Effect of Temperature on Enhanced Oil Recovery from Mixed-Wet Chalk Cores by Spontaneous Imbibition and Forced Displacement Using Seawater

2008 ◽  
Vol 22 (5) ◽  
pp. 3222-3225 ◽  
Author(s):  
Skule Strand ◽  
Tina Puntervold ◽  
Tor Austad
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Spontaneous Imbibition ◽  
Effect Of Temperature ◽  
Forced Displacement

Use of Sulfate for Water Based Enhanced Oil Recovery during Spontaneous Imbibition in Chalk

2011 ◽  
Vol 25 (4) ◽  
pp. 1697-1706 ◽  
Author(s):  
M. A. Fernø ◽  
R. Grønsdal ◽  
J. Åsheim ◽  
A. Nyheim ◽  
M. Berge ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Spontaneous Imbibition ◽  
Water Based

scholarly journals Comparative Study of Using Sea-Water for Enhanced Oil Recovery in Carbonate and Sandstone Reservoirs: Effects of Temperature and Aging Time on Oil Recovery

2018 ◽  
Vol 7 (2) ◽  
pp. 1-13
Author(s):  
Madi Abdullah Naser ◽  
Mohamed Erhayem ◽  
Ali Hegaig ◽  
Hesham Jaber Abdullah ◽  
Muammer Younis Amer ◽  
...  
Keyword(s):  
Aging Time ◽  
Oil Recovery ◽  
Sea Water ◽  
Essential Element ◽  
Recovery Process ◽  
Spontaneous Imbibition ◽  
Effect Of Temperature ◽  
Injection Process ◽  
Reservoir Conditions ◽  
The Impact

Oil recovery process is an essential element in the oil industry, in this study, a laboratory study to investigate the effect of temperature and aging time on oil recovery and understand some of the mechanisms of seawater in the injection process. In order to do that, the sandstone and carbonate cores were placed in the oven in brine to simulate realistic reservoir conditions. Then, they were aged in crude oil in the oven. After that, they were put in the seawater to recover, and this test is called a spontaneous imbibition test. The spontaneous imbibition test in this study was performed at room temperature to oven temperature 80 oC with different sandstone and carbonate rock with aging time of 1126 hours. The result shows that the impact of seawater on oil recovery in sandstone is higher than carbonate. At higher temperature, the oil recovery is more moderate than low temperature. Likewise, as the aging time increase for both sandstone and carbonate rocks the oil recovery increase. 

NMR WETTABILITY INDEX MEASUREMENTS AND METHODS COMPARED ON A VARIETY OF UNCONVENTIONAL SAMPLES

2021 ◽  
Author(s):  
Shaina Kelly ◽  
◽  
Ron J.M. Bonnie ◽  
Micheal J. Dick ◽  
Dragan Veselinovic ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Critical Factor ◽  
Time Lapse ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Rock Properties ◽  
Full Spectrum ◽  
Mixing Ratios ◽  
Rock Types

Matrix wettability is a key driver in relative permeability and, hence, a critical factor controlling imbibition and drainage at UR fracture-matrix interfaces as well as enhanced oil recovery (EOR). In this study, we (1) adapt and apply the NMR-based wettability index (NWI) methodology of Looyestijn et al. (2006) to a variety of unconventional twin samples undergoing, respectively, spontaneous imbibition with oil-displacing-water and water-displacing-oil and (2) compare the robustness of this method among a variety of samples pairs and also to other NMR-based wettability methods. The samples analyzed cover a range of rock types, major formations, maturity and content of organic material. All displayed unique time-lapse wettability profiles and steady state NWI values. This work advances our previous works (Dick et al., 2019; Kelly et al., 2020) on this subject, where the viability of the methodology was established on end-member pilot samples, towards applicability as a UR SCAL method. The NWI methodology predicts T2 spectra using linear combinations (mixing) of “end-point” T2 spectra. The mixing ratios yielding the closest match to the measured spectra are then used to compute a wettability index. These mixing ratios were validated against (1) mass-balance calculations, (2) repeat experiments with heavy water (D2O) instead of H2O and (3) measured T1-T2 maps, enhancing confidence in the robustness of the method. Our comparisons show that alternative approaches representing the T2 spectra through a single mean T2 value or T2 peak-fit, fall short, especially in tight rocks where fast relaxation rate components tend to skew harmonic mean T2 values and also in samples where oil and water peaks are not clearly resolved. Full spectrum-based methods, akin to Looyestijn’s, appear more robust and stable over a much wider range of reservoir conditions. Repeated NMR acquisition throughout our long-term imbibition experiments shows that time-lapse NWI methodology probes the effects of rock properties, saturation changes, and injected fluid chemistry (enhanced oil recovery strategies) on wettability alteration. Additionally, this NWI study quantifies the wide variation in wettability among unconventional samples.

Effect of Total Acid Number and Recovery Mode on Low-Salinity Enhanced Oil Recovery in Carbonates

2021 ◽  
pp. 1-18
Author(s):  
Takaaki Uetani ◽  
Hiromi Kaido ◽  
Hideharu Yonebayashi
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbonate Rock ◽  
Acid Number ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Oil Composition ◽  
Total Acid ◽  
Low Salinity ◽  
Total Acid Number

Summary Low-salinity water (LSW) flooding is an attractive enhanced oil recovery (EOR) option, but its mechanism leading to EOR is poorly understood, especially in carbonate rock. In this paper, we investigate the main reason behind two tertiary LSW coreflood tests that failed to demonstrate promising EOR response in reservoir carbonate rock; additional oil recovery factors by the LSW injection were only +2% and +4% oil initially in place. We suspected either the oil composition (lack of acid content) or the recovery mode (tertiary mode) was inappropriate. Therefore, we repeated the experiments using an acid-enriched oil sample and injected LSW in the secondary mode. The result showed that the low-salinity effect was substantially enhanced; the additional oil recovery factor by the tertiary LSW injection jumped to +23%. Moreover, it was also found that the secondary LSW injection was more efficient than the tertiary LSW injection, especially in the acid-enriched oil reservoir. In summary, it was concluded that the total acid number (TAN) and the recovery mode appear to be the key successful factors for LSW in our carbonate system. To support the conclusion, we also performed contact angle measurement and spontaneous imbibition tests to investigate the influence of acid enrichment on wettability, and moreover, LSW injection on wettability alteration.

scholarly journals Enhanced oil recovery from carbonate reservoirs by spontaneous imbibition of low salinity water

2018 ◽  
Vol 15 (3) ◽  
pp. 564-576 ◽  
Author(s):  
Mohammad Reza Zaeri ◽  
Rohallah Hashemi ◽  
Hamidreza Shahverdi ◽  
Mehdi Sadeghi
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Spontaneous Imbibition ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water

scholarly journals Experimental Investigation of Surfactant Partitioning in Pre-CMC and Post-CMC Regimes for Enhanced Oil Recovery Application

Energies ◽  
2019 ◽  
Vol 12 (12) ◽  
pp. 2319 ◽  
Author(s):  
Ahmed Fatih Belhaj ◽  
Khaled Abdalla Elraies ◽  
Mohamad Sahban Alnarabiji ◽  
Juhairi Aris B M Shuhli ◽  
Syed Mohammad Mahmood ◽  
...  
Keyword(s):  
Surface Tension ◽  
High Temperature ◽  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
High Performance ◽  
Surfactant Concentration ◽  
Effect Of Temperature ◽  
Sweep Efficiency ◽  
Partitioning Coefficient

The applications of surfactants in Enhanced Oil Recovery (EOR) have received more attention in the past decade due to their ability to enhance microscopic sweep efficiency by reducing oil-water interfacial tension in order to mobilize trapped oil. Surfactants can partition in both water and oil systems depending on their solubility in both phases. The partitioning coefficient (Kp) is a key parameter when it comes to describing the ratio between the concentration of the surfactant in the oil phase and the water phase at equilibrium. In this paper, surfactant partitioning of the nonionic surfactant Alkylpolyglucoside (APG) was investigated in pre-critical micelle concentration (CMC) and post-cmc regimes at 80 °C to 106 °C. The Kp was then obtained by measuring the surfactant concentration after equilibration with oil in pre-cmc and post-cmc regimes, which was done using surface tension measurements and high-performance liquid chromatography (HPLC), respectively. Surface tension (ST) and interfacial tension (IFT) behaviors were investigated by performing pendant and spinning drop tests, respectively—both tests were conducted at high temperatures. From this study, it was found that APG was able to lower IFT as well as ST between water/oil and air/oil, and its effect was found to be more profound at high temperature. The partitioning test results for APG in pre-cmc and post-cmc regimes were found to be dependent on the surfactant concentration and temperature. The partitioning coefficient is directly proportional to IFT, where at high partitioning intensity, IFT was found to be very low and vice versa at low partitioning intensity. The effect of temperature on the partitioning in pre-cmc and post-cmc regimes had the same impact, where at a high temperature, additional partitioned surfactant molecules arise at the water-oil interface as the association of molecules becomes easier.

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