Petroleum Engineering

TECHNICAL AND ECONOMIC EVALUATION OF NANOFLUIDALTERNATING-BRINE FLOODING FOR ENHANCED OIL RECOVERY IN NIGER DELTA RESERVOIRS

Tue, 01 Feb 2022 00:00:00 GMT

TECHNICAL AND ECONOMIC EVALUATION OF NANOFLUIDALTERNATING-BRINE FLOODING FOR ENHANCED OIL RECOVERY IN NIGER DELTA RESERVOIRS OMOTOSHO, Yetunde Aderonke 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 ORF obtained 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 (1.0viii 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.

DEVELOPMENT OF A REAL-TIME PETROLEUM PRODUCTS ADULTERATION DETECTOR FOR LIQUID AND PARTICULATE CONTAMINANTS

Mon, 05 Dec 2022 00:00:00 GMT

DEVELOPMENT OF A REAL-TIME PETROLEUM PRODUCTS ADULTERATION DETECTOR FOR LIQUID AND PARTICULATE CONTAMINANTS OLOTU, Olabisi Oluseyi Adulteration of petroleum products with the resultant safety, health, environmental and economic impact on the end-users is a challenge in Nigeria and many developing countries. The current commonly used techniques by regulatory agencies and some end-users for quality assurance of the petroleum products are time-consuming and expensive. The development and use of real-time adulterated petroleum products detector in Nigeria will therefore alleviate these problems. This study was therefore designed to develop a device for real-time detection of petroleum products adulterated with liquid and particulate contaminants. Pure samples of Premium Motor Spirit (PMS), Automotive Gas oil (AGO) and Dual Purpose Kerosene (DPK) were collected from some major petroleum products marketers. Samples of distilled water, naphtha, commercial ethanol, pure and used commercial lubricating oil, and High Pour Fuel Oil (HPFO) were also obtained and used as liquid contaminants; while sawdust, ash and fine-grain sand were used as solid particulates. At temperatures 23:1:28oC, binary mixtures of the products mixed with liquid contaminants were prepared (100:0, 95:5, 85:15, 75:25, 70:30, 65:35 … 15:85, 5:95,0:100 v/v). Likewise, a fixed volume of pure petroleum products was mixed with varying quantity of solid particulates (0, 2, 4, 6, 8, 10 g). The specific Gravity (SG) and Interfacial Tension (IFT) of the pure samples, binary mixtures were determined according to ASTM D1298 and D971 standards, respectively. These physiochemical properties (SG and IFT) of pure and contaminated fuel samples were used to develop a mathematical model. The model was then simulated into a microcontroller-based detector. A microcontroller of PIC16f876 microchip with multiple input/output pins and a load cell sensor with real-time response was used. The microcontroller takes the reading of the weight of liquid from the sensor to get the SG and IFT of the liquid in real-time. Values of SG and IFT of pure and contaminated samples of petroleum products were obtained using the developed adulteration detector and compared with laboratory measurements and those obtained using Kay’s mixing rule. Data were analysed using ANOVA at α 0.05. The SG and IFT (dynes/cm) of the pure samples were (PMS) 0.833, 47.0; (AGO) 0.812, 28.0; (DPK) 0.803, 25.0, for liquid contaminants ranged from (PMS) 0.853-0.890, 44.6-25.0; (AGO) 0.807-0.804, 46.2-29.5; (DPK) 0.811-0.947, 46.4-38.0 and for solid contaminants ranged from (PMS) 0.887-0.910, 47.8-27.2; (AGO) 0.884-0.887, 29.2-30.0; (DPK) 0.817-0.857, 25.8-32.8, respectively. The SG and IFT from Kay’s mixing rule ranged from (PMS) 0.851-0.900, 48.4-25.6; (AGO) 0.850-0.871, 40.1-35.4; (DPK) 0.864-0.881, 42.4-36.4, respectively. Adulteration of products was detected at 20.0-30.0% by volume and 10.0-20.0% by mass of contamination, respectively. The designed adulteration detector responded to the sample in real-time of 3-5s, displayed GREEN and RED for pure and adulterated samples, respectively, with their numerical SG values within ±0.01% of actual measurements. There was no significant difference between the actual and detected SG and IFT of the adulterated samples. A device that detects petroleum products adulteration in real-time and ambient temperature was developed. The method can be adapted to real-time evaluation of similar binary mixtures.

PHASE BEHAVIOUR AND ASPHALTENE ONSET PRESSURE PREDICTION DURING GAS INJECTION IN OIL RESERVOIRS

Mon, 10 Jun 2019 00:00:00 GMT

PHASE BEHAVIOUR AND ASPHALTENE ONSET PRESSURE PREDICTION DURING GAS INJECTION IN OIL RESERVOIRS OGUAMAH, IFEANYI UCHE ALEX Asphaltene Precipitation (AP), a major challenge in the petroleum industry, causes flow assurance issues in reservoirs, pipelines and flow lines. It is therefore important to properly characterise petroleum fluids and predict the conditions under which AP could be prevented. Many of the reported models used for predicting AP to achieve best reservoir and production management practices are rather complex for routine applications. This study was designed to develop a simple but accurate model for characterising petroleum fluids and predicting AP during gas injection into oil reservoirs. A generalised model for predicting phase behaviour of multiphase systems having different energy states was derived using partition function principle. The model obtained was simplified for routine application to a three-parameter cubic Equation of State (EOS), which was used to characterise selected pure gases, binary mixtures, four crude oil samples (F1, F2, F3 and F4) and n-Pentane+Violanthrone-97 simulated oil (F5), to obtain pressure-temperature phase profiles. The Upper Asphaltene Onset Pressures (UAOP) were estimated under natural gas (0, 15, and 30wt %); carbon dioxide (CO2) gas (10 and 20wt %) and nitrogen gas (N2) injections (5wt %). Results were validated using published data, and compared with Soave-Redlich-Kwong (SRK), Peng-Robinson (PR) and the Perturbed Chain Statistical Associating Fluid Theory (PCSAFT) EOS. Data were analysed using ANOVA at α0.05. The developed EOS accounted for the contributions of attractive, repulsive, and non-physical forces in the fluids. Predicted Pressure-Temperature profiles for pure gases compared well to SRK and PR, and matched experimental data with percentage error of 0.04%, 0.13% and 0.05% for nitrogen, carbon dioxide and butane, respectively. The phase envelopes generated for ethanol-benzene, benzene-hexane, hexane-ethanol and methane-propane also matched experimental data. Predicted pressure-temperature envelopes for the crude oils, gave an average deviation of ±0.03%, while the Pentane+Violanthrone-97 rich phase was stable between 16.62 and 65.95kN/m2 at 298K and 65.86 and 241.15kN/m2 at 338K. These predictions matched experimental data and the results obtained using PCSAFT EOS. Estimated UAOP were 30812.93, 38369.75 and 84947.83kN/m2 for F1 at 0, 15, and 30 wt.% natural gas injection, respectively; 52674.81, 59967.88 and 63829.68kN/m2 for F2 at 0, 10, 20 wt.% CO2 gas injection, respectively and 38783.64 kN/m2 at 5 wt.% nitrogen gas injection. For F3 and F4 at no gas injection, predicted UAOP were 117094.58 and 63326.02 kN/m2, respectively; while 19788.77 and 49051.43kN/m2 were predicted for F5 at 10 and 20 wt. % CO2 gas injections, respectively. Generally, UAOP increased with increasing proportion of injected gases and varied with reservoir fluid and type of injected fluid. There was no significant difference between predicted results and those obtained using the PCSAFT EOS. A simplified model for characterising petroleum fluids and predicting Asphaltene precipitation was developed. The model achieved faster and better control of Asphaltene precipitation during gas injection operations in oil reservoirs.

IMPROVED MATERIAL BALANCE EQUATION OF SHALE GAS RESERVES AND PRODUCTION

Sat, 01 Dec 2018 00:00:00 GMT

IMPROVED MATERIAL BALANCE EQUATION OF SHALE GAS RESERVES AND PRODUCTION ALAWODE, ADEOLU JULIUS Langmuir adsorption isotherm has been used extensively when incorporating gas desorption into gas Material Balance Equation (MBE) framework. However, it over-estimates adsorbed gas reserves at higher pressures without adsorption saturation pressure (P_s ). Previous researches developed modified Z-factors incorporating gas desorption, rendering them complex for routine calculations. Therefore, this study was designed to improve shale gas MBE by developing an isotherm that defines the onset of adsorption saturation pressure, and modifying single-porosity Z-factor to a simpler but accurate dual-porosity free gas Z-factor. A new adsorption isotherm involving pressure (P), P_s, maximum adsorbed volume (V_max ), and adsorbate-adsorbent resistance parameter (n) was developed using kinetic approach. The developed and Langmuir isotherms were used in modelling secondary adsorption data of different adsorbents, and the qualities of fit were statistically assessed. The modified Z-factor incorporates ratio of dual porosity to initial matrix porosity (ϕ_mat^' ), and it was statistically correlated with existing dual-porosity Z-factor. The improved MBE is a function of the developed isotherm and the modified Z-factor. Using adsorption and reservoir data of some shale gas formations obtained from literature, variation of cumulative gas production (G_p ) with pressure depletion (∆P) were determined. Effect of fracture porosity (ϕ_frac ) on G_p was determined. Free and total gas production decline rate models were derived from well production history and average change of G_p with pressure depletion from initial reservoir pressure to wellbore flowing pressure. The results were statistically correlated. The developed isotherm, V={█(V_max {P/P_s +(1-P/P_s ) (P/P_s )^n },&for P