Numerical Simulation of ES-SAGD Process in Athabasca Oil Sands with Top Water and Gas Thief Zones. Presented by Xia Bao

Transcription

1 Numerical Simulation of ES-SAGD Process in Athabasca Oil Sands with Top Water and Gas Thief Zones Presented by Xia Bao 1

2 Outline Thermal simulation Optimization on the operating strategy ES-SAGD possibility SAGD geomechanics Conclusion 2

3 Thermal simulation 3

4 Simulation Model Setup 4

5 Simulation Model Setup 5

6 Automatic History Matching Fine-tuning of history matching was achieved using the computerassisted automatically history matching approach (CMOST). 6

7 Optimization 7

8 Injection Pressure Optimization Maintaining a high steam chamber pressure early in the SAGD process, followed by the lower injection pressure when approaching to the top water zone 8

9 Steam Trap Control Optimization Steam trap control optimization results show that 40 C is not suitable for an economic performance. Case # Cum. Oil (m3) csor (m3/m 3) Subco ol1 (oc) Subco ol2 (oc) Subco ol3 (oc) Subco ol4 (oc) Subcool 5 (oc) Basec ase

10 ES-SAGD Investigation 10

11 ES-SAGD ES-SAGD is the co-injection of small amount solvent additive with steam in the SAGD process. Solvent will condensate at the boundary of the steam chamber and diffuse into bitumen, which will reduce the oil viscosity, yield the higher oil drainage and reduce the amount of steam required. (Nasr et al. 2002; Das, 2005; Gupta and Gittins, 2006; Ivory et al., 2008; Deng et al., 2008; Govind et al.; 2008; Ayodele et al., 2010) A solvent mixture (10% volume) ranging from C4 to C11 is characterized using Winprop. 11

12 ES-SAGD Three pseudo components are lumped by matching the solvent liquid density and saturation pressure based on the experimental data. 12

13 ES-SAGD Steam chamber profiles of different solvent mixture. A: IC 4 -NC 5 ; B: C 6 -C 8 ; C: C 9 -C 11 ; D: Solvent mixture (C 4 -C 11 ). A C B D 13

14 ES-SAGD Oil mole fractions in the steam chamber interface. A: Solvent mixture; B: C 9 -C 11 ; C: C 6 -C 8 ; D: IC 4 -NC 5. A C B D 14

15 ES-SAGD Hexane C6 injection improves the bitumen recovery which is consistent with previous publications; however, the optimized solvent co-injection for the top thief zone case should be the solvent mixture containing the heavier components C9-C11. 15

16 Geomechanics Literature has documented numerous geomechanical studies for the SAGD process (Agar, 1984; Vaziri, 1989 and 1990; Settari, 1989 and 1992; Settari et al. 1992; Fung et al. 1994; Chalaturnyk, 1996; Ito and Suzuki, 1996; Touhidi-Baghini, 1998; Collins et al., 2002; Li et al. 2004; Du and Wong, 2007; Yin et al. 2009; Huang et al. 2010). The dilation behaviour associated with volumetric strains is an important feature, which causes an increase of porosity and permeability. Solving the flow and stress equation by the appropriate coupled approach Oil sands constitutive model must be developed before the simulation work 16

17 Modular Coupled Approach Modular coupled approach solves the flow and stress separately by coupling conventional finite difference reservoir simulator with a finite element (FEM) stress simulator (Settari and Walter, 1999). K L t F T L E tp R Where: K: stiffness matrix δ: displacement vector L: coupling matrix to flow unknowns E: flow matrix P: vector of reservoir unknowns (i.e., pressures, saturations and temperature) F: vector of force boundary conditions R: right hand side of the flow equations t: change over time step K L P F t t represents the geomechanical equilibrium T L t EtP R represents the flow equation coupled with reservoir geomechanics through coupling matrix L. 17

18 Geomechanical iteration within a time step Pressure and temperature changes occurred in the reservoir simulator are passed to geomechanical simulator to compute the stress and strain, which will be passed back to reservoir simulator to calculate the porosity and permeability. *The solution is identical to the fully coupled system when the convergence is achieved (Tran, et al. 2004) 18

19 Porosity and Permeability Coupling Settari and Mourits (1998) defined the pore volume coupling formulation by introducing the * apparent porosity, expressed as:. n * v (1 ) The general equilibrium formulation of the porosity coupling is defined as: 1 c p c T c (1 ) c * * n n n o p T v b n m The formulation of the improved porosity coupling (Tran et al. 2004) is defined as: 1 c p c T c (1 ) c ( c c ) p c T * * n n n n o p T v b n m b r b m n v Where: Ø 0 : Initial porosity Ø: True porosity C p : Pressure coefficient C T : Temperature coefficient C Ø : Porosity compressibility C b : Bulk compressibility C r : Rock compressibility β: Volumetric thermal expansion coefficient δ m : Mean total stress εv: Volumetric strain 19

20 Porosity and Permeability Coupling The permeability and volumetric strain correlations derived using the following empirical equation (Touhidi-Baghini, 1998): k k 2 ln CnlV 1 k 2 : Current absolute permeability k 1 : Original absolute permeability C nl : Proportional constant ε v : Volumetric strain 20

21 Oil Sand Constitutive Model Based on tri-axial soil tests, Duncan et al. (1980) proposed a hyperbolic model which accommodates the stress-dependent Poisson s ratio and stressdependent bulk modulus. Hyperbolic model Formulation: The initial modulus Ei defined as : ' ' r n i ( r ) E a( ) e a E k P P The tangent young s modulus Et is given by E E f ' ' t i( r ) ( dev ) The tangential bulk modulus Bm is: ' r n B k P ( ) b P m b a a Shape function is expressed as ' ' ' ( 1 3) f( dev ) 1 R f ' ' ( 13) f The tangent modulus Kt is given by ' r K K P ( ) m P v t B a Poison s ratio is a function of 1 ke 2 6k a ' r and ' r nm ' ( ) f( dev ) b Pa 2 ' dev 21

22 Generalized Hyperbolic Model A modified hyperbolic constitutive model was developed by introducing two arbitrary exponents in the shape function equation. This model successfully matched stress-strain data for McMurray Oil Sand as shown in this plot. ' ' ' ( 1 3) f( dev ) 1 R f ' ' ( 13) f Thermo-elasticity: n ' e ' r T Ei ( r ) kepa P a T ref e2 n ' r T Bm kbpa P a T ref b e1 m m e b (Settari and Walter, 2001)) (Settari, 1993) 22

23 Geomechanical Properties Geomechanical properties of the rock for the non-linear hyperbolic constitutive model are listed in the following Table. 23

24 Vertical Displacement 24

25 Coupled ES-SAGD Case Coupled ES-SAGD model associated with slight higher oil rate compared to the uncoupled ES- SAGD is expected as the dilation taking effect; Oil rate becomes lower after year 2006 because of the steam redistribution involved. 25

26 Conclusion Thief zone SAGD performance is more sensitive to the injection pressure. The optimized solvent co-injection for the top thief zone case should be the solvent mixture containing the heavier components C9-C11. Geomechanical coupling using non-linear constitutive model captured the dynamic changing of the effective stress and rock properties evolved in the thermal process. 26

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28 Thank you Questions? 28