Evaluating Fault and Cap Rock
Seals
Edited by Peter Boult
and John Kaldi
Foreword
Three AAPG Hedberg research conferences on seals have been held
in the past 30 years. Each conference represented a quantum leap in the
understanding and methodology of the subject of seals. This volume is a
compendium of the proceedings of the 2002 meeting. The key driver for
this meeting was the recognition that knowledge of risk (in the
estimation of sealing capacity and faultseal potential) is important in
making judgements at the exploration, appraisal, and development stages
of the petroleum business. In addition, incorporating seal risk in the
overall assessment of hydrocarbons in place can affect decisions to
drill prospects, the location of appraisal and development wells, as
well as reserve estimation. Improved methods to estimate seal capacity
and fault integrity can lead to savings in well costs, improved
recoveries through optimum placement of wells, and greater certainty of
meeting contractual requirements through improved estimates of
hydrocarbon in place.
The 2002 meeting was the first ever Hedberg held in Australia, and the
venue, a glorious setting in the heart of the famous South Australia
wine-growing region, may have had something to do with the attendance
of 85 delegates, most of whom traveled halfway around the world to be
there. The meeting consisted of 53 presentations over a period of
two-and-a-half days with robust debate taking up almost half of the
time. This volume is the result of the papers presented, debated,
revised, and finally submitted to AAPG as part of a thematic
state-of-the-art publication on seals.
The volume contains 18 chapters that reflect the spectrum of
presentations at the conference. The knowledge imparted by these
chapters will be a window on the state of knowledge at this juncture of
time. It will be a lasting tribute to the efforts of the individuals
and the synergy of the group, as a whole, that was established at the
conference.
The plethora of new science presented at the Barossa meeting was
obviously an evolutionary outgrowth of previous seals conferences.
Threads connecting to the Crested Butte conference included the
question of the importance of wettability in seals. At Crested Butte,
the long held assumption that all rocks are water wet was questioned.
Leith et al. (1993) showed that oil had penetrated seals in some North
Sea traps, but whether this was by the process of hydraulic fracturing
or capillary leakage through a water-wet seal was not resolved. Over
the last 10 yr, very little work on seal wettability has been carried
out or at least documented. Aplin and
Larter’s chapter in this volume addresses some of the issues
raised in 1993. Their conclusions are that “hydrophilic organic compounds in
reservoirs, followed by diffusion into cap rock pores, may create
oil-wet pathways into cap rocks and drive leakage.” This means
that not only do petrophysicists and reservoir engineers have to
consider wettability when estimating the saturation and flow properties
of reservoirs, but explorationists also have to consider the phenomenon
when risking entrapment. Aplin and
Larter’s chapter not only probes the wettability question but
also describes a methodology for determining, directly from logs,
properties that control the flow of hydrocarbons through muddy seals
that may undergo wettability change. They do this by investigating the
key relationships between (1) porosity and effective stress, (2)
porosity and permeability, and (3) porosity and threshold capillary
entry pressure. The authors conclude that these properties are “strongly influenced by the grain-size
distribution or clay content of the sediments.” These properties
can be calibrated against cores and constrained by cuttings data.
Although Aplin and Larter do
not consider the role of leakage via hydraulic fracturing of clay-rich
cap rocks, Hermanrud et al.
do. In their chapter, they address “three
sets of such subsurface processes, and how they impact on hydrocarbon
leakage: sediment compaction, fluid mobility in a two-phase
(water-plushydrocarbons) reservoir, and relationships between stress
and rock failure.” They describe the conditions for sediment
compaction and remind us that stress-insensitive chemical compaction
becomes increasingly important above 60°C. They state,
conclusively, that “All pressure
compartments leak fluids as long as [chemical] compaction occurs.”
Hermanrud et al. argue that the
relative permeability of seals and reservoirs to water never reaches
zero on a geological timescale. This, they say, holds true despite the
fact that water in the reservoir may be at a conventional irreducible
saturation. Furthermore, they tell us that the “failure to recognize the mobility of this
water may result in too-pessimistic seal capacity estimates.”
They also describe the conditions for the creation of structural
permeability that will allow the bleed-off of overpressure and the
leakage of hydrocarbons.
The abundance of papers in the conference and in this volume containing
elements of geomechanics attests to the importance of this area of
investigation. Some of the presentations and papers also demonstrate
that as a discipline, the investigation of hydrocarbon flow through
seals has much to gain from other industries such as mining and
construction. Whether leakage occurs through the cap rock as a result
of perturbations in the stress field caused by fault discordance as
suggested by Hunt and Boult
or, as Mildren et al. suggest,
the faults themselves are the mechanism for leakage as they dilate
under the influence of the stress field, is still debatable. It would
serve any explorationist well to keep a foot in both camps because both
may, to some extent, be correct.
Two chapters are present in the volume that introduce, as Gartrell and Lisk put it, a “new layer of complexity to fault
reactivation and associated hydrocarbon leakage.” Gartrell and Lisk’s chapter tests a
new methodology for assessing paleostress regimes, and they conclude
that, despite the potential errors inherent in the methodology they
use, their estimation of the paleostress tensor at the southern end of
the Timor Sea is “not in conflict
with structural histories formulated by more traditional methods.”
For the prediction of the paleostress tensor, they bring together, for
the first time, a three-dimensional fault restoration technique, which
is commonly performed on seismic data sets to verify fault and horizon
interpretation, and a fault slip inversion technique, which had
previously only been used in outcrop studies. They admit that this is
very early work, and one data point does not mean the method is proven,
but all such empirical methods have to start somewhere. Moreover, they
conclude that without such an approach, paleostress estimations based
on simple geometric analysis (such as fault orientations) are possibly
prone to errors.
Dewhurst et al. however,
definitely take the deterministic approach to fault-seal analysis. They
examine the detail of the fault rock itself in terms of its response to
geomechanical laboratory testing and relate results to petrological
properties. Significantly, they find that in two study areas,
phyllosilicate framework fault rocks are “stronger than their host reservoirs as a
direct result of syn- and postdeformational physical and diagenetic
processes.” They point out that with the trend toward using
fault reactivation and consequent seal assessment methods derived from
theoretical geomechanics, their observations of “strength recovery through healing”
means that faults cannot be considered as being purely cohesionless.
Thus, algorithms, such as dilation and slip tendency, which do not
incorporate rock strength, may be misleading when assessing fault-seal
risk. Furthermore, in a regional context, as Hunt and Boult point out, the
regeneration of fault strength (via diagenesis) influences stress
distribution.Within a regional top seal, this may result in fracturing
(creation of pervasive structural permeability) and the concomitant
loss of hydrocarbons.
Reynolds et al’s chapter is
based on the application of geomechanical theory, but in this case,
they explain what can be done to assess faults for leakage potential on
a basinwide scale when little or no data are available for depth
conversion. Their approach is a sensitivity analysis of fault
assessment based on a geomechanical estimation of the relative risk of
reactivation. They assume that risking reactivation of faults in Late
Cretaceous sediments of the Great Australian Bight is equivalent to
risking leakage. This chapter, along with those of Mildren et al. and Lyon et al., assumes that during
reactivation, the rate of strain and the rheology of the fault rocks
are such that when they interact, reactivation occurs by brittle
failure, and dilation occurs to allow leakage. Although this may not be
true for the more prolific hydrocarbon-producing basins of the world,
where stress regimes are more stable and rocks are younger and weaker,
it would appear to be the case for Australia, which, as described by Reynolds et al., currently has and
historically has had a highly variable stress tensor in space and time
relative to its continental margins.
Although not included in this volume, Fisher presented key data at the
2002 Hedberg Conference that helped clarify the debate on whether
faults dilate or leak as they move (reactivate). Fisher described the
controls on the geomechanical properties of sediments as they undergo
burial and compaction and heating and diagenesis. Fisher illustrated
the control of grain size, geothermal gradient, and burial rates on the
depth of the ductile-to-brittle transition, which may also coincide
with the top of the seismogenic zone. Although a useful guide for
considering the impact of faults on production, Fisher’s data, like
many other petrological studies, are largely confined to reservoir
sandstones, because very little data are available from seal
lithologies.
Couples’ chapter, “The role of
geomechanics,” contributes to the debate associated with the assumption
that faults that reactivate exhibit dilation. This chapter revisits
some of the fundamental physical definitions of what a seal is and how
geomechanics can describe its behavior. Couples provides an interesting
definition of seals as “power
transmission barriers,” which are places “where the rate of achievable
energy dissipation (flow) is less than the rate at which potential
energy can be imposed or renewed.” The keyword here is rate, and
this will vary depending on whether one is dealing with the relatively
high rates of stress change as experienced by Australia compared to the
more stable stress regimes such as on the passive margins of the
Atlantic. Couples’ chapter
provides insights to understanding “the big picture” of geomechanics.
Couples also warns us about
some of the pitfalls of upscaling geomechanical laboratory measurements
to large-scale models. He points out that “a scale dependency to the identification
of localized vs. delocalized deformation is present,” which is “basically the same issue that arises in
the way that many people use the terms brittle and ductile.”
This is followed by a discussion of poroplasticity and its relation to
volume loss or gain (dilation) during deformation. Although in many
respects, this chapter is aimed at the geomechanically inclined, Couples is still concerned with
getting his message across to the general practitioner. This message is
that an understanding of “poro-plasticity
provides the critical link to allow us to make realistic geomechanical
predictions about seals.” He also provides some interesting new
insights into everyday observations, such as “we can interpret dilational deformations
as representing material that is ‘too solid’ to be able to undergo the
imposed distortions, so extra porosity must be created to ‘weaken’ the
material enough to allow cataclastic flow.” However, the main
strength of this chapter is that he works through an example (without
using mathematics) where he demonstrates how geomechanics explains most
of what we know about the operation of seals and overpressured rocks.
In addition, he describes how geomechanical modeling can be used to
help understand the phenomena, such as the formation of shale gouge,
the non-Andersonian behavior of stress around faults, and the
prediction of petrophysical properties for input into migration
simulation models.
In the previous Hedberg conferences, there was considerable interest in
pressure compartments, and the term “pressure seal” was in common
usage. From this, the term retention capacity (being the difference
between the least principal stress and the pore pressure) was born,
because seals were assumed to only fail either by hydraulic fracturing
or capillary leakage (Watts, 1987). Thus, in water-wet shales with
extremely high capillary entry pressures, high retention capacities
were thought to be synonymous with good pressure seals. However, in
this volume, Nordgard Bolas et al.
show that in their study area, where differential stress is high, shear
failure instead of tensile hydraulic fracturing occurs, and seals with
high retention capacities may be breached. Shear fracturing is caused
by very recent increases in differential stress attributable to ice
loading and unloading and the advance of sedimentary wedges.
Furthermore, their analysis indicates that in their case study, shear
failure and associated leakage reduce pore pressure and, therefore,
increase retention capacity.
Shear-induced failure and mixed-mode failure are mechanisms that have
long been thought to be responsible for the creation of structural
permeability through cap rocks in and around Australia (Hillis, 1998)
because of the recent collision of that continent with New Guinea and
Indonesia. In this volume, Nordgard
Bolas et al. show that mechanisms other than continental
collision and a resultant, highly variable stress tensor can cause
rapid increases in differential stress, leading to shear failure. Those
working in deep offshore basins where the postcharge advance of
sedimentary wedges has occurred, should consider the findings of Nordgard Bolas et al. Nevertheless,
situations in low differential stress environments where retention
capacity (i.e., failure by tensile hydraulic fracturing) is still a
good indicator of seal adequacy remain. Knowing where to apply this
relationship is the main problem. Fortunately, this can be solved by
use of the delta-P parameter or FAST approach, as described by Mildren et al. Delta-P is a measure
of the increase in pore pressure that would be required to create
fractures by either shear or tensile failure. The methodology considers
not only the stress field and the orientation of planes of weakness and
faults in that field, but also the strength of the fault rocks. The
easiest way to picture this is in terms of the distance between poles
to planes in a Mohr circle (representing stress state) and the Coulomb
failure envelope (representing rock strength) of the rock that is
perceived as the weak link in the sealing system. Whether this is a
fault that cuts the seal or the seal itself depends on their relative
strengths.
What of initial entrapment in fault-related traps? As previously
mentioned, structural uncertainty has certainly been reduced in recent
years by rapid advances in technology. Whether it is worth focusing on
this kind of uncertainty at the exploration stage is still debatable,
given all the other uncertainties of a petroleum system that may still
need to be addressed. This lack of concern is reflected in the absence
of papers presented on this subject at the conference. However, after a
significant discovery has been made, the quantification of structural
uncertainty becomes of greater significance. This is long overdue
because, as Ottesen and Townsend
point out, “the statistical
treatment of tectonic heterogeneities in reservoir simulation is not as
rigorous as that of their sedimentary counterparts.” However,
the increasing tendency toward exploration and discovery of
structurally complex traps demands that this aspect be risked in a
similarly rigorous fashion. Their chapter describes a workflow for
incorporating structural uncertainty into a geological model that can
be used in a reservoir simulator. Ottesen
and Townsend cite fault density and fault-relative permeability
as the most influential structural factors that bear on ultimate
recovery.
Lescoffit and Townsend add to
the contribution of Ottesen and
Townsend by investigating the relative importance and effect of
structural uncertainty on production predicted from models built into a
reservoir simulator. To simplify their experiment, they did not vary
fault location or geometry and only considered fault connectivity,
fault displacement, and parameters related to displacement that affect
transmissibility (e.g., fault thickness and gouge-smear prediction).
Their models are based on a typical North Sea tilted fault block, and
the authors conclude that whereas the sequence-stratigraphic models
still dominate, this is not true for all simulation cases. Of the
structural parameters that they did vary, the fault-seal algorithm and
the subseismic fault pattern used had greatest impact on production
prediction.
Bretan and Yielding have done
considerable work in the past toward empirically constraining
fault-seal capacity in the static case and transmissibility in the
production case. Their chapter in this volume very succinctly describes
the use of buoyancy pressure profiles for calibrating and incorporating
uncertainty in the Vclay parameter, which, in turn, is used along with
fault throw to generate fault algorithm parameters, such as shale gouge
ratio (SGR) and shale smear factor. The use of the SGR factor is
demonstrated in papers by Lyon et al.
and Ottesen et al. Lyon et al.
use it to help understand the original hydrocarbontrapping mechanism in
the Zema structure in the Otway Basin, which has subsequently undergone
leakage because of shear failure either along or associated with the
major bounding fault. Ottesen et al.
use SGR in combination with a clay smear algorithm to determine fault
transmissibility.
Lothe et al. use the
methodologies learned from reservoir simulations and apply these to the
province-scale linked pressure and stress simulator. Their chapter
describes a validated, time-stepping model for predicting overpressure
and hydrocarbon leakage from linked pressure compartments. This, in
turn, is based on the interaction of across-fault leakage and hydraulic
fracturing of the cap rock in each compartment. Through an ingenious
method of altering permeability in faults and modeling stress through
time in the cap rocks, they create multiple realizations of leakage.
The authors compare their results with actual pressure data in wells
and zero in on the most likely hydrocarbon migration route across an
area. This, of course, is potentially invaluable in pinpointing
prospective areas to reduce exploration uncertainty.
Lothe et al. bring faults and
cap rock-sealing mechanisms together in a province-scale linked
pressure and stress simulator. Hunt
and Boult, however, bring these aspects together in an overall
assessment of trap integrity. In the Otway Basin where Dewhurst et al. recognize that some
faults are stronger than surrounding rocks, Hunt and Boult have observed stress
perturbations that corroborate this observation and use discrete
element stress modeling to investigate this phenomena. They base their
model on data from multiple fault-bound traps, some of which have
leaked. They assign three different fault sets and realistic
geomechanical parameters of cap rocks to run their model forward until
zones of high and low differential stress appear. They conclude that a
positive observable relationship exists between zones of modeled high
shear stress and trap leakage, and that in this case where observations
indicate that faults are stronger than the surrounding rock, it is
fracturing and the development of structural permeability in the cap
rock that has caused leakage.
Lyon et al.’s chapter is a case
study on the Zema structure, which occurs in the data set used by Hunt and Boult. This structure
contains a well-documented paleo-oil-gas column in the Otway Basin. A
core from the seal was analyzed to determine the original trapping
mechanism, and Lyon et al.
attribute the weak link to shale gouge that developed on the main
bounding fault. They then consider the mechanism for failure. The seal
over the Zema structure provides the rare opportunity to investigate
structural permeability in the form of a deviation on the SP log, which
correlates with an interpretation of a fault on the dipmeter log. An
in-depth structural interpretation of the Zema structure provides an
insight into how this structural permeability developed. The observed
structural permeability is not associated with the main bounding fault
but appears to be linked to younger faults, which formed under the
current stress regime that propagate through the top seal and into the
reservoir near its crest.
Almon et al.’s chapter is one
of few dealing exclusively with top seal, reflecting the change in the
industry’s focus since the previous Hedberg conference. This chapter
continues to push the knowledge boundary on top seal risk reduction by
describing a methodology for seismic-based predrill evaluation of top
seal capacity. The authors describe the facies variation seen in
outcrop and in shallow drill holes of the Lewis Shale in sufficient
petrological detail to enable their separation using discriminant
function analysis. They then measured the petrophysical properties for
each facies and note that where calcareous laminated shale (from
highstand systems tracts) lies directly above organic laminated shales
(from transgressive systems tracts), a strong seismic reflection and an
associated amplitude-vs.-offset anomaly is generated. These seismic
responses could be confused with reservoired hydrocarbons.
Heggeland’s chapter is a
reminder of how far seismic display and interpretation have come in the
last decade. He shows examples of mobile hydrocarbons in gas chimneys
from the North Sea, Gulf of Mexico, Nigeria, and the Caspian Sea and
classifies them into two types. Type 1 chimneys are chimneys associated
with faults. These commonly have circular cross sections with diameter
in the order of 100 m (330 ft) and create pockmarks where they erupt on
the seafloor. They are interpreted to have a high flux rate and,
depending on fault location, can significantly increase exploration
risk. Type 2 chimneys are not associated with faults, and their lateral
extent can be on the order of several hundred meters. These are
interpreted to have a low flux rate and have proven to be good
indicators of commercial hydrocarbons.
Undershultz et al.’s chapter
encourages the incorporation of hydrodynamics in seal studies. They
comment that hydrodynamics is a commonly underused methodology for
assessing fault-sealing characteristics by stating that “hydrodynamic analysis of aquifers cut by
faults can be used as an indirect indicator of the fault zone hydraulic
properties.” They then use “case studies from the foothills of western
Canada and the North West Shelf of Australia to define a workflow for
hydrodynamic analysis in faulted strata” and provide us with a
checklist for identifying which faults, or parts of faults, are sealing
to aquifer flow. Faults that show medium to strong aquifer flow, either
in an upfault or across-fault sense, are unlikely to be sealing to
hydrocarbons.
Lowry makes a very important
contribution by discussing various prospect-risking methodologies and
how to risk seal, especially top seal, and how this should be
incorporated into expected monetary value investment calculations. He
extols the virtues of valuing prospects by varying the chance of
success with the reserve distribution and states that “If seal capacity is a continuously
varying function of column height, using a single Fill-Factor becomes a
blunt instrument likely to lead to a distorted evaluation.”
Being a realist, Lowry does not
wish to overcomplicate the risking procedure and provides a hint as to
when the more complicated method, which he has proposed, should be used
by stating that “A common early
warning sign is when a group of explorationists focused on risking a
prospect start to ask ‘What are we risking?’”
Clearly, not all leakage through top seals is caused by buoyancy
pressure of the hydrocarbon phase exceeding threshold capillary entry
pressures, perhaps aided by a change of wettability, and much debate
still exists over the role of interconnected fractures as a mechanism
for leakage. A marked contrast between the Hedberg conference on seals
in 1993 and that of 2002 was the increase in the number of
presentations on seals related to fault traps in 2002. This probably
reflects the maturation of the industry in terms of other disciplines
especially geophysical interpretation, which has increased the
certainty of structural modeling that allows previously problematic
fault-related traps to be viable targets. The interaction of seal rocks
with the Earth's paleo- and contemporary stress field is inevitably
more complicated in faulted terrain, where discordance abounds, than in
gently undulating plays that rely on four-way dip closures.The
importance of incorporating the risk element into all such studies is a
marked improvement and brings such work on seals directly in congruence
with the bottom-line of industry needs.
Peter Boult and John Kaldi
Conference co-convenors and editors
REFERENCES CITED
Hillis, R. R., 1998, Mechanisms of dynamic seal failure in the Timor
Sea and central North Sea, in
P.G. Purcell and R. R. Purcell, eds., The sedimentary basins of Western
Australia 2: Proceedings of the Petroleum Exploration Society of
Australia Symposium, Perth,Western Australia: p. 313–324.
Leith, T. L., I. Karstadd, J. Connan, J. Pierron, and G. Caillet, 1993,
Recognition of cap rock leakage in the Snorre field, Norwegian North
Sea: Marine and Petroleum Geology, v. 10, p. 29–41.