Manuales Anexo VII: Manuales

In this section the effect of changing the matrix porosity will be evaluated. To make this comparison, all constants for the base case are used as given in Table 4.1. The saturation curves for the PWW and POW cases are used. 10 grid cells are used along x-direction in the matrix and 30 grid cells along y-direction in the fracture. The matrix porosities used are φM = 0.1, 0.2 and 0.3

Fig.5.9 shows that when changing the matrix porosity, the rate constant B should be adjusted to match the 1D+1D model oil recovery. It is noted that the rate constant B is inversely proportional to matrix porosity in a PWW system. It is interesting to note that when matrix porosity is φM _{= 0.1 the oil recovery is the}

highest compared to the other porosities evaluated. This is because imbibition is especially effective at low porosity.

If we recall the relations for parameters α (Eq. 3.28) and β (Eq. 3.23), we can see that α is inversely proportional to matrix porosity and β directly proportional to matrix porosity. Increasing matrix porosity will decrease α and increase β hence reducing oil recovery. This scenario has been evaluated in Section 4.6, the result was shown in Fig. 4.15.

Fig.5.10 shows that the rate constant B is inversely proportional to matrix porosity in a POW system. As discussed in the previous figure, at φM _{= 0.1 the}

0 5 10 15 20 0 0.2 0.4 0.6 0.8 1

Total oil recovery

τ_f (FVs)

Recovery

1D+1D model φM=0.1

Linear Trans. Func. B=8.5E−8, φM=0.1 1D+1D model φM=0.2

Linear Trans. Func. B=3.8E−8, φM=0.2 1D+1D model φM=0.3

Linear Trans. Func. B=3.5E−8, φM=0.3

Figure 5.9: Oil recovery after injecting 1 RPV in PWW system calculated with the linear transfer function and the 1D+1D model for various values of matrix porosity φM

0 5 10 15 20 −0.1 0 0.1 0.2 0.3

Total oil recovery

τ_f (FVs)

Recovery

1D+1D model φM=0.1

Linear Trans. Func. B=1.0E−8, φM=0.1 1D+1D model φM=0.2

Linear Trans. Func. B=0.8E−8, φM=0.2 1D+1D model φM=0.3

Linear Trans. Func. B=0.7E−8, φM=0.3

Figure 5.10: Oil recovery after injecting 1 RPV in POW rock calculated with the linear transfer function and the 1D+1D model for various values of matrix porosity φM

Chapter 6

Discussion and conclusions

A discussion of the numerical investigations made during this work is presented and conclusions are drawn to answer the objectives posed on Section 1.3. The discussion is developed based on the results presented here and the information obtained from the literature review.

6.1

Discussion on the 1D+1D model

When using the 1D+1D model with different saturations curves, clear differences appear. The effect of the capillary pressure curve on oil recovery is very important, this was studied in Section 4.4. The concept of imbibition potential (∆S = Seq−S0)

is very important. When the rock is POW the imbibition potential is ∆SmP OW ₌

0.1, when the rock is PWW the imbibition potential is ∆SmP W W = 0.6. This characteristic seems to dominate the amount of imbibition that will take place in fracture matrix flow. The higher the imbibition potential, the more imbibition will be. Fig. 4.7 shows the difference in oil recovery when the system is PWW compared to a POW system. In Section 3.3, the 1D+1D model was scaled and two dimensional numbers were obtained α and β. If we consider Eq.3.28 and Eq.3.23, it is noted that by varying the dimensional numbers α and β, the effect of 9 variables (Well spacing Ly, Fracture aperture 2b, Fracture porosity φf, Matrix

porosity φm, Matrix thickness Lx, Fracture pore velocity v f

T, Matrix permeability

Km_{, Oil viscosity µ}

o and Initial capillary pressure Pc,max.) is considered.

When studying the 1D+1D model in Section 4.5, the effect of changing α parameter was evaluated when keeping β constant. From Eq. 3.23 it is possible to see that α is directly proportional to the well spacing Ly, matrix permeability

Km_{, initial capillary pressure P}

c,max and inversely proportional to fracture pore

velocity v_Tf, matrix porosity φm_{, matrix thickness L}

x and oil viscosity µo.

from the fracture into the matrix. Increasing α improves oil recovery as given by Fig. 4.12. It also generates a delay in the water front inside the fracture.

When α is small, the water will flow through the fracture, and only the nearest region of the matrix will imbibe water. This will reduce the total oil recovery and generate early water breakthrough.

When varying α, it is possible to distinguish two flow regimes. When α is large the ”filling fracture” and ”instantly filled” regimes [20] can be identified. When α is small, only the ”instantly filled” regime is observed on the oil recovery curve (Fig. 4.12 middle and right).

Reducing fracture pore velocity vf_T increases α which improves oil recovery. Hence, a lower injection rate represents a more efficient uptake of water by the matrix.

When studying the 1D+1D model in Section 4.6, the effect of changing β parameter was evaluated in two scenarios, first when keeping α constant and then when changing α. From Eq. 3.28 it is possible to see that β is directly proportional to matrix thickness Lx, matrix porosity φm, and inversely proportional to fracture

aperture 2b and porosity φf.

First the scenario when increasing β at constant α is discussed. This can only be achieved by decreasing fracture aperture 2b or/and porosity φf_{. How-}

ever, it is important to keep in mind that in the 1D+1D model, if fracture aper- ture 2b is changed, so is the injection rate, as given by the following relationship InjectionRate = 2bv_Tf. When decreasing the fracture aperture 2b, oil recovery will increase as depicted in Fig. 4.14, the reason for this increase is that the injection rate is reduced, this means that in order to inject a given volume, more time is required, giving more time for imbibition to occur.

The scenario when increasing β and reducing α is discussed now. This scenario takes place when decreasing the fracture aperture 2b and increasing pore velocity v_Tf to keep a constant injection rate. Increasing parameter β and decreasing α increases oil recovery as depicted in Fig. 4.15. The highest oil recovery in this figure describes a scenario when the fracture is wide, and the water takes more time to travel in the fracture, hence there is more time for interaction with the matrix to occur. This is consistent with experiments presented in [20]. Where the fracture aperture was studied by using a computer tomography scanner to take images of the fluids saturations, in these studies the amount of spontaneous imbibition registered was directly proportional to the fracture width.

When varying β, it is possible to distinguish two flow regimes in the oil recovery curves in Fig. 4.14. When β is large the ”filling fracture” regime is dominant and the oil recovery is a linear function of time. When β is small, two flow regimes are present, the ”filling fracture” and ”instantly filled” [20]. The oil recovery is a

When studying the 1D+1D model in Section 4.7, the effect of changing the viscosity ratio (M = µw/µo) is evaluated. From Eq. 3.23 and Eq. 3.28 it is

possible to see that changing µw can modify the viscosity ratio M and keep α and

β constant.

Changing the viscosity ratio M = µw/µo affects the fractions flow functions in

matrix (fM

W) and the fracture (f f

W). as given by Fig. 4.16.

When the viscosity ratio is low (µw/µo = 1/5), the displacement of oil in

the fracture is not as efficient as in the base case (µw/µo = 1). However, more

water imbibes in the matrix in this case. This is because water flows more easily. Reducing the water viscosity will increase oil recovery by spontaneous imbibition. When the viscosity ratio is high (µw/µo = 5), the displacement of oil in the

fracture is more efficient compared to the base case (µw/µo = 1). The mobility of

the water phase is reduced, decreasing the amount of oil produced by spontaneous imbibition.