4.3 Effect of Todd-Longstaff Mixing Parameter and Well Configuration and Injection
4.3.1 Effect of Well Configuration on Condensate Recovery
This section is divided into two, gas injection and WAG injection. It discusses the results obtained when the mixing parameter was tuned using the different well configurations in the limited compositional simulation.
4.3.1.1 Effect of Well Configuration on Condensate Recovery for Gas Injection.
Figures 4.29 and 4.30 show the volume of condensate recovered for well configuration when mixing parameter was tuned in the limited compositional simulation. As mixing parameter was increased (i.e., ω) = 0, 0.167, 0.333, 0.5, and 0.8333), a slight increase in condensate recovery was observed. The slight increase in condensate volume signifies that the impact of viscous fingering has been reduced gradually as the mixing parameter increases, indicating an increase in miscibility between the injected fluid and the in-situ fluid. Viscous fingering exists because of the high mobility ratio of the displacing fluid. A relatively higher increment in condensate volume was observed when the mixing parameter was set between 0.990 and 0.998. At this point, the mobility ratio tends to decrease as the impact of viscous fingering decreases
correspondingly. An abrupt increase in condensate recovery was observed when the mixing parameter was set to 1. This abrupt increase in condensate production was probably due to complete mixing with little or no viscous fingering as defined in the Todd and Longstaff model (1972).
Figure 4.29: Condensate Produced after Tuning Mixing Parameter for Vertical Injector-Vertical Producer Pair using Limited Compositional Simulations of Gas injection. See
Table 4.1 for the definition of used in the simulations.
Figure 4.30: Condensate Produced after Tuning Mixing Parameter for Vertical Injector-Horizontal Producer Pair using Limited Compositional Simulations of Gas injection. See
Table 4.1 for the definition of used in the simulations.
The comparison of the results of the percentage condensate recovery obtained from the two well configurations (i.e., vertical injector-vertical producer vs. vertical injector-horizontal producer) by gas injection is shown in Table 4.2.
Table 4.2: Percentage Condensate Recovery from Gas Injection after Tuning Mixing Parameter in Limited Compositional Simulation for Two Well Configurations.
Run Mixing
Parameter ()
Condensate Recovery, % Vertical
Injector-Vertical Producer
Vertical Injector-Horizontal Producer
1 0 23.5 26.3
2 0.167 24.6 27.0
3 0.333 25.0 27.8
4 0.500 26.0 28..6
5 0.667 26.7 29.8
6 0.833 28.7 31.8
7 0.990 40.9 43.3
8 0.992 42.6 44.6
9 0.994 44.3 46.4
10 0.996 47.0 49.0
11 0.998 51.9 53.5
12 1.000 67.5 67.8
Using the two well configurations, the percentage condensate recovery of 43% was obtained from the fully compositional simulation. When the values in Table 4.2 were compared with the 43% condensate recovery from the fully compositional model, it is observed that the 42.6%
condensate recovery from the vertical injector and vertical producer pair in the limited compositional model is a close match. In this case, the mixing parameter was set equal to 0.992 in the limited compositional model. Using the vertical injector and horizontal producer pair in the limited compositional simulator yielded a 43.3% condensate recovery by gas injection.
Again, this result closely matched the 43% recovery obtained from the fully compositional model for the same well configuration. The corresponding mixing parameter ( is 0.99 for the vertical injector and horizontal producer pair used in simulating gas injection in the limited compositional model. This comparison was to help to determine the optimum condensate recovery using gas injection by varying the Todd-Longstaff mixing parameter () in the limited compositional simulation.
Figures 4.31 and 4.32 shows a pixel plot for condensate saturation at the 1st, 2nd, 5th, 10th, 15th, and 20th year using the optimum mixing parameters for the two well configurations. The pixel plot shows a 2-d view of the reservoir with the injection well at (1,1) layer 1-4 and producer well (20,20) layer 4-7.
1st year 2nd year 5th year
10th year 15th year 20th year
Figure 4.31: Condensate Saturation Distribution for Optimum mixing parameter using Vertical Injector and Vertical Producer Pair in Gas injection.
1st year 2nd year 5th year
10th year 15th year 20th year
Figure 4.32: Condensate Saturation Distribution for Optimum mixing parameter using Vertical Injector and Horizontal Producer Pair in Gas injection.
A comparative analysis of the results obtained using the optimum mixing parameter and the two well configurations in the limited compositional simulation versus those from the fully compositional simulation is presented below. Figures 4.33 through 4.36 show the cumulative gas produced, cumulative oil produced, water cut and reservoir pressure profiles from these simulations.
Figure 4.33: Effect of Well Configuration on the Cumulative Gas Produced by Gas injection for Fully and Limited Compositional Simulations with optimum mixing
parameter.
Figure 4.34: Effect of Well Configuration on the Cumulative Oil Produced by Gas injection for Fully and Limited Compositional Simulations with optimum mixing parameter.
Figure 4.35: Effect of Well Configuration on the Reservoir Pressure by Gas injection for Fully and Limited Compositional Simulations with optimum mixing parameter.
Figure 4.36: Effect of Well Configuration on the Water cut Profile by Gas injection for Fully and Limited Compositional Simulations with optimum mixing parameter.
The results shown in Figures 4.33 through 4.36 indicate that the performance of the vertical injector and horizontal producer is better than those of the vertical injector and vertical producer.
The vertical injector-horizontal producer well configuration gave a higher cumulative oil produced, lower water cut, and more effective reservoir pressure maintenance than vertical injector-vertical producer pair for both the fully compositional and limited compositional simulation. This result is expected because the horizontal producer has more contact with the reservoir and yields higher recovery. Notwithstanding, horizontal wells change the radial flow drainage pattern in vertical wells into a combination of radial, linear and elliptical flows (Economides et al., 2013). The low water cut profile in the horizontal producer signifies a reduction in water coning in the reservoir. Note that the cumulative gas produced was the same for the fully and limited compositional simulations.
4.3.1.2 Effect of Well Configuration on Condensate Recovery for WAG Injection
The same trend observed when the mixing parameter was tuned for gas injection was also observed for WAG injection. An increment of 10-15% of condensate recovery from WAG injection versus gas injection was observed after tuning the mixing parameter in the limited compositional simulation. This increment in WAG condensate recovery is because WAG injection helps in improving the microscopic sweep efficiency in gas injection processes (Afzali et al., 2018). Figures 4.37 and 4.38 shows the result obtained from the two well configurations using the limited compositional simulation of WAG injection. The simulations were conducted using the optimum Todd-Longstaff mixing parameter.
Figure 4.37: Condensate Produced from Vertical Injector-Vertical Producer Pair by WAG injection for Fully and Limited Compositional Simulations with optimum mixing
parameter. See Table 4.1 for the definition of used in the simulations.
Figure 4.38: Condensate Produced from Vertical Injector-Horizontal Producer Pair by WAG injection for Fully and Limited Compositional Simulations with optimum mixing
parameter. See Table 4.1 for the definition of used in the simulations.
Table 4.3 is a comparison of the results of the percentage condensate recovery obtained from the two well configurations (i.e., vertical injector-vertical producer vs. vertical injector-horizontal producer) by WAG injection.
Table 4.3: Percentage Condensate Recovery by WAG Injection after Tuning Mixing Parameter in Limited Compositional Simulation for Different Well Configurations.
Run Mixing
Parameter
Condensate Recovery, % Vertical
Injector-Vertical Producer Vertical Injector-Horizontal Producer
1 0 36.0 38.3
2 0.167 37.3 39.2
3 0.333 38.5 40.3
4 0.500 39.9 41.0
5 0.667 41.0 42.4
6 0.833 44.3 45.2
7 0.990 55.3 56.2
8 0.992 56.5 57.1
9 0.994 57.2 57.9
10 0.996 58.8 59.7
11 0.998 65.7 67.0
12 1.000 77.4 77.9
The results of the WAG injection were analyzed similarly as was done for the gas injection.
Using the two well configurations, the percentage condensate recovery of 59% was obtained from the fully compositional simulation of the WAG injection. Comparing the values in Table 4.3 with the 59% condensate recovery from the fully compositional model, it was observed that the 58.8% condensate recovery from the vertical injector and vertical producer pair in the limited compositional model was a close match. The WAG injection yielded a 59.7% condensate recovery using the vertical injector and horizontal producer pair in the limited compositional simulator; this result closely matched the 59% recovery obtained from the fully compositional model for the same well configuration. The corresponding mixing parameter ( is 0.996 for the two well configurations used in simulating WAG injection in the limited compositional model.
This comparison was to determine the optimum condensate recovery using WAG injection by varying the Todd-Longstaff mixing parameter () in the limited compositional simulation.
Figures 4.39 and 4.40 illustrate the condensate saturation distributions in the reservoir at the 1st, 2nd, 5th, 10th, 15th, and 20th year of WAG injection. The results are for the optimum Todd-Longstaff mixing parameter () in the limited compositional simulation using the two well configurations.
1st year 2nd year 5th year
10th year 15th year 20th year
Figure 4.39: Condensate Saturation Distribution for Optimum mixing parameter using Vertical Injector and Vertical Producer Pair in WAG injection.
1st year 2nd year 5th year
10th year 15th year 20th year
Figure 4.40: Condensate Saturation Distribution for Optimum mixing parameter using Vertical Injector and Horizontal Producer Pair in WAG injection.
The results from WAG injection using the optimum mixing parameter and the two well configurations in the limited compositional simulation are compared to those obtained from the fully compositional simulation. Figures 4.41 through 4.44 show the plots of the cumulative gas produced, cumulative oil produced, water cut and reservoir pressure profiles from these simulations.
Figure 4.41: Effect of Well Configuration on the Cumulative Gas Produced by WAG injection for Fully and Limited Compositional Simulations with optimum mixing
parameter.
Figure 4.42: Effect of Well Configuration on the Cumulative Oil Produced by WAG injection for Fully and Limited Compositional Simulations with optimum mixing
parameter.
Figure 4.43: Effect of Well Configuration on Reservoir Pressure by WAG injection for Fully and Limited Compositional Simulations with optimum mixing parameter.
Figure 4.44: Effect of Well Configuration on Water cut by WAG injection for Fully and Limited Compositional Simulations with optimum mixing parameter.
The same trend was observed from the results of WAG injection for the two well configurations compared to the results of gas injection. For the WAG injection process, the vertical injector and horizontal producer yielded a better condensate recovery performance than the vertical injector-vertical producer pair in terms of the cumulative oil produced, water cut, and reservoir pressure maintenance.