~"",.
!
Abstract
One of the most important processes for revitalization of
mature reservoirs is enhanced oil recovery (EOR) by gas injection. However, some engineers do not understand the scienceand,
consequently, target reservoirs for gas EOR which do not possess
appropriate character.
Six parameters which can be used to screen reservoirs for gas
injection potential are proposed in this article. Using the screening
criteria, three reservoirs have been evaluated. The results of the
evaluation are consistent with observed reservoir performance on
EOR.
Displacement Paradigms
Dullien(l) described the features of importance in multiphase
flow in porous media. Whereas many practitioners of reservoir
engineering have tended to employ global observations to infer
small-scale response,Chatsis(2),Diaz(3),Kwiecien et al.(4),Kantzas
et al.(5),and lonnadis et al.(6.7.8)
have focussed on the pore level to
describe macro-scale performance. A host of other researchers
have also contributed to the body of insightful literature which
helps us to better comprehend flow in porous media. Indeed,
Feder(9), Mandlebrot(IO) and others have begun to see flow in
porous media as a complex phenomenon to which fractal mathematics may hold an insightful eye.
The academicsand the practitioners agree on which parameters
govern fluid flow in porous media. Although it may not be
.
exhaustive,
FIGURE 1: Schematicora pore sizedistribution.
Interfacial Tension Effects
To displace oil from a pore the applied pressure drop must be at
least as large as the capillary pressure.As shown in Equation I, as
the interfacial tension (IFf) decreasesthe capillary force decreases and as the pore throat diameter decreases the capillary force
increases.
Pcapoc
-a
D
(1)
If Figure I portrays pore volume versus diameter and if accessibility equates to displacement then all oil contained in porous
features greater than Dw/o will be produced, where Dwlo corresponds to the 1FT of water and oil. From this model, if the gas/oil
1FT were lower than the water!oillFT, the gas should then access
porous features of a smaller diameter than did the water, thus
recovering more oil. Equation I only provides the relationship
between three parameters which must be considered in understanding gas injection strategies. Parameters causing a deviation
from accessibility! displacement proportionality
are many.
Mobility effects will be discussedfirst.
the set of parameters to consider is:
PhaseBehaviour,
. Interfacial Tension (1FT),
. Mobility Effects,
. Pore Size Distribution,
. Gravity,
. Wettability.
These are not in any order of priority, but every reservoir is
dominated by one or more of these parameters. Each will be discussedbriefly.
Phase Behavior Effects
Some important considerations with respect to phase behavior
are the extent of gas evolution with depressurization, organic
solids deposition tendencies and the presence/absenceof an initial
gas saturation.
14
0 (,m)
Mobility Effects
Another parameter, generally recognized as being of extreme
importance, is mobility.(II,12.13) The common fractional flow equation (data) describes the flow of oil and displacing fluid as
I
f d = -::--T
1+M
(2)
where
M=&~
~d k,o
0
(3)
Collins(14)showed that if dispersion is neglected, the length of a
The Journal of Canadian PetroleumTechnology
"viscous finger" is
10g(L)och
I1d
(4)
Pore Size Distribution
Superimposed over this finger growth expression is a statement
by Feder<9)"the fluid flow problem is controlled by the microscopic length scale in all spatial directions" and therefore
Equation (4) may occur but is influenced by the pore size distribution of the porous media.
Oil reservoirs are replete with interfacial effects due to intermolecular forces(15)and there is attraction between fluid and rock.
The forces of attraction will therefore vary between pore throats
of differing diameters (surface area to volume proportional to
lID). This results in fluid drag being a function of pore throat size,
drag being less in porous features where the surface area to volume ratio is lower. The pore size distribution is also the D in
Equation (I).
Gravity Effects
It is recognized that gravity plays an important role in all reservoirs and the thicker the reservoir, the more dominant the gravitY
influence. AsgarpoUr<16)summarizes some vertical flood results
and Kantzas et al.(17,18)
provide insight into both low and high 1FT
vertical gasfloods. StabilitY analysis indicates that the main benefit of a vertically oriented gasflood is that the buoyancy effect
may compensate for adverse viscosity ratios and pore size distribution effects. Stalkup(19)proposed a viscous to gravity ratio for
classifying the effects of gravity.
~=~
vlg
k Apg
0
(5)
Fayers and Zhou(2O)and Hicks and Deans(21)have provided
insight into gravity influences.
One point which has received short shrift iff the technical literature is whether the rates of oil recovery can be maintained sufficiently high at higher levels of gas/oil IFf.
The aficionados of high IFf gasfloods tend to emphasize the
stability of lean gas stating that "the immiscible displacements
resemble miscible displacements at viscosity ratios at least two
orders of magnitude less, and therefore they can be considered as
considerably more stable(22)."This conclusion was based on HeleShaw experimentation which has no porous media. The low IFf
systems have an implicit stabilizing influence in porous media due
to the greater accessibility which can equate to effectively larger
November 1998, Volume 37, No. 11
cross-sectional areas for flow. Therefore, although the ~p may
favour high IFf lean gas systems,the high 1FT may result in only
a fraction of the pore size distribution being accessed(Figure I).
Stalkup(19)shows the four regimes pertaining to levels of the
viscous to gravity ratio in Equation 5. Sweep in a vertical reservoir is improved by injection/production rates that are gravity
dominated. Sweep in a horizontal orientation is improved by
being viscous-dominated.
Wettability
Much has been written on the influence of wettability on gas
injection schemes. Stem(23)describes the influence of wettability
on by-passing indicating that wettability can predispose a core to
having solvent follow a path of least resistance through large or
small pores stating that it is likely to occur in mixed- and waterwet rock. Rao et al.(24)provided a succinct summary of some of
the influence that wettability can have on gasflood potential.
By means of summary, the influence of water-wetness can be
good and bad. In Figure 2, the assumption is made that the water
is "attracted" to the portion of the rock where the surface area to
volume ratio is maximized. In such a case, if the smallest pore
throats are occupied by water then an 1FT below agio would be
unnecessary-all the oil is contained in pores greater than 01 and
therefore access into porous features smaller than 01 is overkill.
Contrasting this with a reservoir which exhibits significant oil saturation in the smaller pores, the level of 1FT required for an oilwet core will be lower for the samedegree of accessibility.
Water blocking is more severe in water-wet media(25.26.27)
since
the presence of water reduces contact between oil and solvent. If
gas injection is implemented without water injection then this
effect is negligible, but if a tertiary scheme is implemented then
water blocking in water-wet reservoirs can be serious.
Deductions from Data Analysis:
Laboratory and Field
A large body of data was reviewed as part of an investigation
into parametersaffecting gas injection design. References28 to 38
inclusive provide some of the data associatedwith this review. On
this basis, a number of deductions were made:
I. The micro- and macro-scale geology is one of the most
important determinants in the design of EOR strategies.
2. Gas design should assessthe oil target location [which flow
unit(s)] and the cost of achieving an adequate level of Iff in
the several flow units.
3. Although the correct level of Iff is a necessary condition,
the balance between IFf, gravity, mobility and porous feature size distribution must be properly quantified. The
impact of Iff level on cost is critical as seen in Figure 3.
15
interfacial tension, mobility, porous feature size distribution,
gravity and wettability are implicit in these criteria.
These points can be schematically assembled into screening
criteria as in Figure 4. It is hoped that this approach to screening
reservoirs will be helpful to those evaluating mature fields for gas
injection potential.
Proposed Screening Criteria
It is recognized
ratio, although arbitrary. Field scale gas injection schemes have
worked well in this range «0.5 cP) whereas the author's database
is less extensive for oils with live oil viscosities greater than 0.5
cPo
Solids precipitation problems can also be very serious. Those
which occur in the wellbore can be treated fairly easily in many
cases(41)whereas if precipitation occurs in the rock then permeability reduction can ensue which can be more difficult to resolve.
Solids
that there are only a finite number of character-
istics which have been included in the proposed scheme.
Nevertheless. this is intended to provide a reasonable procedure
by which corporate priorities can be associated with individual
proouction units.
Reserves, Gas Availability, Process and
Gas Consumption
Assuming the historical recoveries reported by Asgarpour,(16)
Randall(29),and Fayers and Zhou(2O)(incremental oil recovery in
vertical mode of 15 to 40%, incremental oil recovery after waterflood of 5 to 15% in horizontal mode, 4000 scf/bbl of incremental
oil), an approximate value can be associated with the reservoir.
Note that the gas consumption number of 4 MSCF/bbl is based on
lean gas. Enriched hydrocarbon floods should be much lower (-2
MSCF/bbl). Moreover, the equipment to implement gas injection
will require upfront capital cost and therefore the pool has to be of
such a size to justify the expenditure. It is proposed that with these
conservative numbers along with those of Figure 3 (2 to 3
$CDN/MSCF) an idea of margin can be developed.
The priorities assigned to this initial stage of evaluation are
somewhat arbitrary and each corporation will have their own.
Nevertheless, it is proposed that:
Margin (Mr)
($CDN/m3)
>70
Rank
30
15
c
oJ
50 < Mr < 70
<50
Macroscale Evaluation
Once the initial margin calculation has been performed and the
property is deemed worthwhile for EOR scrutiny then the next
stage is evaluated, the macroscale features. It is proposed that a
hierarchy of characteristics be included in the following manner:
Orientation
Large Reserves
Small Reserves
Vertical
Horizontal
15
5
10
0
An added complexity, as was emphasized throughout the data
reported herein, is the presence of macroscale heterogeneities
such as faults, fractures, high permeability streaks and barriers. It
is proposed that these macroscale characteristics range from 0 to
10. Natural fractures may not present a significant deleterious
effect (Tan and Firoozabadi(39.40).Absence of these factors should
result in a rank of 10 being added to the macroscale evaluation
shown above.
Reservoir Fluid Properties
Most of the reservoirs reviewed contained oil viscosities in the
0.5 to 1.5 cP range. Since the finger growth is exponential with
viscosity ratio. high oil viscosity can be a significant disadvantage. Because oils with viscosities less than 0.5 cP have shown
significant response to gas EaR, it is proposed that:
!tail
@ T&P
Rank
<U.5cP
15
> 1.OcP
5
This provides a means of a~sociating a rank to the viscosity
November 1998. Volume 37, No. 11
Rank
None
10
Wellbore only
5
In Situ
0
The presence of a gas cap can also adversely affect the performance of a gas injection scheme but it is much more pronounced
for a horizontal operation than for a vertical flood.
GasCap
Rank
Gas cap
No gas cap
0
10
Microscale
Geology
Porous feature size distribution (PFSD)greatly impacts the performance of the gas injection schemes.
In the author's opinion, rocks exhibiting narrow pore size distributions (micro scale homogeneity) show the most promise.
Many times these will not be the reservoirs with the best permeability. In some cases, reservoirs which have exhibited poor
waterflood performance show significant upside for tertiary gas
because of the inherent microscale geology. Therefore, it is
proposed:
Microscale Homogeneous
Multiple Homogeneous Row Units
Broad Pore Size Distribution
Vuggy, Bi-modal Pore Size
Necessary Condition
15
10
5
0
1FT
The design of gas is closely coupled to the porous media and
all the attendant conditions.
With the costs approximated
by
Figure 3, the sensitivity of cost on IFI' is apparent. For most reservoirs observed, a gas/oil IFI' of 0.2 dynes/cm or less has been adequate. For enriched gas, the 1FT can always be adjusted by
increasing
the LPG content and/or the C2+ MW. It therefore
becomes a question of whether the enrichment required is affordable or not. Therefore, it is proposed that:
IFf
Achieved
For Accessibility
Yes
Rank
15
Water/Oil IFI'
0
By way of description,
if the gas/oil 1FT is designed low
enough to access all pore throats, then a rank of 15 is attached.
Note this does not mean zero IFf since for water-wet systems the
IFf should be designed to access the diameter corresponding to
water-filled
features and nothing smaller. The water/oil 1FT is
ranked at zero since it is the base level. Most lean gasfloods have
an IFI' in the 3 to 6 dynes/cm range whereas water/oil is usually
in the 12 to 18 dynes/cm range. The interpolation should then be
between:
10glo(0.1) =-1
loglo (lFI'w/o)~1
Rank = (l-log1o(IFI'»*7.5
The ranking for an IFI' of 3 would be 3.9 as an example.
Reservoir Orientation
The benefit of vertical versus horizontal orientation can be
huge in the technical and economic success of a reservoir. The
verticalorientationseemsto synergisewith the IFf influenceand
17
it is therefore proposed that an additional 10 points is added if vertical and nothing added if horizontal.
Necessary Condition 1FT
Vertical
Horizontal
Balance
Balance of 1FT, Mobility Gravity,
Wettability, Secondary, Tertiary
IFf dominant
WAG for mobility
Profile mod for mobility
Gravity override
Between
Wettability,
1FT, Mobility,
Secondary,
Gravity,
Tertiary
Although the different parameters can be determined independently, in order to obtain an initial view of the balance between
them, coreflood responses can be extremely important. To comment on the effects of mobility versus IFf domination, certain
core orientations can be utilized. As well, all other parameterscan
be held constant and the IFf level can be altered. This allows for
insight into the IFf/mobility/PFSD compromise. Secondary and
tertiary operation can also easily be scoped along with WAG,
coinjection or continuous gas. Water shielding versus imbibition
benefit is readily compared as well. It is proposed that the following ranking be used:
IFf Domination
Mobility or PFSD Dominated
(WAG or co-injection when water works well)
Mobility or PFSD Dominated
20
10
5
(water results are poor)
GravityOverrideDominated
0
Mobility or PFSD-dominated reservoirs have an element of risk
associated since they are inherently unstable unless steps prove
efficacious in controlling the gas. This higher risk is why the rank
is downgraded from 20 to 10. If water works well in controlling
the gas displacement however, the system can be very effective. If
the system is mobility or PFSD dominated and if water does not
enhance control, then more risky implementations may be
required (profile modifiers such as foams polymers, bacterial
slimes, etc.,). This type has therefore been downgraded to 5 in the
ranking.
The gravity override factor has been given a zero ranking only
to indicate the potential problem. If the viscous to gravity ratio
can be increased sufficiently to resolve an initial gravity override
problem then this can be upgraded. However, to do so the engineer will need to consider the viscous to gravity ratio and determine if it is possible.
Summary
Although simplistic in nature, three reservoirs will now be
ranked as examples of how to use the screening approach. The criteria are:
Parameter
Rank
Reserves Evaluation
Margin (Mr) > 70 $CDN/m3
50 < Mr < 70 $CDN/m3
50 $CDN/m3
Macroscale (Reserves)
Vertical
~orizonta1
Heterogeneities
None
Present
Fluid Properties
Oil Viscosity
Solids precipitation
None
Production Wells
Core plugging
Presenceof gas cap
Absence of gas cap
Microscale Geology
Homogeneous
Multiple homogeneous flow units
Broad pore size distribution
Vuggy, bi-modal pore size
.
18
30
15
5
Large Small
15
10
5
0
0 - 15
10
0
20
10
5
0
Using this ranking approach the maximum value is 150. The
absolute value is immaterial since the evaluations performed are
on a comparative basis to other reservoirs involved in the examination. The purpose is to identify the reservoir with the best gas
EaR potential from a list of candidates.
An example of the use of these criteria follows. Assume we
have three reservoirs and want to rank them in order to focus limited resources on the development of the best one. Here are the
specifics.
Reservoir 1-Characteristics
.
25 - 40 MMbbls oil
. Horizontal, homogeneous sand, only one flow unit, thin 6 to
10 feet
. 500API, 0.10 cP oil viscosity at reservoir conditions
Gas available from re-injection and pipelines
Low Swc' oil-wet
Some laboratory work was then performed to evaluate the pore
size distribution and interfacial tension.
..
The rank for this reservoir would be (assuming 50 to 70
$CDN/m3
in terms of the initial
reserves evaluation):
Reservoir1
Rank
Margin
Macroscale
- reserves
- no heterogeneities
Fluid Properties
- viscosity
- no solids
- no gascap
Microscale geology
-1 homogenous flow unit
1FT
- <0.1dynes/cm
- horizontal
Balance
- IFf domination
15
0
10
15
10
10
15
15
0
20
110
Thisreservoirhasbeenundergasfloodfor overtenyearsandis
a technicalsuccessand an economicallyviable"miscible" flood.
However,therehavebeensomesurpriseswith respectto premature breakthroughwhich may havebeenpresagedhad core work
beenperformedwhichcouldhaveansweredthis specificquestion.
Nevertheless with 110/150 points, this reservoir scored highly.
10
0
5-15
Reservoir 2-Gharacteristics
.
> 200MMbblsoil
. Vertical,zonesof vuggycarbonate(20% of oil), total reservoir> I 00 metres
10
5
0
0
10
15
10
5
0
. 400API,0.5 cP oil viscosity
. Gasreadilyavailable
. Solidprecipitation(asphaltenes)
Reservoir2
Rank
Margin
Macroscale
- reserves
30
- heterogeneities(20% of pay vuggy)
Fluid Properties
- viscosity
15
7
15
The Journal of Canadian Petroleum Technology
- solids (wellbores)
- gas cap present
Microscale geology
- broad pore size distribution
1FT
- < 0.1 dynes/cm
5
0
20
122
This flood has been operating for many years at a frontal
advance rate below critical. To date over 80% of OOIP has been
recovered and this EOR project is a technical and economic
success.
Reservoir 3-Characteristics
.> 50 MMbblsoil
. Horizontal, vuggy
. 350API, 11> 0.5 cP
. Gas readily available
Reservoir 3
Rank
Margin
Macroscale
- reserves
- heterogeneities
(some)
Fluid Properties
- oil viscosity (11 > 0.5 cP)
- solids
- no gascap
MicroscaleGeology
- bi-modalporesizedistribution
IFf
- about 0.5 dynes/cm
- mobility
dominated
5
5
10
5
10
0
9.8
Balance
(poor water results)
5
-65
This reservoir was never developed since laboratory waterflood
and gasflood recoveries were poor «20%). The only pores swept
were the large vuggy pores of the rock and all the smaller porous
features containing the oil were by-passed. Using lab-generated
relative permeability curves, the field simulation also indicated
inadequate economics to justify development. The operator therefore chose not to continue with the project even though there is
significant oil still in place.
From using this set of screening criteria, the reservoirs ranked
2, I, and 3. Both reservoirs I and 2 have proven to be technical
and economic field successes.
The author hopes that this approach to gas injection will help
operators to prioritize their candidate reservoirs for EOR.
ACKNOWLEDGEMENTS
The author acknowledges the contribution of his associates:
D.B. Bennion, X.L. Zhou, A. Erian, and D.W. Bennion, along
with the technical staff of Hycal Energy ResearchLaboratories.
NOMENCLATURE
p
= density
D
= diameter
f
= fractional
flow
g
= gravity
a
= interfacial
tension
L
= viscous
fingerlength
Mr = margin
M = mobilityratio
k
= permeability
P
= pressure
November 1998, Volume 37, No. 11
= proponionality
= velocity
= viscosity
5
15
10
- vertical
Balance
- Iff dominated
~
v
Ii
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