ORCID Profile
0000-0002-2049-0460
Current Organisation
University of Aberdeen
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Publisher: Elsevier
Date: 2022
Publisher: Elsevier BV
Date: 09-2023
Publisher: SPE
Date: 02-08-2021
DOI: 10.2118/207128-MS
Abstract: Previous studies on smart water effects have suggested wettability alteration as the most significant mechanism for additional oil recovery during smart water injection. Though many other mechanisms have been observed and proposed in several other studies, much more attention is paid to the detachment of oil films from rock surfaces. It is, however, clear from prevailing understanding that the activities at oil/brine interfaces might require as much attention as given to the brine/rock interfaces. This paper presents diffuse double layer surface complexation modelling of the adsorption of potential determining (Ca2+, Mg2+ and SO42-) ions on oil carboxylic and carbonate surfaces. Surface complexation models are developed by defining the adsorption sites, surface area and mass of the oil and carbonate surfaces. The chemical reactions involving the surface sites and five different brine solutions are also defined. The brine solutions include formation water, sea water, sea water diluted 20 and 50 times, and sea water with four times SO42- concentration. The amount of the alent ions adsorbed at pH range of 5 to 8 are determined after the reactions had reached equilibrium. Adsorption of the ions on oil carboxylic and carbonate surfaces at elevated temperature for the sea water is also investigated. Results show that significant number of alent ions are collected at the oil/brine interfaces just as adsorbed at the brine/rock interfaces. The results suggest that the equilibrium reactions and the dynamics at the two mathematical interfaces in any oil/brine/rock systems are equally important to reach a full understanding of the main mechanisms behind smart water effects. Therefore, the dynamics of ionic reactions at the oil/brine interface can play critical roles in defining smart water effects on residual oil mobilization.
Publisher: American Chemical Society (ACS)
Date: 13-04-2023
Publisher: Elsevier BV
Date: 02-2022
Publisher: MDPI AG
Date: 05-07-2022
DOI: 10.3390/EN15134906
Abstract: The ultrasound method is a low-cost, environmentally safe technology that may be utilized in the petroleum industry to boost oil recovery from the underground reservoir via enhanced oil recovery or well stimulation c aigns. The method uses a downhole instrument to propagate waves into the formation, enhancing oil recovery and/or removing formation damage around the wellbore that has caused oil flow constraints. Ultrasonic technology has piqued the interest of the petroleum industry, and as a result, research efforts are ongoing to fill up the gaps in its application. This paper discusses the most recent research on the investigation of ultrasound’s applicability in underground petroleum reservoirs for improved oil recovery and formation damage remediation. New study areas and scopes were identified, and future investigations were proposed.
Publisher: Springer Singapore
Date: 2022
Publisher: Elsevier
Date: 2023
Publisher: Elsevier BV
Date: 11-2020
Publisher: SPE
Date: 05-08-2019
DOI: 10.2118/198876-MS
Abstract: The impact of production tubing diameter on multiphase flow regime profile is investigated. For a given isolated section of the production tubing in selected wells drilled and completed in Oredo fields, velocity profile and fluid flow characteristics at the production tubing centreline and along the pipe wall were evaluated. Complex flow behaviour is characterised by tubing diameter and asymptotic flow pattern at the tubing surface where no-slip boundary condition was imposed. Future inflow production performance relationship (IPR) and influence on vertical lift performance are determinable from the multiphase flow regime profiles. Furthermore, we investigate the impact of production tubing diameter on multiphase flow regime profile in Oredo oil field Nigeria. Mechanisms responsible for complex fluid flow behaviour and transition in different tubing configuration with implication on production optimisation and performance analysis are also included in the model design and analysis. From the results obtained in this study, it is evident that higher volume of oil is producible from bigger production tubing. However, implications on vertical lift performance and production optimisation require a more critical analyses.
Publisher: MDPI AG
Date: 18-05-2023
Abstract: In this work, geochemical modelling using PhreeqC was carried out to evaluate the effects of geochemical reactions on the performance of underground hydrogen storage (UHS). Equilibrium, exchange, and mineral reactions were considered in the model. Moreover, reaction kinetics were considered to evaluate the geochemical effect on underground hydrogen storage over an extended period of 30 years. The developed model was first validated against experimental data adopted from the published literature by comparing the modelling and literature values of H2 and CO2 solubility in water at varying conditions. Furthermore, the effects of pressure, temperature, salinity, and CO2% on the H2 and CO2 inventory and rock properties in a typical sandstone reservoir were evaluated over 30 years. Results show that H2 loss over 30 years is negligible (maximum 2%) through the studied range of conditions. The relative loss of CO2 is much more pronounced compared to H2 gas, with losses of up to 72%. Therefore, the role of CO2 as a cushion gas will be affected by the CO2 gas losses as time passes. Hence, remedial CO2 gas injections should be considered to maintain the reservoir pressure throughout the injection and withdrawal processes. Moreover, the relative volume of CO2 increases with the increase in temperature and decrease in pressure. Furthermore, the reservoir rock properties, porosity, and permeability, are affected by the underground hydrogen storage process and, more specifically, by the presence of CO2 gas. CO2 dissolves carbonate minerals inside the reservoir rock, causing an increase in the rock’s porosity and permeability. Consequently, the rock’s gas storage capacity and flow properties are enhanced.
Publisher: American Chemical Society (ACS)
Date: 15-12-2022
Publisher: Elsevier BV
Date: 12-2023
Publisher: Springer Singapore
Date: 2022
Publisher: SPE
Date: 20-10-2008
DOI: 10.2118/115065-MS
Abstract: Gas injection is one of the key enhanced oil recovery (EOR) methods. Significant volumes of the residual oil, remaining after earlier EOR methods, has been reported to be recovered through the gravity drainage mechanism, following the crestal gas injection in the horizontal, dipping or reef type oil reservoirs. The rate of oil recovery is controlled by the viscous/capillary/gravity forces, the rate of gas injection and oil production, the difference of oil and gas density, the oil relative permeability, the oil viscosity and number of other operational parameters. Risk analysis of these parameters helps to identify their relative dominance during gas-oil gravity drainage process. The interactions between various process controlling parameters is studied through development of scaling groups that govern the displacement process. Functional relationships between those scaling groups and their effect on the overall performance of immiscible gas-driven gravity drainage EOR are investigated in this study. This enables an estimation of fractional oil recovery for the combinations of scaling groups. The results of numerical sensitivity analysis through the reservoir simulations are presented to map the effective combinations of the dimensionless scaling groups for gas-oil gravity drainage EOR method.
Publisher: SPE
Date: 08-2022
DOI: 10.2118/212047-MS
Abstract: A method of optimising gas production from condensate well in Oredo field by simulating surface proportional integral derivative controller, downhole transmitter, wellhead and bottomhole chokes is presented. This method overcomes the potential risk of high backpressure imposed on the production tubing by manual choking or other control solutions using wellhead valve. Firstly, a model of Oredo well O7 is constructed with a closed node constituting the reservoir unit and a surface pressure node on the wellhead. An automated pressure integral derivative controller that senses and controls the bottomhole flowing pressure by actuating the wellhead choke is then installed at the wellhead. Measurement input to the auto-controller is delivered via an insitu transmitter. This design approach is successfully applied to the well O7 model through a commercial multiphase simulator on well models and provides a condensate banking monitoring mechanisms with improved production output.
Publisher: Elsevier BV
Date: 08-2022
Publisher: Elsevier BV
Date: 08-2023
Publisher: Elsevier BV
Date: 2023
Publisher: Elsevier BV
Date: 11-2023
Publisher: Elsevier BV
Date: 11-2023
Publisher: Elsevier
Date: 2023
Publisher: Informa UK Limited
Date: 23-10-2019
Publisher: Institute of Electrical and Electronics Engineers (IEEE)
Date: 2023
Publisher: SPE
Date: 02-08-2021
DOI: 10.2118/208449-MS
Abstract: A new pseudo-radial pressure model for inflow performance analysis and near-wellbore condensate banking deliverability is developed. Analysis of condensate banking and evolution in near wellbore region (i.e. zone 3) has been extensively studied. The new zone 4 region identified in this work will help in delineating the limit of retrograde condensation and the onset of revapourisation. Revapourisation after retrograde condensation is usually not accounted for in most field applications. However, in mature fields such as the Oredo field investigated in this study, revapourisation and near wellbore dynamics play an important role in optimising production from the field. The results of the newly formulated model captured the transient retrograde revapourisation near the wellbore for the well X studied in this work.
Publisher: Elsevier BV
Date: 11-2012
Publisher: Elsevier BV
Date: 11-2022
Publisher: American Chemical Society (ACS)
Date: 31-12-2020
Publisher: Society of Petroleum Engineers (SPE)
Date: 02-2010
DOI: 10.2118/133373-PA
Abstract: Abstract The oil recovery process is controlled by the rates of gas injection and oil production, relative permeabilities, reservoir heterogeneities and the balance among viscous, capillary and gravity forces. Crestal gas injection in horizontal, vertical or reef type oil reservoirs recovers significant volumes of the residual oil due to the gas-oil gravity drainage mechanism, indicating the significance of gravity forces. This study investigates the effects of the parameters that control the process (e.g., rate of the gas injection and oil production) and reservoir heterogeneities on the overall performance of immiscible gravity drainage enhanced oil recovery (EOR). Reservoir simulation studies are conducted to map effective combinations of these parameters with respect to the oil recovery performance. Introduction Gravity forces play an important role at nearly every stage of the producing life of the reservoir, whether it is primary depletion, secondary water or gas injection schemes or tertiary enhanced or improved oil recovery methods(1). They can be advantageously used to maximize oil recovery from the oil bearing zone under investigation through gravity drainage mechanism. Several cases reported in the literature suggest that it could deliver as high as 87 to 95% incremental oil recoveries in contrast to other gas injection EOR methods. Gas-Oil Gravity Drainage Process Gravity drainage is a process in which gravity acts as a main driving force and where gas replaces voidage volume(2). It is commonly implemented in either of the dipping or pinnacle reef type reservoirs. CO2-assisted gravity drainage EOR process is a top-down process in which gas is injected in the gas cap through vertical wells at a rate lower than the critical rate (Figure 1). Critical rate is the rate at which injection gas fingers through oil zone (viscous instabilities) leading to its premature breakthrough at the production wells. Injected gas segregates and creates a gas-oil interface. Controlled oil production is started through horizontal wells placed at the bottom of the oil zone such that the voidage created by oil withdrawal (in addition to minor dissolved volumes) is replaced by the equivalent CO2 injection volume. When this happens, pressure differential across the gas cap and oil zone [that is gas-oil contact (GOC)] stay at or close to zero implying that the pressure in the gas zone behind the CO2 floodfront would be constant(3). This helps to maintain the reservoir pressure nearly constant.
Publisher: SPE
Date: 05-08-2019
DOI: 10.2118/198877-MS
Abstract: An enhanced neuro-fuzzy technique is deployed in production optimisation and fluid flow analysis for wells drilled and completed in Oredo oilfields Niger delta Nigeria. The impact of historical production data, reservoir rock and fluid properties, well geometry, architecture, completion profile and surface data on overall well deliverability is incorporated in the model. The artificial intelligence training process is complete at the point a minimum quantifiable error is obtained or when a value less than the set tolerance limit is reached. Production data obtained from the short and long-strings for wells completed in Oredo field was processed, analysed and input into the enhanced neuro-fuzzy algorithm. The adopted enhanced neuro-fuzzy system is capable of modelling the direct approach of Mamdani and that of Sugeno in a five-layer feed-forward neural network and fuzzy logic process designed and implemented in a C/C++ numerical computation objected oriented platform. This study highlights the significance of data analytics and artificial intelligence in well performance prediction and cost reduction and optimisation in oil producing wells.
Publisher: Inderscience Publishers
Date: 2022
Publisher: Elsevier BV
Date: 2021
Publisher: Kluwer Academic Publishers
Date: 2006
Publisher: Elsevier BV
Date: 2022
Location: United Kingdom of Great Britain and Northern Ireland
Location: United Kingdom of Great Britain and Northern Ireland
Location: United Kingdom of Great Britain and Northern Ireland
No related grants have been discovered for Prashant Jadhawar.