Petroleum Engineering

Nanofluid flooding in the petroleum industry has generated growing interest because of its potential to greatly improve oil recovery. However, studies have reported that injection of nanofluid could lead to impaired permeability due to adsorption of nanoparticles on reservoir rocks thereby incurring high costs. The use of single Nanofluid Flooding (NF) has not appreciably reduced permeability impairment. This study was therefore, designed to investigate the technical and economic viability of Nanofluid-Alternating-Brine Flooding (NABF) for enhanced oil recovery in Niger Delta reservoirs. Eight sandstone core samples obtained from Niger Delta, were characterised for porosity and permeability using Helium-Porosimeter and Permeameter, respectively. Densities and viscosities of crude oil samples and brine (Salinity: 32.2g/L) were determined using pycnometer and viscometer, respectively. Core samples were initially saturated with brine and drained with crude oil, to determine the initial Water Saturation (SWi). Silica nanoparticles of size: 20-70 nm, were dispersed in brine at concentrations ranging from 0.01 to 3.00 wt%. Interfacial Tensions (IFT) between oil and nanofluids were measured. Brine Flooding (BF) of core samples was conducted at 2.00 cm3 /min. The Optimum Concentration (OC) and Optimum Injection Rate (OIR) during NF were determined by injecting each nanofluid concentration at 0.50, 1.00, 2.00 and 3.00 cm3 /min. The NABF was carried out at OC and OIR. The Oil Recovery Factors (ORF) for all experiments were computed using material balance. The images of pre-flooded and post-flooded core samples were obtained using Scanning Electron Microscope. Nanoskin factors (Sn) were determined for NF and NABF and compared with the analytical model developed from Darcy’s equation. The ORFobtained were upscaled for field application and evaluated for Threshold Oil Price (TOP). Risk analysis with varying ORF, Capital Expenditure (CAPEX) and Operating Expenses (OPEX) was carried out using a commercial software. Data were analysed using ANOVA at 𝛼0.05. Porosity and liquid permeability for the samples were 17.0-30.0% and 1.1x10-8 -1.6x10-8 cm2 (1104.9-1584.0 md), respectively. The densities of crude oil and brine were 0.88 and 1.02 g/cm3 , while their viscosities were 3.0x10-4 kgms-2 (3.0 cp) and 1.0x10-4 kgms-2 (1.0 viii cp), respectively. The SWi were 11.0-18.4%. The IFT were 1.9x10-2 -2.3x10-2 N/m (18.5- 23.0 dynes/cm) while the OC and OIR for NF were 2.00 wt % and 2.00 cm3 /min, respectively. The ORF for BF, NF and NABF were 68.9-73.1, 63.8-66.2 and 83.8-86.2%, respectively. The pre-flooded cores had evenly distributed grain matrices void of external particles while permeability impairment was observed for NF. Permeability impairment reversal was observed during NABF. The predictive model for Sn agreed with the experimental result. Economic analysis revealed that for unit CAPEX (N13,985.56/bbl; $34.00/bbl) and OPEX (N1,867.48/bbl; $4.54/bbl), at discount rate of 10.0%, TOP was N20,196.79/bbl ($49.10/bbl). Risk analysis on profitability showed that TOP for proved, probable and possible ORF were 33,400.81, 19,197.24 and N12,545.87/bbl (81.20, 46.67 and $30.50/bbl), respectively. The order of impact of the economic variables on profitability was ORF>CAPEX>OPEX. Improved oil recovery in Niger Delta reservoirs was achieved using nano-alternating-brine flooding with minimal permeability impairment. The method is also profitable within the stipulated oil price regime.

In formation evaluation, the knowledge of porosity, permeability and fluids saturation are very important in the determination of the hydrocarbon in place. These petro physical properties are necessary to understand the nature of the reservoir and help for proper field development planning. This was aimed at determining the petro physical properties (pore volume, bulk volume, grain volume, permeability and fluid saturation) of a reservoir from core plugs. A total of ten core plugs were used in this work. Archimedes immersion method was used in the determination of the bulk volume. Liquid saturation method was used in the determination of the porosity. The Dean-Stark extraction method was used in the determination of fluid saturation. From the results obtained in the core analysis, the sandstone reservoir has an average porosity of 14.9±5.1%, very good permeability with an average value of 349.77±0.3 mD and a very large water saturation value of 82±0.4%. Consequently the hydrocarbon saturation is approximately 18%. This implies that the formation is not commercially viable to develop based on the hydrocarbon saturation. The study shows that experimental work is one of the valid tools for making informed decisions on the development of a field in the petroleum industry and highlights the importance of the basic petrophysical properties in reservoir management.

Petroleum Engineering

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