Fig 1 - available via license: Creative Commons Attribution 4.0 International
Content may be subject to copyright.
Source publication
This research investigates the combined effect of grain size and water salinity on oil recovery. Water flooding was carried out using unconsolidated formation from Niger Delta. Five groups consisting of five samples, were tested for the effective interaction of two factors (grain size and salinity) and how they affect oil recovery. Each group was a...
Contexts in source publication
Context 1
... E: Here, the results indicate that sample E5 which was contacted with 20,0 0 0 ppm gave the highest (78.8%) amount of oil. Sand sample E1 recorded the least oil recovery of 70.3% when flooded with no saline water ( Figs. 9 & 10 ). Table 11 shows the calculated recovery factor for salt concentrations of 50 0 0 ppm, 10 0 0 0 ppm, 150 0 0 ppm and 20 0 0 0 ppm for the varying sand grain sizes represented in Fig. 1 through to 10. ...
Context 2
... with 20,0 0 0 ppm gave the highest (78.8%) amount of oil. Sand sample E1 recorded the least oil recovery of 70.3% when flooded with no saline water ( Figs. 9 & 10 ). Table 11 shows the calculated recovery factor for salt concentrations of 50 0 0 ppm, 10 0 0 0 ppm, 150 0 0 ppm and 20 0 0 0 ppm for the varying sand grain sizes represented in Fig. 1 through to ...
Similar publications
Even after a long time of polymer flooding, over half of the crude oil is still trapped in the reservoir due to the poor plugging capacity. It has been demonstrated that fuzzy-ball fluid can be utilized as an effective plugging fluid. The idea of further increasing oil recovery by fuzzy-ball fluid following polymer flooding drew us to investigate i...
Citations
... Within the Niger Delta region, there are studies showcasing reservoir quality (e.g., Abraham-A, 2013; Mode and Anyiam, 2007;Uroro and Igharo, 2015;Abraham and Taioli, 2017;Abe et al., 2018;Abraham-A and Taioli, 2019;Oluwadare et al., 2020;Ojo et al., 2021;Nzekwu and Abraham-A, 2022) and water cut prediction (e.g., Abraham-A and Taioli, 2018). Others include geothermal gradients (e.g., Ejedawe et al., 1984;Akpabio et al., 2013;Olumide et al., 2013;Emujakporue and Ekine, 2014;Odumodu and Mode, 2016;Uko et al., 2021) and hydrocarbon recovery/reservoir capacity to transmit fluids (e.g., Abraham-A and Taioli, 2019;Okoro et al., 2021). Most of these studies considered hydrocarbon viability-related objectives involving some of the physical parameters engaged in this study. ...
Core samples representing depths of hydrocarbon-bearing zones are not readily accessible for reservoir evaluations. On the other hand, wireline logs with incorporated seismic data, which can be archived over a more extended period while retaining their original forms, are typically more available for research purposes. Therefore, the study relies on wireline logs with seismic data to predict the reservoirs' fluid mobility by evaluating the hydraulic (flow) units, reservoir depths, fluid saturations, and geothermal gradients. It also indicates the associated water cut (Cw) within Ritchie oil and gas field, Niger Delta considering a three-phase (oil-gas-water) reservoir (RA) and an oil-saturated reservoir (RB) delineated across three wells (RW1, RW2 and RW3). Research activities combining the presented factors to achieve the stated objectives are not quite common within the study location. It shows lower, average and upper limits of the flow unit factors and irreducible water saturation (Swirr) within the reservoirs. The study shows the relationship between hydraulic units/fluid saturations and fluid mobility/associated Cw within the sandstone reservoirs. It maximises porosity (Ф) for the theoretical flow units' prediction during qualitative and quantitative estimation based on the adopted expressions. Therefore, the study reveals that water saturation (Sw) and hydrocarbon/water ratios substantially control Cw, and other contributing factors include thermal gradients and Swirr. The flow unit factors are also significant and will encourage fluid mobility. RA and RB are below 10 400 ft (3 170 m) across RW1, RW2 and RW3 within the Agbada Formation of a geothermal gradient up to 2.7 °C/100 m; therefore, they have good thermal conditions to enhance hydrocarbon mobility and increase Swirr. Hence, the reservoir should feature significant hydrocarbon extraction via primary recovery. The average water cut (Cw-avg.) (12.3%) estimated for RA is within the acceptable range; therefore, the associated water production from the three-phase reservoir will not be much of a concern. In addition, simple models are presented to aid an alternative approach for predicting reservoir quality and Cw within sandstone reservoirs, especially in the absence of core samples.
