Transcript
Surfactant Flooding: (Chemical Recovery Methods) Typically, it is a multiple-slug process involving the addition of surface-active chemicals to water. These chemicals reduce the capillary forces that trap the oil in the pores of the rock. The surfactants slug thus displaces oil forming ahead a flowing oil-water bank. Interfacial properties, slug mobility relative to that of the oil-water bank, slug integrity in the reservoir, and cost influence the design of this method. A slug of water containing polymer in solution follows the surfactant slug. The polymer solution preserves the integrity of the more costly surfactant slug and increases the sweep efficiency. The viscosity of polymer solution is adjusted to obtain a favorable mobility ratio. The polymer solution is then followed by injection of drive water, which continues until the project is completed. Multi-slug process (picture on slide 2) Microemulsion Flooding: (Chemical Recovery Methods) Microemulsion on micellar solution is a concentrated, surfactant-stabilized dispersion of water and hydrocarbons. It is homogeneous, transparent or translucent, and stable to phase separation. At concentrations above a certain critical value, the surfactant molecules in solution from aggregates (sized 106-104 mm) called micelles. These micelles are capable of solubilizing fluids in their cores and are called swollen micelles. In one method, a relatively low-concentration (2-4 wt.%) surfactant microemulsion is injected at large pore volumes of 15% to 60% to reduce the interfacial tension between the water and oil, thereby increasing oil recovery. In another method, a relatively small pore volume, from 3% to 20%, of a high-concentration (8-12 wt.%) surfactant microemulsion is injected. With the high surfactant concentration, the micelles solubilize the oil and water similar to miscible flooding. As the high-concentration slug moves through the reservoir, it is diluted by the formation fluids, and the process ultimately or gradually reverts to a low-concentration flood. The mobility buffer following the microemulsion slug prevents rapid slug deterioration from the rear and thus minimizes the slug size required for efficient oil displacement. Polymer Flooding: (Chemical Recovery Methods) This method involves the injection of polymeric additives with water to improve the areal and vertical sweep efficiencies of the reservoir by increasing the viscosity and decreasing the mobility of the water injected. The polymer solution affects the relative flow rates of oil and water and contacts more oil and moves it to production wells. Polymers currently in use are produced both synthetically (polyacrylamides) and biologically (polysaccharides) Polymer Flooding (Picture on slide 8) Polymer flooding has its greatest utility in heterogeneous reservoirs and those that contain moderately viscous oils. Oil reservoirs with adverse waterflood mobility ratios have a potential for increased oil recovery through better horizontal sweep efficiency. Heterogeneous reservoirs may respond favorably as a result of improved vertical sweep efficiency. Oxygen contamination can lower the screen factor of polyacrylamide solutions by as much as 30%. Sodium hydrosulfite in low concentrations is an effective oxygen collector for polyacrylamide solutions. Therefore, the proper use of sodium hydrosulfite is imperative to avoid severe polymer degradation. Alkaline Flooding: (Chemical Recovery Methods) This method uses aqueous solutions of sodium hydroxide, sodium silicate, and sodium carbonate that are strongly alkaline. These solutions react with constituents present in some crude oils or present at the rock/crude oil interface to form detergent-like materials, which reduce the ability of the formation to retain the oil. These chemicals enhance oil recovery by one or more of the following mechanisms: interfacial tension reduction, spontaneous emulsification, or wettability alteration. These mechanisms rely on the in situ formation of surfactants during the neutralization of petroleum acids in the crude oil by the alkaline chemicals in the displacing fluids. Sometimes polymer is included as an ancillary mobility control chemical in alkaline flooding to augment any mobility ratio improvements due to alkaline-generated emulsions. Other variations on this theme include the use of steam and the means of reducing interfacial tension by the use of various solvents. Chops: Chops is cold heavy oil production with sand, which is used in unconsolidated sandstone reservoirs (i.e., with movable sand). It is a Canadian discovery that encouraging sand production by removing sand filters from oil wells can enhance oil production. Snd is introduced to the well bore by aggressive perforation and swabbing in vertical or inclined wells. No heat is introduced; hence the method is called “cold.” A downhole pump is used to create a large pressure difference between the formation and wellbore. Tis forms high-permeability channels (wormholes) in the adjacent low-cohesive-strength sands,which facilitates oil to flow as foam due to solution gas drive. CHOPS results in improved reservoir access and enhanced permeability. As more sand is produced, a growing zone of greater permeability is generated, similar to a arge-radius well, which gives better production. CHOPS yields higher oil production, 12-25% of the OOIP over typical 5% in primary production without sand. Gas produced with oil does not form a continuous gas phase but flows as bubbles in oil. Gas bubbles do not coalesce but expand moving forward to production, generating an internal as drive termed as foamy flow. Foamy flow helps to locally destabilize the sand and sustains production. Gas bubbles evolving at the wormhole-sand interface destabilize sand grains. The expanding gas helps move the mixture through the wormholes. Gravity drive on the unconsolidated sands also provides energy for production. Continuous sand production means that asphaltene or fines plugging of the near-well-bore environment potentially do not occur, so there is no possibility of an effect to impair productivity. As sand is removed, the overburden weight acts to shear and destabilize the sand, helping to drive sand and oil toward the well bore. Sand handling and disposal is a major issue with CHOPS. Pressure Pulse Technology (PPT): PPT relies on large-amplitude pressure pulses, which are porosity dilation waves that displace reservoir fluids. Pulses at velocity 40-80 m/s and low frequency (15/minute), expand and contract the pores, thereby move reservoir liquids in and out of pores. This helps unblock pore throats, increase the velocity of liquid flow, overcome capillary blockages, and reduce some of the negative effects such as viscous fingering. PPT is effective in reservoirs having elastic properties, such as unconsolidated sediments and sedimentary rocks. PPT applied for five to 30 hours to a blocked producing well ca reestablish economic production in a CHOPS well for many months, even years. PPT applied to injector wells improves the efficiency of water flood patterns and help increase oil production. Microbial Enhanced Oil Recovery (MEOR): MEOR methods involve the use of bacteria in reservoirs to produce metabolic events that lead to enhanced oil recovery. MEOR depends on physico-chemical properties of the reservoir in terms of salinity, pH, temperature, pressure, and nutrient availability. Conditions for microbial metabolism are supported via injection of nutrients. Sometimes, fermentable carbohydrates are injected into the reservoir. Some reservoirs also require inorganic nutrients as substrates for cellular growth or to serve as alternative electron acceptors in place of oxygen or carbohydrates. Bacteria produce a variety of fermentation products such as carbon dioxide, methane, hydrogen, bio-surfactants, and hydrocarbons. Organic acids produced through fermentation readily dissolve carbonates and can greatly enhance permeability in limestone reservoirs. However, certain bacteria produce H2S, which can corrode pipeline and other components of the recovery equipment. In cyclic MEOR, a solution of nutrients and microorganism are injected into the reservoir. The injection well is shut for an incubation period to allow the microorganisms to produce carbon dioxide gas and surfactants that assist in mobilization of the oil. The well is then opened, and oil and oil products resulting from the treatment are produced. The process is repeated. In oil recovery by microbial flooding, the reservoir is usually conditioned by a water flush, and a solution of microorganisms and nutrients is injected into the formation. As this solution is pushed through the reservoir by water drive, gases and surfactants are formed, and the oil is mobilized and pumped through the well. Various Effects: (Microbial enhanced oil recovery, MEOR) Improvement of the relative mobility of oil to water by biosurfactants and biopolymers. Partial repressurization of the reservoir by methane and carbon dioxide. Reduction of oil viscosity through the dissolution of organic solvents in the oil phase. Increase of reservoir permeability and widening of the fissures and channels through the etching of carbonaceous rocks in limestone reservoirs by organic acids produced by anaerobic bacteria. Steam-Assisted Gravity Drainage (SAGD): This method involves drilling two parallel horizontal wells, one above the other, along the reservoir itself. The top well is used to introduce hot steam into the oil sands. The heat reduces the oil viscosity to values as low as 1 to 10 centipoises (depending on temperature and initial conditions) and develops a steam chamber that grows vertically and laterally. SAGD process diagram (slide 32) The steam and gases rise because of their low density, and the oil and condensed water are removed through the lower well. As the heavy oil thins and separates from the sand, gravity causes it to drain into the lower well, from where it is pumped to the surface for processing. The gases produced during SAGD tend to be methane, with some carbon dioxide and traces of hydrogen sulfide. Even though the injection and production wells can be very close (5-7 m), the steam-saturated zone (steam chamber) rises to the top of the reservoir, expands gradually sideways, and eventually allows drainage from a very large area. The method is claimed to significantly improve heavy oil recovery by between 50-60% of the OOIP and is therefore more efficient than most other thermal recovery methods. Operating the production and injection wells at approximately the same pressure as the reservoir eliminates viscous fingering and coning processes and also suppresses water influx or oil loss through permeable streaks. This keeps the steam chamber interface relatively sharp, and reduces heat losses considerably. Injection pressures are much lower than the fracture gradient, which means very low chances of breaking into a thief zone. SAGD is extremely stable since it relies on gravity, not on pressure drive, which causes instabilities such as channeling, coning, or fracturing. It is vital to maintain a volume balance, replacing each unit of oil produced with a unit volume of steam injected. If bottom-water influx develops, it indicates that the water pressure is larger than steam pressure and steps must be taken to balance and pressures. Because it is not possible to reduce the pressure in the water zone, the pressure in the steam chamber and production well region must be increased. This is achieved by increasing the operating pressure of the steam chamber through the injection rate of steam or through reduction of the production rate from the lower well. Also, a low pressure gradient between the bottom water and the production well must be sustained. If pressure starts to build up in the steam chamber then loss of hot water can take place as well. In such cases, the steam chamber pressure must be reduced and perhaps the production rate must be increased slightly to balance the pressures. SAGD seems to be relatively insensitive to shale streaks and similar horizontal barriers (even up to several meters) that otherwise would restrict vertical flow rates. This occurs because as the rock is heated, differential thermal expansion causes the shale to be placed under tensile stress, and vertical fractures are created, which serve as conduits for steam (up) and liquids (down). As high temperatures hit the shale, the kinetic energy in the water increases, and adsorbed water on clay particles is liberated. This causes shale to shrink. The lateral stress drops until the pore pressure exceeds the lateral stress, which causes vertical fractures to open. Gravity drive and shale thermal fracturing make SAGD so efficient that recovery ratios of 60-70% are achievable even when there are many thin shale streaks. Currently, steam is generated with natural gas, and when the cost of natural gas rises. Operating costs rise considerably. Nonetheless, SAGD is about twice as thermally efficient as cyclic steam stimulation for similar cases, with steam-oil ratios that are now approaching two (instead of four for cyclic steam soak). Heat losses and deceleration of lateral growth mean that there is an economic limit to the lateral growth of the steam chamber. This limit is thought to be a chamber width of four times the vertical zone thickness. For thinner zones, horizontal well pairs would therefore have to be placed close together, increasing costs as well as providing lower total resources per well pair. SAGD is not suitable for all reservoirs. It performs best in clean, continuous sands, and it requires continuous vertical permeability. Other challenges are: Low initial oil rates Artificial lifting of bitumen to the surface as it cools progressively Reservoirs with low permeability, low pressure, or bottom water Vapor Assisted Petroleum Extraction (Vapex): Vapex is SAGD with steam replaced by vaporized solvent or solvent mixture. The method is non-thermal, solvent-based, and works at relatively low temperatures (40?C). Upon injection, solvents (ethane, propane, butane and naphtha) form a vapor chamber in the reservoir. Vapex picture (slide 45) Due to large dependence on molecular diffusion, initial production rates are relatively low in Vapex. There is a risk of solvent loss from the reservoir through fractures and thief zones. Loss of solvents may impact underground formations such as aquifers. However, Vapex is more environment-friendly than Vapex in terms of energy and water usage. Toe to Heel Air Injection (THAI): THAI is a combustion method that combines a vertical air injection well with a horizontal production well. A combustion front is created where part of reservoir oil is burned, generating heat that reduces the viscosity of the oil, which flows by gravity to the horizontal production well. The combustion front sweeps the oil from the toe to the heel of the production well, recovering it partially upgraded in situ. THAI picture (slide 48) THAI begins with preheating both well bores using steam to initiate oil mobility and clear pore space between the injector and the toe of the producing well. After ignition, the energy to sustain combustion comes from the burning of the coke that is continuously laid down within the reservoir. Product sulfur is reduced, as are heavy metals, which are left as an inert residue on the reservoir rock. No water or gas fuel is required during production. THAI has potential to operate in reservoirs that are lower in pressure, of a lower quality, thinner, and deeper than required for SAGD. Oil recovery in THAI occurs via a short displacement mechanism, which requires oil to move downwards (with the help of gravity) typically just 15 to 30 feet, as opposed to the lateral movement of several hundred feet in the usual combustion processes. Ahead of the combustion front (typically around 600?C) is the coking zone, in front of which is a 10-to-15-feet-wide mobile oil zone through which drainage takes place into the horizontal well. These zones move through the reservoir at about one to three feet per day, depending on the air injection rate. The temperature drops to 200-350?C at the front of the mobile oil zone, with a corresponding reduction in the rate of drainage. Ahead of the mobile oil zone is the cold immobile virgin oil layer, through which there is no communication for gas. This characteristic of the process geometry means that the only way out is down into the open section of the horizontal well. The horizontal well trajectory is thus a built-in self-controlling guidance system for fluid flow. Benefits (Toe to Heel Air Injection THAI): About 70-80% recovery of the OOIP Feasibility for low pressure, thin reservoirs Well geometry that enforces a short flow path so that the instabilities associated with the longer flow path is conventional combustion methods are reduced or even eliminated Lower environmental impact due to negligible fresh water use, less greenhouse gas emissions, a smaller surface footprint, and easier reclamation. Catalytic Upgrading Process In-situ (CAPRI): CAPRI is a catalytic variant of THAI An annular sheath of solid catalyst surrounds the horizontal producer well in the bottom of the oil layer. The produced drains into the horizontal producer well and through the catalyst layer where thermal cracking and hydro-conversion reactions take place so that only light, converted oil is produced at the surface. CAPRI picture (slide 55) Hybrid Processes: Use of a mixture of steam and miscible and non-condensable hydrocarbons in a hybrid SAGD-VAPEX Single horizontal laterally offset wells operated as moderate-pressure cyclic steam stimulation wells in combination with SGD pairs to widen the steam chamber and reduce steam-oil ratios by about 20% Simultaneous CHOPS and SAGD, with CHOPS used in offset wells until steam breakthrough occurs and oil recovery commences. Then the CHOPS wells are converted to slow gas and hot-water (or steam) injection wells to control the process. The high-permeability zones generated by CHOPS accelerate SAGD. Incorporating PPT along with CHOPS. PPT may aid in partially stabilizing water flood by reducing the viscous fingering and coning intensity. Research Objectives: To prove experimentally that oil production in Vapex can be increased by suitably varying solvent injection pressure with time, i.e. by utilizing solvent pressure versus time as a control function. To utilize the theory of Optimal Control to determine optimal solvent injection pressure versus time function (or policy) to maximize oil production in Vapex. To experimentally validate the optimal policy determined for different solvents in Vapex. Mathematical Model, Mass Transfer Model & Optimal Control Derivation (slide 2-11) In Situ Combustion: This method produces partially upgraded oil. Some of the higher-molecular-weight (less volatile) constituents crack (thermally decompose). The lower-molecule-weight (more volatile) constituents vaporize ahead of the combustion front and mix with unheated oil. Cracking produces a carbonaceous residue that is consumed as fuel during the combustion process. Dry Forward Combustion (In Situ Combustion): In this method, air is injected into a heavy oil reservoir, the oil is ignited in-situ, and the resulting combustion front moves away from the injection well. The heat generated at the combustion front propagates through the reservoir, reduces the oil viscosity, and increases the oil recovery. Wet Combustion (In Situ Combustion): In this method, air and water are injected concurrently or alternately. The water carries heat from the burned zone to the colder regions downstream of the combustion front. This method is useful in thin reservoirs, where heat loss to adjacent formations is significant. Reverse Combustion (In Situ Combustion): In this method, the combustion zone is initiated at a production well. The combustion front travels counter-current to the air towards the injection well where air is injected. The oil flows towards the production well, through the combustion zone. Since no oil bank is formed, the total flow resistance decreases with time, and thus this method is particularly suitable for reservoirs containing very viscous crude oils. Reverse combustion is particularly applicable to reservoirs with lower effective permeability, in contrast with forward combustion. The method is more effective because there is no chance of lower permeability causing fluids to plug the reservoir ahead of a forward combustion front. In reverse combustion, the vaporized and mobilized fluids move through the heated portion of the reservoir behind the combustion front. The method partially cracks the oil, consumes a portion of the oil as fuel, and deposits residual coke on the sand grains, leaving 40-60% of the oil as recoverable oil. Reverse combustion is difficult to maintain because the oxygen gets depleted close to the injection well. Furthermore, sustained air injection into an unheated reservoir generally leads to spontaneous ignition near the injection well. Inert Gas Injection (IGI): IGI involves injection of nitrogen or methane injection through vertical wells at the top of the reservoirs. This creates a gas-oil interface that is slowly displaced toward long horizontal production wells. IGI is suitable for conventional oils in reservoirs where good vertical permeability exists or can be created through fracturing. Oil Mining: Oil mining is surface or subsurface excavation of petroleum-bearing formations for removal of the heavy oil or bitumen by washing, flotation or retorting. Oil mining also includes recovery of heavy oil by drainage from reservoir beds to mine shafts or other connections. Surface Mining (Oil Mining): Surface mining is used to recover tar sand from the ground under 75m of overburden. Tar sand is ready for mining after the removal of muskeg and overburden. Muskeg is a water-soaked area of decaying plant material that is 1-3 m thick and lies on top of the overburden material. Overburden is a layer of clay, sand, and silt that lies directly above the tar sand deposit. Cyclic Steam Stimulation Enhanced Oil Recovery (EOR ) Methods The first stage is of injection, during which a measured amount of steam is introduced into the reservoir. The second stage is the soak period during which the well is shut (for several days) to allow uniform heat distribution to reduce oil viscosity. The third stage is the production of the now-mobile oil through the same well. The stages are cycled as long as the oil production is feasible. In Situ Combustion EOR Methods In Situ combustion is the combustion of oil or fuel in the reservoir to displace unburned oil toward production wells. Combustion is sustained by injection of air, oxygen, or supplemental fuel. This method may include the concurrent, alternating or subsequent injection of water. In Situ combustion (picture in slide) Performance depends on the -quantity of oil in the reservoir -quantity of air required to burn a portion of oil -extent to which vigorous combustion can be sustained -mobility of the air and combustion product gases Since gases are lighter and less viscous than oil, the burning front tends to override reservoir liquids. The method is most effective for the recovery of viscous oils in moderately thick reservoirs, which provide effective gravity drainage or with close well spacing. Combustion may be short (ie 30 days) or long (90 days), depending upon requirements. COFCAW Process It is combination of forward combustion and water flooding (COFCAW), which displaces more oil. Forward combustion involves the injection of air to sustain a combustion zone that moves through the reservoir. During water flooding, some of the water (and air) remains in the burned-out region behind the combustion zone. The remaining water is converted into steam, which flows through and ahead of the combustion zone and displaces much of the oil. Modified In Situ Extraction A large-diameter vertical shaft is dug into the reservoir. Horizontal drifts from the shaft bottom are excavated. Injection and production wells drilled horizontally from the drifts. The injected heat rises from the injection wells through the reservoir. The oil drains down to the production wells. Miscible Gas Displacement Gas Flooding Methods In this method, the injected fluid dissolves in the oil forming a less viscous liquid that flows more easily to the production well. Injection fluids include alcohols, carbon dioxide, hydrocarbons mixtures of ethane, propane, butane and pentane. The method may include the concurrent, alternating, or subsequent injection of water. Miscible process (picture on slide) Light hydrocarbons are generally too valuable to be used commercially. N2 and flue gases have also been used for commercial miscible floods. Minimum miscibility pressures for these gases are usually high. They are more suitable in high-pressure, high temperature reservoirs. Passing through the reservoir, the miscible solvent slug gets more and more enriched with oil and less and less effective in scavenging oil. As the oil is produced, the injected fluids can be readily separated from the oil and brine via pressure reduction. Miscible CO2 Displacement CO2 is injected at sufficiently high pressure to render it miscible with oil. The mobility ratio is very high and may lead to fingering and bypassing. This unfavorable phenomenon is controlled by keeping the injection pressure sufficiently high. The volume of carbon dioxide injected ranges from 20-40% of the reservoir pore volume. CO2 not only extracts hydrocarbons from the oil but also dissolved in it. Miscibility is achieved at the displacement front when no interfaces exist between the hydrocarbon-enriched carbon dioxide mixture and the carbon dioxide-enriched oil. Thus, by a dynamic (multiple contact) process involving interphase mass transfer, miscible displacement overcomes the capillary forces that otherwise trap oil in pores of the rock. CO2 also swells crude oils, thus increasing the volume of pore space occupied by the oil and reducing the quantity of oil trapped in the pores. CO2 also reduces the oil viscosity All of these enhance the mobility of the oil. Gravity Drive (picture on slide) Gravity Drive Recovery Operation Compared to solution gas drive, much higher recoveries are obtained with water and gas cap drives. Gravity drive when present further promotes oil production. Improvement of Formation Recovery Operation Formation characteristics can be improved using acidizing and fracturing. Acidizing involves injecting an acid into a soluble formation, such as a carbonate, where it dissolves rock. This process enlarges the existing voids and increases permeability. Fracturing (fracking) involves injecting a fluid into the formation under significant pressure. This makes existing small fractures larger and creates new fractures. Heavy oil reservoirs are subject to only one recovery technology. Primary and secondary recovery methods are not applicable to oil sands because bitumen is not mobile at reservoir conditions. Therefore, oil sands developments generally start with a thermal recovery technology, which would be considered a tertiary or enhanced recovery method for conventional oil. Recovery Efficiencies Displacement efficiency: The fraction of oil that has been recovered from a zone swept by a waterflood or other displacement process. Areal sweep efficiency (horizontal sweep efficiency): The fraction of the flood pattern area that is effectively swept by the injected fluids. Vertical displacement efficiency: The ratio of the cumulative height of the vertical sections of the pay zone that are contacted by injection fluid to the total vertical pay zone height. Areal sweep efficiency (picture on slide) Breakthrough : Access of reservoir fluid to production well. Screen Factor: A qualitative measure of viscosity in polymer flooding. Ratio of time taken by polymer solution to flow due to gravity through screen viscometer to that taken by a brine solution. Secondary Recovery Begins when underground pressure is not sufficient to force the oil to the surface. Up to 70% of oil may be left in the reservoir when primary recovery ends. Usually involves, injection of gas or water into the reservoir. Shallow reservoirs tend to have both low pressures and small amounts of dissolved gas. They are more amenable to secondary recovery methods. Conversely, deeper oil reservoirs tend to have higher pressures, more dissolved gas and consequently, fare better with primary recovery methods. This replaces the space left by produced fluids and maintains or increases reservoir pressure. There is no change in the state of oil. Gas when used alone is usually injected to the top to form a gas cap. When water is used, the process is water flooding : with gas, gas flooding. Separate wells are often used for injection and production. Injection wells are located in a pattern that will best push oil toward the production wells. Water flooding (picture on slide) In reservoirs with high permeability and high vertical span, gas flooding from the top or into the gas cap may result in high recovery factors due to gravity segregation. Water flooding is suitable in reservoirs with low permeability and/or thickness. While oil is produced, gas or water are injected at suitable rates to maintain pressure in the reservoir at or near the original levels. This helps to keep up production as long as possible. Produced gas or water can be recycled and disposed of safety in this manner. Fresh gas or water is also conserved. Mobility: A measure of the ease with which a fluid moves through reservoir rock. It is the ratio of rock permeability (k) to apparent fluid viscosity. Mobility ratio: The ratio of mobility of an injection fluid to mobility of fluid being displaced. The mobility ratio (M) is the mobility of the flooding fluid divided by the mobility of oil. M<1 indicated a favorable displacement as oil moves faster than the injected fluid. M>1 indicated otherwise. The mobility ratio of injected fluid remains constant before breakthrough but increases thereafter. Flooding Patterns Secondary Recovery A proper flooding pattern provides the injection fluid with the maximum possible contact with the crude oil and minimized bypassing. In a four-spot pattern, three injection wells form an equilateral triangle with a production well at the center. N a five-spot pattern, four injection wells form a square with a production well at the center. Five spot pattern (picture on slide) In a seven-spot pattern, the injection wells are located at the corner of a hexagon with a production well at its center. A nine-spot pattern is similar to the five-spot pattern but with an extra injection well drilled at the middle of each side of the square. Four and five –spot patterns (picture on slide) Seven and nine-spot (picture) Line drives(picture) If a reservoir has lower injectivity or higher heterogeneity than seven or nine spot pattern is used. If a reservoir has higher injectivity or lower heterogeneity than inverted seven or nine spot pattern is used. Production and injection wells are interchanged in inverted spot patterns. In the direct line-drive pattern, the lines of injection and production are directly opposite to each other. This pattern is good for low injectivity is low or large heterogeneity in the reservoir. A staggered line-drive pattern is similar to the direct line-drive pattern, but wells are offset by a specified distances depending on well-type and spacing between the injector and producer wells. A pattern with more producer wells is needed if the mobility ratio is high. More injector wells are needed in the pattern if the mobility ratio is low. More water would flow through larger passages in the reservoir, bypassing smaller ones and leaving oil therein. Flooding by a miscible fluid (liquid butane and propane at high pressure) helps salvage that oil. The fluid dissolves in the oil and carries it out of the smaller passages. Post Secondary Recovery Operation The oil is left behind in the pore space of reservoir rock at a lower concentration than originally existed. In portions of the reservoir that have been contacted or swept by the injection fluid, the residual oil remains as droplets (or ganglia) trapped in either individual pores or clusters of pores. The oil may also remain as films partly coating the pore walls. Entrapment of this residual oil is predominantly due to capillary For example, during waterflooding, the capillary forces that cause the displacement of oil by water can also result in the trapping of residual oil. Particularly important is the faster movement of water through the smaller pore because -the smaller diameter increases the capillary force -the oil volume displaced by water is far less. Flooding Patterns Secondary Recovery Water movinf more rapidly through the small pore will reach a common outlet before all the oil is displaced from the upper large pore. A net capillary force than acts on the downstream end of the large pore. Further displacement of oil ceases, trapping oil between the two interfaces. EOR Methods These methods target this residual oil and reservoirs with extra heavy oil. EOR methods kick in after secondary recovery becomes unfeasible or for reservoirs with extra heavy oil. The intent is to increase the effectiveness of oil removal from pores of the rock (displacement efficiency) and to increase the volume of rock contacted by injected fluids (sweep efficiency) EOR methods include thermal and non-thermal methods in general. Thermal methods are steam-based (cyclic steam injection, steam flooding, etc.) or utilize in situ combustion. Non-thermal methods rely on chemicals (surfactants, polymers, gases, etc.) EOR methods use thermal, chemical, or fluid phase behavior effects to -reduce or eliminate the capillary forces that trap oil within pores. -thin the oil or otherwise improve its mobility, or -alter the mobility of the displacing fluids. These are the only recovery methods for in reservoirs containing viscous oils and tars. In in-situ combustion, some reservoir oil is burned to heat the surrounding oil. Steam-based methods are the most technically advanced. These methods have been applied almost exclusively in relatively thick reservoirs containing viscous crude oil. Thermal Recovery Methods They add heat to the reservoir to reduce oil viscosity and/ or to vaporize the oil. A driving force (pressure) is exerted to the oil to move to producing wells. The oil is thus made sufficiently mobile and is effectively produced. Steam drive injection is the continuous injection of steam into injection wells to move oil toward production wells. Cyclic steam injection is the alternating steam injection and oil production from the same well (s). Steam generated at the surface is injected in a well and the same well is subsequently put back on production. Cyclic Steam Stimulation The method has two steps: -steam stimulation of production wells, that is, direct steam stimulation -steam drive by steam injection to increase production from other wells (indirect steam stimulation) When injection well is used for production, the method is called huff and puff or steam soak. The period of steam injection is followed by production of reduced viscosity oil and condensed steam (water) One mechanism that aids production of oil is the flashing of hot water (originally condensed from steam injected under high pressure) back to steam as pressure is lowered when a well is put back on production. CSS (Huff and Puff) –Diagram on slide
