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The Effect of Fluid Velocity and Rock on Emulsion and Asphaltene Stability in Engineered Salinity Waterflooding

Balavi, Ali | 2024

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  1. Type of Document: Ph.D. Dissertation
  2. Language: Farsi
  3. Document No: 57535 (06)
  4. University: Sharif University of Technology
  5. Department: Chemical and Petroleum Engineering
  6. Advisor(s): Ayatollahi, Shahabeddin; Mahani, Hassan
  7. Abstract:
  8. Water-flooding, has been known as one of the most effective techniques to increase oil recovery efficiency. Many studies especially in the past decade have shown that by controlling the amount and type of ions of the injected water the recovery efficiency is significantly improved. It should be noted that inadequate design of flooding operation can disturbed the prevailing balance between the rock and fluids in the reservoir, hence damage the formation. Several different damages are reported such as the formation of unwanted emulsion, mineral and organic material deposition (such as asphaltene) that would affect the operation and hinder the recovery efficiency. Therefore, it is necessary to carefully examine the mutual effects of water/rock/oil interaction in order to predict and prevent and damage before the operation is started. The studies carried out in the literature often focus on the investigation of fluid/fluid interaction and the properties of the water/oil interface. These studies showed that, the accumulation of asphaltene molecules (as the most complex and largest polar compounds in the oil phase) at the water-oil interface, depends on the asphaltene types and amount and nature of ions in the water phase. Although these studies provide researchers with useful and valuable information regarding the fluid’s interactions, they were mainly based on the bottle tests while the reservoir rock was not present. However, the effect of rock presence on the properties of reservoir fluids (especially water with different salinities) and the surface electric charge of reservoir rock, which can affect the arrangement of asphaltene at the oil-water interface and asphaltene deposition on the rock surface cannot be ignored. Studies show that the investigation of emulsion stability and asphaltene deposition in engineered water injection operations is still not fully understood. The main reason for this is the large number of influencing parameters and their independent and mutual effect on each other that result in very complex laboratory tests design. Therefore, the aim of this study is to investigate the factors affecting emulsion stability and asphaltene precipitation during engineering water injection operations. For this purpose, the effect of water phase salinity and the presence of rock particles, in two physical/non-physical states on the stability of asphaltene and emulsion was statically investigated. In the next stage, the stability of asphaltene and emulsion under the simultaneous effect of the type and amount of injected water, the aging time of water with oil and rock, and the type and amount of rock were investigated. Therefore, Minitab software was used to design and interpret the results of the experiments. To mimic the flowing conditions in reservoir porous rock, a series of dynamic tests using artificial calcite cores was performed. It should be noted that in all the mentioned experiments, the amount of asphaltene instability was analyzed by analyzing the absorption of UV-Vis rays by the aged oil sample. Moreover, by measuring the pH of water phase, FTIR of oil samples, zeta potential of rock particles dispersed in different brines and IFT of different waters and fresh/aged oil samples, the obtained results were analyzed and evaluated. In dynamic tests, in addition to asphaltene precipitation, the effect of water/rock/oil aging time, temperature and flow rate of injected brine, on oil recovery and changes in injectivity were investigated. The results of the static tests showed that, asphaltene would be more instable in the presence of calcite/quartz powder during static tests. The degree of instability depends on the type of water and rock, and for samples without reservoir rock, the maximum instability occurred in the oil/2DSW emulsion. In addition, asphaltene particles tend to be adsorbed on the surface of calcite particles more than quartz particles. Moreover, the results showed that the effect of contact time on the instability of asphaltene in the first 10 days was greater than in the next 10 days, which indicates that the system has reached an equilibrium state. The results obtained in this stage showed that the use of low-salinity brine leads to less asphaltene deposition on the rock surface, the reservoir rock is more hydrophilic and subsequently increases the injectivity and oil recovery. The results of the dynamic tests performed on synthetic cores indicate a significant effect of brine’s salinity on the final oil recovery, the amount and distribution of asphaltene deposits. The highest oil recovery for the un-aged and aged tests were 69% and 65% respectively, occurring in SW and 10DSW. Maximum asphaltene deposition, similar to static tests, occurred in FW-flooding in both aged (15.96 micrograms of asphaltene on 65 grams of calcite, 140% more than the average concentration in different cores) and un-aged (3.83 micrograms of asphaltene on 65 grams of calcite, 80% more than the average concentration in different cores). This study also showed that changes in the water injection rates during the flooding stage have no effect on oil recovery, but have a significant effect on the profile of asphaltene deposition. The results show that the asphaltene precipitation in outlet part of core samples increases about 17%, when the SW-flooding rate increases from 0.2 to 0.6 cc/min. In addition, during the preparation of the cores, before flooding, by increasing the oil volume injection, in the stage of saturation of the cores with oil, the amount of asphaltene precipitation in middle and outlet of core sample increases by 2.28 and 3.9 times. Therefore, with the proper design of injection brine, asphaltene precipitation can be prevented and the operation efficiency can be reduced to a great extent
  9. Keywords:
  10. Asphaltene Particles Stability ; Water-in-oil Emulsion ; Engineered/Low Salinity Water ; Reservoir Rock Characterization ; Porous Medium Equation ; Formation Damage ; Enhanced Oil Recovery ; Zeta Potential ; Carbonated Rock

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