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Collaborating Authors
Results
Abstract Alberta (Canada) has the third largest proven reserves of oil in the world, mostly comprised of bitumen and heavy oil. To date, Steam Assisted Gravity Drainage (SAGD) has been the only commercially viablein-situ recovery technology for the Athabasca Oil Sands, but the current economic conditions have made the SAGD technology challenging, even for some high quality reservoirs. Moreover, from an environmental perspective, large water usage and high carbon emissions also make SAGD difficult to sustain. Due to the current low oil prices and rising penalties on carbon emissions, there is a need to develop improved recovery technologies that are more thermally efficient, with reduced environmental impact and at the same time economically feasible to develop. One of the technologies that has the potential to overcome these economic and environmental shortcomings is a hybrid steam and in-situ combustion process (ISC) called SAGDOX, as this process offers advantages over pure steam injection such as greater energy efficiency, lower water usage and reduced carbon emissions. The SAGDOX (SAGD and Oxygen Injection) process, which is proprietary to Nexen (Kerr, 2015), combines the benefits of both SAGD and ISC processes. Steam is used to preheat and pre-condition the reservoir, also aiding in carrying heat from the combustion zone towards the rich oil saturation zone. One of the main advantages of SAGDOX is the elimination of most of the nitrogen that otherwise would be injected when using air and this reduces the amount of non-condensable gas (NCG) in the reservoir substantially. Heat delivery to the formation using a combination of steam and enriched air injection is more energy efficient than pure steam injection and reduces the steam-oil ratio compared to SAGD. This also lowers the volumes of steam condensate in the produced fluids and thus reduces the produced water handling and processing requirements. The purpose of this study is to provide data to evaluate the feasibility of the SAGDOX process using a 3-D laboratory physical model. A description of the physical model is provided along with the method of operation. The results from two tests are presented and the findings from the experimental studies are also discussed.
Abstract The aim of this work is to evaluate the micro-displacement mechanisms associated with heavy oil recovery by water and chemical flooding in a non-linear system (2D Model). To evaluate the effect of sweep efficiency improvements with no local pore level trapping of fluids, a 2D neutral water wet Hele-Shaw cell is used to visualize the dominant mechanisms of surfactant, polymer and their combinations to enhance heavy oil recovery. Waterfloods were conducted as a base line, and compared to surfactant, polymer and SP floods at different injection stages (secondary and tertiary) and under variable injection rates. Post-breakthrough oil recovery and pressure drop during the water flood and chemical flood were evaluated with the analysis of images which show the distribution of the fluids in the cell. The results demonstrated that in waterflooding, oil pinches off the pre-formed water fingers and allows the formation of snap-off which divert further water to un-swept zones. Oil is produced discontinuously because of snap-off effects, with production of oil related to small pressure spikes in the system. This mechanism was also observed in polymer displacements. This observation can explain viscous flow of oil and discontinuous oil and water production after breakthrough in a heavy oil waterflood. Oil stripping and zones of low IFT, in the form of O/W emulsions were mechanisms observed in surfactant and SP flooding. Such emulsions are present in secondary fingers that then propagate and sweep new areas of the cell. The synergy between polymer and surfactant leads to a slightly better sweep efficiency in the cell by stripping oil and stabilizing the flood front compared to surfactant or polymer alone. Injection rate has also an impact in the flow stability and formation and flow of emulsions. At higher injection rates, flow is more unstable and leads to a less oil recovery. Multiple tests under the same conditions revealed the reproducibility levels of each displacement process. The novelty of this study is that it provides insights into fluid flow behavior in diverging flow paths as observed in 2D systems, as opposed to linear core floods that have limited flow pathways. In particular, these visual observations help to illustrate the role that surfactants can play in heavy oil systems, with and without the addition of polymer.
- Research Report > Experimental Study (0.93)
- Research Report > New Finding (0.67)
Abstract Steam-assisted gravity drainage (SAGD) is the method of choice to extract bitumen from Athabasca oil sand reservoirs in Western Canada. Bitumen at reservoir condition is immobile due to high viscosity and its saturation is typically large that limits the injectivity of a steam at in-situ condition. In a current industry practice, steam is circulated within injection and production wells. In theory wells, should be converted to SAGD production mode once bitumen at interval is mobile and communication is established between the injector and the producer. Operators try to use temperature fall-off data to predict successful conversion time. Although the bitumen heating sounds simple approach recently three wells fails after steam injection due to steam break-through or sand production. And they are periodically returned to circulation to ramp up production rates and heal the hot spots. Most such failures are associated with early conversion to full SAGD. This paper presents a method to describe physics based initial steam injection timing and describes different Suncor assets viscosity variation with temperature and a proper interval temperature for initiation of steam injection in SAGD process. In this study an analytical tool is developed using time-of-flight (ToF) concept to match the temperature fall-off data. The tool is used to discuss successful and failed cases in Suncor McKay River asset.
Abstract Recently, coupled electromagnetic-reservoir simulators based on full numerical schemes have been developed using commercial software packages. However, simplified analytical and semi-analytical models can provide useful and quick insight of the complicated coupling between radio wave propagation and transport phenomena in heavy oil reservoirs. In this study, we developed simplified coupled EM-thermal models to emphasize on two important aspects of radio frequency heating process, near-field analysis and insulated antenna setups. It will be shown how much thermal error can be introduced when a proper full-wave analysis is not taken into account. We will also demonstrate the thermal advantage of applying an insulated antenna over a bare antenna when radio waves are used for heating purposes. Another key aspect of radio-frequency heating process is to consider dependency of electrical properties to thermal and water saturation conditions. This one is more difficult to verify analytically and it will be done in the second part of this study.
Lessons Learned from Extending Run Life for Hundreds of ESPs in a Heavy Oil Environment
Mogollon, M.. (Frontera Energy) | Arguelles, A.. (Frontera Energy) | Rodriguez, A.. (Frontera Energy) | Anaya, O.. (Ecopetrol) | Miranda, S.. (Schlumberger) | Velasquez, E.. (Schlumberger) | Villalobos, J.. (Schlumberger)
Abstract Electric submersible pump (ESP) applications with heavy oil pose substantial technical challenges: decreased pump head capacity, increased power requirements, and poor cooling capacity. This paper shares experiences, lessons learned, equipment standardization exercises, and improvements performed in a field with heavy oil (13º API to 15ºAPI) to extend mean time between failures (MTBF) in more than 3,000 days in a high ESP population with an average of 500 wells. To achieve production goals and extend ESP run life, the project tracks five elements of the ESP life cycle: design, optimization, failure analysis, monitoring, and equipment standardization. As the field evolved, ESPs faced the challenges such as: increased production with increasing water cuts to higher flow rates in horizontal completions with high dogleg severity. Chronological performance of pump mean time between failure is shown before and after improvements. The ESP lifecycle is used as the basis to analyze several factors that caused either total system failure or inability to meet production expectations. This paper explains the implications of each factor and how they affect ESP components, through case studies of representative or repetitive failures and examples of how they were remediating without incurring the expense of oversizing the ESP equipment or completion. This paper shares lessons learned in a five-year, dynamic heavy oil project and includes practical tools to improve ESP run life and optimize well production, which are applicable across the industry and around the world.
- Asia (0.68)
- South America > Colombia > Meta Department (0.29)
- North America > United States > Texas (0.28)
- South America > Colombia > Meta Department > Llanos Basin > Rubiales Field (0.99)
- Oceania > Australia > South Australia > Cooper Eromanga Basin > Moomba Field > Toolachee Formation (0.99)
- Oceania > Australia > South Australia > Cooper Eromanga Basin > Moomba Field > Daralingie Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
- Management > Professionalism, Training, and Education (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract Co-injection of CO2 or light hydrocarbons with steam in the SAGD process may improve SAGD efficiency and lead to lower greenhouse gas emissions through reduced Steam Oil Ratios (SORs). Various additives are postulated to have differing effects on bitumen recovery, depending on the nature of the reservoir, the operating conditions, and the API gravity of the oil. A PVT study was conducted to investigate the phase behaviour of CO2-, C3-, and C4-bitumen systems at varying concentrations, representing the edge of a SAP steam chamber with the expected temperature range of 70°C to 160°C. A produced and dewatered bitumen sample was collected from the Cenovus Osprey Pilot in the Cold Lake oil sands region and characterized. Constant Composition Expansion (CCE) experiments were conducted on solvent-bitumen systems in the temperature range of 70°C to 160°C. Filtration tests were also conducted at high temperature and reservoir pressure to investigate the effect of solvent type and concentration on asphaltene precipitation. A Peng-Robinson Equation of State (PR-EOS) model was calibrated to measured data for CO2-, C3-, and C4-bitumen systems. Viscosity of the bitumen saturated with CO2, C3, and C4 was measured with an electromagnetic-based viscometer elevated temperatures. Phase equilibrium calculations were performed using the calibrated EOS to predict the solubility of the solvents in bitumen. A correlation was fitted to the measured viscosity data to predict the liquid phase viscosity as a function of solvent solubility and temperature for each solvent. From the CCE tests, two equilibrium phases (i.e., liquid and vapour) were observed for the C3- and CO2-bitumen systems. Three equilibrium phases were observed for the C4-bitumen system at high C4 concentrations. These three phases include a bitumen-rich heavy oil phase, a solvent-rich lighter oil phase, and a vapour phase. Due to the extracting/condensing mechanism and asphaltene precipitation, the bitumen-rich phase formed in C3-bitumen system was lighter than the one in C4-bitumen system. Filtration tests showed more asphaltene precipitation by C3 and C4 dissolution than CO2. Moreover, C3 has more potential for asphaltene precipitation than C4. Viscosity measurements showed that dissolution of C3 and C4 in bitumen resulted in greater viscosity reduction than CO2 dissolution. This difference was more pronounced at lower temperatures. The highest C4 solubility in bitumen and C4 potential for forming a C4-rich liquid phase showed stronger condensing and extracting effect of C4 than C3 and CO2 in solvent-bitumen interactions. Moreover, C4 lead to more bitumen swelling than C3 and CO2. EOS predictions and viscosity measurements indicated that increasing the solvent concentration in a solvent-bitumen system beyond a defined Threshold Solvent Concentration (TSC) has an insignificant effect on solvent solubility and bitumen viscosity reduction.
- North America > United States (1.00)
- North America > Canada > Alberta (0.67)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Middle East > Turkey > Bati Raman Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Cold Lake Oil Sands Project > Clearwater Formation (0.98)
Nanoparticle Stabilized Solvent-Based Emulsion for Enhanced Heavy Oil Recovery
Kumar, Ganesh (Indian Institute of Technology Madras) | Kakati, Abhijit (Indian Institute of Technology Madras) | Mani, Ethayaraja (Indian Institute of Technology Madras) | Sangwai, Jitendra Shital (Indian Institute of Technology Madras)
Abstract The objective of this study is to develop a solvent-based Pickering emulsion stabilized by silica nanoparticle for enhanced heavy oil recovery. Unlike the light oil, the recovery of heavy oil is quite challenging because of its high viscosity. To reduce the viscosity of heavy crude oil, solvent-based Pickering emulsion is explored to improve the recovery of heavy oil. The approach is to use solvent-in-water emulsion stabilized by nanoparticle which is more economical as compared to thermal or solvent-based enhanced oil recovery (EOR) methods. In this work, the solvent-in-water Pickering emulsion has been prepared by homogenizing the mixture with the help of homogenizer at 13000 rpm for 3 minutes. It can be inferred from the experimental results that the use of nanoparticle has helped to improve the stability of solvent-based Pickering emulsion for a longer period of time as compared to conventional surfactant based emulsions due to irreversible adsorption of silica nanoparticle at the oil-water interface. The silica nanoparticle of 15 nm size is used to make the Pickering emulsion. The colloidal stability and surface charge of the nanoparticle is evaluated by zeta potential. Silica nanoparticle is expected to improve the rheological stability of solvent-based emulsion and provides favorable mobility. Hence, these solvent-based emulsion flooding can provide high displacement efficiencies like miscible solvent flooding and better sweep efficiency like polymer flooding and helps to improve the enhanced heavy oil recovery. The novelty of the nanoparticle stabilized solvent-based Pickering emulsion is that it can sustain harsh reservoir conditions and remains very stable for a longer period of time as compared to other EOR techniques. The droplet size of these emulsions is few micron in size so that it can easily flow through the pore throat size of the formation reservoir and helps in improving the enhanced heavy oil recovery.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract SAGD is an energy-intensive process with large amount of greenhouse gas (GHG) emissions and required water treatment. One option to reduce emissions and water is to use electromagnetic (EM) heating in either the induction (medium frequency) or radio frequency (RF) ranges. Since the early 1970s, research into the use of RF energy to effectively heat heavy oil reservoirs has led to incremental technology advancements. Since 2009, the Effective Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH™, pronounced "easy") consortium suggested a process named similarly that dielectric heating of oil sand is combined with the injection of a solvent such as propane or butane to reduce bitumen viscosity. In January 2012, the mine face test was declared a success and confirmed the ability to generate, propagate, and distribute electromagnetic heat in an oil sand formation. Phase II of ESEIEH™ exploring scaled pilot tests with horizontal antenna in Suncor’s Dover facility is under developing. To distribute electromagnetic heating into the reservoir creation of desiccated zone and its controlled growth is a key. Since the reservoir is an electrically lossy environment, the growth of desiccated zone as a lossless medium helps the electromagnetic fields to propagate deeper into the formation and associated heating is also further developed within the reservoir. The water will continue to vaporize and move away from the "flashed or desiccated zone" at a rate which diminishes with time. Eventually it reaches the equilibrium condition that it cannot grow with given delivered RF power from the radiating antenna. In this study, the desiccated zone extension at its equilibrium is calculated on the basis of this concept to prevent the zone from collapsing. In this process, water should vaporize and leaks into reservoir to create the flow rate normal to the desiccated zone surface that pushes the water back and grow the zone. Another highlight on this study is to provide the solution for RF-heating avoiding the Lambert’s law or plane-wave assumption. Lambert’s law is (only) accurate and valid in guided-microwave structures or when the EM radiating source is far from the receiving load (relative to the wavelength), such as in optical regime or in telecommunication applications. Although, for heating applications, the maximum energy dissipation of RF waves takes place in the near-field region and not in the far-field region, hence, Lambert’s law does not give a correct solution in these cases. As a result of this study minimum required power is a function of reservoir mobility or in-situ water relative permeability. If efficiency of antenna is not high enough and reservoir mobility is greater than 10 then the RF power transmission system could not deliver enough energy to grow the desiccated zone.
- North America > United States (1.00)
- North America > Canada > Alberta > Athabasca Oil Sands (0.28)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > North Steepbank Mine (0.99)
- Africa > South Africa > Western Cape Province > Indian Ocean > Bredasdorp Basin > Block 9 > EM Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Clearwater Formation (0.98)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Health, Safety, Environment & Sustainability > Environment (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Abstract … And expecting different results. Electrical heating of oil reservoirs has fascinated petroleum engineers for more than 70 years - longer, if you include the use of heaters in Siberian oilfields. The earliest laboratory study was done in Pennsylvania in 1940's. Since then, many more studies and field tests have been carried out, none of which was a commercial success. This paper takes a look at different forms of electrical heating, the supporting theoretical work, and field tests. Additionally, several examples are given illustrating the limitations of electrical heating processes. Also discussed is the logic behind the resurgence of electrical heating in recent years. Not discussed are over 200 patents on electrical heating. The major electrical heating processes are resistance heating, using direct current or low frequency alternating current, induction heating, microwave heating, and heating by means of electrical heaters. These are described briefly, and compared. In applications to oil sands, the intent is to utilize the connate water as the heating element (resistance heating) or oil sands as the dielectric (microwave heating). Induction heating is much less effective but has been tested in many field projects. Shale that has a permeability of zero to fluid flow, is electrically conductive, and thus channels much of the electric current flow in resistance heating, which also has other limitations. Microwaves suffer from low depth of penetration (of the order of 20 cm in oil sands) and low power delivery (of the order of 1 MW as a maximum). The power requirements for a typical SAGD pair, in contrast, are 15-30 MW. Electric heaters have been used in oilfields for many years for near-wellbore heating. Two large field pilots used powerful electric heaters, and were recently shut down. Although electrical heating has not had commercial success, recently there has been a resurgence in various electrical processes, as a means of reducing GHG emissions, under the flawed logic that oilfield use of electricity would displace emissions caused by steam generation.
- South America (1.00)
- North America > United States (1.00)
- North America > Canada > Alberta > Athabasca Oil Sands (0.28)
- Europe > United Kingdom > North Sea > Central North Sea (0.24)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- South America > Colombia > Llanos Basin (0.99)
- South America > Brazil > Rio Grande do Norte > South Atlantic Ocean > Potiguar Basin (0.99)
- North America > United States > Texas > Permian Basin > Central Basin > Dover Field > Strawn Formation (0.99)
- (6 more...)
Abstract Cyclic solvent injection (CSI) is a promising technology for enhanced production of heavy oil in post-CHOPS (Cold Heavy Oil Production with Sand) fields. The first stage of a CSI cycle involves the injection of solvent vapour, which re-energizes the reservoir and dissolves into oil, reducing its viscosity. The second stage of a CSI cycle involves dropping the pressure to flow the solvent-diluted oil back to the well. This is the solvent analog to cyclic steam stimulation (CSS). A key difference between solvent and steam is that the heat from steam stays in the oil even during production, while in solvent-diluted oil, if solvent comes out of solution as pressure drops, oil viscosity will increase again and one of the main benefits of the solvent will be lost. Solvent selection in CSI needs to consider which solvents have non-equilibrium properties, specifically delayed release during pressure depletion. This study presents a set of low field nuclear magnetic resonance (NMR) tests that were run on a 3,370 mPa·s viscosity heavy oil and several solvents: methane-propane and methane-CO2. NMR measures the relaxation rate of protons in the presence of magnetic fields. When fluid viscosity decreases, the fluid signal relaxes more slowly. A properly calibrated NMR model can be used to measure the viscosity of the liquid phase in a solvent-oil mixture as pressure drops and gas leaves solution. This approach does not require flow, and can also be used to measure the in-situ viscosity of oil in the sand. Tests were run using methane-CO2 solvents with varying CO2 concentration to study the impact of live oil viscosity on the rate of solvent release. For lower initial live oil viscosity, the solvent is able to more quickly leave solution from the oil. Additional tests run using a methane-propane solvent demonstrate the impact of varying solvent type for the same initial solution viscosity. Both CO2 and propane show significant non-equilibrium solvent release during depletion. Measurements of non-equilibrium solvent release from oil are an important piece in the understanding and modeling of heavy oil CSI. Equilibrium PVT data shows how different solvents can affect heavy oil systems, but the non-equilibrium solvent release is crucial for these solvents to work as recovery agents in the field. The results presented in this study provide useful data for CO2 and propane as potential CSI solvents, and help in the understanding of the role of viscosity vs. solvent type in the diluted oil response.
- North America > Canada > Alberta (0.29)
- North America > United States > Wyoming > Campbell County (0.24)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Steam-solvent combination methods (1.00)
- (3 more...)