SPE 94134

Quantifying Bypassed Oil in the Vicinity of Discontinuous Shales During Gravity

Dominated Flow
A.H. Muggeridge, SPE, M.D. Jackson, SPE, O. Agbehi, SPE, H. Al-Shuraiqi, SPE, and C.A. Grattoni, SPE, Imperial College

Copyright 2005, Society of Petroleum Engineers

many of these field applications are in reef deposits3, 6, 9-11
This paper was prepared for presentation at the SPE Europec/EAGE Annual Conference held which are generally very homogeneous with high vertical
in Madrid, Spain, 13-16 June 2005.
permeability, others have been implemented in clastic
This paper was selected for presentation by an SPE Program Committee following review of
information contained in an abstract submitted by the author(s). Contents of the paper, as
reservoirs2, 4, 5, 7, 8. These latter formations typically contain
presented, have not been reviewed by the Society of Petroleum Engineers and are subject to discontinuous shales which act as barriers or baffles to flow14-
correction by the author(s). The material, as presented, does not necessarily reflect any 22
position of the SPE, their officers, or members. Electronic reproduction, distribution, or storage and may result in reduced sweep efficiency as well as
of any part of this paper for commercial purposes without the written consent of the Society of reducing the overall single phase vertical permeability (Fig.
Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract
of not more than 300 words; illustrations may not be copied. The abstract must contain 1a).
conspicuous acknowledgment of where and by whom the paper was presented. Write
Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435. Studies of immiscible displacements in simple ‘generic’
shale models suggest that oil in the vicinity of a shale is
initially bypassed by the displacing fluid, and subsequently
Abstract
drains from around the shale driven by viscous and
Gravity-stable, miscible gas injection is a common oil
gravitational forces (Fig. 1b).23-26 The initial bypassing of oil
recovery technique throughout the world. In homogeneous
leads to early breakthrough of the displacing fluid, and if
environments recovery efficiencies may be more than 90%.
many shales are present, to disruption of the displacement
However the influence of heterogeneity on the sweep
front. In this case sweep efficiency will depend on the time-
efficiency in these recovery schemes is not well understood.
scales for gravity drainage of oil from around the shales. If
For example most clastic reservoirs contain ‘discontinuous’
the timescale is short compared to the timescale of reservoir
shales that cannot be correlated between wells. Several
production, the ultimate recovery of oil is unchanged.15, 27
numerical studies have suggested that these may cause
In contrast, studies of more realistic shale distributions28-29
significant bypassing of oil during waterflooding or gas
suggest very little oil is bypassed except when shales are
injection. However flow experiments and detailed simulation
continuous over large areas of the bedding surfaces and are
of viscous dominated displacements, without gravity, indicate
steeply inclined to the flow or if the displacement is highly
that very little oil is bypassed1.
unfavourable. Further experimental studies investigating
In this paper, we investigate flow patterns around
viscous dominated flow around a single isolated shale1,
discontinuous shales during vertical, gravity-influenced
confirmed that very little oil is bypassed.
miscible gas injection in well-characterised bead-pack
There is relatively little data about vertical, gravity
experiments at three flow-rates corresponding to unstable,
dominated miscible flow around shales. A number of
partly stable and completely stable flow regimes. We examine
workers12, 13, 30-32 have performed experiments to investigate
the volume of oil bypassed and whether viscous fingering is
the stabilization of viscous fingering in vertical miscible
reduced by gravity or altered by the presence of a
displacements and compared those results with simulation33,
discontinuous shale. The results are compared to the
but in all cases the cores or sand-packs were homogeneous.
predictions of detailed simulation. We find that, during
Furthermore no fluid distributions within the core/pack are
miscible displacements, an isolated shale causes negligible
available to compare with those predicted by simulation, only
bypassing. However, during adverse mobility ratio
recoveries and solvent cuts. Log data from Prudhoe Bay35
displacements, the simulation program erroneously predicts
suggests that the oil lenses trapped underneath shales after
significant bypassing of oil both upstream and downstream of
miscible WAG are much smaller than those observed for
the shale at high and intermediate flow-rates.
water-flood, however these resulted from horizontal WAG
displacement. Simulation studies by Newley and Begg35
Introduction
suggest that volumes of oil bypassed during vertical multi-
Gravity stable, miscible gas injection has been applied in
contact miscible displacements through reservoirs with large
many oil reservoirs around the world2-11. The recovery
numbers of discontinuous shales may be significant.
strategy relies on low rates of miscible gas injection allowing
In this paper, we investigate gravity influenced, miscible
gravity segregation to reduce or prevent viscous fingering12-13.
flow in vertical displacements using a combination of well-
As a result, in homogeneous reservoirs, the bulk sweep
characterised experiments and detailed simulation. The sweep
efficiency approaches the improved local sweep efficiency (→
efficiency in a homogeneous system is compared with that
100%) associated with miscible displacements. Although
2 SPE 94134

obtained for a system containing a single ‘isolated’ shale (one Experimental techniques
which is far from the influence of other shales and the Pack design and construction
reservoir boundaries) as a function of mobility ratio and flow Grade 11 (160-250µm) Ballotini glass beads were chosen as
rate. We find good agreement between the experiments and the porous medium because they enabled a relatively
simulation for all M=1 displacements but the simulation homogenous sample to be constructed and simple flow
predicts significant bypassing of oil in the vicinity of the shale visualization techniques to be used. Two packs were
for unfavourable mobilities and flow rates between the critical constructed, each sealed in a Perspex box (20 × 10 × 0.7 cm).
and stable flow rates. This bypassing is not observed in the The homogeneous model was filled entirely with glass beads.
experiments. However all bypassed oil is recovered after The second model also contained a ‘shale’, formed by placing
injecting more than two pore volumes. a rubber strip in the centre of the model and attached to one
side, before the pack was filled with beads (Fig. 3a). By
Stabilization of viscous fingering. symmetry arguments the pack represented one half of the
Dumore13 identified three flow regimes in vertical miscible discontinuous shale. The length of the shale was constrained
displacements at adverse mobility ratios (Fig. 2): by the streamline pattern predicted by an analytic solution1,
1. completely stable flow when the flow is less than the and was chosen to ensure that the flow pattern around the
stable flowrate Qst, determined by shale would not be affected by the inlet and outlet boundaries.
A( ρo − ρs ) The thickness of the packs was determined by the requirement
Qst = kg (1) that the flow be essentially two-dimensional so that direct
µo(ln µo − ln µs ) comparison with 2D numerical simulations could be made.16
where k is the permeability (m2), g is the acceleration The models were packed following the method described
due to gravity (9.81 m s-2), A is the cross-sectional in Caruana17. A proportion of the beads were carefully poured
area (m2), ρo is the oil density (kg m-3), ρs is the into the Perspex box whilst it was held vertically. The pack
solvent (miscible gas) density (kg m-3), µo is the oil was then vibrated at approximately 100Hz for 60 s, in order to
viscosity (N s m-2) and µs is the solvent viscosity (N pack down the beads and ensure uniform packing. This
s m-2). In this case the flow-rate is so slow that process was repeated until the model was full.
gravitational segregation prevents the formation of To establish uniform flow at the inlet, fluid was injected
any viscous fingering. into a 1cm wide reservoir that was separated from the pack by
2. partly stable flow, where the flow-rate is greater than a wire mesh. The reservoir served to smooth out pressure
the stable flow rate Qst but less than the critical flow- variations. At the outlet there was a 0.2 cm wide reservoir that
rate Qcr was divided into two sections with an outlet port in the centre
kg ( ρo − ρs ) of each section. The packs were mounted vertically with the
Qcr = A (2) inlet uppermost (see Fig. 3) to enable the investigation of
( µo − µs ) gravity stabilisation of viscous fingering on the displacement
Small fingers form in the dispersed front between the efficiency.
oil and miscible gas but do not grow with time. The properties of the two packs are summarized in Table 1.
3. completely unstable flow, where the flow rate is Their porosities and permeabilities are typical of this type of
greater than the critical flow rate (equation 2). In this bead packs.16, 19-21.
case viscous fingers form and continue to grow.
Obviously these distinct flow regimes do not apply to unit Experimental conditions
mobility ratio displacements as there is no viscous fingering in A total of 5 miscible displacements were carried out in each
this case. pack. These used two mobility ratios (M=1 and M=10).
In this work we investigated the flow behaviour in Three M=10 displacements were performed at constant rates
vertical, miscible displacements at two mobility ratios (M=10 corresponding to the three flow regimes identified by
and M=1). The adverse mobility ratio (M=10) displacements Dumore13 and discussed in the previous section. The
were performed at 3 rates corresponding to the three flow calculated critical and stable flow rates for these pack and
regimes identified above. The unit mobility displacements fluid properties were 0.2 and 0.05 cm3/min respectively. The
were not expected to be influenced by gravity as there was no actual flow rates used in the experiments were 0.5 cm3/min
density difference between the displacing and displaced fluids. rates for the unstable flow regime, 0.14 cm3/min for the
Nonetheless displacements were performed at two rates, one intermediate (between stable and critical flow-rates) and 0.03
corresponding to that used for the unstable flow regime in the cm3/min for the completely gravity stable displacement. Two
adverse mobility ratio displacement and the other M=1 displacements were performed, one at 5 cm3/min and the
corresponding to the partly stable flow regime. other at 0.2 cm3/min. These corresponded to the unstable flow
and intermediate flow regimes in the adverse mobility ratio
displacements.
The fluid pairs used for each displacement and their
properties are summarized in Tables 2 and 3. The longitudinal
and transverse dispersion characteristics were required in the
numerical simulations. These values were taken from
Muggeridge et al1. They used a longitudinal dispersion
SPE 94134 3

coefficient of 0.036 cm and a transverse dispersion coefficient Results

of 0.0012 cm (giving αL/αT=30). Comparison of simulation and experiment (M=1)
Before starting each experiment the model was flooded Fig. 4 compares the recovery curves and solvent cuts obtained
with carbon dioxide to displace the air and then flooded with from experiments and simulation for the M=1 displacements
distilled water until the model was completely saturated. At in the homogeneous and shale packs at a flow rate of 5
the start of each experiment the water was immediately cm3/min. The results for the 0.5 cm3/min displacements are
displaced by clear glycerol solution (M=10) or distilled water not shown but they overlay the curves shown in Fig. 4 exactly,
(M=1). confirming that the M=1 miscible displacements with matched
All the displacements were conducted at a constant rate. densities are not influenced by gravity. The simulation results
Volumes and effluent fractions were measured at regular match the experimental data almost exactly. This confirms the
intervals and used to calculate recovery curves and effluent results of Muggeridge et al1 that simulation can predict the
profiles. flow behaviour of a unit mobility ratio, miscible displacement
around a shale.
Measurement techniques
Lissamine red dye was used as the tracer in the displacing Comparison of simulation and experiment (M=10)
phase. This enabled visualization of the displacement and Fig. 5 compares the fluid distributions predicted by simulation
allowed the effluent to be analyzed by colorimetry. From this with those observed in the experiments for the miscible M=10
data, outlet concentrations were determined with an accuracy displacements in the homogeneous pack at flowrates of 0.5
of ±2%. The displacements were also recorded using a camera cm3/min, 0.14 cm3/min and 0.03 cm3/min respectively. The
and video recorder. corresponding recovery curves and solvent cuts are shown in
Fig. 6.
Numerical techniques Overall agreement is very good. The simulation predicts
A full description of the simulation program and its validation the same fingering patterns as the experiments with fewer,
against Blackwell’s experiments30 is given in Christie and smaller fingers at the intermediate flow-rate than at the higher
Bond36. It has been further validated by comparison with flow-rate. There are subtle differences between simulation
miscible displacements in both glass bead-packs1, 33, 37, 38 and and experiment due to the differences in finger locations but
in a well-characterised, sandstone slab.39 The program was we would not expect to predict the exact locations of
designed to be fast and accurate, to enable it to model the individual fingers, since we do not know the details of how
development of viscous fingers in miscible displacements. It those fingers were triggered.
achieves this by using an IMPES solution technique Fig. 7, 8 and 9 compare the fluid distributions observed in
incorporating Flux Corrected Transport (FCT) and including the experiments and predicted by simulation for the miscible
only the physics essential to the description of unstable M=10 displacements in the shale pack at flowrates of 0.5
miscible flow. The following assumptions are made: cm3/min, 0.14 cm3/min and 0.03 cm3/min respectively. The
1. 2 phase, incompressible Darcy flow corresponding recovery curves and solvent cuts are shown in
2. 3 components – water, oil and miscible gas (‘solvent’) Fig. 10.
3. oil and solvent are first contact miscible In these cases, although the simulation correctly predicts
4. quarter power mixing rule for oil/solvent viscosities the experimental flow behaviour for the low rate (gravity
5. oil and solvent can mix by diffusion and dispersion: stable) case, it does not predict the correct flow behaviour for
⎛ D + α Lv 0 ⎞ the intermediate and high rate (unstable) flow regimes. In
D = ⎜⎜ ⎟ (3) both these cases the simulation predicts a worse sweep both
⎝ 0 D + α T v ⎟⎠ upstream and downstream of the shale than is actually
where D is molecular diffusion (cm2 sec-1), v is the total observed in the experiments (see Fig. 7 and 8). Muggeridge
velocity (cm/sec), αL is the longitudinal dispersion coefficient et al1 found good agreement between experiment and
(cm) and αT is the transverse dispersion coefficient (cm). simulation for the viscous dominated cases they examined
The full set of equations is described in detail in Christie40 (flow-rates 5 cc/min, no gravity).
and will not be reproduced here. Note that the data used in the
simulations were taken directly from the experimental Discussion
measurements. The simulation results are therefore The results obtained from these experimental and numerical
predictions and are not the result of a history matching models of flow around a single, isolated, shale demonstrate
procedure. that:
The simulations used a grid of 100×50 for the 1. Well converged numerical simulations correctly predict the
homogeneous experiments and a grid of 100×52 for the experimentally observed flow patterns, breakthrough time
experiments incorporating the shale. This resulted in square and ultimate sweep for miscible, gravity-influenced flows
grid-blocks, 2mm long, which were several times greater than in a homogeneous system. This confirms the results of
the dimensions of the glass beads. Grid refinement studies Christie et al38 who examined the influence of gravity in
demonstrated that the simulations were dominated by physical gravity influenced horizontal displacements.
rather than numerical dispersion. The shale was modelled by 2. The simulations do not predict the correct flow behaviour
using a transmissibility multiplier of zero. around the isolated shale for adverse mobility ratio
displacements at intermediate and high viscous to gravity
numbers. Bypassed oil is predicted both upstream and
4 SPE 94134

downstream of the shale. This is despite the use of a model volume for a fixed size of shale, the less impact the
higher order scheme and a very fine grid. We originally shale will appear to have on bypassing when measured in
suspected that this may be due to grid orientation error but terms of fraction of oil produced. Further work is required to
further investigations using a nine-point stencil and a determine why numerical simulation over-predicts the volume
commercial simulator did not improve the match; of bypassed oil in the vicinity of a shale at high and
3. The actual volume of bypassed oil upstream of the shale is intermediate rates.
minimal and independent of the flow rate. In general the
majority of bypassed oil is located downstream of the Nomenclature
shale; A = area, L2, m2
4. Regardless of mobility and displacement rate, oil which is D = molecular diffusion, L2/T, cm2 s-1
initially bypassed will ultimately be recovered; g = gravity acceleration, L/T2, m /s2
5. The rate at which the bypassed oil will be recovered k = permeability, L2, m2
depends upon the displacement conditions. For high rate M= mobility ratio
displacements more than 2.5 PV of solvent may be needed Q = flowrate, L3/T, m3 /s
to recover all the oil. v = velocity, L/T, m/s
Point (4) agrees with the findings of Thomas25 and Jackson αT= longitudinal dispersion coefficient, L, cm.
and Muggeridge29, who investigated the effect of multiple αL= transverse dispersion coefficient, L, cm
discontinuous shales on waterflooding and concluded that it µ0 = oil viscosity, M/L T, Pa s
was ‘surprisingly difficult’ to bypass oil in the vicinity of the µs = solvent viscosity, M/L T, Pa s
shales. Despite their findings, the conventional view of ρ0 = oil density, M/L3, kg m3
discontinuous shales is that they cause bypassing of oil. Point ρs = solvent density, M/L3, kg m3
(3) also contrasts with this conventional view which assumes
that the bypassed oil is located upstream of the shale,23,24,25. References
Conclusions 1. Muggeridge, A. H., Jackson, M. D., Al-Mahrooqi, S., Al-Marjabi,
We have compared experimental results and numerical M. and Grattoni, C.A., “Quantifying Bypassed Oil in the
simulation to quantify the sweep efficiency during vertical Vicinity of Discontinuous Shales”, paper SPE 77487 presented
miscible displacements. Both homogeneous systems and a at the 2002 SPE Annual Technical Conference and Exhibition,
system containing an isolated shale have been investigated. San Antonio, 29 September – 2 October.
Our principal findings are: 2. Perry, G. E., “Weeks Island ‘S’ Sand Reservoir B Gravity Stable
1. Simulation correctly predicts both the flow patterns, and Miscible CO2 Displacement, Iberia Parish, Louisiana”, paper
SPE 10695 presented at the 1982 SPE/DOE 3rd Joint
oil recovery profiles for vertical, miscible displacements
Symposium on Enhanced Oil Recovery held in Tulsa, OK, April
in homogeneous systems as a function of flow-rate. 4 - 7.
2. Regardless of the mobility ratio and viscous to gravity 3. Nagai, R. B., “Numerical Simulation of a Gravity Stable, Miscible
ratio, experimental results show that the volume of oil CO2 Injection Project in a West Texas Carbonate Reef”, paper
bypassed upstream of an isolated shale is minimal; the SPE 11129 presented at the Middle East Oil Technical
majority of bypassed oil is located downstream of the Conference of the SPE held in Manaina, Bahrain, March 14 –
shale. This does not agree with the conventional view 17, 1983.
that the bypassed oil is located upstream.23-25 4. Nute, A. J., “Design and Evaluation of a Gravity-Stable, Miscible
3. Regardless of the miscible displacement conditions, oil CO2-Solvent Flood, Bay St. Elaine Field”, paper SPE 11506
presented at the Middle East Oil Technical Conference of the
which is initially bypassed will ultimately be recovered; it
SPE held in Manaina, Bahrain, March 14 – 17, 1983.
is ‘surprisingly difficult’ to bypass oil in the vicinity of 5. Moore, J. S., “Design, Installation, and Early Operation of the
the shales over significant times. This agrees with the Timbalier Bay S-2B(RA)SU Gravity-Stable, Miscible CO2-
findings of Thomas25 and Jackson and Muggeridge.29 Injection Project, SPE Production Engineering (September
4. Numerical simulation will tend to over-predict the 1986) 369-378.
volumes of bypassed oil in the vicinity of an isolated 6. McIntyre, F. J., Polkowski, G. A., Bron, J. and Pow, M. J.,
shale at intermediate and high viscous to gravity numbers. “Radioactive Tracers Monitor Solvent Spreading in Rainbow
All this bypassed oil is recovered eventually, albeit more Vertical Hydrocarbon Miscible Flood”, SPE Reservoir
slowly than occurs in reality. Engineering (February 1988) 273-284.
7. Johnston, J. R., “Weeks Island Gravity Stable CO2 Pilot”, paper
Throughout this work we have assumed that the length-scale
SPE 17351 presented at the SPE/DOE Enhanced Oil Recovery
of these discontinuous shales is significantly less than the Symposium held in Tulsa, OK, April 17-20, 1988.
length-scale of the reservoir, so that we do not need to 8. Haugen, S. A., Lund, Ø. and Høyland, I. A., “Statfjord Field,:
consider the interaction of the shales with the reservoir Development Strategy and Reservoir Management”, JPT (July
boundaries. We have also assumed that the minimum volume 1983), 863-873.
associated with a shale which can be used to investigate flow 9. Hsu, H. H., “Numerical Simulation of Gravity-Stable
is given by the position at which the streamlines return to their Hydrocarbon Solvent Flood, Wizard Lake D-3A Pool, Alberta,
unperturbed position (i.e. the position they would have had if Canada”, paper SPE 17620 presented at the SPE Inetrnational
there were no shale). These assumptions are similar to those Meeting on Petroleum Engineering held in Tianjin, China,
November 1 – 4, 1988.
made by Begg and King19 when investigating single-phase
flow around discontinuous shales. Clearly, the larger the
SPE 94134 5

10. Da Sle, W. J., “Assessment of a Vertical Hydrocarbon Miscible Reservoirs?” paper SPE 37996 presented at the 1997 SPE
Flood in the Westpem Nisku D Reef”, SPE Reservoir Reservoir Simulation Symposium, Dallas, 8-11 June.
Engineering (May 1990) 147-159. 29. Jackson, M.D. and Muggeridge, A.H.: “The Effect of
11. Bangia, V. K., Yau, F. F. and Hendicks, G. R., “Reservoir Discontinuous Shales on Reservoir Performance During
Performance of a Gravity-Stable, Vertical CO2 Miscible Flood: Horizontal Waterflooding”, SPE Journal, 5(4) (2000), 446-455.
Wolfcamp Reef Reservoir, Wellman Unit”, SPE Reservoir 30. Blackwell, R.J., Rayne, J. R. and Terry, W. M., “Factors
Engineering (November 1993) 261-269. influencing the efficiency of miscible displacement”, Trans
12. Hill, S., “Channelling in Packed Columns,” Chem. Eng. Sci. AIME (1959), 216.
(1952), 1, 247-254. 31. Cardenas, R. L., Alston, R. B., Nute, A.J. and Kokolis, G. P.,
13. Dumore, J.M., “Stability Considerations in Downward Miscible “Laboratory Design of a Gravity-Stable Miscible CO2 Process”,
Displacement,” SPEJ (Oct. 1964). JPT (January 1984), 111-118.
14. Haldorsen, H.H. and Lake, L.W.: “A New Approach to Shale 32. Hudgins, D. A., Liave, F. M. and Chung, F. T. H., “Nitrogen
Management in Field-Scale Models,” SPEJ (August 1984) 447. Miscible Displacment of Light Crude Oil: A Laboratory Study”,
15. Haldorsen, H.H., Chang, D.M. and Begg, S.H.: “Discontinuous SPE Reservoir Engineering (February 1990), 100-106.
Vertical Permeability Barriers: A Challenge to Engineers and 33. Fayers, F. J. and Newley, T. M. J., “Detailed Validation of an
Geologists,” North Sea Oil and Gas Reservoirs, Kleppe et al. Empirical Model for Viscous Fingering with Gravity Effects”,
(eds.), Graham and Trotman, London (1987) 127-151. paper SPE 15993 presented at the 9th SPE Symposium on
16. Martin, J.H. and Cooper, J.A.: “An Integrated Approach to the Reservoir Simulation held in San Antonio, Texas, February 1-4,
Modelling of Permeability Barrier Distribution in a 1987.
Sedimentologically Complex Reservoir,” paper SPE 13051 34. McGuire, P.L. Foakes, A. and Spence, A. P., “Field Evaluation of
presented at the 1984 SPE Annual Technical Conference and Different Recovery processes in Zone 4 of the Prudhoe bay
Exhibition, Houston, 16-19 September. Field”, paper SPE 75152 presented at the SPE/DOE Improved
17. Hazeu et al.: “The Application of New Approaches for Shale Oil Recovery Symposium held in Tulsa, OK, 13-17 April 2002.
Management in a Three-Dimensional Simulation Study of the 35. Newley, T. M. J. and Begg S. H., “Characterizing the Effects of
Frigg Field,” SPEFE (September 1988) 493. Heterogeneity on Oil Recovery by Dry Gas Injection”, paper
18. Begg, S.H., Carter R.R. and Dranfield, P.: “Assigning Effective SPE 24921 presented at the 67th Annual Technical Conference
Values to Simulator Grid-Block Parameters Heterogeneous and Exhibition of Petroleum Engineers held in Washington
Reservoirs,” paper SPE 16754 presented at the 1987 SPE DC,October 4-7, 1992.
Annual Technical Conference and Exhibition, Dallas, 27-30 36. Christie, M.A. and Bond, D.J.: “Detailed Simulation of Unstable
September. Flows in Porous Media”, SPE Reservoir Engineering 2 (1987)
19. Begg, S.H. and King, P.R.: “Modelling the Effects of Shales on 514-522
Reservoir Performance: Calculation of Effective Vertical 37. Christie, M.A. and Jones, A.D.W.: “Comparison between
Permeability,” paper SPE 13529 presented at the 1985 SPE Laboratory Experiments and Detailed Simulation of Miscible
Reservoir Simulation Symposium, Dallas, 10-13 February. Viscous Fingering”, presented at the 4th European Symposium
20. Begg, S.H., Chang, D.M. and Haldorsen, H.H.: “A Simple on Enhanced Oil Recovery, Hamburg (1987)
Statistical Method for Calculating the Effective Vertical 38. Christie, M.A., Jones, A.D.W. and Muggeridge, A.H.:
Permeability of a Reservoir Containing Discontinuous Shales,” “Comparison between Laboratory Experiments and Detailed
paper SPE 14271 presented at the 1985 SPE Annual Technical Simulations of Unstable Miscible Displacement Influenced by
Conference and Exhibition, Las Vegas, 22-25 September. Gravity”, North Sea Oil and Gas Reservoirs II, Buller et al.
21. Deutsch, C.: “Calculating Effective Absolute Permeability in (eds.), Graham and Trotman, London (1990) 245-300.
Sandstone/Shale Sequences,” SPEFE (September 1989) 343. 39. Davies, G.W., Muggeridge, A.H. and Jones, A.D.W.: “Miscible
22. Desbarats, A.J.: “Numerical Estimation of Effective Permeability Displacements in a Heterogeneous Rock: Detailed
in Sand-Shale Formations,” Water Resources Research (1987) Measurements and Accurate Predictive Simulation”, paper SPE
23, 273. 22615 presented at the 1991 SPE Annual Technical Conference
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Shales on Oil Recovery,” JPT (November 1978) 1531. 40. Christie, M.A.: “High Resolution Simulation of Unstable Flows in
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Formations Containing Discontinuous Shales: A Numerical 297-304.
Study,” paper SPE 16012 presented at the 1987 SPE Reservoir
Simulation Symposium, San Antonio, 1-4 February.
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Stochastic Shale Barriers,” North Sea Oil and Gas Reservoirs II,
Buller et al. (eds.), Graham and Trotman, London (1990) 437-
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Immiscible Gravity-Stable Gas Injection into Stratified
Reservoirs”, SPEJ (August 1985), 554-564.
27. Bradley, M., Mayson, H. J. and Wilkins K. L., “An Integrated
Approach to Refining Reservoir Description Through
Monitoring Fluid Movements in the Prudhoe Bay Reservoir”,
paper SPE15567 presented at the 61st Annual Technical
Conference and Exhibition of the Society of Petroleum
Engineers held in New Orleans, LA October 5-8, 1986.
28. de Riz, L. and Muggeridge, A.H.: “Will Vertical Mixing Improve
Oil Recovery for Gravity Dominated Flows in Heterogeneous
6 SPE 94134

Model Porosity Permeability (D)

Homogeneous 0.42 32

Shale 0.35 28

Table 1. Porosity and permeability of the beadpacks.

Displaced Phase Displacing Phase

Miscible, M=1 Clear water Red water
(oil) (solvent)
Miscible, M=10 Glycerol solution Red water
(viscous oil) (solvent)

Table 2. Fluid pairs used in the displacements.

Density ( Kg/m3) Viscosity (mPa.s)

Water 991±5 1.01±0.05
Glycerol solution 1156±2 10.6±0.4

Table 3. Properties of fluids used in the displacements

SPE 94134 7

Oil lens

Tortuous path for Gravity drainage

single phase flow over edges of
through shales shale

(a) (b)

Figure 1: Schematic of how discontinous shales can

a) reduce the vertical permeability by making the flow path more tortuous and
b) can result in a bypassed lens of oil upstream of the shale during displacement by gas

(a) (b) (c)

Figure 2: Schematic of the three flow regimes that may be encountered during vertical downwards displacement of oil by miscible gas:
a) high rate – unstable viscous fingering
b) rate between the critical and the stable rates, small levels of viscous fingering
c) flow rate is less than the stable flow rate, no fingering and a uniform front.
8 SPE 94134

Flui d i n le t Flui d i n le t

T o M a n ome te r a n d

T ra n sduc

Flui d o utl et Flui d o utl e t

(a ) (b)

Figure 3: Schematic of bead packs used for performing the displacements.

(a) system with an isolated shale, and (b) homogeneous system.

1
0.9
0.8
Oil Recovery, PV

0.7
Experiment, Homogeneous,
0.6
Q=5 cc/min
0.5 simulation
0.4
Experiment, Shale,
0.3 Q=5cc/min
simulation
0.2
0.1
0
0 0.5 1 1.5 2 2.5 3
Pore Volumes Injected

1
0.9
0.8
0.7
Solvent cut, PV

0.6 Experiment, Shale, Q=5

cc/min
0.5 simulation
0.4
Experiment, Homogeneous,
0.3 Q=5 cc/min
0.2 simulation
0.1
0
0 0.5 1 1.5 2 2.5 3
Pore Volumes Injected

Figure 4: Comparison of predicted and observed oil recoveries (top) and solvent cuts (bottom)
for an M=1 miscible displacement through a homogeneous pack and one containing a shale at a flow-rate of 5 cc/min.
SPE 94134 9

Flow Direction

A B C

Fig. 5: Comparison of concentration distributions predicted by simulation and observed during the experiment in the
3 3
homogeneous pack, for various flow rates: a) at 0.8 PVI and 0.5 cm /min , b) at 0.8 PVI and 0.14 cm /min and c) at 0.9 PVI and
3
0.03 cm /min.

0.9

0.8
Oil recovery (PV)

0.7

0.6

0.5

0.4 Experiment, Q=0.14 cc/min

simulation
0.3
Experiment, Q=0.5 cc/min
0.2 simulation
Experiment, Q=0.03 cc/min
0.1 simulation

0
0 0.5 1 1.5 2 2.5
Pore Volumes Injected
1

0.9

0.8

0.7
Solvent Cut (PV)

Experiment, Q=0.14 cc/min

0.6 simulation
Experiment, Q=0.5 cc/min
0.5
simulation
0.4 Experiment, Q=0.03 cc/min
simulation
0.3

0.2

0.1

0
0 0.5 1 1.5 2 2.5
Pore Volumes Injected
Figure 6: Comparison of simulated and experimental fluid recoveries (top) and solvent cuts (bottom) for the homogeneous pack at 5cc/min,
0.14 cc/min and 0.03 cc/min.
10 SPE 94134

Flow Direction

Fig. 7: Comparison of concentration distributions predicted by simulation

3
and observed in the experiment for a flow-rate of 0.5cm /min in the
shale pack at 0.8 PVI.

Flow Direction

A B
Fig. 8: Comparison of concentration distributions predicted by simulation
3
and observed in the experiment for a flow-rate of 0.14 cm /min in the
shale pack at A) 0.6 PVI and B) 1PVI.

Flow Direction

A B
Fig. 9: Comparison of concentration distributions predicted by simulation
3
and observed in the experiment for a flow-rate of 0.03 cm /min in the
shale at A) 0.4 PVI and B) 0.9 PVI
SPE 94134 11

1
0.9
0.8
Oil Recovery, PV

Experiment, Q=0.5 cc/min

0.7
simulation
0.6 Experiment, Q=0.14 cc/min
simulation
0.5
Experiment, Q=0.03 cc/min
0.4 simulation
0.3
0.2
0.1
0
0 0.5 1 1.5 2 2.5
Pore Volumes Injected

1
0.9
0.8
Solvent Cut, PV

0.7
Experiment, Q=0.5 cc/min
0.6 simulation
0.5 Experiment, 0.14 cc/min
simulation
0.4 Experiment, Q=0.03 cc/min
0.3 simulation

0.2
0.1
0
0 0.5 1 1.5 2 2.5
Pore Volumes Injected

Figure 10: Comparison of simulated and experimental fluid recoveries (top) and solvent cuts (bottom) for the shale pack at 5cc/min, 0.14
cc/min and 0.03 cc/min.