Reservoir simulation modeling of the surfactant flooding using Schlumberger Petrel Simulation modeling software. Definition and Process Description Surfactant Conservation (Mass Balance) Equations Simulation Solution Vector Surfactant Effects; Treatment of PVT data Treatment of SCAL data Modeling the Change in Wettability Surfactant Keywords Summary Simulation Model Construction Sensitivities Runs & Simulation Results Conclusions

1. Pre-master Petroleum Engineering, Cairo University,
Spring 2016
1
Presented to:
Prof. Helmy Sayyouh & Prof. Ahmed El-Banbi

2. Team Members
• Hesham Mokhtar Ali
• Mohamed Hussein Abdel Kareem
• Heba Abdel-Moneim Younes
• Ahmed Nasser Hassanien
• Mahmoud Hamdy Gobran
• Beshoy Safwat Morees
• El-Saied Ameen
• Mohammed Osama Abdullah El-Ghareeb
2

3. Agenda
• Definition and Process Description
• Surfactant Conservation (Mass Balance) Equations
• Simulation Solution Vector
• Surfactant Effects;
• Treatment of PVT data
• Treatment of SCAL data
• Modeling the Change in Wettability
• Surfactant Keywords Summary
• Simulation Model Construction
• Sensitivities Runs & Simulation Results
• Conclusions
3

4. Surfactant Flooding; Definition
• It’s an EOR process in which a small amount of
surfactant (typically 0.3 – 1 volume %) is added
to an aqueous fluid (water) injected to sweep
the reservoir.
• The presence of surfactant reduces the
interfacial tension between the oil and water
phases and also alters the wettability of the
reservoir rock to improve oil recovery.
4

5. Process Description
• Behind the flowing oil bank the surfactant will prevent the
mobilized oil to be re-trapped.
• The purpose of surfactant flooding is to recover the
capillary trapped oil after waterflooding (De-Saturation).
• After the surfactant solution has been injected, the trapped
oil droplets can be mobilized by a strong reduction in oil-
water Interfacial Tension (IFT).
• The surfactant overcomes natural capillary forces by
lowering the oil/water interfacial tension (IFT) to a lower
level.
• This allows oil globules in the reservoir to flow through
rock pores and combine to form a clean oil bank.
5

6. Surfactant Model Modifications
• In ECLIPSE 100; the distribution of injected surfactant is
modeled by solving a conservation equation for surfactant
within the water phase.
• The surfactant concentrations are updated fully implicitly at
the end of each time step after the oil, water and gas flows
have been computed.
• The surfactant is assumed to exist only in the water phase,
and the input to the reservoir is specified as a concentration
at a water injector using the “WSURFACT” keyword.
• Modification is required to the standard aqueous (water)
equation and additional equations are needed to describe the
flow of surfactant and brine within the finite difference grid.

7. Black Oil Formulation of Equations
For a three-phase, three-component system:
• Oil’s FDE
• Water’s FDE
• Gas’s FDE

8. 8
Modifications of Equations
• Water Phase Continuity Equation:
𝑑
𝑑𝑡
𝑉𝑆 𝑤
𝐵𝑟 𝐵 𝑤
=
𝑇𝑘 𝑟𝑤
𝐵 𝑤µ 𝑤 . 𝑒𝑓𝑓 𝑅 𝑘
𝛿𝑃𝑤 − 𝜌 𝑤 𝑔𝐷𝑧 + 𝑄 𝑤
• Brine continuity Equation:
𝑑
𝑑𝑡
𝑉𝑆 𝑤 𝐶 𝑛
𝐵𝑟 𝐵 𝑤
=
𝑇𝑘 𝑟𝑤 𝐶 𝑛
𝐵 𝑤µ 𝑛 . 𝑒𝑓𝑓 𝑅 𝑘
𝛿𝑃𝑤 − 𝜌 𝑤 𝑔𝐷𝑧 + 𝑄 𝑤 𝐶 𝑛
• Surfactant Continuity Equation:
𝑑
𝑑𝑡
𝑉∗ 𝑆 𝑤 𝐶𝑠
𝐵𝑟 𝐵 𝑤
+
𝑑
𝑑𝑡
𝑉𝜌 𝑟 𝐶𝑠
𝑎
1 − 𝜙
𝜙
=
𝑇𝑘 𝑟𝑤 𝐶𝑠
𝐵 𝑤µ 𝑠 . 𝑒𝑓𝑓 𝑅 𝑘
𝛿𝑃𝑤 − 𝜌 𝑤 𝑔𝐷𝑧 + 𝑄 𝑤 𝐶𝑠
𝑉∗ = 𝑉 1 − 𝑆 𝑑𝑣𝑝

9. • 𝑆 𝑑𝑣𝑝 denotes the dead pore space within each grid cell
• 𝐶𝑠
𝑎
 Denotes the surfactant adsorption concentration
• 𝜌 𝑟  Denotes the mass density of the rock formation
• 𝜙 Denotes the porosity
• 𝜌 𝑤 Denotes the water density
• Σ  denotes the sum over neighboring cells
• 𝑅 𝑘  denotes the relative permeability reduction factor for the aqueous phase due to
surfactant retention
• 𝐶𝑠 , 𝐶 𝑛 denote the surfactant and salt concentrations respectively in the aqueous
phase
• µ 𝑎 . 𝑒𝑓𝑓 denotes the effective viscosity of the water (a=w), surfactant (a=s) and salt
(a=n).
• 𝐷𝑧 is the cell center depth.
• 𝐵𝑟, 𝐵 𝑤 are the rock and water formation volumes
• T is the transmissibility
• 𝑘 𝑟𝑤 is the water relative permeability
• 𝑆 𝑤 is the water saturation
• V  is the block pore volume
• 𝑄 𝑤 is the water production rate
• 𝑃𝑤 is the water pressure
• g is the acceleration due to gravity
Continuity Equations- Cont’d

10. • The model makes the assumption that the density and formation
volume factor of the aqueous phase are independent of the
surfactant and salt concentrations.
• The surfactant solution, the reservoir brine and the injected water
are represented in the model as miscible components in the
aqueous phase, where the degree of mixing is specified through the
viscosity terms in the conservation equations.
• The fluid viscosities (μw eff, μn eff, μs eff) are dependent on the local
concentrations of salt and surfactant in the solution.
• Surfactant adsorption is represented by the additional mass
accumulation term on the left hand side of Surfactant Continuity
Equation
• The adsorption term requires that you specify the adsorption
isotherm “𝑪 𝒔
𝒂” for each rock type.
• The effect of pore blocking and adsorption on the aqueous phase
relative permeability is treated through the term, Rk , which requires
the input of a residual resistance factor for each rock type.
Continuity Equations- Cont’d

11. Simulation Solution
Method of
Solving
• For black oil model, there is two options (IMPES and
Fully Implicit) schemes.
• For Surfactant flooding model , there is only Fully
Implicit scheme.
Solution
Vector
• For black oil in every grid block, we have 3 unknowns:
1. Pressure
2. Water Saturation
3. Gas Saturation
• For Surfactant flooding model in every grid block, we
have 5 unknowns:
1. Pressure
2. Water Saturation
3. Gas Saturation
4. Surfactant Concentration
5. Salt Concentration.

12. Summary of Equations & Unknowns
• There are 5 equations & 5 independent unknowns in case of
surfactant flooding with brine active simulation.
• The main 5 Mass Balance equations to solve for 5 unknowns
are:
1. Oil Equation
2. Gas Equation
3. Water Equation
4. Surfactant Equation
5. Brine Equation
• The 5 independent unknowns for every grid block will be:
Pressure, Water saturation, Gas saturation, Surfactant
concentration, and Salt concentration.

13. Surfactant Effects
• The presence of surfactant in the solution can
affect reservoir performance in three different
ways;
1. PVT modifications; the water properties.
2. SCAL modifications; the oil-water surface tension
which affects the capillary pressure and the oil and
water relative permeabilities.
3. The rock wettability; by the adsorbed surfactant on
the rock surface.
13

14. Water PVT Properties
• The surfactant modifies the viscosity of the pure
or salt water that’s defined by the PVTW or
PVTWSALT keywords respectively.
• The viscosity of water surfactant solution input
as a function of surfactant concentration using
the SURFVISC keyword as follows:
14

15. Water PVT Properties
• The viscosity of the water (at reference pressure) is
given as input as a function of surfactant
concentration.
• Effect of surfactant on water viscosity is defined
by the keyword SURFVISC;
15

16. Water PVT properties
• If the Brine option is active, the previous equation
becomes a function of salt concentration Cs as well:
16
PVTWSALT
keyword (PROPS
section)

17. Relative Permeability Model
• It is expected that the relative permeability to water should
increase when the residual oil saturation (Sor) decreases,
simply because there is less oil to restrain the flow of
water.
• This applies an increase in mobility for the injected
solution when the IFT and Sor is decreased due to
surfactant flooding.
• In addition to the existing immiscible relative permeability
curves with low capillary number (Nc) a miscible relative
permeability curve with high Nc is required.
17

18. Relative Permeability Model
• A transition between these curves are made, and a
table that describes the transition as a function of
log10(Nc) must be included.
• The relative permeability model is essentially a
transition from immiscible relative permeability curves
at low Nc to miscible relative permeability curves at
high Nc.
• The SURFCAPD keyword describes that transition by
defining an interpolation parameter (Fkr) as a function
of the log10(Nc) as following;
18

19. Relative Permeability Model
• The relative permeability at a
value of the miscibility function
between the two curves
(immiscible and miscible) is
calculated in 2 steps;
1. The endpoints of the curve
are interpolated and both
the immiscible & miscible
curves are scaled to honor
these points.
2. The relative permeability
values are looked up on
both curves, and the final
relative permeability is
taken as an interpolation
between these two values
(weighting). 19

20. Relative Permeability Model
• A weighted average (F) times the oil-wet Kr and (1-F)
times the water-wet Kr is used.
• The interpolated relative permeability is calculated as
following;
20

21. Capillary Pressure
• The water-oil capillary pressure will reduce as the concentration
of surfactant increases; causing a reduction in the capillary-
trapped residual oil saturation (Sor).
• The oil water capillary pressure is given by:
21
Where; Fcp is the capillary pressure multiplier
SURFST keyword: Surfactant IFT
(Right) vs. surfactant concentration
(Left)

22. Capillary De-saturation
• To reduce the residual oil saturation in the water
flooded zones (Sorw), the pressure drop over the
trapped oil has to overcome the capillary forces that
keep the oil trapped.
• This is done in the surfactant model when the IFT
between oil and water is reduced.
• The residual oil saturation can be correlated with
capillary number (NC) by Capillary Desaturation
Curve (CDC).
22

23. Capillary De-saturation
• The capillary number represents the ratio of shear forces to
capillary (surface tension) forces and is defined as:
Where;
• u = The Darcy's velocity of phase p,
• µ = The viscosity of the displacing fluid (water-surfactant
solution),
• σ = Interfacial tension between oil and the surfactant solution.
23
• By substituting Darcy’s velocity; we will get the equation used in
Eclipse* 100:

24. Capillary De-saturation
• The Capillary Desaturation Curve (CDC) describes the
relationship between Nc and residual oil saturation.
• CDC varies with pore size distribution and wettability.
24
NCri(Lake, 1984)

25. Capillary De-saturation
• In surfactant model; SURFCAPD keyword defines the miscibility
factor vs. the value of log10 (Nc).
• If the log10(Nc) is in the range -9.0 to -5.0 the immiscible
condition will be used and this means that the surfactant
concentration is low or zero, but if the log10(Nc) is -2.5 or
higher the miscible condition is satisfied and the surfactant
concentration is high enough to mobilize the capillary trapped
oil.
25

26. Capillary Number and Oil Recovery
26
• A relationship between the Nc and oil recovery, by Chatzis
and Morrow (1982).

27. Surfactant Adsorption
• The adsorption of surfactant occurs at the interface between
the solid and liquid, and is initiated by electrostatic
interaction between the solid and surfactant.
• To obtain as low IFT as possible, it is important to keep the
surfactant concentration as high as possible.
• The shape of the adsorption isotherm may vary for different
systems, and some factors that influence the plateau is salinity,
pH-value, temperature, and wettability.
• To prevent adsorption, it is suggested to use pre-flushing with
different types of chemicals in order to reduce hardness,
make the rock more negative charged and block the active
sites of the rock.
27

28. Surfactant Adsorption
• In E100, The adsorption of surfactant is assumed to be
instantaneous, and the quantity adsorbed is a function of the
surrounding surfactant concentration.
• The quantity of adsorbed surfactant on the rock as a function of
surfactant concentration is given by:
28
SURFADS: defines saturated concentration
of surfactant adsorbed by the rock as a
function of Surf. concentration.
• Eclipse surfactant model requires adsorption isotherm as a
function of surfactant concentration as input by SURFADS
keyword.

29. Surfactant Adsorption
• Two adsorption models that can be selected using SURFROCK
keyword;
1. Model 01: ensures that each grid block retraces the
adsorption isotherm as the surfactant concentration falls.
2. Model 02: assumes that the adsorbed surfactant
concentration on the rock may NOT decrease with time, so
it does not allow for any de–adsorption.
29

30. The Wettability Change
• E100 surfactant model is capable of modeling the changes in
rock wettability due to the accumulation of Surfactant.
• SURFACTW: activates the surfactant model and enables
modeling of changes of wettability as well, and requires oil–wet
immiscible saturation functions as input (Keywords;
SWFN,SOF2),
• The user defines additional immiscible saturation functions and
these are then taken to model the water–wet situation.
• A weighted average (F) times the oil–wet value and (1–F) times
the water–wet value is used.
• The formula for the new relative permeability is;
30

31. Surfactant Model in Eclipse
• E100 does not provide a detailed chemical simulation
of surfactant flooding, but it models the most important
features on a full field basis.
• The surfactant distribution is modeled by solving the
conservation equation for surfactant within the water
phase.
31

32. E100 keywords; RUNSPEC section
• SURFACT: activates the surfactant model.
• SURFACTW: activates the surfactant model and
enables modeling of wettability changes, this
keyword must be specified in PROPS section
using SURFADDW keyword.
32

33. E100 keywords; PROPS section
• SURFADDW : Defines weighting between oil-wet and
water-wet relative permeabilities as a function of the
adsorbed surfactant mass (with SURFACTW).
• SURFADS: Defines surfactant adsorption isotherm.
• SURFCAPD: Defines surfactant capillary de-saturation.
• SURFROCK: Defines surfactant-rock properties.
• SURFST: Defines water-oil surface tension in the
presence of surfactant.
• SURFVISC: Defines modified water viscosity.
33

34. E100 keywords; SCHEDULE section
• WSURFACT: surfactant concentration in a water
injection well.
• SURFMAX: maximum adsorbed surfactant
concentration (output keyword inside RPTRST
keyword).
• EWV_SUR: effective water viscosity due to surfactant
(output keyword inside RPTRST keyword).
34

35. 35

36. Model Description
• Model Dimensions (ΔX/ ΔY/ ΔZ): 10*10*3 (300 Grid blocks)
• 2D area of model= 250,000 m2
• Phases: Oil, Water, Surfactant.
• Homogeneous reservoir (Kx=Ky).
• PERMX (Kx): 100*4500 100*3300 100*2400 /
• PERMZ (Kz): 100*1050 100*1800 100*500 /
• Porosity (φ): Constant (0.25); 300*0.25 /
• Oil-wet reservoir.
• Water viscosity is 0.34 cp.
• Oil viscosity is 0.47 cp.
• Initial reservoir pressure (Reference Pressure, Pref)= 270 bar.
• Two wells: 1 oil producer (OP) and 1 water injector (INJ) at the model
edges.
• Start date of the run: 01/05/1990.
• Water injection start date since start up (01/05/1990).
• Control data for production well: Production well economic limits.
36

37. Model Description
37
Perm X=Perm Y Perm Z
Porosity=0.25SWAT=0.145
PERMX (Kx): 100*4500 100*3300 100*2400 / PERMZ (Kz): 100*1050 100*1800 100*500 /

38. Sensitivities Runs
• Six sensitivity runs were conducted to investigate the effect of
different parameters on the reservoir performance;
1. Waterflooding vs. surfactant flooding,
2. Surfactant viscosity,
3. Surfactant concentration,
4. Surfactant adsorption,
5. Capillary de-saturation, and
6. Surfactant rock properties.
• The simulation results are shown in terms of:
• FOPR; Field oil production rate,
• FWCT; Field W.C,
• FOPT; Field cumulative oil production,
• FWPT; Field cumulative water production.

39. Waterflooding vs.
Surfactant Flooding
39

40. Waterflooding vs. Surfactant Flooding-
Injection Rates
40
• Water injection rate =485
m3/D
• Surfactant concentration in
INJ =30 Kg/Sm3=14550 Kg/D

41. Waterflooding vs. Surfactant Flooding
41
Waterflooding Surfactant flooding
235.7
72.8 M
75.09 M
0.52
19.02
0.96
60.81 M
86.6 M

42. Water Saturation
42
Surfactant
Flooding
Waterflooding
About 100 %
Water saturation
(0 % SORW)
About 65 % Water
saturation (35 %
SORW)

43. Effect of Surfactant Viscosity
43
0.5 cp100 cp2.5 cp
Using SURFVISC keyword (SURF concentration, Kg/Sm3 versus the SURF
Viscosity , CP)

44. Water Saturation
44
(2.5 cp)
(0.5 cp)
(100 cp)
• The water saturation in the
water flooded area is 100
% in case of 2.5 CP
SURFVISC to about 93 %
in case of 0.5 cp
SURFVISC.

45. Effect of Surfactant Concentration
45
30 Kg/Sm3 10 Kg/Sm3 60 Kg/Sm3
The surfactant concentration in INJ

46. Residual Oil Saturation
46
30 Kg/Sm3,
Nc=-1.7
10
Kg/Sm3
Nc=-2.2
60 Kg/Sm3
Nc=-1.2
• The area of zero %
residual oil saturation is
the highest for the highest
surfactant concentration
(60 Kg/Sm3).

47. Effect of Surfactant Adsorption
47
0.0005 Kg/Kg 0.0002 Kg/Kg No SURFADS
The surfactant adsorption by changing SURFADS keyword

48. Residual Oil Saturation
48
0.0005 Kg/Kg
0.0002 Kg/Kg
No Adsorption
Concentration of surfactant
adsorbed by the rock
• The area of zero residual oil saturation
(SORW) is increasing with the
decreasing the surfactant losses due
to the adsorption.

49. Effect of Capillary De-saturation
49
Full Miscibility 0.5 Miscibility 0.1 Miscibility
Reduction in
capillary-trapped
residual oil will
increase FOPR
The effect of CAPD is modeled by the miscibility function (SURFCAPD)

50. Residual Oil Saturation
50
Full Miscibility
0.5 Miscibility
0.1 Miscibility

51. Effect of Surfactant-rock Properties
51

52. Simulation Results; Category of
the Parameters
• By reviewing the achieved simulation results,
we can categorize the most effective
parameters on the performance of the
surfactant flooding project as following;
1. Surfactant concentration
2. Surfactant adsorption
3. Capillary de-saturation
4. Surfactant viscosity
5. Surfactant rock properties

53. Conclusions
• E100 surfactant model models the distribution of injected
surfactant by solving a conservation equation for
surfactant within the water phase.
• E100 does NOT provide a detailed chemical simulation of
surfactant flooding, but it models the most important
features on a full field basis.
• The surfactant flooding is a promising EOR-method under
right conditions.
• The simulation results is needed to be supported by a
calibrated (history matched) model.
• A high adsorption level will reduce the effect of the
surfactant flooding performance.
• The surfactant concentration is the most effective
parameters on the field performance.
53

54. References
• Schlumberger: “Eclipse Reference Manual”, Version 2013.1.
• Schlumberger: “Eclipse Technical Description”, Version 2013.1.
• Al–Hashim, H.S., Obiora, V., Al–Yousef, H. Y., Fernandez, F., and Nofal,
W.: “Alkaline Surfactant Polymer Flooding Formulation for Saudi
Arabian Carbonate Reservoirs”, Tulsa, OK, Apr., 1996.
• Arihara, N., Yoneyama, Akita, Y., and Lu, X.: “Oil Recovery Mechanism
of Alkali–Surfactant–Polymer Flooding”, SPE 54330 prepared for
presentation at SPE Asia Pacific Oil and Gas Conference and
Exhibition, Jakarta, Indonesia, Apr., 1999.
• Baviere, M., Glenat, P., Plazanet, V., and Labrid, J.: “Improvement of the
Efficiency/Cost Ratio of Chemical EOR Processes by Using
Surfactants, Polymers, and Alkalis in Combination”, SPE 27821
presented at the SPE/DOE Ninth Symposium on Improved Oil
Recovery, Tulsa, OK, Apr., 1994.
• Chatzis, I., Morrow, N. R.: “Correlation of Capillary Number
Relationships for Sandstone”, SPE10114, 1984.
• Craig, F.F.: “The Reservoir Engineering Aspects of Waterflooding,” SPE
Monograph Series, Dallas, p. 21, 1971.
54

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