental
components required to form authigenic chlorite in-
dependently of depositional environment (Thomson,
1979; Pittman et al., 1992; Anjos et al., 2003).
Microcrystalline Quartz Coats
on detrital quartz grains has been identified as a
potentially effective mechanism for inhibiting the
formation of pore-filling quartz overgrowths (Aase
et al., 1996). Because of the crystal size, microcrys-
talline quartz is difficult to detect in thin section
using standard light microscopy but easily identified
using standard scanning electron microscope (SEM)
secondary electron images (Figure 9). Microquartz
coats consist of a layer of approximately 115-mm,
prismatic quartz crystals with randomly oriented
c-axis directions. The morphology of microcrystal-
line quartz is thought to be a result of rapid crys-
tallization from silica-supersaturated solutions.
Dissolution of siliceous sponge spicules, a vari-
ably abundant but common component of shallow-
marine Jurassic and Cretaceous sandstones in the
North Sea, provides a mechanism for creating and
maintaining elevated concentrations of dissolved
silica at relatively low temperatures. Dissolution
of amorphous, silica-rich volcanic glass also repre-
sents a potential detrital source for generating silica
Although initially it seems peculiar to propose
that one morphology of quartz would inhibit or
prevent the nucleation of another, growing empiri-
cal, theoretical, and experimental evidence support
Figure 8. The volume of quartz cement and the percentage of
coated quartz surface area, both determined petrographically,
are plotted for Jurassic and Triassic sandstones from the central
North Sea and for the Jurassic Norphlet sandstones of Mobile
Bay in the Gulf of Mexico.
Figure 9. Scanning electron
microscope photomicrographs
of microcrystalline quartz in
Jurassic Fulmar Formation sand-
stones of the central North Sea.
(A) Minute crystals of quartz line
the surfaces of detrital quartz
grains in this example. The crys-
tals range from approximately 1
15 mm in length measured along
the c axis. (B) High-magnification
view of microquartz crystals.
The c-axis directions are generally
not aligned with the c axis of
the underlying detrital quartz grain.
Taylor et al. 1103
such a mechanism (Bonnell et al., 2006a, b; Lander
et al., 2006). Documented examples of micro-
quartz coats in deeply buried, porous sandstones
are from Jurassic and Cretaceous intervals of the
North Sea (Aase et al., 1996; Ramm et al., 1997;
Jahren and Ramm, 2000; Aase and Walderhaug,
2005) and from Devonian sandstones of western
Brazil (Lima and De Ros, 2002). In these examples,
sand intervals that contain robust microcrystalline
quartz coats have significantly lower amounts of
quartz overgrowth cement and have higher inter-
granular porosity than associated sandstones that
lack well-developed microquartz coats.
The apparent capacity for microcrystalline quartz
to inhibit the development of pore-filling quartz
overgrowths is likely related to crystal growth me-
chanics (Lander et al., 2006). The random c-axis
orientations of microquartz crystals (Haddad et al.,
2006) may prevent their merging into larger syn-
taxial, quartz overgrowths. Laboratory experiments
and numerical modeling studies (Bonnell et al.,
2006a, b; Lander et al., 2006) indicate that quartz
nucleation and growth on a microcrystalline quartz
substrate are significantly slower than on a mono-
crystalline quartz host. Additional experiments
(Lander et al., 2008) strongly suggest that growth
rates slow greatly once quartz crystals achieve
euhedral form. Smaller crystals growing next to
larger crystals in the experiments achieve euhedral
terminations much sooner. From that point for-
ward, the growth rate for small euhedral crystals
is radically diminished, whereas the larger crystals
continue to grow. The growth mechanisms revealed
in these experiments are potentially analogous to
the effects of microcrystalline quartz in naturally
occurring sandstones.
The term secondary porosity refers to pore space
resulting from postdepositional dissolution of detri-
tal grains or cements. Petrographic evidence for sec-
ondary porosity produced by leaching of feldspars,
lithic fragments, and carbonates is very commonly
observed and has been documented in numerous
reports (Loucks et al., 1979, 1984; Schmidt and
McDonald, 1979; Mathisen, 1984; Taylor, 1990;
Ehrenberg and Jakobsen, 2001). In the 1970s and
1980s, the notion that porosity in deeply buried
sands was dominantly secondary porosity produced
intense debates. Based mostly on qualitative petro-
graphic observations and interpretations, this idea
was accepted by many as fact (Loucks et al., 1979;
Schmidt and McDonald, 1979). Opposing views
centered on the apparent lack of viable geochemical
mechanisms by which dissolution and mass trans-
fer could occur in the deep subsurface (Bjørlykke,
1984; Bjørlykke and Brendsdal, 1986; Lundegard
and Land, 1986; Giles, 1987; Giles and de Boer,
1990; Bjørlykke, 1998; Chuhan et al., 2001).
Volume Considerations: How Much
Secondary Porosity?
Porosity related to framework-grain dissolution
(e.g., feldspars) can be recognized and statistically
quantified by most capable and experienced sand-
stone petrographers. Dissolution of pore-filling ce-
ments (e.g., calcite) is less commonly recognized
and more difficult to quantify. The absence of ce-
ment should not be interpreted as secondary po-
rosity unless considerable petrographic evidence
of its former presence can be established. For this
reason, careful consideration must be given to the
criteria used to classify porosity. In our opinion, a
critical eye must be cast on conclusions derived from
large public data sets due to the application of in-
consistent, subjective criteria, made by multiple
petrographers of varying levels of experience, re-
garding quantities of secondary porosity. As a re-
sult, the volume of secondary porosity is probably
overstated in some publications.
In the following analysis, only petrographic data
collected by the authors using consistent standards
for determining porosity types are used. For this
reason, a high degree of confidence is placed in the
volume of porosity attributed to the dissolution of
framework grains in this data set, as summarized
in Table 1. These data are representative of sand-
stones from a variety of depositional environments,
basin settings, geological ages, geothermal gradients
and thermal maturities.
1104 Sandstone Reservoir Quality Prediction
The total thin-section porosity is the sum of
visible intergranular porosity and framework-grain
dissolution porosity. In Figure 10, these two po-
rosity types are plotted versus the maximum burial
temperature as determined from basin modeling
studies. No simple relationship exists in our data set
between framework-grain dissolution porosity and
temperature. The greatest volume (mean = 4.8 ± 2%)
Table 1. Summary of Global Petrographic Porosity Data
Thin-Section Porosity Framework-Grain Dissolution Porosity
Mean Max Min
Deviation NMean Max Min
Gulf of Mexico, Eocene 17.3 27.0 3.5 6.4 129 1.7 5.0 0.0 1.1
North Sea, Jurassic 19.7 29.6 6.6 5.6 101 4.8 9.3 0.1 2.0
Gulf of Mexico, Miocene1 20.3 33.0 0.0 7.6 116 1.0 5.3 0.0 1.1
Gulf of Mexico, Miocene2 14.5 29.6 1.3 7.8 66 1.6 6.3 0.0 1.4
Gulf of Mexico, Jurassic 9.2 19.0 0.0 4.8 63 0.2 2.0 0.0 0.4
North Sea, Triassic 12.3 23.0 5.0 4.2 68 1.1 3.3 0.0 0.9
West Africa, Oligocene 22.8 35.0 12.7 5.3 20 1.2 4.3 0.0 1.0
North Sea, Permian 21.1 25.7 15.3 3.4 13 2.9 5.8 0.4 2.2
Figure 10. Porosity types derived from
thin-section analyses versus maximum his-
torical temperature for a global sandstone
data set. The open symbols represent the total
thin-section porosity (TSf) and the filled
symbols represent the volume of framework-
grain dissolution porosity (FGDf). GOM =
Gulf of Mexico.
Taylor et al. 1105
occurs in Jurassic sandstones from the North Sea
and is primarily the result of feldspar dissolution
(Haszeldine et al., 1999; Taylor et al., 2005). All of
the other sandstones average 2% or less framework-
grain dissolution porosity (Table 1). Two sandstone
units with mean values of less than 1.1%, the Tri-
assic Skagerrak Formation from the central North
Sea and the Jurassic Norphlet Formation from the
Gulf of Mexico, are highly feldspathic sands that
have been exposed to high temperatures for ex-
tended geologic periods. We can conclude from
Figure 10 that although porosity from framework-
grain dissolution can be important in some situa-
tions, it generally represents a minor fraction of total
porosity. Further evidence is revealed in a large
regional data set (750 point-count analyses) from
the Eocene Wilcox sands of the Texas Gulf Coast,
collected by a single petrologist. The volume of
framework-grain dissolution porosity varies, aver-
aging 1.7%, and shows no discernable trend with
depth (Figure 11). Total thin-section porosity de-
creases with depth due primarily to the precipita-
tion of intergranular pore-filling cements. Although
the proportion of framework-grain dissolution po-
rosity to total visible porosity increases with depth,
the absolute volume is statistically constant.
An additional important question regarding the
formation of secondary porosity from dissolution
of aluminum-silicate framework grains is whether
porosity or permeability is significantly enhanced as
a result of the overall process (Bjørlykke, 1984; Giles
and Marshall, 1986). At issue is the effective mass
transfer of the products of dissolution and the scale
on which it occurs (Hays and Boles, 1992). If the
frame of reference is a standard thin section, one
end-member case is that in which all the compo-
nents of framework-grain leaching (e.g., feldspars)
are precipitated in the pore network as an authigenic
phase (e.g., kaolinite, illite), resulting in an insig-
nificant change in total porosity and a significant
decrease in permeability (Figure 12A). The opposite
end-member case results in most of the dissolved
components being transported out of the frame of
Figure 11. Porosity types derived from thin-section analyses
versus burial depth for Eocene Wilcox sandstones from the Texas
Gulf Coast. The open symbols represent the total thin-section
porosity (TSf) and the filled symbols represent the volume of
framework-grain dissolution porosity (FGDf).
Figure 12. Thin-section photo-
micrographs showing examples
of framework-grain dissolution.
(A) Feldspars and volcanic rock
fragments show evidence of
extensive dissolution. Abundant
authigenic chlorite and illite clays
line and partially fill pore space.
(B) Feldspar-grain dissolution
results in secondary porosity,
and insignificant amounts of
authigenic clay are found.
1106 Sandstone Reservoir Quality Prediction
reference, leading to a net increase in porosity with-
out a reduction of permeability (Figure 12B). In
the collective experience of the authors, the most
common result for dissolution of aluminum silicate
minerals is nearer to the first end member where
clay minerals are precipitated in roughly equal pro-
portions to the dissolved solid volume. Cases of true
porosity enhancement due to dissolution of feldspars
and lithic grains are less frequently encountered.
Chemical Drive for Secondary
Porosity Generation
In the 1980s and early 1990s, attempts were made
to reconcile the observedoccurrence of framework-
grain dissolution pores and the lack of geochemical
models capable of explaining their formation. The
efforts to predict the development and location of
secondary porosity in the subsurface were directed
at identifying the geochemical mechanisms by which
subsurface dissolution could occur.
Carbon Dioxide and Organic Acids
The production of CO
by thermal decarboxyla-
tion of organic matter was initially proposed as a
mechanism for generating carbonic acid, presum-
ably driving dissolution and development of sec-
ondary porosity (Schmidt and McDonald, 1979;
Franks and Forester, 1984). The results of mass bal-
ance calculations, however, indicate that the amount
of CO
generated by this process cannot account
for the volumes of secondary porosity commonly
observed in sandstones (Bjørlykke, 1984; Lundegard
et al., 1984; Giles and Marshall, 1986; Lundegard
and Land, 1986). This mass-balance discrepancy is
particularly evident when one considers that in-
organic chemical equilibria between pore fluids,
feldspars, clay minerals, and carbonates control
in clastic reservoirs (Smith and Ehrenberg,
1989; Hutcheon et al., 1993). Large perturbations
in pCO
and carbonic acid concentration are there-
fore not possible in these strongly rock-buffered,
clastic systems.
Surdam and coworkers (Surdam et al., 1984,
1989; Crossey et al., 1986; Surdam and Yin, 1994)
proposed that short-chained carboxylic acids, gen-
erated from maturation of kerogen within source
rocks, supply the chemical drive for the formation
of secondary porosity in sandstones. Expulsion and
migration of these water-soluble organic compounds
were seen as a practical mechanism linking inorganic
and organic diagenesis in the creation and filling of
reservoirs. On the basis of formation water analyses
(Carothers and Kharaka, 1978; Hanor and Workman,
1986; Kharaka et al., 1986; Lundegard and Kharaka,
1990; MacGowen and Surdam, 1990), a tempera-
ture window from 80 to 140°C was hypothesized
as optimal for secondary porosity generation. The
proposed effect of these organic acids at their peak
concentrations was todecrease the stability of both
carbonate and aluminosilicate minerals. In addi-
tion, carboxylic acids were thought to inhibit the
precipitation of authigenic clay by complexing alu-
minum derived from feldspar dissolution.
The hypothesized link between organic acids
and porosity enhancement in sandstones sparked
considerable research. However, numerous lines of
evidence and extensive further research cast se-
rious doubt on the proposed mechanisms. Objec-
tions were raised on a series of issues:
1. Detailed chemical analyses of formation waters
indicate that most contain concentrations of or-
ganic acids that are too low to significantly in-
fluence bulk rock-water equilibria (Barth and
Bjørlykke, 1993; Lundegard and Kharaka, 1994).
2. Mass-balance calculations reveal that the vol-
ume of organic acids that can be derived from
typical source rocks is insufficient to account for
the observed volumes of secondary porosity
(Lundegard and Land 1986; Giles and Marshall
1994; Pittman and Hathon, 1994; Giles, 1997).
3. Geochemical studies have failed to substantiate
meaningful levels of Al-complexing by organic
acids, a potentially instrumental factor for sig-
nificant feldspar dissolution (Bevan and Savage,
1989; Stoessell and Pittman, 1990; Manning
et al., 1991; Giles and Marshall, 1994; Harrison
and Thyne, 1994).
4. Geochemical modeling using experimental and
estimated thermodynamic data indicates that or-
ganic acid anions have minimal influence on rock-
water reactions in natural systems (Harrison and
Thyne, 1994; Hyeong and Capuano, 2001).
Taylor et al. 1107
For more extensive discussion, the interested
reader is directed to the references above and others
cited in those articles.
Equilibrium Water-Rock Reactions
Diagenetic reactions in intermediate to deep burial
regimes are rock buffered (Smith and Ehrenberg,
1989; Land and Macpherson, 1992; Hutcheon et al.,
1993; Hanor, 1996; Giles, 1997). Reactions involv-
ing the dominant aluminum silicate and carbonate
minerals found in most siliciclastic rocks control
the evolution of aqueous pore fluids in sedimentary
basins. As a consequence of relatively low porosities,
pore fluids represent comparatively small volumes
and thus cannot dissolve large volumes of solid
minerals unless extremely high (unrealistic?) flow
rates are involved (Giles, 1997). This has impor-
tant implications with regard to understanding and
modeling how much secondary porosity can in fact
be formed during burial diagenesis.
Dissolution and replacement of detrital potas-
sium and plagioclase feldspar are natural conse-
quences of diagenesis under conditions of increas-
ing burial and temperature. No unusual or special
source of acidic pore fluids is required (Giles and de
Boer, 1990). Under the most common circum-
stances, unstable feldspar grains react to form more
stable authigenic phases (e.g., albite, kaolinite, illite)
with the pore waters acting primarily as transport
agents. As pore fluids reach equilibrium with the
reacting feldspar phases, mass transport must oc-
cur for further reactions to proceed. The scales of
mass transport determine whether reservoir poros-
ity and permeability are indeed enhanced by the
overall process. As stated above with regard to feld-
spar dissolution, most cases studied by the authors
involve little or no net gain in sandstone porosity and
permeability. Exceptions are the Jurassic Fulmar
and Heather sandstones of the deep central graben
of the central North Sea where the observed vol-
ume of secondary porosity attributable to feldspar
dissolution exceeds the volume of authigenic clay
minerals on the thin section or core scale (Haszeldine
et al., 1999; Taylor et al., 2005). Another rare de-
viation from the norm is the Jurassic Norphlet
Sandstone in Mobile Bay (offshore Gulf of Mex-
ico), where detrital K-feldspar grains have authi-
genic K-feldspar overgrowths and where little or no
evidence is found for feldspar alteration despite
burial to temperatures in excess of 200°C (Taylor
et al., 2004). The evident stability of K-feldspar is
related to the chemistry of pore fluids in the Nor-
phlet. Formation waters from Mobile Bay fields are
extremely saline brines (300 g/L total dissolved
solids [TDS]) with exceptionally high concentra-
tions of dissolved potassium (1317 g/L). These
brines are in equilibrium with K-feldspar, and no
significant chemical drive exists for further reaction.
Dissolution of significant amounts of carbonate
cements and detrital carbonate grains in sandstones
is of debatable importance (Taylor, 1990; Hesse
and Abid, 1998). The greater solubility of carbon-
ate minerals compared to aluminum silicate min-
erals suggests that porosity enhancement could more
readily occur without precipitation of byproducts
(i.e., clay minerals) that negatively impact perme-
ability. Nevertheless, carbonate dissolution is sub-
ject to similar mass balance and rock-dominated
equilibrium constraints as feldspar dissolution. Pore
waters equilibrate relatively quickly with carbonate
minerals in the subsurface. The volume of solid
carbonate minerals that can be dissolved by a single
volume of pore fluid is necessarily small given typical
water/rock ratios. The removal of a large enough
quantity of carbonate material to significantly im-
pact reservoir quality hence requires fluid flow to
replenish the system with undersaturated solutions.
Given that the rates of compactional fluid flow in
deep subsurface environments are extremely lim-
ited (Bethke, 1985; Giles, 1987, 1997; Harrison
and Summa, 1991), porosity enhancement by dis-
solution of carbonate minerals is not likely to be
One area where carbonate dissolution is thought
to be a factor in reservoir quality enhancement is
the Corsair trend (offshore Texas, Gulf of Mex-
ico). Deeply buried middle Mioceneaged sand-
stones are frequently cemented with calcite along
the more than 100-mi (161-km)-long Corsair fault
system (Vogler and Robison, 1987; Taylor, 1990).
Reservoir quality is significantly impaired by the
presence of pore-filling calcite in most locations
as evidenced in numerous unsuccessful explora-
tion tests along the trend that have encountered
1108 Sandstone Reservoir Quality Prediction
sandstones with marginal or noneconomic poros-
ity. Thick sandstones with anomalously high po-
rosities (>20%) are found at only a few locations, the
most notable being Picaroon field.
The anomalous nature of the high porosities at
Picaroon field is clearly seen in a porosity-versus-
depth plot for middle Mioceneage sands of the
Corsair trend (Figure 2) and in a porosity-versus-
permeability plot (Figure 13). At depths greater than
approximately 4200 m (13,800 ft), Picaroon area
sands fit the definition of anomalous porosity quoted
previously (Bloch et al., 2002). A detailed petro-
graphic study has established evidence for partial
dissolution of pore-filling calcite cement and de-
trital carbonate grains in the most porous sands at
Picaroon (Figure 14), which is lacking in the sands
with typically lower porosity from the region (Taylor,
1990; Taylor and Land, 1996). Additional quartz
cementation following calcite dissolution is inhib-
ited by the presence of grain-coating chlorite that
Figure 13. Porosity versus permeability
from laboratory core analyses of middle
Miocene deltaic sandstones from the Corsair
trend, offshore Texas. Sandstones from
Doubloon and Plank locations lack evi-
dence of calcite dissolution and significant
secondary porosity. The highest porosities
at Doubloon are approximately 1521%,
and the maximum for Plank is 17%. Nearby
Picaroon area sands span the same range
but extend to porosities in the range of
2029%. Petrographic examination indi-
cates that dissolution of calcite occurred in
the high porosity and permeability sand-
stones from the greater Picaroon area.
Figure 14. Thin-section photo-
micrographs of middle Miocene
reservoir sandstones from Pica-
roon field, offshore Texas. (A) A
highly corroded detrital calcite
grain (center) is typical of those
found in highly porous (2029%)
reservoir sandstones from Pica-
roon. Small, irregularly shaped
remnants of ferroan calcite ce-
ment (arrows) occur nearby.
(B) Corroded remnants of ferroan
calcite cement (mauve) are com-
sandstones from Picaroon.
Taylor et al. 1109
formed prior to calcite cementation. Statistical com-
parisons using thin section and core analysis data
indicate that deep sandstones from Picaroon have on
average 46% greater porosity than equivalent-age
sands from nearby locations (Taylor and Land, 1996).
Although obtaining conclusive proof is impossible,
carbonate dissolution has probably been a signifi-
cant factor in contributing to the observed anom-
alous porosities.
Understanding the reasons why carbonate dis-
solution is substantial at Picaroon but not at other,
geologically similar locations is important if predrill
prediction of comparable anomalous deep porosity
is to be achieved. Evidence is found in the chemical
composition of produced formation waters from
Picaroon and Doubloon fields, located approximately
6 mi (9.6 km) apart (Taylor and Land, 1996). For-
mation waters from Doubloon field are moderately
saline Na-Cl brines (6275 g/L TDS), typical of
those found in the Gulf of Mexico Cenozoic section
(Morton and Land, 1987; Land and Macpherson,
1992). Incontrast, formation waters produced from
Picaroon are highly saline Na-Ca-Cl brines (150
244 g/L TDS) with uncommonly high concentra-
tions of Sr, Ba, Fe, Pb, and Zn. The major and trace
element compositions and isotopic signatures of
Picaroon brines are comparable to brines produced
from underlying, deep, high-temperature reservoirs
of Mesozoic age (Taylor and Land, 1996). The asso-
ciation of chemically distinct, allochthonous brines
with anomalously high porosities and ample pet-
rographic evidence for calcite dissolution strongly
suggests a link between a deep source of fluid and
the diagenetic evolution of these sands. Taylor and
Land (1996) proposed a model in which highly sa-
line brines in chemical equilibrium with sedimen-
tary rocks at very high temperatures (>250°C)
are episodically injected along the Corsair fault
causing focused dissolution in sandstones in the
greater Picaroon area. The fact that this process
does not operate everywhere along the Corsair re-
gional growth-fault system suggests that the geo-
logical conditions that provide access to deep-fluid
sources are somewhat extraordinary. Examples
from isolated fields in onshore south Texas present
similar evidence of calcite dissolution and associ-
ated saline Na-Ca-Cl brines in the Oligocene Frio
Formation (Diggs, 1992; Diggs and Land, 1993).
In contrast to the Picaroon example, however, con-
tinued postdissolution diagenesis obscures any sig-
nificant porosity gain in the Frio reservoirs. Giles
and de Boer (1989) proposed a comparable model
that could result in calcite dissolution in sandstones
adjacent to fault zones. Driven by the retrograde
solubility of calcite coupled with fluid migration
along porous fault zones, localized dissolution zones
could potentially develop where permeable sands
provide a conduit for cooling fluids.
The idea that the presence of hydrocarbon pore
fluids in sandstones could influence porosity loss
by inhibiting cementation was offered many years
ago (Johnson, 1920). The concept has been widely
accepted by geologists and geophysicists as a
mechanism for porosity preservation in sandstones
that have been exposed to high temperatures. The
extent to which this process might operate is im-
portant because, if found to be effective, the focus
of reservoir quality modeling changes from inor-
ganic diagenetic reactions toward prediction of early
hydrocarbon migration and trapping.
Examples of high porosity at structural crests
and declining porosity toward structural flanks
within an existing hydrocarbon accumulation, or
contrasts in porosity across oil-water contacts, are
commonly cited as evidence that hydrocarbon em-
placement inhibits diagenesis (Emery et al., 1993;
Gluyas et al., 1993; Marchand et al., 2000, 2001).
ferred to be due to continued diagenesis (e.g., quartz
or carbonate cementation, authigenic clay forma-
tion) in the water leg.
The existence of oil-bearing fluid inclusions in
quartz cement is cited as evidence to the contrary,
proving that cementation continues with some frac-
tion of hydrocarbon fluids present in the pore sys-
tem (Ramm, 1992; Saigal et al., 1992; Walderhaug
1996). Hydrocarbon fluid inclusions also occur in
carbonate and albite cements. Authigenic illite in
the Garn Formation (Norwegian continental shelf)
1110 Sandstone Reservoir Quality Prediction
shows no significant change in abundance across
several oil-water contacts (Ehrenberg and Nadeau,
1989), suggesting that illite precipitation continues
in the oil column within the continuous water phase
or precipitated throughout prior to hydrocarbon
emplacement. Illite K-Ar ages have been used to
investigate the possibility of diagenesis influenced
by hydrocarbon charge (Burley and Flisch, 1989;
Hamilton et al., 1992; Darby et al., 1997; Wilkinson
et al., 2006), but analytical issues involving sepa-
ration of detrital and authigenic phases cloud the
interpretation of these data.
Worden and coworkers (Worden et al., 1998;
Barclay and Worden, 2000; Worden and Morad,
2000) presented a thorough review of the empir-
ical and theoretical arguments for and against po-
rosity preservation by hydrocarbon emplacement.
For water-wet sands under conditions of high hy-
drocarbon saturation, advective transport of silica
into sands (e.g., from mudrocks) essentially stops
because of the very low relative permeability to
water. Similarly, advective transport of the chem-
ical components needed for carbonate cementation
would be impeded. Diffusive transport of silica (or
3) within a static but connected
water phase could still proceed. However, at low
to irreducible water saturations, diffusion must oc-
cur through much longer and more tortuous paths.
The rate of diffusive transport of silica in solution
may become progressively slower as the oil satura-
tion increases and water saturation decreases. Ulti-
mately, at very low water saturation, diffusion could
slow by up to two orders of magnitude (Worden
et al., 1998), supplanting quartz precipitation as the
rate-controlling step and essentially halting quartz
cementation. For the relatively rare case of oil-wet
sands, the mechanism is much like grain-coating
chlorite, effectively isolating detrital quartz grains
from the aqueous pore fluids.
Proposed Field Examples: How Strong is
the Evidence?
Despite anecdotal evidence being widespread within
the industry, convincing documented cases of hy-
drocarbons inhibiting diagenesis are rare. In most
instances, the lack of conventional core in general
or from the water leg in particular precludes the
quantitative comparison of cement volumes and po-
rosity types required to rigorously evaluate the po-
tential effect of pore-fluid type on diagenesis. As a
result, porosity preservation by hydrocarbon em-
placement is sometimes advocated as a model
without examining other possible causes. These in-
clude differences in grain size and sorting (related
to depositional environment or facies), sand com-
position (facies or provenance related), and diage-
netic alteration (i.e., cementation or porosity en-
hancement unrelated to the present hydrocarbon
and water distribution).
Suppression of Quartz Cement Precipitation
In a study of the Middle Jurassic sandstone res-
ervoirs of the North Sea Brent Group, Giles et al.
(1992) compiled data from 44 wells over a broad
geographic area. The data span a wide range of
burial depths and temperatures. This extensive and
detailed data set was used to show that reservoir
quality is primarily related to depositional facies,
compaction, and quartz cementation. A compar-
ison of measured porosities for 2917 samples of
Brent Group sandstones shows that no systematic
difference between the porosity can be expected
in the hydrocarbon zones as opposed to the water-
bearing zones. Molenaar et al. (2008) compared
the porosity and volumes of quartz cement in oil-
and water-bearing Cambrian sandstones from the
Baltic Basin and reported no significant difference
related to pore-fluid type.
Other studies that have made arguments for a
causal link between oil emplacement and suppres-
sion of quartz cementation in central North Sea Ju-
rassic sandstones (Emery et al., 1993; Gluyas et al.,
1993) present virtually no quantitative data regard-
ing facies, sandstone texture and composition, quartz
cement abundance, or porosity types. Furthermore,
no mention of the presence or absence of grain-
coating clay is made. The lack of these key data
makes it impossible to critically assess whether hy-
drocarbon pore fluids have in fact influenced the
diagenesis of these sands.
More recent investigations reached conflicting
conclusions regarding the diagenesis of the Juras-
sic Brae Formation sandstones from Miller field
Taylor et al. 1111
(south Viking Graben, North Sea) (Figures 15,16).
Marchand et al. (2000, 2001) presented data in-
increases from 6% in the oil-bearing zones at the
structural crest to 13.2% in the water-bearing sands
along the structural flank. Statistical data are in-
cluded to demonstrate that sand composition, grain
size, and sorting do not vary significantly as a func-
tion of structural or paleodepositional position. The
results of kinetic modeling calculations are inter-
preted to show that oil emplacement has signifi-
cantly retarded the rate of quartz precipitation.
Subsequent studies (Aase and Walderhaug,
2005; Bonnell et al., 2006a, b) present data and
evidence that contradict the previous work. Addi-
tional petrographic data from core material not
used in the original study reveal that highly quartz-
cemented sandstones occur in the oil column as well
as in the water leg (Figure 17). When all data are
taken into account, no discernable relationship be-
tween quartz cement volume and pore-fluid type is
apparent. Detailed petrographic analyses employ-
ing the SEM (Figure 18) document the presence
of microcrystalline quartz coats in the sandstones
with comparatively low volumes of quartz cement
(Bonnell et al., 2006a, b). When petrographic data
from three wells are plotted versus depth, sandstones
with the highest grain coat coverage and lowest
quartz cement are evidently confined to the upper-
most sands in the J stratigraphic unit (Figure 17A,
B). The stratigraphically controlled distribution of
microcrystalline quartz coats at Miller field likely
reflects the concentration of detrital sponge debris
related to favorable marine conditions present at the
time of deposition.
The relative timing of quartz cementation in
sandstones and maturation of the source rocks must
be considered when evaluating the possible effects
of hydrocarbon emplacement on porosity evolu-
tion. Both processes are highly dependent on ther-
mal exposure (temperature over time) with the rate
of quartz cement precipitation increasing exponen-
tially as temperature exceeds approximately 80°C.
The rate of oil generation from source rocks com-
monly peaks between temperatures of approximately
110 and 140°C. Peak generation temperature for in-
dividual source rocks is a function of organic matter
composition, heating rate, and geologic time.
To illustrate the potential consequences of the
difference in relative timing of inorganic and organic
diagenetic processes, three simple geologic scenar-
ios are considered. Touchstone modeling software
is used to calculate and compare the volumes of
quartz cement that would be generated in each set
of geologic circumstances. Two well-sorted, 0.12
0.16-mm (0.0040.006-in.), quartz-rich sands (Q:
80; F: 7; R: 13) were used as starting material
for the diagenetic simulations. Grain coatings were
assumed to be negligible. Model parameters for
quartz precipitation kinetics and compaction were
obtained from internal studies and held constant in
all the model runs.
In the first case, the reservoir sandstone is bur-
ied to a maximum depth corresponding to a tem-
perature of 80°C (Figure 18A). An older, organic-
rich source rock occurs considerably deeper in the
Figure 15. Quartz cement volume determined from thin section
versus depth for Jurassic sandstones from the Miller field, United
Kingdom North Sea (data from L. M. Bonnell, R. E. Larese, and
R. H. Lander, 2006, personal communication). Points A, B, and C are
referenced and explained in Figure 16. OWC = oil-water contact.
1112 Sandstone Reservoir Quality Prediction
section at a temperature of 120°C and has reached
its oil generation peak. At the hypothetical well
location, quartz cementation in the reservoir would
be in an incipient stage with only minor volumes
(<1%) of authigenic quartz present (Figure 19,
model 18a). Following the migration of oil into the
reservoir, a well penetration would encounter highly
porous, oil-bearing sandstone. Given this situa-
tion, the emplacement of hydrocarbons has had
no factor in influencing cementation and reservoir
The second scenario considers the case of a
sandstone reservoir juxtaposed with an organic-rich
source rock (Figure 18B). The reservoir-source rock
pair follows virtually the same burial history, en-
tering the greater than 80°C temperature window
for quartz cementation long before the source rock
reaches peak oil generation. During this time, quartz
precipitation occurs forming volumetrically signifi-
cant amounts of cement (4.65.5%) prior to oil em-
placement (Figure 19, model 18b). Oil-bearing fluid
inclusions in quartz cement and albitized feldspar
grains may form during the filling of the reservoir.
Given the proximity of the source rock, migration
and charge would be geologically simultaneous. If
we assume that peak oil charge occurs at 120°C and
no further burial or heating occurs, then the sand-
stone would exhibit no discernable evidence of ce-
ment suppression due to hydrocarbon charge. Fluid
inclusions in quartz cement and authigenic albite
would yield homogenization temperatures of less
than approximately 120°C.
A modification of the previous configuration
in which subsequent burial and heating to 150°C
occur (Figure 18C) could yield evidence at the hy-
pothetical well location that would allow the eval-
uation of the hypothesized hydrocarbon effect. If
hydrocarbon emplacement occurred at 10 Ma when
temperatures reached approximately 120°C and
impeded further precipitation of quartz cement,
fluid-inclusion evidence would reflect this upper
temperature limit. Furthermore, approximately 2
3% quartz cement would be found in the reservoir
if oil emplacement halted cementation (Figure 19,
Figure 16. Photomicrographs
of Jurassic Brae Formation sand-
stones at Miller field, United King-
dom North Sea (from L. M. Bonnell,
R. E. Larese, and R. H. Lander,
2006, personal communication).
(A) Low-magnification SEM view
showing the surfaces of detrital
grains within an intergranular
pore. This sample has high poros-
ity and low quartz cement (point A
in Figure 15, hydrocarbon leg).
(B) High-magnification view. De-
trital quartz grain surfaces are
coated with microcrystalline
quartz in this highly porous res-
ervoir interval. (C) Thin-section
photomicrograph of lower poros-
ity interval with abundant over-
growth quartz cement (point B in
Figure 15, hydrocarbon leg).
(D) Scanning electron microscope
photomicrograph of lower poros-
ity interval (point C in Figure 15,
water leg). Note the lack of micro-
crystalline quartz and develop-
ment of large quartz overgrowths.
Taylor et al. 1113
Figure 17. Petrographic data from Jurassic Brae Formation sandstones at Miller field, United Kingdom North Sea, plotted versus
(A) Sandstones with grain coat coverage of greater than 30% (primarily microcrystalline quartz) are found exclusively in the J-level
stratigraphic unit at Miller field. (B) Samples with lower amounts of quartz cement are concentrated in the J-level sandstones at Miller field.
The low volumes of quartz cement correspond to higher degrees of grain coat coverage and greater intergranular porosity. Note that
abundant quartz cementoccurs at the top of the structure in close proximity to microquartz-bearing samples with low cement abundances.
OWC = oil-water contact.
1114 Sandstone Reservoir Quality Prediction
model 18c-HC). In comparison, Touchstone calcu-
lations made assuming that hydrocarbon pore fluids
do not significantly impede cementation (Figure 19,
model 18c) predict much greater amounts of quartz
cement (8.09.4%). If aqueous fluid inclusions were
present in these cements, homogenization tempera-
tures would approach an upper threshold of 150°C.
Associated hydrocarbon-bearing inclusions might
be expected as well.
The hydrocarbon filling history of most sand-
stone reservoirs is undoubtedly more complicated
than the three hypothetical examples presented
above. Nonetheless, these end-member scenarios
are useful when considering the types of data and
evidence that are required to thoroughly evaluate
whether hydrocarbon pore fluids have influenced
quartz cementation rates.
The Fulmar Formation of the central North Sea
high pressure-high temperature area provides an
opportunity to test whether hydrocarbon pore
fluids have had any discernable effect on quartz
cementation. Cores from Shearwater field, a large
gas condensate accumulation, and the Martha well
(22/30a-1), a water-bearing Fulmar section, have
been studied and compared in detail (Taylor et al.,
2005). Porosities commonly range between 24 and
33% at depths of 45005800 m (14,75019,000 ft)
(Figure 20) and temperatures are approximately
145170°C. Extreme overpressures are encoun-
tered in this area with the highest fluid pres-
sures approaching lithostatic levels (Cayley, 1987;
Gaarenstroom et al., 1993; Darby et al., 1996). The
main hydrocarbon source rock in the area is the
Upper Jurassic Kimmeridge Clay, which occurs
stratigraphically above the Fulmar. Hydrocarbon
charge modeling indicates that oil generation and
migration began at approximately 100 Ma and
peaked at 7060 Ma, whereas peak gas generation
occurred from 15 to 0 Ma (Winefield et al., 2005).
Porosity generally decreases with depth below
the top of the Fulmar in Shearwater wells that pen-
etrate the gas-water contact (Figure 20). However,
Figure 18. Schematic cross sections depicting reservoir sand
and source rock configurations. (A) At the well location, a sand-
stone reservoir occurs at a depth where temperatures have
reached approximately 80°C. The hydrocarbon source rock
occurs at greater depth where the in-situ temperature is about
120°C. (B) The sandstone reservoir and hydrocarbon source
rock are juxtaposed. At the well bottom, the temperature has
reached approximately 120°C. (C). The sandstone reservoir and
hydrocarbon source rock shown above in panel B have under-
gone greater burial where the bottom-hole temperature is ap-
proximately 150°C.
Taylor et al. 1115
visual examination of the core slabs and thin sec-
tion analyses indicate that porosity decline is due
to the transition from relatively clean upper shore-
face sands to bioturbated, clay-rich, lower shoreface
sands. The present-day gas-water contact occurs far
beneath the porosity drop. The Martha well pene-
trated an entirely water-bearing Fulmar section with
comparatively low porosity at the top that increases
with depth (Figure 21).
The composition and texture of the Fulmar
sandstones at the two locations are similar (Table 2).
The amounts of detrital quartz, feldspar, and lithic
grains are comparable. The range of IGV values
overlaps, indicating analogous levels of mechanical
compaction. Quartz cement volumes are roughly
the same with a slightly greater average abundance
at Shearwater. Total authigenic pore-filling and
replacement clay (chlorite and illite) is on average
4% greater at Shearwater. As a result, Fulmar sands
at the Martha well have proportionally greater
intergranular porosity. Framework-grain dissolution
porosity is significant in both locations but some-
what higher at Martha.
Both aqueous and liquid petroleum fluid in-
clusions are present in quartz cement in samples
from Shearwater field, indicating that quartz pre-
cipitation was active during filling of the reservoir.
Homogenization temperatures for the aqueous
inclusions range from 126 to 155°C, approaching
present-day bottom-hole temperatures (165°C).
Log, core, and geochemical analyses of the Fulmar
at the Martha location have uncovered no indica-
tion of a previous static hydrocarbon accumulation.
However, quartz cement contains some liquid pe-
troleum fluid inclusions as well as aqueous inclu-
sions, suggesting that hydrocarbons have periodically
Figure 19. Touchstone model results for
three schematic burial histories, models
18ac, corresponding to scenarios illus-
trated in Figure 18. Model 18c-HC rep-
resents the results assuming that oil em-
placement occurs at 10 Ma and stops
further formation of quartz cement (see
the text for an explanation).
1116 Sandstone Reservoir Quality Prediction
migrated through the Fulmar at Martha (Winefield
et al., 2005).
Basin modeling indicates that during peak oil
generation and migration, temperatures in the Fulmar
sands at both Martha and Shearwater were between
7584°C. If hydrocarbon pore fluids had signifi-
cantly slowed quartz precipitation, one would ex-
pect to find that quartz cement formed at a much
slower rate at Shearwater given present-day tem-
peratures and their comparable thermal histories.
Numerical modeling of compaction and quartz ce-
mentation using Touchstone indicates that quartz
cement precipitation occurred at similar rates in the
Fulmar sandstones at both Shearwater and Martha
(Figure 22). A single set of model parameters for
both compaction and quartz precipitation kinetics
yields consistently good fit for both data sets de-
spite the clear differences in their exposure to hy-
drocarbon pore fluids. These model parameters
have been successfully applied in a predrill predic-
tion mode for other locations (Taylor et al., 2005).
The model results, data, and observations, along with
or more porous than gas condensate-bearing sands
at Shearwater, clearly indicate that hydrocarbon
pore fluids did not significantly influence quartz
cementation rates and reservoir quality.
The results of basin modeling predict that a zone
of suppressed temperatures will occur beneath thick
salt sequences (Mello et al., 1995). This phenom-
enon is caused by the high thermal conductivity
of salt (K
6.0 W m
at 100°C) relative
to shale and sand (K
1.5 and 3.5 W m
100°C, respectively), allowing for heat to be more
rapidly transmitted away from the underlying strata
(the thermal conductivity of salt is highly tempera-
ture dependent and decreases with increasing tem-
perature, thus the contrast is greatest at shallow
depths of burial). As a consequence, temperatures
Figure 20. Wireline logs
through the Fulmar sandstone
gas reservoir at Shearwater field
(United Kingdom central North
Sea, 22/30b) reveal a decrease
in porosity with depth. Upper
shoreface sands dominate the
upper Fulmar, whereas the lower
Fulmar is composed of lower
shoreface, bioturbated sands.
As seen in the resistivity log re-
sponse, the current gas-water
contact is found well below the
point where porosity decreases
from approximately 2530% to
values of approximately 20%.
Open circles represent porosity
analyses of core samples.
Taylor et al. 1117
above large salt bodies are typically elevated com-
pared to laterally depth-equivalent strata farther
away from salt. The properties of the sediments,
structural configuration, depth of salt, thickness of
salt, and the timingof salt emplacement controlthe
magnitude of this effect.
The volume of quartz cement precipitated in
a sandstone per unit time is primarily controlled
by temperature and the available quartz substrate
surface area. The rate at which quartz cement pre-
cipitates increases exponentially with temperature,
rising by a factor of approximately five between 70
and 100°C and another factor of five between 100
and 135°C. Suppression of temperature over time
could clearly have a significant impact on the loss of
porosity due to quartz cementation. This can be par-
ticularly important in sandstones that lack significant
grain-coating clay and are therefore highly suscep-
tible to quartz cementation at high temperature.
Gulf of Mexico Examples
Wells that penetrate the thick allochthonous salt
in the Gulf of Mexico have frequently encountered
subsalt sedimentary sections that are substantially
cooler than predicted by regional geothermal gradi-
ents. For example, at Tahiti field in the deep-water
Gulf of Mexico (Green Canyon 640), wells pene-
trate approximately 3000 m (9800 ft) of alloch-
thonous salt prior to encountering Miocene reservoir
sands at depths of more than 7000 m (23,000 ft)
below the sea floor. Subsalt well temperatures are
depressed approximately 30°C relative to the re-
gional trend for nonsubsalt wells at depths of 5800
7500 m (19,00024,600 ft) (Figure 23). In contrast,
at a well location more than 200 km (124 mi)
away (Poseidon; Mississippi Canyon 727), roughly
1200 m (3900 ft) of salt section was drilled above
Miocene-aged sands found at depths of approxi-
mately 52007500 m (17,00024,600 ft). In this
case, subsalt temperatures are consistent with the
higher regional geothermal gradient for the Mis-
sissippi Canyon area.
Petrographic analysis of core material from
Tahiti wells indicates the presence of minor amounts
of quartz cement (12%) in clean sands with po-
rosities that range between 21 and 24% (Figure 24A)
at depths of more than 7000 m (23,000 ft). In stark
contrast, sandstones of equivalent-age and compar-
able composition from Poseidon (Figure 24B),
where temperatures are more than 40°C hotter at
roughly the same depth, have substantially more
quartz cement (27%) and porosities of only 12
17%. The differences in porosity are mostly attrib-
uted to differences in quartz cement volumes, a di-
rect result of the contrasting thermal histories.
The timing, thickness, burial depth, and verti-
cal separation of salt from the underlying objective
sandstone reservoir may all be important factors
in determining the magnitude of the thermal sup-
pression effect on quartz cementation. A thermal
modeling exercise using stratigraphic data and model
parameters appropriate for the Gulf of Mexico,
Figure 21. Wireline logs through the Fulmar sandstone res-
ervoir at the Martha well location (22/30a-1; United Kingdom
central North Sea). The well encountered highly porous, water-
bearing sandstone with no evidence of significant hydrocarbons.
Open circles represent porosity analyses of core samples.
1118 Sandstone Reservoir Quality Prediction
deep-water Mississippi Canyon area illustrates the
direction and potential magnitude of change asso-
ciated with these factors. The resulting temper-
ature histories brought about by simulated varia-
tions in the timing of salt emplacement and the
induced effects on quartz cementation are shown
in Figures 2527. Eleven Gulf of Mexico Miocene
sandstone samples, for which petrographic data were
available, were used as starting material for Touch-
stone simulations (Table 3). Appropriate model
parameters for mechanical properties of the ma-
jor framework grains and for quartz precipitation
kinetics were taken from previous unpublished
studies of Gulf of Mexico Miocene sands. These
were held constant for all simulation scenarios to
compare only the effects of thermal history on po-
rosity evolution. Note in the following discussion
that these results apply to the specific cases pre-
sented. Different results are likely where geologic
factors and rock properties depart significantly from
those assumed here.
Presence of salt. The impact of the presence or
absence of allochthonous salt is illustrated by
comparing a thermal model derived assuming no
salt in the sedimentary section to another with
approximately 1500 m (4921 ft) of salt. Salt
emplacement is modeled to occur from 9.4 to
9.2 Ma (Figure 25A). The temperature histories
diverge at the initiation of salt emplacement and
follow different paths to the present at which
Table 2. Summary of Porosity, Grain Size, and Compositional Data for Fulmar Formation Sandstones from the Shearwater (22/30b)
and Martha (22/30a-1) Wells
Martha Shearwater
Mean Standard Deviation NMean Standard Deviation N
Core analysis porosity 30.7 1.7 15 29.2 1 9
Grain size (mm) 0.16 0.02 16 0.14 0.03 24
Intergranular porosity 16.2 3.5 16 10.9 3.7 24
Secondary porosity 5.9 1.7 16 4.2 1.1 24
Total clay 6.9 1.4 16 11.4 3.3 24
Quartz 42.4 4.2 16 43.1 6.1 24
K-feldspar 4.5 1.8 16 4.4 1.4 24
Plagioclase 7.8 2.4 16 5.4 2.7 24
Shale rock fragments 1.9 1.1 16 3.6 2.4 24
Quartz cement 3.7 2.9 16 4.4 1.6 24
Ankerite 0.8 1.3 16 1.1 1 24
Intergranular volume 27.2 2.3 16 27.2 4.3 24
Total cement 9.3 2.4 16 13.2 3.5 24
Figure 22. Touchstone quartz cementation model calibration
results for Fulmar sandstones from the Shearwater and Martha
wells. A single set of quartz precipitation kinetic parameters can
be used to accurately reproduce measured quartz cement vol-
umes within a model tolerance of ±3%.
Taylor et al. 1119
point the salt-free model is 23°C hotter. The
two temperature paths yield significantly dif-
ferent amounts of quartz cement and porosity
(Figure 25B, C), with predicted porosity valued
for the salt-free scenario approximately 57%
lower porosity than those predicted using the
1500-m (4921-ft) salt model.
Thickness of salt. The potential influence of
overlying salt thickness is demonstrated by a
comparison of thermal models for stratigraphic
sections containing 1500 and 3000 m (4921
and 9842 ft) of salt (Figure 26). The emplace-
ment of salt occurs over the same time interval
(11.7 to 9.1 Ma) but at double the rate for the
thicker salt scenario. The results for the 3000-m
(9842-ft)-thick salt scenario are roughly 22°C
cooler than those for the 1500-m (4921-ft) salt
model (Figure 26A). The Touchstone models
Figure 23. Measured temperature versus
depth for two deep-water Gulf of Mexico
wells. The Green Canyon (GC) and Mis-
sissippi Canyon (MC) regional thermal gra-
dients are shown for reference. The block
arrows depict the approximate thicknesses
and depth positions of salt encountered
in the two wells.
Figure 24. Equivalent-aged
Miocene sands from two subsalt
wells in the deep-water Gulf of
Mexico differ in the amount of
porosity and quartz cement.
(A) Thin-section photomicrograph
of Tahiti well reservoir sand-
stones. These sands contain
approximately 12% quartz ce-
ment. (B) Thin-section photo-
micrograph of Miocene sand-
stone from the Poseidon well.
Sandstones at Poseidon contain
27% quartz cement.
1120 Sandstone Reservoir Quality Prediction
predict that given these two thermal histories,
doubling the salt thickness will result in about
35% less quartz cement and greater inter-
granular porosity (Figure 26B,C).
Timing of salt emplacement. The possible ef-
fects of the timing of salt emplacement relative
to the reservoir interval are evaluated by con-
trasting two models in which 1500 m (4921 ft)
Figure 25. Burial history and Touchstone
simulations designed to evaluate the po-
tential effects of the presence of thick salt
on porosity loss due to quartz cementa-
tion. (A) Temperature versus time for two
hypothetical burial history scenarios, with
and without the presence of 1500 m (4921 ft)
of overlying salt. Salt emplacement occurs
between 9.4 and 9.2 Ma. (B) Porosity and
quartz cement volumes for clean sandstones
subjected to the thermal history for 1500 m
(4921 ft) of salt shown in panel A. (C) Po-
rosity and quartz cement volumes for
clean sandstones subjected to the thermal
history for the salt-free scenario shown
in panel A.
Taylor et al. 1121
of salt is emplaced. In one case, salt is emplaced
from 15.6 to 14.8 Ma and in the other case from
9.4 to 9.2 Ma (Figure 27A). The final tempera-
tures are essentially the same in these two mod-
els, but the temperature paths as a function of
time differ. In this example, the resulting effect
on quartz cement and porosity volumes is rela-
tively small (12% bulk volume), with early em-
placement producing marginally higher porosity
values (Figure 27B,C).
Figure 26. Burial history and Touchstone
simulations designed to simulate the po-
tential effects of the variable salt thickness
on porosity loss due to quartz cementation.
(A) Temperature versus time for two hy-
pothetical burial history scenarios, one with
1500 m (4921 ft) and the other with 3000 m
(9842 ft) of salt. Salt emplacement occurs
between 11.7 and 9.1 Ma. (B) Porosity and
quartz cement volumes for clean sandstones
subjected to the thermal history shown
in panel A for 1500 m (4921 ft) of salt.
(C) Porosity and quartz cement volumes for
clean sandstones subjected to the ther-
mal history shown in panel A for 3000 m
(9842 ft) of salt.
1122 Sandstone Reservoir Quality Prediction
Application in Predictive Mode: Gulf of Mexico
The subsalt cooling model was used to predict po-
rosity for a prospective deep-water Gulf of Mexico
subsalt well prior to drilling. The Perdido fold-belt
area contains several subsalt prospects and discov-
eries with varying thicknesses of salt cover (Fiduk
et al., 1999; Trudgill et al., 1999). This extreme
variation in salt thickness results in extreme dif-
ferences in predicted temperature at a given depth
below the sea floor. The prospect modeled here
Figure 27. Burial history and Touchstone
simulations designed to evaluate the po-
tential effects of the variable timing of salt
emplacement on porosity loss due to
quartz cementation. (A) Temperature ver-
sus time for two hypothetical burial history
scenarios; one in which salt emplacement
occurs between 15.6 and 14.8 Ma and the
other where salt emplacement occurs be-
tween 9.4 and 9.2 Ma. (B) Porosity and
quartz cement volumes for clean sand-
stones subjected to the thermal history
shown in panel A in which salt emplace-
ment occurs from 9.4 to 9.2 Ma. (C) Porosity
and quartz cement volumes for clean
sandstones subjected to the thermal history
shown in panel A in which salt emplace-
ment occurs from 15.6 to 14.8 Ma.
Taylor et al. 1123
targeted Eocene Wilcox sands as potential res-
ervoir intervals beneath approximately 2200 m
(7200 ft) of salt. A porosity versus temperature
regression, based on regional well data, had been
previously employed as a method to forecast po-
rosity for exploration prospects in the area. The
temperature regressions predicted an average po-
rosity of roughly 14 ± 4% for the upper Wilcox ob-
jective and about 9 ± 5% for the lower Wilcox ob-
jective (Figure 28) at the prospect well location.
Alternative predictions were made using a three-
dimensional (3-D) basin model (Cauldron) for the
prospect and a Touchstone model calibrated with
Wilcox sands from regional analogs. The Cauldron
and Touchstone models predicted mean porosity
values of approximately 24 ± 2% for the upper
Wilcox sand and roughly 17 ± 2% for the lower
Wilcox sand (Figure 28). The subsequent well pen-
etration encountered Wilcox sandstones with po-
rosity values consistent with the Touchstone model
predictions and significantly higher than fore-
casted using the simple temperature regressions
(Figure 28).
As discussed in a previous section, using present-
day measured parameters such as depth or tem-
perature to predict porosity in sandstones is prone to
errors in all but the most simple, low-temperature
Table 3. Summary of Textural and Compositional Data for Gulf
of Mexico Miocene Sands Used as Input for Touchstone Model
Simulations Shown in Figures 25, 26, and 27
Deviation N
Mean grain size (mm) 0.10 0.02 11
Sorting (Trask [P75/P25]) 1.54 0.14 11
Intergranular porosity 19.94 2.34 11
Secondary porosity 1.36 0.54 11
Matrix, pore-filling 0.44 0.79 11
Mono quartz 63.19 2.77 11
Poly quartz 4.59 2.68 11
K-feldspar 2.56 1.22 11
Plagioclase 0.91 0.51 10
Shale/silt RF* 0.70 0.37 8
Chert 1.15 0.89 10
Volcanic RF 0.25 0.22 7
Metamorphic RF 1.02 0.76 10
*RF = rock fragments.
Figure 28. Present-day temperature
versus porosity for Eocene Wilcox Group
sandstones from the Perdido area, Gulf of
Mexico. The regional T-porosity trend rep-
resents a regression fit to regional data
(small filled circles). Touchstone models
calibrated with regional analogs and cou-
pled with 3-D burial history models that
consider the effects of thick allochthonous
salt on thermal evolution predicted sig-
nificantly higher porosity prior to drilling
of the well (large circles: bar equals ± 1
standard deviation). The well results (solid
squares) are in good agreement with the
Touchstone model predictions.
1124 Sandstone Reservoir Quality Prediction
burial scenarios. The success of our approach to
predict porosity in Wilcox sandstones at this pros-
pect validates both the general methodology of
burial historybased reservoir quality modeling and
the subsalt porosity preservation mechanism.
Assessing reservoir quality risk for sandstones that
are currently, or have in the past been subjected
to extensive diagenetic alteration, remains a major
challenge for geoscientists in the petroleum indus-
try. Current approaches are applied with widely
variable success, attesting to the difficulty in mak-
ing quantitative predictions of complex geologic
Empirically calibrated kinetic models for quartz
cementation (Walderhaug, 1996; Lander and Wal-
derhaug, 1999), albitization of plagioclase (Perez
and Boles, 2005), smectite illitization (Pytte and
Reynolds, 1988; Velde and Vasseur, 1992; Huang
et al., 1993; Elliott and Matisoff, 1996), and fibrous
illite formation (Lander and Bonnell, 2010, this
issue) have been shown to be applicable for sand-
stones and mudrocks. Numerical forward model-
ing of sandstone compaction and quartz cementa-
tion (e.g., Touchstone) linked to thermal and stress
histories derived from rigorous basin modeling rep-
resents the present state of the art for quantitative
porosity and permeability prediction. As its use
has grown among petroleum industry sedimentary
petrologists and basin modelers, the need for more
accurate ways to constrain key model inputs is
Global applications of quartz cement models
based on the premise that the rate of quartz ce-
mentation is controlled by the kinetics of precip-
itation (Walderhaug, 1994, 1996; Oelkers et al.,
1996; Lander and Walderhaug, 1999) strongly sug-
gest that the sources of silica are readily available
on the geologic time scales at which significant
volumes of quartz cement form. Potential intra- and
extraformational sources of silica in clastic mudrock
and sandstone systems are many (McBride, 1989;
van de Kamp, 2008), and the sizable majority of
analyzed formation waters are saturated or super-
saturated with respect to silica (Land, 1997). Con-
sequently, the supposition in many basin modeling
programs that quartz cementation can be linked to a
single source such as stress-induced intergranular
pressure solution (i.e., chemical compaction) im-
plies systematic covariations between quartz ce-
ment, IGV, and effective stresses that are inconsis-
tent with data from reservoir sandstones (Figure 5).
Reservoir quality potential for many deeply buried
sandstones therefore hinges on issues of surface
area (e.g., grain size, sorting, composition) and the
presence and efficiency of grain coatings, most fre-
quently chlorite. Various sedimentological and geo-
chemical conditions that favor the formation of
grain-coating chlorite have been identified, but
accurate prediction remains elusive in most data-
poor exploration settings. Studies of the controls
on chlorite formation in sandstones may result in
better methods to quantitatively predict chlorite
coatings prior to drilling.
Rigorous evaluation of available field data and
evidence does not support the concept that the
presence of hydrocarbon pore fluids measurably
retards quartz cementation in sandstones. This sug-
gests that the underlying hypothesized process
is either not operative or extremely rare. Greater
understanding of wettability may reveal conditions
where oil-wet behavior is favored and the effects of
hydrocarbon pore fluids on cementation are po-
tentially more substantial. Little is known about
the possible effects of hydrocarbon pore fluids on
carbonate cementation in sandstones although field
examples have been reported (e.g., de Souza and
de Assis Silva, 1998). Given the current state of
knowledge, the proposed hydrocarbon fluid effect
does not represent a viable model for predicting
porosity preservation in sandstone reservoirs.
Although secondary porosity due to framework-
grain dissolution (primarily feldspars) is almost
ubiquitous, it represents a relatively minor propor-
tion of total porosity in most cases. Exceptions are
known but not necessarily well understood, accu-
rately predicted, or important on a global scale.
Porosity enhancement due to dissolution of car-
bonate cements and grains is also rare. To date, we
have documented such dissolution in one case where
Taylor et al. 1125
deep fluids were introduced into shallower sands
along fault zones. Efforts to predict the local occur-
rence of porosity enhancement related to deep-basin
fluid migration are limited by the quality of deep
seismic imaging of faults and the limitations of
existing geochemical and fluid-flow models.
Closer integration of diagenetic, depositional,
and 3-D basin models holds promise for more ac-
curate predictions. Regional variations in geother-
mal gradients in basins such as the Gulf of Mexico
(Nagihara and Smith, 2008) along with differ-
ences in sediment composition can drive very dif-
ferent diagenetic patterns as evidenced by the
dominance of carbonate cement in the offshore
Texas Miocene versus quartz cement in the off-
shore Louisiana Miocene. On a smaller scale, the
evolution of temperature over time in clastic sedi-
ments near allochthonous salt can potentially lead
to acceleration and suppression of rates of impor-
tant diagenetic reactions depending on location and
proximity. The development of 3-D basin models
that more realistically simulate salt emplacement
through time is needed to delineate prospect-scale
thermal histories and their effects on diagenetic
The development of fully coupled, diagenetic
and basin models that integrate processes operat-
ing on a broad range of length scales may represent
the way forward for reservoir quality prediction
in sandstones (Giles, 1997; Tuncay and Ortoleva,
2004). Pore-scale mineral precipitation or dissolu-
tion reactions can be affected by processes that oc-
cur on much smaller scales (Parsons et al., 2005;
Lüttge, 2006) or on much larger scales (Ayalon and
Longstaffe, 1988; Taylor and Land, 1996; Schulz-
Rojahn et al., 1998). Under some conditions, these
may couple to reinforce or cancel each other, po-
tentially influencing the development of diagenet-
ically induced reservoir quality heterogeneity of
importance at well, field, or basin scales. To be suc-
cessful, future models must move beyond present-
day reaction-transport models by incorporating a
more quantitative treatment of rock microstrucure
geometries and the effects of mineral surface prop-
erties on reactivity (Lasaga and Lüttge, 2003, 2004).
Although these models will by necessity be mathe-
matically based and require the application of su-
percomputers, natural and experimental rock data
derived using established and new petrographic,
geochemical, and petrophysical techniques are es-
sential for calibration and validation (Ullo, 2008).
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... Quartz is volumetrically the most important pore-occluding diagenetic cement in deeply buried clean sandstone reservoirs (McBride 1989;Ehrenberg 1990;Walderhaug 1996;Worden and Morad 2000;Molenaar et al. 2007;Gier et al. 2008;Worden et al. 2018a;Worden et al. 2018b). Quartz cementation starts at around 70-80°C (McBride 1989;Bjørlykke and Egeberg 1993;Walderhaug 1994a;Storvoll et al. 2002;Lander et al. 2008;Ajdukiewicz and Lander 2010;Taylor et al. 2010;Oye et al. 2018). The presence of early-formed clay coats (e.g., chlorite) can inhibit quartz cementation by blocking nucleation sites and making the surface area unavailable for poreoccluding quartz overgrowths, thereby preserving anomalously high porosity in deeply buried sandstones (Worden and Morad 2000;Bloch et al. 2002;Ajdukiewicz and Larese 2012;Nguyen et al. 2013;Stricker and Jones 2016;Worden et al. 2020;Xia et al. 2020). ...
... Quartz cementation is the dominant mechanism for porosity loss in deeply buried sandstones, especially those with prolonged exposure to elevated temperatures (Worden and Morad 2000;Taylor et al. 2010;Xia et al. 2020). In this study, the modelled burial-thermal history (Fig. 3) reveals that the Triassic Skagerrak Formation is at its maximum burial depth (>3400 m) and temperature (> 160°C) at the present day. ...
Clay-coated grains play an important role in preserving reservoir quality in high-pressure high-temperature (HPHT) sandstone reservoirs. Previous studies have shown that the completeness of coverage of clay coats effectively inhibits quartz cementation. However, the main factors controlling the extent of coverage remain controversial. This research sheds light on the influence of different depositional processes and hydrodynamics on clay coat coverage and reservoir quality evolution. Detailed petrographic analysis of core samples from the Triassic fluvial Skagerrak Formation, Central North Sea, identified that channel facies offer the best reservoir quality; however, this varies as a function of depositional energy, grain size and clay content. Due to their coarser grain size and lower clay content, high energy channel sandstones have higher permeabilities (100-1150 mD) than low energy channel sandstones (<100 mD). Porosity is preserved due to grain-coating clays, with clay coat coverage correlating with grain size, clay coat volume and quartz cement. Higher coverage (70-98%) occurs in finer-grained, low energy channel sandstones. In contrast, lower coverage (<50%) occurs in coarser-grained, high energy channel sandstones. Quartz cement modelling showed a clear correlation between available quartz surface area and quartz cement volume. Although high energy channel sandstones have better reservoir quality, they present moderate quartz overgrowths due to lesser coat coverage, thus prone to allowing further quartz cementation and porosity loss in ultra-deep HPHT settings. Conversely, low energy channel sandstones containing moderate amounts of clay occurring as clay coats are more likely to preserve porosity in ultra-deep HPHT settings and form viable reservoirs for exploration. Supplementary material: of data and technique used in this study are available at
... The difference of the sedimentary process leads to the difference of the original sediment composition. Diagenesis may affect reservoir properties through postdepositional processes [3][4][5]. Diagenesis in deep, tight reservoirs mainly encompasses compaction, cementation, replacement and dissolution [6][7][8][9]. These diagenetic Figure 2). ...
Full-text available
The optimization of reservoir sweet spots is the key to the efficient exploration and development of low-permeability and tight sandstone gas reservoirs. However, offshore deep, low-permeability and tight sandstone has the characteristics of large burial depth, large diagenesis heterogeneity and prominent importance of diagenetic facies, which make it difficult to predict reservoir sweet spots. This work comprehensively used logging data, core observation, conventional core analysis, thin section, powder particle size analysis, clay X-ray diffraction analysis, cathode luminescence analysis, scanning electron microscopy and energy spectrum analysis and carried out the study of diagenesis, diagenetic facies and reservoir sweet spots of low-permeability and tight sandstone of H3 and H4 (the third and fourth members of Huagang Formation) members in the Jiaxing area of the Xihu Sag. The results show that the H3 and H4 sandstones were divided into five diagenetic facies types, and chlorite-coated facies and dissolution facies were favorable diagenetic facies belts. The H3 member mainly develops chlorite-coated facies, dissolution facies and quartz-cemented facies, whereas the H4 member primarily develops quartz-cemented facies and chlorite-coated facies. The percentages of type I sweet spot, type II1 sweet spot and type II2 sweet spot in the H3 reservoir are approximately 21%, 23% and 26%, respectively, whereas the percentages of type I sweet spot, type II1 sweet spot and type II2 sweet spot in the H4 reservoir are about 16%, 15% and 16%, respectively. The distribution rules of reservoir sweet spots were investigated. Type I sweet spot was mainly developed in the areas of chlorite-coated facies and dissolution facies of medium sandstone and coarse sandstone in the channel bar and braided channel sedimentary microfacies. Type II sweet spot was primarily distributed in the areas of quartz-cemented facies, chlorite-coated facies and minor dissolution facies of medium sandstone, fine sandstone and sandy conglomerate in the braided channel, subaqueous distributary channel and channel bar sedimentary microfacies. Type III sweet spot was chiefly developed in the areas of tightly compacted facies, calcite-cemented facies and quartz-cemented facies of fine sandstone, siltstone and a small amount of sandy conglomerate in the subaqueous distributary channel sedimentary microfacies.
... Previous studies have shown that sedimentary facies, lithology and sorting control the original porosity of the reservoir, while diagenesis, abnormal formation pressure, granular film and early oil and gas filling are important control factors for the formation of high-quality reservoirs in the diagenetic process (Henares et al. 2014;Bjorlykke 2014;Zhao et al. 2019;Shi et al. 2021;Bai et al. 2021;Quandt et al. 2022). Dissolution is a common mechanism for forming deep high-quality clastic rock reservoirs (Zhong and Zhu 2008), but some researchers believe that under some geological conditions, dissolution pores only account for a small part of the overall pore volume, and there is no standard for the identification of dissolution pores (Taylor et al. 2010). The dissolution of unstable minerals such as feldspar leads to the redistribution of minerals and the formation of micropores, resulting in a decrease in permeability and affecting the physical properties of the reservoir (Yuan et al. 2015). ...
Full-text available
With the continuous improvement of oil and gas exploration in the middle and shallow layers, the deep Paleogene in Raoyang sag has become an important exploration field of “increasing reserves and production” in North China. The recognition and control factors of deep effective reservoirs are unclear, which restricts the recognition effect of oil and gas exploration. The key to identify effective reservoirs is to determine the lower limit standard of reservoir physical properties. The single method for calculating the lower limit of physical properties has limitations. The lower limit of the effective reservoir physical properties of the Shahejie Formation in the Dawangzhuang area was obtained by comprehensively using physical property, well logging and oil test data. The data were analysed by oil testing method, metre oil production index test method and frequency curve intersection method. On this basis, combined with the cast thin-section observations, scanning electron microscopy and other test results, the comprehensive control of effective reservoir development of the Shahejie Formation in the Dawangzhuang area of the Raoyang sag was studied from various factors, such as formation pressure, sand body thickness and diagenesis. The results show that the lower limit of porosity was 9.73, 9.44 and 8.85% at depths of Es1, Es2 and Es3, respectively. The lower limit of permeability was 1.21 × 10 –3 , 1.18 × 10 –3 and 0.59 × 10 –3 μm ² , respectively. Effective reservoirs are easier to form in areas with formation pressure coefficient greater than 1.2. Formation overpressure inhibits compaction and promotes dissolution. The proportion of effective reservoirs of sand bodies with thicknesses greater than 2 m can reach more than 75%. The influence of diagenesis on the reservoir is mainly manifested in compaction and cementation making the reservoir compact. The porosity reduction rate caused by compaction can reach 20–75%, while dissolution makes the reservoir form secondary pores. The average pore throat radius of secondary pores can reach 4 ~ 6.3 µm. This study makes use of the applicability of different methods, which is more instructive for predicting the effective reservoir of the Shahejie Formation in the study area. In addition, the research results provide a reference for the development mechanism of medium-deep clastic reservoirs.
... These redox reactions also generate organic acids by step oxidation reactions, and CO 2 by the thermal decarboxylation of organic acids (Seewald, 2003;Yuan et al., 2019). It has been well documented that organic acids and CO 2 cause the dissolution of acid labile minerals (e.g., carbonate and silicate), generating secondary porosity (Surdam et al., 1984;Surdam and Crossey, 1987;Taylor, 1990;Morad et al., 2000;Worden and Burley, 2003;Taylor et al., 2010;Cai et al., 2022a). Simultaneously, the consumption of organic acids and the mineralization of CO 2 may promote the overall redox reactions, and hence the degradation of oils. ...
... Although the lithology and microporous structure characteristics have been clari ed and the sediment source and sedimentary facies are the preconditions for developing high-quality reservoirs, the primary causes of sandstone compactness and the quantitative contribution of destructive and constructive diagenesis are unclear. Furthermore, the diagenetic process can widely affect the reservoir quality of sandstone (Taylor et al., 2010;Stroker et al., 2013), which might lead to poor physical properties and strong heterogeneity of tight oil and gas reservoirs. The water relationship is complex, and the formation pressure is abnormally high and low, increasing the di culty of exploration and development. ...
Full-text available
This study takes the tight sandstone of the Es 1 L Submember in the Suning area, Raoyang Sag, Bohai Bay Basin, furthermore, it determines the rock type of the mid-deep tight sandstone through lithologic profiling, core observation and log data analysis. The genetic control factors of tight sandstone in the study area are analysed using conventional thin section, casting thin section and scanning electron microscope, and the characteristics and genetic control factors of tight sandstone reservoirs are summarised. The research results show that the tight sandstone rocks in this area are primarily feldspathic and lithic sandstone, with high quartz contents. The reservoir space is dominated by primary and secondary pores, which are characteristics of low-porosity and low-permeability reservoirs. Compaction is the primary reason for the poor physical properties of reservoir space, and the influence of cementation on reservoir physical properties differs in different periods. Sedimentary facies, reservoir physical properties and diagenesis control the development and distribution of tight sandstone reservoirs in this area. The results provide an important basis for guiding the exploration and development of tight sandstone oil and gas in the submember of Es 1 L in the Suning area.