Randy Agra Pratama
A passionate PhD researcher with total 5 years of work experience in oil and gas industry. Graduated and holds B.Sc in Petroleum Engineering from Bandung Institute of Technology with Cum Laude honour and M.Sc in Petroleum Engineering from the University of Alberta. I am currently pursuing my Ph.D in Petroleum Engineering at the University of Alberta with focused research on chemical enhanced oil recovery for thermal recoveries: rock surface wettability alteration, intermolecular interactions, and pore-scale visualization.
Several experiences working in light oil business unit, including production & operations, well completion, pump optimization, workovers & well services, reservoir management & optimization for waterflood fields, well development execution, and heavy-oil business unit, including Reservoir Management Framework (RMFW), Asset Development Plan (ADP), Uncertainty/Risk Management Plan (RMP/UMP), annual reserves, Business Planning (BP), contingent resources, and asset forecasting (base and project productions, CAPEX, and OPEX). Exposure to productivity and economic analyses tools, such as DSS (Dynamic Surveillance System), Spotfire, Excel Macros & SQL, Merak PEEP
Competencies:
- Production & Reservoir Engineering
- Waterflood Management & Optimization
- Reservoir Management Framework
- Reserves
- Asset Forecasting
- Asset Business Planning
Supervisors: Prof. Tayfun Babadagli, Ph.D., P.Eng.
Address: Edmonton, Alberta, CA
Several experiences working in light oil business unit, including production & operations, well completion, pump optimization, workovers & well services, reservoir management & optimization for waterflood fields, well development execution, and heavy-oil business unit, including Reservoir Management Framework (RMFW), Asset Development Plan (ADP), Uncertainty/Risk Management Plan (RMP/UMP), annual reserves, Business Planning (BP), contingent resources, and asset forecasting (base and project productions, CAPEX, and OPEX). Exposure to productivity and economic analyses tools, such as DSS (Dynamic Surveillance System), Spotfire, Excel Macros & SQL, Merak PEEP
Competencies:
- Production & Reservoir Engineering
- Waterflood Management & Optimization
- Reservoir Management Framework
- Reserves
- Asset Forecasting
- Asset Business Planning
Supervisors: Prof. Tayfun Babadagli, Ph.D., P.Eng.
Address: Edmonton, Alberta, CA
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Papers by Randy Agra Pratama
and ZrO2 ), ethers, alcohols, and chelating agents—were applied to the steam with a range of concentrations throughout surface tension and contact angle measurements to evaluate wettability alteration performance at steam temperature and pressure.
The observation presented that pressure does not contribute substantially to the wettability state and was perceived to be more oil-wet in steam conditions—as also confirmed by our previous research. The irreversible mechanism of wettability state was the result when phase change occurred with the presence of brine. Wettability alteration and surface tension reduction in steam condition were achieved after involving these unconventional chemicals, an example being in the steam with biodiesel application. In addition, optimum chemical concentration was also observed through surface tension and contact angle measurements.
The study and analysis of chemical additives applications provides a stronger understanding of steam-induced wettability alteration mechanisms in a rock/heavy-oil/steam system. In summary, conventional steam additives can be altered by these novel chemicals that are both cheaper and more thermally stable, thus showing potential and appearing promising for steam wettability improvement and surface tension reduction in steam applications.
Heavy oil from a field in Alberta (27,780 cp at 25°C) was used in contact-angle measurements conducted on quartz, mica, calcite plates, and rock pieces obtained from a bitumen-containing carbonate reservoir (Grosmont). All measurements were conducted at a temperature ranging up to 200°C using a high-temperature/high-pressure interfacial tension (IFT) device. To obtain a comprehensive understanding of this process, different factors, including the phase of water, pressure, rock type, and contact sequence, were considered and studied separately.
To study the effect of pressure on wettability, we started by maintaining the water in liquid phase and measuring the contact angles between the oil and water at different pressures. Next, the contact angle was measured in pure steam by keeping the pressure lower than saturation pressure. The influence of contact sequence was investigated by reversing the sequence of generating steam and introducing oil during measurement; these measurements were repeated on different substrates. Different temperature-resistant chemical additives (alkalis, surfactants, ionic liquid) were added to the steam during contact-angle measurement to test the wettability alteration characteristics at different temperatures and pressure conditions (steam or hot-water phase). In addition to these wettability-state observations, surface-tension experiments were conducted to evaluate the performance of additives in reducing surface tension for the oil/steam system. The results showed that the wettability of the tested substrates is not sensitive to pressure as long as the phase has not been changed. The system, however, was observed to be more oil-wet in steam than in water at the same temperature in the calcite test. The wettability state could be altered by using chemical additives in certain ranges of concentration; moreover, the optimal chemical-additive concentration was also observed from both contact-angle and surface-tension measurements.
Analysis of the degree of wettability alteration induced by steam (or hot water) and temperature was helpful to further understand the interfacial properties of the steam/bitumen/rock system, and proved useful in the recovery-performance estimation of the steam-injection process in carbonate and sand reservoirs, specifically in chemically enhanced heavy-oil recovery.
injectors.
The main oil production comes from the Sierra group formation that consists of 3 main reservoirs, A, B and C. The A reservoir is subdivided into A1950 sand, A2020 sand, and A2050 sand. The B reservoir is subdivided into B2250 sand. The C reservoir is subdivided into C2420R, C2420S, C2420T, and C2420U. Those reservoirs are deposited in the Early Miocene age in an estuary environment setting. The reservoir depth ranges from 1900-2800 feet. Since 1997 enhanced waterflood method was started to improve oil recovery by converting producer well at the flank structure into injector wells. Those peripheral injectors surround the Rahayu field, even near the main thrust fault, in order to maintain reservoir pressure and also fluid displacement.
Rahayu field is considered as a matured waterflood field and it needs alignment between peripheral injector-to-producer to make sure that the water is injected to the right reservoir. The main concern for this study is for all injectors that located along the thrust fault boundary. The main focus of this study was to make a robust interpretation for thrust fault outline and the subsurface location of injector and producer well trajectory along the fault surface.
This is a problem occurring in some injectors in the Pelana Field, where the injection is not evenly distributed vertically so that the topmost reservoir, which also has the poorest quality with permeability of around 100 mD, does not receive enough injection to balance its production. Most of the injected water goes to MN_XX sand which has permeability of about 1000 md. Injector PL-55, for instance, injects into both sands to support the production from both reservoirs. However, the previous completion uses only open ended tubing and therefore, based on the spinner result, the water will be distributed naturally based on the well-to-reservoir pressure difference, being directly affected by reservoir permeability. This practice resulted in an unbalanced performance for both sands. While MN_XX has a good sweep efficiency with recovery factor (RF) increment > 8%, the BK_AA sand would has an opportunity to be optimized due to its current low incremental of RF.
Side Pocket Mandrel has been chosen to resolve the vertical distribution problem in PL-55 and improve the injection rate into BK_AA sand. It is observed that the well can finally split its injection into more desirable allocation, allowing more water to flow into BK_AA sand. This paper presents the application of this technology in PL-55 well, including the technology principles, the tool design, the strategy to improve the injection distribution and the enhanced performance to the surrounding producers.
Recoverable oil down-structure in the ESE flank is not because of structural or stratigraphic compartmentalization but rather due to isolation of oil as a local result of peripheral water injection. Borehole image data from a directional infill well shows no fault indication as indicated in 3-D seismic cube. Reservoir pressure data in X Sand shows high pressure ranges from 420 to 750 psi up from initial pressure of 200 psi which indicates reservoir connectivity to the peripheral injectors. Well-to-well correlation shows flexure oil-water-contact with draping oil pay thickness ranges from 15 to 20 feet.
Discovery of the flexure oil trapped below the peripheral water injection level BK has led to the conclusion that classic piston-like waterflood displacement might not be a suitable approach since the calculated Dietz flood front angle approximation is –1.57 degree (< 0 degree). Gravity force with strong water-drive mechanism and low structure angle (1 to 3 degree) in the ESE flank are much stronger influences as compared either to mobility contrast or to rock heterogeneity that made the flexure oil trap in X Sand. Therefore, injector placement strategy and injector to producer alignment prioritization are critical factors for maximizing and improving oil recovery in the flank structure.
and ZrO2 ), ethers, alcohols, and chelating agents—were applied to the steam with a range of concentrations throughout surface tension and contact angle measurements to evaluate wettability alteration performance at steam temperature and pressure.
The observation presented that pressure does not contribute substantially to the wettability state and was perceived to be more oil-wet in steam conditions—as also confirmed by our previous research. The irreversible mechanism of wettability state was the result when phase change occurred with the presence of brine. Wettability alteration and surface tension reduction in steam condition were achieved after involving these unconventional chemicals, an example being in the steam with biodiesel application. In addition, optimum chemical concentration was also observed through surface tension and contact angle measurements.
The study and analysis of chemical additives applications provides a stronger understanding of steam-induced wettability alteration mechanisms in a rock/heavy-oil/steam system. In summary, conventional steam additives can be altered by these novel chemicals that are both cheaper and more thermally stable, thus showing potential and appearing promising for steam wettability improvement and surface tension reduction in steam applications.
Heavy oil from a field in Alberta (27,780 cp at 25°C) was used in contact-angle measurements conducted on quartz, mica, calcite plates, and rock pieces obtained from a bitumen-containing carbonate reservoir (Grosmont). All measurements were conducted at a temperature ranging up to 200°C using a high-temperature/high-pressure interfacial tension (IFT) device. To obtain a comprehensive understanding of this process, different factors, including the phase of water, pressure, rock type, and contact sequence, were considered and studied separately.
To study the effect of pressure on wettability, we started by maintaining the water in liquid phase and measuring the contact angles between the oil and water at different pressures. Next, the contact angle was measured in pure steam by keeping the pressure lower than saturation pressure. The influence of contact sequence was investigated by reversing the sequence of generating steam and introducing oil during measurement; these measurements were repeated on different substrates. Different temperature-resistant chemical additives (alkalis, surfactants, ionic liquid) were added to the steam during contact-angle measurement to test the wettability alteration characteristics at different temperatures and pressure conditions (steam or hot-water phase). In addition to these wettability-state observations, surface-tension experiments were conducted to evaluate the performance of additives in reducing surface tension for the oil/steam system. The results showed that the wettability of the tested substrates is not sensitive to pressure as long as the phase has not been changed. The system, however, was observed to be more oil-wet in steam than in water at the same temperature in the calcite test. The wettability state could be altered by using chemical additives in certain ranges of concentration; moreover, the optimal chemical-additive concentration was also observed from both contact-angle and surface-tension measurements.
Analysis of the degree of wettability alteration induced by steam (or hot water) and temperature was helpful to further understand the interfacial properties of the steam/bitumen/rock system, and proved useful in the recovery-performance estimation of the steam-injection process in carbonate and sand reservoirs, specifically in chemically enhanced heavy-oil recovery.
injectors.
The main oil production comes from the Sierra group formation that consists of 3 main reservoirs, A, B and C. The A reservoir is subdivided into A1950 sand, A2020 sand, and A2050 sand. The B reservoir is subdivided into B2250 sand. The C reservoir is subdivided into C2420R, C2420S, C2420T, and C2420U. Those reservoirs are deposited in the Early Miocene age in an estuary environment setting. The reservoir depth ranges from 1900-2800 feet. Since 1997 enhanced waterflood method was started to improve oil recovery by converting producer well at the flank structure into injector wells. Those peripheral injectors surround the Rahayu field, even near the main thrust fault, in order to maintain reservoir pressure and also fluid displacement.
Rahayu field is considered as a matured waterflood field and it needs alignment between peripheral injector-to-producer to make sure that the water is injected to the right reservoir. The main concern for this study is for all injectors that located along the thrust fault boundary. The main focus of this study was to make a robust interpretation for thrust fault outline and the subsurface location of injector and producer well trajectory along the fault surface.
This is a problem occurring in some injectors in the Pelana Field, where the injection is not evenly distributed vertically so that the topmost reservoir, which also has the poorest quality with permeability of around 100 mD, does not receive enough injection to balance its production. Most of the injected water goes to MN_XX sand which has permeability of about 1000 md. Injector PL-55, for instance, injects into both sands to support the production from both reservoirs. However, the previous completion uses only open ended tubing and therefore, based on the spinner result, the water will be distributed naturally based on the well-to-reservoir pressure difference, being directly affected by reservoir permeability. This practice resulted in an unbalanced performance for both sands. While MN_XX has a good sweep efficiency with recovery factor (RF) increment > 8%, the BK_AA sand would has an opportunity to be optimized due to its current low incremental of RF.
Side Pocket Mandrel has been chosen to resolve the vertical distribution problem in PL-55 and improve the injection rate into BK_AA sand. It is observed that the well can finally split its injection into more desirable allocation, allowing more water to flow into BK_AA sand. This paper presents the application of this technology in PL-55 well, including the technology principles, the tool design, the strategy to improve the injection distribution and the enhanced performance to the surrounding producers.
Recoverable oil down-structure in the ESE flank is not because of structural or stratigraphic compartmentalization but rather due to isolation of oil as a local result of peripheral water injection. Borehole image data from a directional infill well shows no fault indication as indicated in 3-D seismic cube. Reservoir pressure data in X Sand shows high pressure ranges from 420 to 750 psi up from initial pressure of 200 psi which indicates reservoir connectivity to the peripheral injectors. Well-to-well correlation shows flexure oil-water-contact with draping oil pay thickness ranges from 15 to 20 feet.
Discovery of the flexure oil trapped below the peripheral water injection level BK has led to the conclusion that classic piston-like waterflood displacement might not be a suitable approach since the calculated Dietz flood front angle approximation is –1.57 degree (< 0 degree). Gravity force with strong water-drive mechanism and low structure angle (1 to 3 degree) in the ESE flank are much stronger influences as compared either to mobility contrast or to rock heterogeneity that made the flexure oil trap in X Sand. Therefore, injector placement strategy and injector to producer alignment prioritization are critical factors for maximizing and improving oil recovery in the flank structure.