We truly declare that this submitted work entitled “Evaluation of Natural Surfactant Potential in a Carbonate Reservoir” is the product of our original research work to the best of our knowledge. Overall, this study provides valuable insights to optimize the use of the CO2 Huff and Puff method, contributing to the development of more efficient and sustainable oil recovery techniques.
Background
Maximize CO2 huff 'n' puff oil recovery by providing a sensitivity analysis to CO2 huff 'n' puff operational parameters. Oil swelling occurs throughout the contact area, resulting in an increase in relative oil permeability. As a result, the viscosity of the oil decreases and swells, increasing the production of heavy oil.
In addition, when the asphaltene percentage is greater than 4.6%, the wettability of the field will switch between being water-wet and oil-wet, which lowers the recovery of heavy oil (Al-Maamari & Buckley, 2000). According to the results, the GOR of the Huff and Puff method has increased by 33% (Jeong & Lee, 2015). The results of the study show that the CO2 Huff and Puff method affects oil production and recovery factor.
If only internal reservoir pressure is applied, the incremental oil recovery was 6.53%. For the third scenario, the reservoir porosity and permeability were increased to 20% and 200md. By increasing the number of cycles in the CO2 gassing and blowing method, the oil production and recovery factor can be increased because it allows more efficient use of the injected CO2.
During the injection phase, the CO2 helps lower the viscosity of the oil and pushes it towards the production well. The results of the study show that increasing the CO2 injection rate leads to higher incremental oil recovery and cumulative oil production. Overall, the results of our study demonstrate the economic feasibility of the CO2 huff and puff method for improving oil recovery.
Laboratory evaluation of the huff-n-puff CO2 process for heavy oil reservoirs.Journal of Canadian Petroleum Technology,23(03).
Research Problem
Aims and Objectives
Justification of Research
Literature review 11
- Processes of CO2 huff ‘n’ puff method
- Mechanisms of CO2 huff ‘n’ puff method
- Viscoisty reduction
- Oil swelling
- Effect of Diffusion coefficient
- Operational Issues of CO2 huff ‘n’ puff
- Review of simulation studies
- Eagle Ford Shale Simulation Study
- Simulation Study of M field in Indonesia
- Review of field cases
- South Louisiana field in USA
- Jiangsu Oilfield in China
A decrease in the viscosity of heavy oil leads to a shift of the partial flow curve to the right. The viscosity reduction ratio of the heavy oil-CO2 system varies with temperature, pressure, and dissolved CO2 solubility (Yuan, 2023). Viscosity reduction coefficient and solubility in heavy oil-CO2 system at different temperatures and pressures.
Oil swelling coefficient in heavy oil-CO2 system at different temperatures and pressures.
Methodology 31
- Reservoir grid model
- Fluid component data
- Rock properties data
- Capillary pressure
- Relative permeability
- Rock compressibility
- Well data
- Fluid flow through reservoir
- Simulation case scenarios
A diagram of the relative permeability curve of oil and water in a water-wet reservoir is shown below. In water-wet rocks, a layer of water covers the surface of the rock and acts as a lubricant for the oil located in the middle parts of the pores. The mass balance equation describes the conservation of mass in the reservoir, while the Darcy equation describes the flow of fluid through the reservoir.
The equation of state describes the relationship between pressure, temperature and volume of the liquid. Additionally, to the mass conservation equation, we must state momentum conservation in terms of Darcy's law. Such a condition is known as a boundary condition of the first kind, or a Dirichlet boundary condition, in the theory of partial differential equations.
Boundary conditions of the second kind, or NeumannΓ boundary conditions, are what is known as this circumstance. We are often interested in the simultaneous flow of two or more fluid phases through a porous material in reservoir modeling. It is necessary to include some new parameters specific to multiphase flow, including relative permeability, capillary pressure, and saturation in the governing equations.
In this case study, three types of reservoirs with varying porosities in the range of 10-20% and permeability of 100-200 mD were used. To analyze the effect of irrigation period, different irrigation periods ranging from 0 to 60 days were carried out.
Results and discussion 47
Effect of cycles on 10% porosity and 50 md permeability
After two cycles, cumulative oil production reached 34.57 MSTB, and after three cycles this production increased to 39.43 MSTB. After the first and second cycles, incremental oil recovery grew by about 6%, but in the third cycle it increased by less than 3%. The use of three cycles will not be efficient for increasing oil recovery because with increasing cycles the incremental oil recovery will still increase somewhat.
Therefore, we can conclude that the implementation of the two cycles of the CO2huff-n-puff technique is an efficient solution for increasing oil production for a reservoir with a porosity of 10% and a permeability of 50 md.
Effect of cycles on 15% porosity and 100 md permeability
Moreover, the ratio of oil to CO2 is approximately the same for the first and second cycles, and the third cycle is twice as much compared to the second cycle. For the second scenario, the formation porosity and permeability were increased to 15% and 100md. The initial oil-in-place of the deposit increased by approximately 89.05 MSTB and reached 272.95 MSTB with an increase in oilfield porosity.
Therefore, the capacity of the rock to accumulate oil and gas increases with the increasing porosity of the oil field. After one cycle of the CO2 huff-n-puff method, the percentage of oil recovery increased by approx. twice and reached up to 33,104 MSTB. When the second and third CO2 injection cycles were used, the oil recovery increased by 3% each time, reaching up to 18.6%.
The difference between the second and third cycle is negligible in terms of the ratio of produced oil and pumped CO2 gas, but they are smaller compared to the first cycle. However, three cycles in the reservoir are significantly more than the three cycles in the previous reservoir in terms of the ratio of extracted oil and injected CO2 gas. Therefore, the profitable option would be to apply three cycles of the CO2 huff-n-puff injection method as there would be no significant growth in cumulative oil production during the application of the fourth cycle.
Effect of cycles on 20% porosity and 200 md permeability
After two cycles, the cumulative oil extraction reached 50.64 MSTB, and after three cycles, this production rose to 60.72 MSTB. The difference in the ratio of exhausted oil and injected CO2 gas is small compared to previous deposits. The percentage of oil recovery after the first cycle was lower than in reservoirs with lower permeability and porosity.
There will not be a significant increase in incremental oil recovery when applying the fourth cycle and it would be beneficial to apply only three cycles for this scenario.
General discussion
The incremental oil recovery and the cumulative oil production were measured and compared for each injection rate. The most optimal injection rate will be 80 tons per day as the oil recovery factor is higher compared to other injection rates. The results from Figure 35 and Table 19 of the study indicate that cumulative oil production and incremental oil recovery increase with increasing soaking period.
Although cumulative oil production and incremental oil yield increased with increasing soaking period, the optimal soaking period was found to be 30 days. The increase in oil recovery and cumulative oil production with increasing irrigation period can be attributed to several factors. However, the increase in oil recovery and cumulative oil production with increasing irrigation period is not linear.
By increasing the number of cycles of CO2 Huff and Puff techniques, increased oil production and increased oil recovery. The increase in oil recovery and cumulative oil production with increasing soaking period is not linear. This means that the study did not investigate the effect of the CO2 gas and puff method on reservoirs with significantly different permeability values.
On the potential of CO2 storage in a cyclic CO2 injection process for enhanced oil recovery. Fuel, 124, 14-27. Cyclic CO2 injection for heavy oil recovery in the Halfmoon field: laboratory evaluation and pilot performance.
Effect of different injection rates
Effect of Soaking Period
In this section, we investigated the effect of the soaking period on cumulative oil production and incremental oil recovery using a base scenario of 20% porosity and 200 md permeability, a CO2 injection rate of 80 tons per day, and three soaking periods of 0 days, 30 days and 60 days. Recovery factor, oil production and CO2 injection volume for different week periods Week Time Oil Recovery. The increase in cumulative oil production can be attributed to the increased contact time between the injected CO2 and the oil.
The longer the soaking period, the greater the chance for CO2 to diffuse into the oil, resulting in better recovery. In the case study, cumulative oil production increased from 81.95 MSTB after a 30-day soaking period to 82.45 MSTB after a 60-day soaking period. This means that the additional 30-day soaking period only resulted in an incremental oil recovery of 0.5 MSTB.
The difference between the week periods was 30 days since the time interval was chosen in 1 month. When the week periods were 0 and 90 days, the cumulative volume of CO2 produced was 1875 tons and 1915 tons, respectively. After a certain point, the incremental oil recovery and cumulative oil production can plateau as can be seen from Figure 35 or even decrease due to factors such as CO2.
Economic Analysis
This is because the increase in injection rate leads to more efficient oil recovery from the reservoir, resulting in higher turnover. Based on the case studies, the optimal parameters for the CO2 huff-n-puff method were chosen. By increasing the number of cycles in the CO2huff-n-puff method, the oil production and recovery factor can be increased because it allows for more efficient utilization of the injected CO2.
This may affect the efficiency of the CO2 Huff and Puff method in other tight oil reservoirs that have less reservoir depth. As a result, the effect of the CO2 Huff and Puff method on more permeable reservoirs may not appear to be fully covered. For example, in case 1, for all baseline scenarios, oil recovery remained at 6.54% with no difference when permeability was increased.
Need for more complicated simulation: The complexity of the gas and CO2 blowing method and the dynamic nature of the reservoirs make it difficult to accurately simulate the process. It is recommended to optimize the number of cycles, CO2 injection rate and soak period based on reservoir characteristics to achieve maximum oil recovery. Analysis of heavy oil-carbon dioxide emulsion system on oil swelling factor and interfacial tension using hanging drop method for enhanced oil recovery and carbon dioxide storage.
