Figure 23. Cumulative NPV of the scenarios for fixed and extended cycles of cyclic CO2, C2 and NG injection as well as natural depletion, FS = 30, Oil API = 38.
Figure 24. NPV of the scenarios for fixed and extended cycles of cyclic CO2, C2 and NG injection as well as natural depletion, FS = 10, Oil API = 38.
Figure 25. Cumulative NPV of the scenarios for fixed and extended cycles of cyclic CO2, C2 and NG injection as well as natural depletion, FS = 10, Oil API = 38.
Figure 26. NPV of the scenarios for fixed and extended cycles of cyclic CO2, C2 and NG injection as well as natural depletion, FS = 30, Oil API = 31.
Figure 27. Cumulative NPV of the scenarios for fixed and extended cycles of cyclic CO2, C2 and NG injection as well as natural depletion, FS = 30, Oil API = 31.
Figure 28. NPV of the scenarios for fixed and extended cycles of cyclic CO2, C2 and NG injection as well as natural depletion, FS = 10, Oil API = 31.
Figure 29. Cumulative NPV of the scenarios for fixed and extended cycles of cyclic CO2, C2 and NG injection as well as natural depletion, FS = 10, Oil API = 31.
Table 3. High API and low API Oil recovery factor, IRR and cumulative NPV during the reservoir life for n = 30 and n = 10.
38° API Oil
Figure 30. Changes in NPV and IRR coming from variation in fracking costs.
Figure 31. Changes in NPV and IRR coming from variation in Oil Price.
Figure 32. Changes in NPV and IRR coming from variation in Gas Price.
31° API Oil
Figure 33. Changes in NPV and IRR coming from variation in fracking costs.
Figure 34. Changes in NPV and IRR coming from variation in Oil Price.
Figure 35. Changes in NPV and IRR coming from variation in Gas Price.
CO2 preferentially mobilizes the lighter oil components and reservoir residual oil becomes heavier with time. The molecular selectivity of CO2 leads to the retention of intermediate and heavy components in residual oil. Natural gas has higher MMP compared with CO2 and pure ethane. Because miscibility is achieved quicker than with CO2 and NG, ethane is capable of effectively mobilizing the light, intermediate and even heavier hydrocarbon components. The poor performance of natural gas is related to incomplete miscibility and inefficient mobilization of crude oil. To observe how the IFT changes in each scenario, one grid block is selected and the IFT trend versus time is plotted for all cases.
Though the volumes of injected solvents are identical for all scenarios, pure ethane has led to highest oil recovery for the same production time and operation conditions. Comparison between three injection gases of C2, CO2 and NG, the ethane-EOR results in terms of RF are the most favorable followed by CO2 and NG.
Constant and extended C2, CO2 and NG injection modes are compared along with the primary production recovery. Number of fracture stages is also studied in terms of profitability and are included in economic analysis. By sensitivity analysis of uncertainties on the key field development metrics (ultimate produced oil and costs) and visualizing the results in spider plots the impacts can be ranked. The vertical range generated by each parameter represents the expected range of profits it would produce if the changes in that parameter varies between the minimum and maximum (−30% and +30%).
Result shows that fracking cost and gas price have the minimum influence on project’s economic corresponding to short vertical ranges in NPV and IRR. However, reduction in oil price shows a huge effect and extends the vertical range to more negative NPV values. This reduction is intrinsic in large fracture spacings. In fracture stages more than FS = 20, the NVP and IRR changes becomes minimum.
Amongst the variables, oil price is the most influential factor in project’s NPV and IRR. Oil price decline has a dramatic effect on NPV and IRR and −30% changes leads to 467% decrease in NPV while 30% increment in oil price only results in 48% higher NPV.
When the oil price declines by 30% and 15%, cumulative NPV is reduced by −100.24% and −33.39%, meaning that while keeping the rest of the costs constant, 30% decrease in oil price may lead to negative NPV and IRR, making the project uneconomic. This trend is seen in scenarios for FS = 10-C2 (fixed) and FS = 10-CO2 (fixed). The scenario of FS = 25-C2 (fixed) is showing the minimum reduction in NPV. Almost all the scenarios will result in 30%−33% and 19%−20% increment of NPV if the oil price increases by 30% and 15% respectively. Variation in IRR lies between −120% and −80% with 30% decline in oil price and between −28% to −35% with 15% decline in oil price.
Fracking cost has fewer effects on the profit compared with oil price. If the fracking cost decreases by 30% and 15%, NPV increases by 1.29% to 4.59% and 0.7% to 2.31% respectively. 30% and 15% increase in fracturing costs results in 9.96% and 1.36 decrease in NPV.
Gas price is the factor with minimum effect on the economic responses. 30% and 15% reduction in gas prices lead to 0.43–2.93% and 0.38% to 1.05% increment in NPVs respectively. The scenario with the most benefit is FS = 40-NG (fixed and extended) and scenario with the least profit is FS = 10-CO2 (extended). 30% and 15% increase in gas price yields to 0.31–2.73% and 0.26–0.91% incremental in NPV.
Scenarios with minimum influences on the project’s economic in terms of NPV are fracking cost for n = 10-C2 (extended), oil price for n = 30-C2 (extended) and gas price for n = 10-CO2 (extended).
Formal analysis, Y.A.; Supervision, P.P.A.; Writing—original draft, Y.A.
This research was funded by University of Calgary.
Conflicts of Interest
The authors declare no conflict of interest.
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