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Pre-master Petroleum Engineering, Cairo University, Spring 2016

Surfactant Flooding Reservoir SimulationPresented to:

Prof. Helmy Sayyouh & Prof. Ahmed El-Banbi

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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

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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

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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.

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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.

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.

Black Oil Formulation of Equations

For a three-phase, three-component system:

• Oil’s FDE

• Water’s FDE

• Gas’s FDE

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Modifications of Equations• Water Phase Continuity Equation:

• Brine continuity Equation:

• Surfactant Continuity Equation:

Adsorption Term

Gravity Effect

Surfactant concentration

Salt concentration

• denotes the dead pore space within each grid cell• Denotes the surfactant adsorption concentration• Denotes the mass density of the rock formation• Denotes the porosity• Denotes the water density• Σ denotes the sum over neighboring cells• denotes the relative permeability reduction factor for the aqueous phase due to

surfactant retention• , denote the surfactant and salt concentrations respectively in the aqueous phase• denotes the effective viscosity of the water (a=w), surfactant (a=s) and salt (a=n).• is the cell center depth.• are the rock and water formation volumes• T is the transmissibility• is the water relative permeability• is the water saturation• V is the block pore volume• is the water production rate• is the water pressure• g is the acceleration due to gravity

Continuity Equations- Cont’d

• 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 “” 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

Simulation SolutionMethod 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. Pressure2. Water Saturation 3. Gas Saturation

• For Surfactant flooding model in every grid block, we have 5 unknowns:

1. Pressure2. Water Saturation3. Gas Saturation4. Surfactant Concentration5. Salt Concentration.

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 Equation2. Gas Equation3. Water Equation4. Surfactant Equation5. Brine Equation

• The 5 independent unknowns for every grid block will be: Pressure, Water saturation, Gas saturation, Surfactant concentration, and Salt concentration.

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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.

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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:

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;

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Water PVT properties• If the Brine option is active, the previous equation

becomes a function of salt concentration Cs as well:

PVTWSALT keyword (PROPS section)

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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.

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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;

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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).

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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;

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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:

Where; Fcp is the capillary pressure multiplier

SURFST keyword: Surfactant IFT (Right) vs. surfactant concentration (Left)

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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).

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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.

• By substituting Darcy’s velocity; we will get the equation used in Eclipse* 100:

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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.

NCri(Lake, 1984)

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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.

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Capillary Number and Oil Recovery• A relationship between the Nc and oil recovery, by Chatzis

and Morrow (1982).

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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.

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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:

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.

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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.

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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;

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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.

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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.

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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.

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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).

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Simulation Model

Construction

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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.

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Model DescriptionPerm X=Perm Y Perm Z

Porosity=0.25SWAT=0.145PERMX (Kx): 100*4500 100*3300 100*2400 / PERMZ (Kz): 100*1050 100*1800 100*500 /

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, and6. 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.

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Waterflooding vs. Surfactant Flooding

Waterflooding vs. Surfactant Flooding-Injection Rates

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• Water injection rate =485 m3/D• Surfactant concentration in INJ =30 Kg/Sm3=14550 Kg/D

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Waterflooding vs. Surfactant Flooding

Waterflooding Surfactant flooding

235.7

72.8 M

75.09 M

0.52

19.02

0.96

60.81 M

86.6 M

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Water SaturationSurfactant Flooding

Waterflooding

About 100 % Water saturation

(0 % SORW)

About 65 % Water saturation (35 %

SORW)

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Effect of Surfactant Viscosity

0.5 cp100 cp2.5 cp

Using SURFVISC keyword (SURF concentration, Kg/Sm3 versus the SURF Viscosity , CP)

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Water Saturation

(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.

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Effect of Surfactant Concentration

30 Kg/Sm3 10 Kg/Sm3 60 Kg/Sm3The surfactant concentration in INJ

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Residual Oil Saturation

30 Kg/Sm3, Nc=-1.7

10 Kg/Sm3Nc=-2.2

60 Kg/Sm3Nc=-1.2

• The area of zero % residual oil saturation is the highest for the highest surfactant concentration (60 Kg/Sm3).

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Effect of Surfactant Adsorption

0.0005 Kg/Kg 0.0002 Kg/Kg No SURFADSThe surfactant adsorption by changing SURFADS keyword

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Residual Oil Saturation

0.0005 Kg/Kg

0.0002 Kg/Kg

No Adsorption

Decreasing SURF losses to the rock

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.

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Effect of Capillary De-saturation

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)

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Residual Oil Saturation

Full Miscibility

0.5 Miscibility

0.1 Miscibility

Moving towards Immiscibility (Increase in capillary-

trapped residual oil saturation)

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Effect of Surfactant-rock Properties

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 concentration2. Surfactant adsorption3. Capillary de-saturation4. Surfactant viscosity5. Surfactant rock properties

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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.

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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.

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