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Collaborating Authors
Results
Abstract The Viking reservoirs of west-central Saskatchewan contain a large number of light oil resources, of which only approximately 10% is considered recoverable. Oil production is hindered by (a) permeability damage due to clay swelling and migration during water injection and (b) organic solid (asphaltenes/wax) precipitation due to pressure and temperature variations. The Saskatchewan Research Council conducted laboratory experiments to evaluate and address these problems. Reservoir cores were tested for permeability damage measurements using both injection and produced brine. Different additives [i.e., potassium chloride (KCl) with/without hydrochloric acid (HCl), commercial clay stabilizers, liquid CO2, and isopropyl alcohol] were assessed as permeability remedies. The results showed that injection brine caused greater permeability damage than produced brine. KCl solutions preserved permeability, whereas KCl acidized with HCl appreciably improved it in one core. None of the used commercial additives significantly improved permeability. Injection of liquid CO2 and isopropyl alcohol caused encouraging permeability improvement in some cores. Wax precipitation tests were carried out on both dead oil and live oil samples. It was found that precipitation occurred in the dead oil even at the reservoir temperature of 22 °C. Filtration tests demonstrated that the live oil was much less sensitive to wax precipitation than the dead oil. Introduction The Viking horizon of the Kindersley area of west-central Saskatchewan contains an estimated 300?10 m initial oil in place (IOIP), of which only about 10% is deemed to be recoverable. The Saskatchewan Research Council (SRC) carried out an experimental study aimed at evaluating and solving two major problems that hinder effective oil production in the Viking reservoirs of west-central Saskatchewan: permeability damage due to water sensitivity of the formation and organic solid precipitation due to pressure and temperature change. Most of the Viking oil reservoirs are thin, with net pays from 2.0 to 5.4 m, and produce from depths between 640 and 750 m. The reservoir temperatures are around 23 °C, and the discovery pressures are approximately 6.4 MPa. The oil generally has densities between 840 and 870 m/kg (37- 31 °API) and formation volume factors of about 1.1 m/m. Figure 1 shows a detailed map of well locations in Kindersley area in Saskatchewan. It is seen that most of the wells produce oil at rates below 1 m/d (yellow), whereas a number of wells produce more than 10 m/d (black). The Viking reservoirs are sandstone of Lower Cretaceous age that was deposited in a shallow marine environment. The reservoir rocks have variable lithology, and are from mid- to poorly consolidated and contain movable and swelling clays, such as kaolinite and montmorillonite. Due to the presence of these clays, the formation is sensitive to fresh water and this has hampered efforts to improve oil recovery by waterflooding. Organic (waxes and/or asphaltenes) solid precipitation is another major factor hindering oil production. This solid removal is costly because it requires periodic workovers as well as disruption to well flow. Consequently, productivity will be greatly improved if these two problems are alleviated or solved.
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin > Viking Formation (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin > Eureka Field > Viking Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Viking Formation (0.99)
- Well Drilling > Formation Damage (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
Abstract Phase behaviour and minimum miscibility pressure measurements were carried out to evaluate the potential of applying miscible CO2S/H2S flooding in Zama reefs of NE Alberta, Canada. Since there is some variability in the properties of oils from different wells or reefs, the measurements were carried out on recombined reservoir fluids from two different wells. The injection solvent will be supplied from a nearby gas plant that is expected to produce CO2S/H2S streams with a range of compositions due to a number of operational factors. Accordingly, three solvent injection gases were considered: pure CO2S, and CO2S containing 20 and 40 mol% H2S. Minimum miscibility pressure (MMP) measurements were carried out using the rising bubble apparatus (RBA). The MMP decreased almost linearly with the amount of H2S in the injection gas in the range of compositions studied. Some evidence of precipitation of solids was observed. Measurements were also carried out to determine the CO2S MMP of these reservoir fluids as they were depleted of gas through a differential liberation procedure. The results show that the MMP decreased with decreasing liberation pressure. Key properties of the liberated reservoir fluids were also measured and compared with those of the recombined reservoir fluids. The results show that miscible flooding with sour acid gas is feasible in this case, and could provide an excellent means of storing/sequestering these gases while improving oil recovery. Introduction Vertical gas floods have an excellent track record for producing additional oil. For example, hydrocarbon miscible floods have been carried out in a number of Canadian reefs. Vertical gravity-stable carbon dioxide floods were reported in three US fields, also with excellent additional oil recoveries. The Zama Field9 is located in northeastern Alberta and contains a large number (600–800) of relatively small pinnacle reefs with up to 1.5*10 m (10 mmbbl) of original oil in place. The wells selected for this study produce from the Keg River formation. Al-Dliwe and Asghari10 described the reservoir and its production history from the 1960s. The produced oil and gas are sour and contain an appreciable amount of carbon dioxide. The centrally located Zama Gas Plant (operated by Apache Canada Ltd.) removes the H2S and CO2S from the produced gases by amine absorption. These acid gases constitute an excellent miscible flooding agent for the field, thereby achieving the double advantage of increasing the oil recovery and providing storage capacity for these gases. Trivedi et al. simulated different strategies for solvent injection to maximize oil recovery and gas storage as well as delaying breakthrough, and found that pressure maintenance is a key factor in the operation. A significant degree of acid gas breakthrough is expected to occur due to the reservoir heterogeneity represented by these Zama/Keg River pinnacles. Breakthrough will occur at H2S concentrations that are too high to process through the existing amine systems. To accommodate early breakthrough, recycle compression is to be installed in order to bypass the amine systems and re-inject acid gas back into miscible flooded pinnacles.
- North America > Canada > Alberta (1.00)
- North America > United States > Texas (0.68)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Arabian Gulf (0.24)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Montana > Rainbow Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Eugene Island > Block 193 > Bay St. Elaine Field (0.99)
- North America > United States > California > Sacramento Basin > 3 Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Zama Virgo Basin > Zama Field > Keg River Formation (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
Abstract As heavy oil begins to overtake conventional oil in western Canada's energy supply, it becomes increasingly urgent to address the greater technical challenges posed by enhanced heavy oil recovery. This study investigates the technical feasibility of using CO2and enriched flue gas in an immiscible water-alternating-gas (WAG) injection process in those heavy oil reservoirs for which thermal recovery methods are likely to be uneconomic. In addition to phase behaviour and fluid property measurements of CO2, N2, and an enriched flue gas mixed with a heavy crude oil (12.4 ° API), this study focused on coreflooding tests of immiscible WAG injection at reservoir conditions.Additional tertiary recoveries of around 6% initial oil in place were obtained. The results indicate that N2 in the enriched flue gas (i.e., 70% N2 + 30% CO2) did not have a detrimental effect on oil recovery. Addition of a foaming agent with the injected CO2 was also beneficial. The phase behaviour measurements indicate that the viscosity reduction mechanism of a conventional immiscible injection process cannot alone account for the results obtained in the laboratory corefloods. Additional mechanisms are suggested for oil recovery and water blocking by free gas.The analysis discussed in this paper seeks to establish a better understanding of the possible mechanisms involved in the heavy oil immiscible gas flood process, and thereby improve oil recovery performance. Introduction Heavy oils are playing an increasingly important role in supplying Canada's energy needs, as global energy consumption escalates and conventional oil resources shrink. However, enhanced recovery of the vast heavy oil resource in west-central Saskatchewan faces greater technical challenges than do light oils. Heavy oil in this area is not only very viscous, but is also located in thin and shallow formations. The study discussed here investigated the technical feasibility of using CO2 and enriched flue gas in a water-alternating-gas injection process to enhance recovery from those heavy oil reservoirs for which thermal recovery methods are likely to be uneconomic. Heavy oil reservoirs in west-central Saskatchewan typically have low reservoir pressures; miscibility between the oil and injected solvent gases, such as CO2, cannot be achieved. Immiscible gas injection appears to be a practical enhanced oil recovery (EOR) method for these heavy oil reservoirs. In an mmiscible water-alternating-gas process, gas and water are alternately injected: the water following gas injection drives the reduced-viscosity oil, resulting in displacement with an improved mobility ratio. In addition to reducing viscosity, the dissolved gas also swells the oil so that, for a given fixed residual oil saturation, less oil remains after a waterflood. These two mechanisms have been demonstrated by numerous laboratory phase behaviour studies, coreflood tests and simulations.1–5 Analysis of results from a tertiary CO2 injection field test revealed that incremental oil production by immiscible CO2 injection has two components. The first is an instantaneous response, probably resulting from gas displacing oil that was not being displaced by water. The second component is the long-term effect caused by viscosity reduction, swelling, and relative permeability alteration.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.50)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)