RESULT AND DISCUSSION
4.4 Extensive Spontaneous Imbibition Experiment
1
……….……… (2) Here, is the rock porosity, k is rock permeability in md,
is interfacial tension in mN/m between oil and water,
is the density difference in g/cm3,gis the gravitational constant in cm/S2, andLis length of the core in mm. The numerator of Eq.2 is capillary pressure. The denominator of Eq.2 is gravity force.
For water alone, the macroscopic inverse Bond number, NB-1, may be greater than 1.
However, when the oil-wet cores with a negative capillary pressure are immersed in a surfactant solution, IFT is lowered, NB-1 may become less than 1. At lower IFT, gravity force can overcome negative capillary force and imbibe brine into the core and push oil out from top of the core.
Furthermore, if wettability can be altered, the capillary pressure changes from negative to positive, and counter-current imbibition mobilizes more oil.
Table 14 shows estimated inverse Bond number NB-1 for five surfactants based on optimal salinity from IFT curves. According to Table 14, most NB-1 values are less than 1. By the IFT reducing, surfactant solutions will diffuse into the core and drive the oil out at optimal salinity.
4.4 Extensive Spontaneous Imbibition Experiment
In this study, core plugs were saturated with Bakken oil and stored for 4 to 8 weeks in
Table 14. Inverse Bond Number NB-1 at 90°C
Here, k is the permeability with respect to surfactant. For surfactant 58N that only involved brine water and 0.1%
58N, IFT measurement was very challenging at 90°C using current equipment because the oil drops could not be separated from the tube wall of the Spinning Drop Tensiometer.
graduation in 0.1 mL (Fig. 21). The cells filled with surfactant solution first, and then were immersed into a temperature bath at 120°C for 300 to 500 hours until no more oil was displaced out (Fig. 22). The volume of oil expelled was used to calculate the oil rate and %OOIP of oil recovery. No confining pressure was added during the process of Imbibition.
Three groups of surfactant formulations were studied in this section: (1) surfactants by preliminary optimization with 30% TDS (Wang, et al, 2011b), (2) surfactant using optimal salinity based on phase behavior and IFT study, (3) surfactants using optimal salinity and formation water salinity. Extensive imbibition was conducted at reservoir temperature of 120°C. Core samples came from the Middle Member of Bakken Formation in Well # 17450, in depth of 7347 to 7401.55 ft. Core sample properties are listed in Table 9.
4.4.1 Imbibition Rate in Different Aqueous Solutions The tested aqueous solutions of group 1 included:
(1) Fresh water;
(2) Brine water with 30% TDS;
(3) 0.1% of surfactant formulation N2512 (nonionic) with 30% TDS;
(4) 0.05% of 58N (nonionic) with 30% TDS, 0.1% alkaline content;
(5) 0.2% of TA-15 (cationic) with 30% TDS.
For the fresh water and Brine water in Group 1, four reservoir temperatures ranging from 23°C to 120°C were simulated in cores from Well # 17450. Experimental results show that imbibition using fresh water or brine water resulted in very little imbibition at low temperatures.
However, oil was imbibed out at higher temperatures for the tested core as shown in Table 15. It was noted that some oil drops imbibed out (2 -3 hours) using fresh water, but imbibition times for fresh water or brine water took much longer to obtain a reading on the imbibition cell compared to the surfactants. The explanation for these phenomena is that using fresh water or brine water alone, the wettability cannot be altered, or not obviously with Bakken oil, even though oil drops imbibed out at high temperature.
Table 15. Imbibition Rate in Different Aqueous Solution (30% TDS)
Core sample Diameter,
4.4.2 Imbibition Rate and Oil Recovery at Optimal Salinity The tested aqueous solutions of group 2 included:
(1) 0.1% of S-2 (nonionic) with 10% TDS; 0.25% alkaline content (2) 0.1% of 58N (nonionic) with 7.5% TDS, 0.1% alkaline content
(3) 0.1% of N-2512 (nonionic) with 4.38～5.62% TDS, with/without 0.1% alkaline.
(4) 0.1% of 17A (amphoteric) with 29% TDS, with/without 0.1% alkaline.
(5) 0.1% of TA-15 (cationic) with 12.5～15% TDS, with/without 0.1% alkaline.
(6) 2% of S-2 (nonionic) with 10% TDS; 0.25% alkaline content
For surfactant formulations, experimental results show that imbibition using these optimal salinities resulted in higher imbibition rate and faster oil extraction times at high temperature compared to solutions without salinity optimization, as Table 16 shows. At optimal salinity, an average instantaneous imbibition rate was increased by up to 45%. Here, the imbibition time was 380 hours.
Table 16. Imbibition Rate at Optimal Salinity vs. Formation Water Salinity, 120°C, 0.1% Concentration
Core sample Diameter, mm
Thickness
mm Aqueous liquid Instantaneous imbibition rate, ft/day
1-47A 38.07 50.99 TA-15 0.028 at 30% TDS
1-80 38.03 38.69 TA-15 0.132 , at 15% TDS
1-53A 38.17 51.46 N 2512 0.069 at 30% TDS
1-79 38.02 38.00 N2512 0.101 at 4.38 %
TDS
1-44A 38.07 51.10 58N 0.120 at 30% TDS
1-77 38.04 38.50 58N 0.158 at 7.5% TDS
Figure 35. Oil Recovery at Optimal Salinity at 120°C vs. Time
For surfactant formulations at optimal salinities, as shown in Fig. 35, we found: (1) At lab scale, the oil recovery using spontaneous imbibition with optimization surfactant formulations and the Bakken cores ranged from about 30% to 60% of OOIP, (2) with 0.1% concentration, nonionic surfactants N2512 and 58N exhibit a fast imbibition rate and strong effect oil recovery at reservoir temperature (~120°C), (2) at higher concentration 2%, an anionic surfactant S-2, shows slow imbibition rate compared with a lower concentration (0.1%) surfactant solution, (3) higher oil recovery was seen with the amphoteric surfactant 17A without alkaline. This is consistent with the observation in IFT test. In contrast, when using cationic surfactant TA-15, higher oil recovery was seen with alkaline compared with 17A.
4.4.3 Oil Recovery at Optimal Salinity vs. Formation Water Salinity The tested aqueous solutions of group 3 included:
0
(1) 0.1% of TA-15 (cationic) with 12.5% TDS, with 0.1% alkaline (2) 0.1% of TA-15 (cationic) with 30% TDS, with 0.1% alkaline (3) 0.1% of YYC5-44 (nonionic) with 5.62% TDS, with 0.1% alkaline (4) 0.1% of YYC5-44 (nonionic) with 30% TDS, with 0.1% alkaline.
Figure 36. Oil Recovery Comparison at Optimal Salinity and Formation Water Salinity at 120°C
Oil recovery using optimal salinity up to 18% compared the surfactant with formation water salinity (Fig. 36). In Fig. 36, cationic surfactant solutions, TA-15 and nonionic surfactant solutions, YYC5-44 was mixed by optimal salinity and formation water salinity, respectively.
CHAPTER 5
CONCLUSIONS
Wettability, phase behavior, and interfacial tension (IFT) were investigated in this study to evaluate the potential of surfactant imbibition to oil recovery improvement from the Bakken shale and the behind mechanisms. The significant findings and conclusions are summarized as below: