50
CHAPTER ONE1.0 INTRODUCTIONTrap mechanism in hydrocarbon
migration is fundamental in the analysis of a prospect and an
important part in any successful oil and gas exploration or
resource assessment program. A trap can be defined as any geometric
arrangement of rock, regardless of origin, that permits significant
accumulation of oil or gas, or both, in the subsurface. Although we
define a trap as the geometric configuration that retains
hydrocarbons several critical component must be in place for a trap
to be effective, including adequate reservoir rocks and seals, and
each of these must be addressed during trap evaluation. The oil and
gas within a trap is part of the petroleum system, whereas the trap
itself is part of one or more sedimentary basins and is evaluated
as part of a prospect. The hydrocarbon-forming process and the
trap-forming process occur as independent event and commonly at
different types. The timing of the trap-forming process is
important in a petroleum system study because if the trap forms
before the hydrocarbon-forming process the evidence (oil and gas)
that a petroleum system exist is preserved. The volume of oil and
gas preserved depends on the type and the size of the trap, which
is important in the evaluation of the prospect. The critical
component of a trap (the reservoir, seal, and the geometric
arrangement with each other) can be combined in variety of ways by
a number of separate processes. Different authors have focused on
various trap attributes as the key elements or elements of their
classifications.
1.1 HYDROCARBON MIGRATIONHydrocarbon migration refers to the
movement of petroleum from the source rock to the reservoir rocks.
It is important to understand this process so that the direction of
migration and trapping of petroleum can be predicted. Many
different theories have been proposed in the past but it is now
clear that petroleum is mainly transported as a separated phase and
that the process is mainly driven by the buoyancy of petroleum
relative to water. The solubility of oil in water is very low for
most compounds. The solubility of oil in water is very low for most
compounds. The solubility of gas, particularly methane, is much
higher both in oil and water and increases with depth (pressure).
There is however, also very limited flow in sedimentary basins to
transport petroleum.
Figure 1.0: petroleum geology, (migration process in hydrocarbon
migration) shanawaz mustafa
Figure 1.2: diagram illustrating the movement and accumulation
of hydrocarbon (Kevin.T Bibble)
1.2 PRIMARY MIGRATIONPrimary migration is here defined as the
movement of hydrocarbons (oil and natural gas) from mature
organic-rich source rocks to an escape point where the oil and gas
collect as droplets or stringers of continuous-phase liquid
hydrocarbon and secondary migration can occur. The escape point
from the source rock can be any point where hydrocarbons can begin
to migrate as continuous-phase fluid through water-saturated
porosity. The escape point then could be anywhere the source rock
is adjacent to a reservoir rock, an open fault plane, or an open
fracture. Secondary migration is the movement of hydrocarbons as a
single continuous-phase fluid through water-saturated rocks,
faults, or fractures and the concentration of the fluid in trapped
accumulations of oil and gas. Numerous mechanisms for primary
migration have been proposed. The main proposed mechanisms for
secondary migration are buoyancy and hydrodynamics.The mechanisms
of primary hydrocarbon migration and the timing of hydrocarbon
expulsion have been debated by petroleum geologists since the
beginning of the science. Mechanisms proposed for primary
hydrocarbon migration include: solution in water, diffusion through
water, dispersed droplets, soap micelles, continuous-phase
migration through the water-saturated pores, and others. Early
workers generally favored early expulsion of hydrocarbons with the
water phase of compacting sediments, primary hydrocarbon migration,
and secondary migration through reservoir carrier beds is the
necessary next step for the formation of a commercial oil or gas
accumulation. A thorough understanding of the mechanics of
secondary hydrocarbon migration and entrapment is useful in the
exploration for oil and gas. Knowledge in this area of exploration
can be critical in tracing hydrocarbon migration routes,
interpreting hydrocarbon shows, predicting vertical and lateral
seal capacity, exploiting discovered fields, and in the general
understanding of the distribution of hydrocarbons in the
subsurface.1.3 SECONDARY MIGRATIONThe hydrocarbons expelled from a
source bed next move through the wider pores of carrier beds (e.g.,
sandstones or carbonates) that are coarser-grained and more
permeable. This movement is termedsecondary migration. The
distinction between primary andsecondary migrationis based on pore
size and rock type. In some cases, oil may migrate through such
permeable carrier beds until it is trapped. If an oil droplet were
expelled from a source rock whose boundary was the seafloor, oil
would rise through seawater as a continuous-phase droplet because
oil is less dense than water and the two fluids are immiscible. The
rate of rise would depend on the density difference (buoyancy)
between the oil and the water phase. The main driving force then
for the upward movement of oil through sea water is buoyancy.
Buoyancy is also the main driving force for oil or gas migrating
through water-saturated rocks in the subsurface. In the subsurface,
where oil must migrate through the pores of rock, there exists a
resistant force to the migration of hydrocarbons that was not
present in the simple example. The factors that determine the
magnitude of this resistant force are (1) the radius of the pore
throats of the rock, and (2) the hydrocarbon-water interfacial
tension, and (3) wettability. These factors, in combination, are
generally called "capillary pressure." Capillary pressure has been
defined as the pressure difference between the oil phase and the
water phase across a curved oil-water interface pointed out that
capillary pressure between oil and water in rock pores is
responsible for trapping oil and gas in the subsurface.
Figure 1.2 definition of primary and secondary migration (after
tissot and welte).
1.4 DRIVING FORCES FOR HYDROCARBON MIGRATIONUnder hydrostatic
conditions, buoyancy is the main driving force for continuous-phase
secondary hydrocarbon migration. When two immiscible fluids
(hydrocarbon and water) occur in a rock, a buoyant force is created
owing to the density difference between the hydrocarbon phase and
the water phase. The greater the density difference, the greater
the buoyant force for a given length hydrocarbon column (always
measured vertically). For a static continuous hydrocarbon column,
the buoyant force increases vertically upward through the
column.1.5 EFFECTS OF HYDRODYNAMICS ON DRIVING FORCESThe importance
of hydrodynamics with regard to oil entrapment in structural traps
has been discussed in detail by Hubbert (1953). Numerous other
authors have since documented the effects of hydrodynamics on
structural oil reservoirs throughout the world. In thinking of the
effects of hydrodynamics on secondary migration and primarily
stratigraphic-type entrapment of hydrocarbons, we must consider how
a hydrodynamic condition would effect the buoyant driving force of
a hydrocarbon filament in the subsurface. Hydrodynamic conditions
in the subsurface change the buoyant force, and therefore the
migration potential, for a hydrocarbon column of a given height.
Buoyancy, as has been defined for a static oil filament, is the
pressure in the water phase minus the pressure in the oil phase at
a given height above the free water level. When a hydrodynamic
condition exists, the pressure in the water phase (and therefore
the buoyant force) at any point will be different from that for
hydrostatic conditions.
1.6.0 RESISTANT FORCES TO SECONDARY MIGRATIONIn a previous
example we discussed how a filament of oil released at the seafloor
would rise through seawater because of the force of buoyancy. If
the same filament of oil or gas is required to move through a
water-saturated porous rock we have introduced a resistant force to
hydrocarbon movement. For the hydrocarbon filament or globule to
move through a rock, work is required to squeeze the hydrocarbon
filament through the pores of the rock. In more technical terms,
the surface area of the hydrocarbon filament must be increased to
the point that it will pass through the previously water-saturated
pore throats of the rock. The magnitude of this resistant force in
any hydrocarbon-water-rock system then is determined by the radius
of the pore throats of the rock; the hydrocarbon-water interfacial
tension (surface energy); and wettability as expressed by the
contact angle of hydrocarbon and water against the solid pore walls
as measured through the water phase. This resistant force to
migration is generally termed "capillary pressure."For a simplified
example, visualize a hydrocarbon filament trying to move upward
through a water-saturated cylindrical pore .The variables of the
resistant force to hydrocarbon movement can be expressed by a
simple equation (Purcell, 1949):
Where Pd = hydrocarbon-water displacement pressure (dynes/cm2);=
interfacial tension (dynes/cm);= wettability, expressed by the
contact angle of hydrocarbon and water against the solid (degrees);
and R = radius of largest connected pore throats (cm). The
displacement pressure is that force required displacing water from
the cylindrical pore and forcing the oil filament through the
pore.
1.6.1 INTERFACIAL TENSIONInterfacial tension can be defined as
the work required enlarging by unit area the interface between two
immiscible fluids (e.g., oil and water). Interfacial tension is the
result of the difference between the mutual attraction of like
molecules within each fluid and the attraction of dissimilar
molecules across the interface of the fluids.Oil-water interfacial
tension varies as a function of the chemical composition of the
oil, amount and type of surface-active agents, types and quantities
of gas in solution, pH of the water, temperature, and pressure. At
atmospheric pressure and 70F, interfacial tension of crude oils and
associated formation water for 34 Texas oil reservoirs of different
ages ranged from 13.6 to 34.3 dynes/cm, with a mean of 21 dynes/cm
(Livingston, 1938). Oil-water interfacial tension generally tends
to decrease with increasing API gravity and decreasing viscosity
(Livingston, 1938).With increasing temperature, oil-water
interfacial tension generally decreases. For pure benzene-water and
decane-water systems, interfacial tension decreases between 0.03 to
0.08 dynes/cm/F (Michaels and Hauser, 1950) depending on the
pressure.In attempting to quantify oil-water-rock displacement
pressure, a value for oil-water interfacial tension in the
subsurface must be measured or estimated. Sophisticated laboratory
equipment can measure oil-water interfacial tension at reservoir
temperature and pressure. If this equipment is not available,
interfacial tension can generally be measured at atmospheric
conditions in most chemical laboratories. The results of
atmospheric interfacial tension measurements must be extrapolated
to subsurface temperature and pressure. If no laboratory data are
available for the oil-water system in question, then an estimate
must be made. Livingston's mean value for 34 Texas crude oils of 21
dynes/cm at 70F is the best value for medium-density crude oils (30
to 40 API). A value of approximately 15 dynes/cm may be appropriate
for higher gravity crude oils (greater than 40 API) with 30
dynes/cm being a reasonable approximation for low-gravity crude
oils (less than 30 API). These estimates or measurements at
atmospheric temperature (70F) must be extrapolated to reservoir
temperature. It is suggested that the oil-water interfacial tension
value at 70F be decreased 0.1 dynes/cm/F temperature increase above
70F.
1.6.2 WETTABILITYWettability can be defined as the work
necessary to separate a wetting fluid from a solid. In the
subsurface we would generally consider water the wetting fluid and
the solid would be grains of quartz in sandstone, calcite in a
limestone, etc. The adhesive force or attraction of the wetting
fluid to the solid in any oil-water-rock system is the result of
the combined interfacial energy of the oil-water, oil-rock, and
water-rock surfaces. Wettability is generally expressed
mathematically by the contact angle of the oil-water interface
against the rock or pore wall as measured through the water phase.
For rock-fluid systems with contact angles between 0 and 90, the
rocks are generally considered water-wet; for contact angles
greater than 90, the rocks are considered oil-wet. Water-wet rocks
would imbibe water preferentially to oil. Oil-wet rocks or oil-wet
surfaces would imbibe oil preferentially to water. Although a
contact angle of 90 has generally been considered the break over
point to an oil-wet surface, Morrow et al (1973) stated that a
contact angle of greater than 140 in dolomite laboratory packs was
necessary for oil to be imbibed. Water-laid sedimentary rocks are
generally considered to be preferentially water-wet owing to the
strong attraction of water to rock surfaces and the initial
exposure of pore surfaces to water rather than hydrocarbons during
sedimentation and early diagenesis. Water is thought by many
workers to be a perfect wetting fluid and a thin film of water
would coat all grain surfaces. If this is the situation, the
contact angle for oil-water-rock systems would be zero. The
wettability term in the displacement pressure equation would then
be unity, as the cosine of zero is one. If water is not a perfect
wetting fluid and the oil-water contact angle is greater than zero,
the displacement pressure should theoretically decrease for that
oil-water rock system. L. J. M. Smits (1971, personal commun.) has
done experimental work on identical size bead packs which suggests
that displacement pressures are only slightly affected by changing
the oil-water-solid contact angle from 0 to 85. Similar results
were obtained by Morrow et al (1973) on displacement pressure tests
in dolomite packs with contact angles ranging from 0 to 140. These
data and the general assumption that most rocks are preferentially
water-wet suggest that the wettability term in the displacement
pressure equation can be considered unity.
If the rocks are partially oil-wet, then the wettability term
can be significant in reducing displacement pressure from that for
the water-wet case. In the subsurface, rocks are seldom completely
oil-wet but are fractionally oil-wet, that is, some of the grain
surfaces are oil-wet and some are water-wet. According to Salathiel
(1972), this would most likely occur in reservoir rocks where oil
has been trapped and the grain surfaces in the larger pores would
be exposed to the surface-active molecules in the oil phase and
form an oil film or coating on the grain, making it preferentially
oil-wet. The pore surfaces at the smaller pores or in the corners
of the larger pores that are not saturated with oil would remain
water-wet. Fatt and Klikoff (1959) have determined that when a rock
is partially oil-wet there is a reduction in the oil-water
displacement pressure for that oil-water-rock system. They
suggested that the degree of fractional wettability needed to
significantly reduce displacement pressure from that for the
water-wet case is greater than 25% oil-wet grain surfaces.
Figure 1.3 driving forces on hydrocarbon migration
wikipedea(2009)
CHAPTER TWOHYDROCARBON TRAPS2.0 HYDROCARBON TRAPSA trap is a
geologic structure or a stratigraphic feature capable of retaining
hydrocarbons. Hydrocarbon traps that result from changes in rock
type or pinch-outs, unconformities, or other sedimentary features
such as reefs or buildups are calledstratigraphic traps.
Hydrocarbon traps that form in geologic structures such as folds
and faults are called structural traps. Any mixture of structural
and stratigraphic elements is called a combination trap.2.1
STRUCTURAL TRAPSStructural traps are created by syn-to post
depositional deformation of strata into a geometry (a structure)
that permits the accumulation of hydrocarbons in the subsurface.
The resulting structures involving the reservoir, and usually the
seal intervals, are dominated by either folds, faults, piercements,
or any combination of the foregoing. Traps formed by gently dipping
strata beneath an erosional unconformity are commonly excluded from
the structural category, although as sub unconformity deformation
increases these distinction becomes ambiguous. Super posed multiple
deformations may also blur the forgoing distinctions. Subdivisions
of structural traps have been proposed by many authors based on a
variety of schemes, example of these are fault dominated traps and
fold dominated traps.
2.1.1 FOLD DOMINATED TRAPSStructural traps that are dominated by
folds at the reservoir-seal level exhibit a wide variety of
geometries and are formed or modified by a number of significantly
different syn-and post depositional deformation mechanisms.
Although usually considered to result from tectonically induced
deformation the term fold is purely descriptive and refers to
curved or non planer arrangements of geologic (usually bedding)
surfaces. Therefore, folds include not only tectonically induced
phenomena but also primary depositional features, gravity-induced
slumping, compaction effect etc. it is convenient to divide
prospect-scale folds into two categories those that are directly
fault related and those that are largely fault free.Most fault
related folds result from bending above non planar fault surface.
Crystalline basement may or may not be involved, and strata
shortening, extension, or transcurrent movements may have occurred.
Common examples are fault bend folds and fault propagation folds in
detached fold and thrust belts. Fault bend folds are also common in
extensional Terranes. Other faulted related folds include drag
fold, or fold formed by frictional forces acting across a fault,
and drape folds, those formed by flexure above a buried fault along
which there has been renewed movement. These latter folds however
are not caused by slip over a nonplanar fault surface. Also, drape
folds do not involve significant strata shortening or extension at
the reservoir level. Fault free, or lift off folds result from
buckling caused by strata shortening above a docollement, usually
within a thick or very efficient sequence of evaporates or shale.
Kink bands and chevron folds are special types of fault free folds.
Other type of fault free folds may form by bending above material
that moves vertically or horizontally by flow without significant
strata shortening or extension at the reservoir seal interval.
Figure 2.1: diagram illustrating fault dominated trap (Kevin.T
Bibble)
2.1.2 FAULT DOMINATED TRAPAs already pointed out, faults can be
extremely important to the viability of a trap by providing either
seals or leak points. They are capable of acting as top, lateral,
or base seals by juxtaposing relatively permeable rock units
against more permeable reservoir units or by acting as seals
surfaces due to impermeable nature of the material along the
faults. In addition, they may act as leak points by juxtaposing of
permeable units or by creation of a fracture network. The term
fault is descriptive in that it refers to a surface across which
they have been displacement without reference to the cause of that
reference (either, whether it is tectonically, gravitationally,
diagenetically or otherwise induced). Structural traps that are
dominated by faults at the reservoir - the seal level (the fault
itself makes the trap by sealing the reservoir without an ancillary
fold) can be divided into three categories based on the types of
separation, or slip if it is known that geologic surface exhibit
across the fault. These are normal, reverse, and strike separation
or slip fault trap.
2.2 NORMAL FAULT Normal traps are the most common fault
dominated structural traps. They are of two fundamentally different
geometries and are most common in two different
tectonostratigraphic setting. Normal fault involving the basement
occur in areas of significant crustal extension, such as the gulf
of cuez and the North Sea, and are characterize by tilted fault
block that exhibit a zigzag map pattern. Probably the most
important trap geometry is the trap door closure at fault
intersection. Syn-and post depositional normal fault that are
detached from the basement occur in area of rapid subsidence and
sedimentation, commonly on passive continental margins, such as the
USA, gulf coast, Niger-Delta and are characterized by a listric
profile and a cuspate map pattern that is usually concave
basinward. On the downthrown side of major displacement normal
fault in these setting smaller synthetic and antithetic fault
dominated trap are typically keystone normal fault dominated traps
above deep seated salt intrusions are also common.
2.3 REVERSE FAULT Reverse fault traps may be associated with
detached or basement involved thrust (No angle or high angle
reverse faults.) these structures tend not to produce pure fault
dominated traps because of attendant folding. In this position, the
hanging wall moved up relative to the foot wall, indicating reverse
fault activity. The picture shows that the central hanging wall was
pushed up relative to the foot wall. Most of the faults in the
Rocky Mountains are reverse fault.
Figure 2.3: types of traps in which folding dominate the
reservoir-seal interval. Fault related traps include (A) fault bend
(B) fault propogation, (C) fault grab (D) fault drape. Fault free
types include (E) lift off, (F) chevron/king band, (G) diaper, and
(H) differential compaction2.4 STRATIGRAPHIC TRAPIn 1936 levorsen
proposed the term stratigraphic features in which a variation in
stratigraphy is the chief confining element in the reservoir which
traps the oil. The existence of such non structural trap has been
recognized atleast the late 1800. Today we would define a
stratigraphic trap as one which the requisite geometry and
reservoir- seals combination where formed by any variation in the
stratigraphy that is independent of structural deformation except
for regional tilting. Many attempts have been made to classify
types of stratigraphic traps. Early efforts, while not specifically
using the term stratigraphic, lead to broad categories of traps
that where close because of varying porosity within rocks later
works recognized that considerable variability exist among such
trap, and subdivision became more numerous. A number of treatments
of stratigraphic traps provide information on different approaches
to classification and supply abundant, we generally follow
Ritten-House, (1972) and divide stratigraphic traps into primary
and depositional stratigraphic trap, stratigraphic traps associated
with unconformities, and secondary stratigraphic traps.Figure 2.4:
types of traps in which faulting dominate the reservoir-seal
interval. (A) Basement involved normal fault trap and trap. (B)
Synthetic detached listric normal fault traps (C) two types of
reverse fault traps. (D) strike-slip traps
2.4.1 PRIMARY OR DEPOSITIONAL STRATIGRAPHIC TRAPPrimary or
depositional stratigraphic traps are created by changes in
contemporaneous deposition. As described here such traps are not
associated with significant unconformity two general classes of
primary stratigraphic traps can be recognized: those formed by
lateral depositional changes, such as facies changes and
depositional pinchouts, and those created by buried depositional
relief.Facies changes may juxtapose potential reservoir rocks and
impermeable seal rocks over relatively short lateral distance in
either siliciclastic or carbonate settings. The lateral transition
from reservoir to seal is generally gradational, leading to
possible non economic segment within the reservoir. Particular care
must be taken to identify strike closure in this type of trap.
Deposional pinchouts may lead to reservoir and seal combination
that can trap hydrocarbon. The transition from reservoir to lateral
seal may be abrupt, in contrast to facies change traps. Strike
closure is also a risk for pinchouts traps.Both lateral facies
change and depositional pinchouts traps generally require a
component of regional dip to the effective. Both types are common
elements of combination structural-stratigraphic traps,
particularly if the structure was growing during deposition of the
reservoir and seal rocksThe general second general class of primary
stratigraphic traps is associated with buried depositional relief.
These traps are equivalent to the constructive paleogeomorphic
traps of Martin (1966). Carbonate reefs provide a classic example
of potential traps associated with buried depositional relief. Reef
growth with time enhances depositional relief, and the transition
from tight lagoonal rocks to porous and permeable
backreef-reef-fore reef rock may provide a good reservoir-lateral
seal combination. The relationship between the forereef rocks and
adjacent basinal deposits (potential source rocks) can create
excellent migration partway. Formation of a top seal requires that
reef growth is terminated and that the reef is very buried beneath
the trap with low permeability material. A key risk for this type
of trap is accurate prediction of porosity and permeability with
the reef complex. The Devonian reef fields of the western Canada
sedimentary basin are excellent example of this type of trap.
Another type of buried depositional relief is associated with some
submarine fan deposit. In such depositional settings sand- ridge
depositional lobes may be encased in shale.
Figure 2.5 primary or Deposional stratigraphic traps. (A) Traps
created by lateral changes in sedimentary rock type during
deposition. (B) traps formed by buried Deposional relief.
2.4.2 SECONDARY STRATIGRAPHIC TRAPSAnother major category of
stratigraphic traps results from post depositional alteration of
strata. Such alteration may either create reservoir quality rocks
non reservoir or create seals from former reservoir. Although the
example used is taken from a carbonate setting, similar digenetic
plugging can occur in just about any rock type under the proper
circumstances. Porosity occlusion is not limited to only digenetic
mineral cements. Asphalt, permafrost, and gas hydrates are other
possible agents that may form seals for these types of
stratigraphic traps. Unfortunately it is often difficult to predict
position of the cementation boundaries in the subsurface before
drilling, and this type of trap can be a challenging exploration
target.The second type of secondary stratigraphic traps is
associated with porosity enhancement that improves reservoir
quality in otherwise tight sections.Dolomization of limited
permeability limestones is a good example. Dissolution of framework
or material is another porosity and permeability enhancement
mechanism. Porosity enhancement associated with dolomization and
dissolution potentially can create traps on its own. Commonly,
though, porosity enhancement is associated with other types of
traps as a modifying element.
Figure 2.6: secondary digenetic stratigraphic traps. (A) Traps
created by post depositional up dip porosity occlusion. (B) Traps
created by post depositional porosity and permeability enhancement
2.5 COMBINATION TRAPMany of worlds hydrocarbon traps are not simple
features but instead combine both structural and stratigraphic
elements. Levorsen recognized this in his 1967 classification of
trap he noted that every a complete gradation exist between
structural and stratigraphic end members and that discovered traps
illustrates almost imaginable combination of structure and
stratigraphy. Levorsen restricted the use of the term combination
trap to features in which neither the structural nor the
stratigraphic element alone forms the traps but both are essential
to it. Many people now use the term combination trap in a less
rigorous way and apply it to any trap that has both structural and
stratigraphic element, regardless of whether both are required for
the trap to be viable strict adherence to the definitions does not
necessarily find hydrocarbon, both early recognition of
stratigraphic complication associated with structural traps or
structural modification of dominantly stratigraphic trap can help
eliminate exploration or development suprises. An explanation that
is commonly proposed for these observations is that reservoir
conditions are hydrodynamic rather than hydrostatic. In general,
dips of oil water contacts seldom exceed a few degrees, but higher
dips have been reported up to 10 degrees, if the dip(tilt) of the
oil water contact exceeds the trap flanks, the trap will be flushed
(generally, if trap flank dips exceed 5 degrees, there is little
risk of flushing). Therefore, in the evaluation of structural traps
with relationship gently dipping flanks, consideration should be
given to hydrodynamic conditions, it is important to note that
tilted oil water contacts may be related to phenomena other than
hydrodynamics (e.g), variation in reservoir characteristics and
geotectonic), and that present day hydrodynamic condition may not
reflect those in the past.It is possible to calculate the
theoretical change in trap capacity and therefore the risk
associated with trap capacity and therefore the risk associated
with trap flushing in a strongly hydrodynamic situation. Hubbert
(1953) showed that the tilt of the oil water contact is the
direction of flow is a function of the hydraulic gradient and the
densities of both hydrocarbons and water .the lower the oil density
and greater the water flow, the more easily the oil density and
greater the water flow, the more easily the oil is displaced.Figure
2.7: combination traps. (A) Intersection of a fault with an updip
depositional edge of porous and permeable section (B) folding of an
updip depositional pinchouts of reservoir section.
2.6 HYDRODYNAMIC TRAPSExplorationists have known since about
mid-century that oil-water contacts in many hydrocarbons-bearing
traps are tilted. In other cases, traps that have no static closure
contain hydrocarbons, and traps that do not have static closure and
should reasonably contain hydrocarbons do not. An explanation that
is commonly proposed for these observations is that reservoir
conditions are hydrodynamic rather than hydrostatic. In general,
dips of oil-water contacts seldom exceed a few degrees, but higher
dips have been reported. If the dip (tilt) of the oil water contact
exceeds the dip of the trap flanks, the trap will be flushed
(generally, if trap flank dips exceeds 50 , there is little risk of
flushing). Therefore, in the evaluation of structural traps with
relatively gently dipping flanks, considering should be given to
hydrodynamic conditions. It is important to note that tilted oil
water contact may be related to phenomena other than hydrodynamics
(e.g., variations in reservoir characteristics and neotectonics),
and that present day hydrodynamic conditions may not reflect those
in the past. It is possible to calculate the theoretical change in
trap capacity and therefore the risk associated with trap flushing
in a strongly hydrodynamic situation. Hubbert (1953) showed that
the tilt of the oil water contact in the direction of flow is a
function of the hydraulic gradient and the densities of both
hydrocarbons and water. The lower the oil density and greater the
water flow, the more easily the oil is displaced.
Figure 2.8: (A) Generalized hydrostatic trap. (B) Generalized
hydrodynamic trap. (C) Hydrodynamic traps with increased water flow
or oil density. (D) Hydrodynamic trap without static closure
created by down dip water flow. (E) Same situation as in (D) but
with updip water flow. (F) Tilted oil-water contact in fold
dominated trap with down dip water movement. (G)Tilted oil-water
contact in fold dominated trap with updip water movement.
CHAPTER THREECOMPONENT OF A TRAP3.0 TWO CRITICAL COMPONENTS OF
TRAPTo be a viable trap, a subsurface feature must be capable of
receiving hydrocarbons and storing them for some significant length
of time. This requires two fundamental components: a reservoir rock
in which to store the hydrocarbons, and seal (or set of seals) to
keep the hydrocarbon from migrating out of the trap. We do not
consider the presence of hydrocarbons to be critical component of a
trap, although this is certainly a requirement for economic
success. The absence of hydrocarbons may be the result of failure
of other play or prospect parameters, such as the lack of a pod of
active source rock or migration conduits, and it may have nothing
to do with the ability of an individual feature to act as a trap.
3.1 RESERVIORThe reservoir within a trap provides the storage space
for the hydrocarbons. This requires adequate porosity within the
reservoir interval). The porosity can be primary (depositional),
secondary (digenetic), or fractures, but it must supply enough
volume to accommodate a significant amount of fluids. The reservoir
must also be capable of transmitting and exchanging fluids. This
requires sufficient effective permeability within the reservoir
interval and also along the migration conduit that connects the
reservoir with a pod of active source rock. Because most traps are
initially water filled, the reservoir rock must be capable
exchanging fluids as the original formation water is displaced by
hydrocarbons, traps are not passive receivers of fluids into
otherwise empty space; they are focal points of active fluid
exchange.A trap that contains only one homogenous reservoir rock is
rare. Individual reservoir commonly include lateral/or vertical
variation in porosity and permeability. Such variation can be
caused either by primary depositional processes or by secondary
digenetic or deformational effects and can lead to hydrocarbon
saturation but non productive waste zones within a trap. Variation
in porosity and, more importantly, permeability can also create
transition that occurs over some distance between the reservoir and
the major seals of a trap. This interval may contain significant
amount of hydrocarbons that are difficult to produce effectively.
Such intervals should be viewed as uneconomic parts of the
reservoir and not part of the seal. Otherwise, trap spill points
may be mis-identified. Many traps contain several discrete
reservoir rocks with interbedded impermeable units that form
internal seals and segment hydrocarbon accumulations into separate
compartments with separate gas-oil-water contacts and different
pressure distributions.
Figure 3.0: common trap limitations. (A) Waste or non productive
zones in trap. (B) Multiple impermeable layers in trap creating
several individual oil-water contacts (C) Non-to poorly productive
transition zone. (D) Lateral transition from reservoir to seal. (E)
Lateral stratigraphically controlled leak point. (F) lateral leak
point or thief bed.
3.2 SEALThe seal is equally critical component of a trap,
without effective seals, hydrocarbons will migrate out of the
reservoir rock with time and the trap will lack viability. Most
effective seals for hydrocarbon accumulations are formed by
relatively thick; laterally continuous, ductile rocks with high
capillary entry pressure, but other types of seals may be important
parts of individual traps (e.g. Fault zone material, volcanic rock,
asphalt, and permafrost). All traps require some form of top seal
when the base of the top seal is convex upward in three dimensions,
the contours drawn to represent this surface (called the sealing
surface by Downey, 1984) close to map view. If these are the case,
no other seal is necessary to form an adequate trap. In fact some
authors have used the basic convex or non convex geometry of
sealing surface as a way of classifying traps.Many traps are more
complicated and require that, in addition to a top seal, other
effective seals must be present. Lateral seals impede hydrocarbon
movement from the sides of a trap and are a common element of
successful stratigraphic traps. Facie changes from porous and
permeable rocks to rocks with higher capillary entry pressures can
form lateral seals, as can lateral digenetic changes from reservoir
to tight rocks. Other lateral seals are created by the
juxtaposition of dissimilar rock types across erosional or
depositional boundaries. Traps in incised valley complexes commonly
rely on this type of lateral seal. Stratigraphic variability in
lateral seals poses a risk of leakage and trap limitation. Even
thinly interbedded intervals of porous and permeable rock (thief
beds) in a potential lateral seal can destroy an otherwise viable
trap. Base seals are present in many traps and most commonly
stratigraphic in nature. The presence or absence of an adequate
base seal is not a general trap requirement, but it can play an
important role in deciding how a field will be developed. Faults
can be important in providing seals for trap, and fault leak is a
common trap limitation. Fault can create or modify seals by
juxtaposing dissimilar rock types across the fault, by smearing or
dragging less permeable material into the fault zone, by performing
a less permeable gouge because of differential sorting and
cataclasis, or by preferential digenesis along the fault, fault
induced leakage may result from juxtaposing of porous and permeable
rocks across the fault or by formation of a fracture network along
the fault itself.
Figure 3.1: diagram illustrating positions of seal in a
hydrocarbon system.
CHAPTER FOURPOROSITY AND PERMEABILTY4.0 INTRODUCTION TO POROSITY
AND PERMEABILITYHydrocarbon accumulations can occur only if all
essential elements (source rock, reservoir rock, seal rock, and
overburden rock) and processes (generation-migration-accumulation
of petroleum and trap formation) have operated adequately and in
the proper timespace framework. Absence or inadequacy of even one
of the elements or processes eliminates any chance of economic
success. Thus, sandstone reservoir parameters (reservoir size,
porosity, and permeability) are among the geologic controls that
have to be included in the consideration of risk factors for plays
and prospects. The importance of accurate pre-drill assessments,
including reservoir quality, is growing as oil and natural gas
companies are increasingly exploring deeper targets. The proportion
of undeveloped, deep reservoirs was even higher for gas fields. The
trend toward greater producing depths has not been limited to the
North Sea. Anomalously high porosities and permeabilities in deeply
buried sandstones can extend the economic basement and provide
critical support for commercial production. Four known major causes
of anomalously high porosity in sandstones are as follows: (1)
grain coats and grain rims (effective only in detrital-quartzrich
sandstones), (2) early emplacement of hydrocarbons, (3) shallow
development of fluid overpressure, and (4) secondary porosity.
Although these phenomena are generally known to geologists,
misconceptions exist regarding their occurrence and effectiveness.
In this article, we discuss quantification and predictability of
anomalous porosity as the result of the first three causes. 4.1
POROSITYPorosity refers to the percentage of total volume of a
material that is occupied by voids or air spaces that exist between
the rock grains. The more porous a material is, the greater the
amount of open space, or voids, it contains. Stored in these voids
are liquids and gases. Porosity differs from one material to
another. Unconsolidated deposits of clay have the greatest
porosities because of their crystallographic structure; they are
comprised of parallel sheets of clay minerals. Unconsolidated
deposits of sand have lower porosities because of the nature of the
sand grains to each other. Source rocks have high porosities; the
best source materials are clays & shales, but these same
materials make poor reservoir rocks. Porosity of a rock is a
measure of its ability to hold a fluid. Mathematically, porosity is
the open space in a rock divided by the total rock volume (solid +
space or holes). Porosity is normally expressed as a pecentage of
the total rock which is taken up by pore space. For example, a
sandstone may have 8% porosity. This means 92 percent is solid rock
and 8 percent is open space containing oil, gas, or water. Eight
percent is about the minimum porosity that is required to make a
decentoil well, though many poorer (and often non-economic) wells
are completed with less porosity. Even though sandstone is hard,
and appears very solid, it is really very much like a sponge (a
very hard, incompressible sponge). Between the grains of sand,
enough space exists to trap fluids like oil or natural gas! The
holes in sandstone are called porosity (from the word porous). Here
is a very thin slice (thinner than a human hair) of actual
sandstone as seen through a microscope. The larger brown and yellow
pieces are grains of quartz, an extremely common mineral. Between
the grains, you can see the porosity in the rock.If you take a
piece of sandstone and pour water on it, you will see the water is
absorbed right into the rock. The water is soaked into the
porosity.The porosity is shown as black in the drawing on the
right. Oil or gas will fill these holes in the rock. Notice that
the more spherical the grains are, the more space or porosity is
left between them. Hence, well-rounded sandstone will have more
porosity than a poorly-routed one! A geologist loves to encounter
well-rounded sandstone, because they hold the most oil and gas of
any of the clastic rocks.4.2 PERMEABILITYPermeability (measured in
centimeters per second) refers to the ability of a material to
transmit [fluid or gas]. The rate at which a material will transmit
a fluid or gas depends upon total porosity, number of
interconnections between voids, and size of interconnections
between voids. For example, although clay has a higher porosity
than sand (clay has a greater number of voids), the voids that make
up the clay are not interconnected and therefore cannot transmit
the fluid or gas out of it. The permeability of a typical clay in
Louisiana would be 1 x 10-7cm/sec, or a movement of about 3 feet in
30 years. Therefore movement of a fluid or gas out of clay is very
difficult. Sand on the other hand has a typical permeability of 1 x
10-5cm/sec, or a movement of about 300 feet in 30 years. Therefore
sand has greater permeability than clay. The permeability of a rock
is a measure of the resistance to the flow of a fluid through a
rock. If it takes alotof pressure to squeeze fluid through a rock,
that rock has low permeability or low perm. If fluid passes through
the rockeasily, it has high permeability, or high perm.Table 1.0:
diagram illustrating permeability chart for typical sediments.
Permeability in petroleum-producing rocks is usually expressed
in units calledmillidarcys(one millidarcy is 1/1000 of a darcy).
Most oil and gas reservoirs produce from rocks that have ten to
several hundred millidarcys. One darcy (1000 millidarcys) is a huge
amount of permeability!In the last 10 years, an increasing amount
of US gas production is coming from shale gas wells. Shale has a
lot of porosity (much more than sandstone), butextremely low
permeability. That means shale has historically been a poor
producer of hydrocarbons. While gas has been produced from shales
for over a hundred years, quantities were small. Two things have
changed the situation, allowing for increased shale gas
development. These concepts have allowed petroleum companies to
artificially induce more permeability into shale gas rocks:
CHAPTER FIVESUMMARY AND CONCLUSIONWe have defined a trap as any
geometric arrangement of rock that permits significant accumulation
of hydrocarbons in the subsurface. We do not consider the presence
of hydrocarbons in economic accounts to be a critical element of a
trap. The absence of oil or gas in a subsurface feature can be the
result of failure or absence of other essential elements or
processes of a petroleum system and may have nothing to do with the
viability of a trap. Although we use the geometric arrangement of
key elements to define a trap, trap evaluation must include much
more than just mapping the configuration of those elements.
Reservoir and seal characteristics are so important to trap
viability that their evaluation must be an integral part of any
trap study. Traps can be classified as structural, stratigraphic,
or combination trap, in addition, hydrodynamic flow can modify
traps and perhaps lead to hydrocarbon accumulations where no
conventional traps exist, as more and more of the worlds
hydrocarbon provinces reach mature stages of exploration, such
traps may provide some of the best opportunities for future
discoveries.