Krishna Hara Chakravarty

Determining Optimum Aging Time Using Novel Core Flooding Equipment

(11/12/2018) Determining optimum aging time using novel core flooding equipment New methods for enhanced oil recovery are typically developed using core flooding techniques. Establishing reservoir conditions is essential before the experimental campaign commences. The realistic oil-rock wettability can be obtained through optimum aging of the core. Aging time is affected by temperature, crude oil, formation brine, and coreplug lithology. Minimum time can significantly reduce the experimental cost while insufficient aging time can result in false conclusions. Real-time online resistivity measurements of coreplugs are presented and a novel method is introduced for determining the optimum aging time regardless of variations in crude oil, rock, and brine properties. State of the art core flooding equipment has been developed that can be used for consistently determining the resistivity of the coreplug during aging and waterflooding using advanced data acquisition software. In the proposed equipment, independent axial and sleeve pressure can be applied to mimic stresses at reservoir conditions. 10 coreplugs (four sandstones and six chalk samples) from the North Sea have been aged for more than 408 days in total and more than 29000 resistivity data points have been measured to consistently investigate the change of wettability during aging. At 60°C and 100 bars a homogeneous sandstone coreplug attained optimized wettability after 5 days, a heterogeneous coreplug required 30 days of aging. Chalk coreplugs needed 45 days of aging. This shows that coreplugs originating from the same field, when aged at equivalent conditions can have significantly different aging times because of minor variations in the coreplug properties. No fixed aging time can be recommended on the other hand a method is recommended which can determine the extent of aging. Coreplug aging patterns were studied for variation in pressure (20 to 130 bar) and temperature (60 to 130°C).

Fine Formation During Brine-Crude Oil-Calcite Interaction in Smart Water Enhanced Oil Recovery for Caspian Carbonates

Recovery for Caspian Carbonates DTU Orbit (09/11/2017) Fine Formation During Brine-Crude Oil-Calcite Interaction in Smart Water Enhanced Oil Recovery for Caspian Carbonates Modified sea water has been shown to affect the oil recovery fraction considerably during secondary and tertiary waterfloods. Available soluble potential ions (i.e. Ca2+, Mg2+ & SO4 2-) in the interacting waterflood (ITW) are suggested to play a key role in increasing the displacement efficiency of oil. In previous studies, compositions of injected waterfloods (IJW) have been correlated to the observed oil recovery. This study highlights differences between IJW and ITW for different studies reported in literature.

Importance of fines in smart water enhanced oil recovery (SmW-EOR) for chalk outcrops

DTU Orbit (19/09/2019) Importance of fines in smart water enhanced oil recovery (SmW-EOR) for chalk outcrops In SmW-EOR it is generally believed that precipitation of brines must be avoided since it can have a negative impact on the SmW sweep efficiency. But substitution of Mg2+ by Ca2+ on calcite surfaces (a well-accepted phenomenon) can change the brine combination and enhance the possibility of fine formation at speciation. Considering this phenomenon we analyze the possibility of fines formation and its influence in SmW-EOR. To calculate the brine speciation and the amount of precipitate formed at different pressure and temperature conditions, we use the Extended UNIQUAC model for 61 SmW-EOR experiments reported in literature. Both the amount of available soluble SO4 2(aq) in the solution and the amount of CaSO4 precipitation has been calculated and correlated to the corresponding oil recovery.

Formation of Anhydrite Due to Interaction Between Water Soluble CO 2 (aq) and Calcite Mineral During Enhanced Oil Recovery

Mineral During Enhanced Oil Recovery DTU Orbit (06/01/2019) Formation of Anhydrite due to Interaction Between Water Soluble CO2 (aq) and Calcite Mineral During Enhanced Oil Recovery In the Low Salinity based EOR method, formation and migration of fines have proved to have profound effect on the displacement efficiency of residual oil. Salinity variations of injected brines have also been shown to affect oil recovery for WAG-CO2 processes. But the effect of fines in EOR during LSWAG-CO2 has not been previously studied. This study explores the possibility of fines formation during CO2 injection and attempts to understand its implication in EOR. In this study we use the Extended UNIQUAC model to calculate the possibility of fines formation during CO2 injection. Detailed simulations were conducted over a temperature range of 50°C to 250°C and a pressure range of 5 bars to 500 bars. The amounts of fines formation taking place for different LSWAG-CO2 processes were correlated to the described oil recovery. It is observed that significant amounts of fines formation can take place during CO2 injection in limestone reservoirs. At reservoir conditions, a considerable fraction of the injected CO2 becomes soluble in sea water. This dissolved CO2 causes dissolution of CaCO3 from the mineral surface and releases Ca 2+ ions into the pore space. Excess Ca2+ ions form anhydrite fines with the available SO4 2ions. The salinity and composition of brines present in pore space shows direct correlation with the amount of fines produced during CO2 injection. With increase in temperature and pressure, the amount fines formation increased significantly. The described oil recovery for different LSWAG injections showed a consistent correlation with the amounts of fines formation taking place in the pore space. The amount of mineral dissolution taking place was also precisely calculated using the Extended UNIQUAC model. Good correlation was also observed between calculated amounts of mineral dissolution and the observed increase in permeability. Copyright: 2015. Society of Petroleum Engineers