Enhanced Recovery
Crude oil development and production in oil reservoirs can include up to three distinct phases: primary, secondary, and tertiary (or enhanced) recovery. During primary recovery, the natural pressure of the reservoir or gravity drive oil into the wellbore, combined with artificial lift techniques (such as pumps) which bring the oil to the surface. But only about 10 percent of a reservoir's original oil in place is typically produced during primary recovery.
Secondary recovery techniques extend a field's productive life generally by injecting water or gas to displace oil and drive it to a production wellbore, resulting in the recovery of 20 to 40 percent of the original oil in place.
However, with much of the easy-to-produce oil already recovered from oil fields, producers have attempted several tertiary, or enhanced oil recovery (EOR), techniques that offer prospects for ultimately producing 30 to 60 percent, or more, of the reservoir's original oil in place.
Cost Estimation and Fasibility Analysis models for the EOR's are very complicated matter. Adding oil recovery methods adds to the cost of oil — in the case of CO2 typically between 0.5-8.0 US$ per tonne of CO2. The increased extraction of oil on the other hand, is an economic benefit with the revenue depending on prevailing oil prices. Onshore EOR has paid in the range of a net 10-16 US$ per tonne of CO2 injected for oil prices of 15-20 US$/barrel. Prevailing prices depend on many factors but can determine the economic suitability of any procedure, with more procedures and more expensive procedures being economically viable at higher prices.
NoDoC models for this sector are developed based on the Three major categories of EOR that have been found to be commercially successful to varying degrees:
- Thermal recovery
- Non-Thermal Recovery
- ESP
Each of these techniques has been hampered by its relatively high cost and, in some cases, by the unpredictability of its effectiveness. NoDoC cost simulation for this part always include probability and statistical analysis such that can extract the result for different alternatives.
Therefore NoDoC estimate the cost for enhanced oil recovery process in three stages or categories which are:
1- Primary Oil Recovery
2- Secondary Oil Recovery
3- Tertiary Oil Recovery
Except for artificail lift, and for easy use, NoDoC divides the EOR to two groups: Non-Thermal Recovery and Thermal recovery.
Non-Thermal Recovery
Non-thermal recovery techniques can be broken down into the following:
Pressure Maintenance. More complete recovery of oil is achieved by special technological methods. A common method employed today is artificial maintenance of formation pressure. This traditional step for increasing oil recovery involves the injection of fluid into (or near) an oil reservoir for the purpose of delaying the pressure decline during oil production. Pressure maintenance can significantly increase the amount of economically recoverable oil over that to be expected with no pressure maintenance.
Water flooding. Production can be increased after a decline in pressure from the water drive or pressure maintenance by a technique called waterflooding, which is the injection of water through injection wells to push crude oil toward producing wells. Water is pumped into the productive layer at injection pressure through bore holes in a volume equal to (or greater than) the volume of oil extracted. So, the formation energy in the deposit is kept at the optimum level. The original lifetime of the well is prolonged, which greatly reduces the amount of drilling operations and consequently reduces the cost of the oil.
Gas Injection. There are two major types of gas injection, miscible gas injection and immiscible gas injection. In miscible gas injection, the gas is injected at or above minimum miscibility pressure (MMP) which causes the gas to be miscible in the oil. On the other hand in immiscible gas injection, flooding by the gas is conducted below MMP. This low pressure injection of gas is used to maintain reservoir pressure to prevent production cut-off and thereby increase the rate of production. Gas injection processes can be broken down into the following techniques:
Liquefied Petroleum Gas Miscible Slug. Displacement by miscible slug usually refers to the injection of some liquid solvent that is miscible upon first contact with the resident crude oil. In particular, this process uses a slug of propane or other liquefied petroleum gas (2 to 5% PV [pore volume]) tailed by natural gas, inert gas, and/or water. Thus, the solvent will bank oil and water ahead of it and fully displace all contacted oil.
Enriched Gas Miscible Process. In the enriched gas process,a slug of methane enriched with ethane, propane, or butane (10 to 20% PV) and tailed by lean gas and/or water is injected into the reservoir. When the injected gas contacts virgin reservoir oil,the enriching components are slaked from the injected gas and absorbed into the oil.
High Pressure Lean Gas Miscible Process. This process involves the continuous injection of high pressure methane, ethane, nitrogen,or flue gas into the reservoir. The lean gas process, similar to enriched gas, involves multiple contacts between reservoir oil and lean gas before forming a miscible bank. But, there is a difference in the enriched gas process where light components condense out of the injected gas and into the oil, then intermediate hydrocarbon fractions (C2 to C6) are stripped from the oil into the lean gas phase.
Carbon Dioxide Process. Oil displacement may be initiated by a number of mechanisms due to injection of CO2 into oil reservoirs. Carbon dioxide is not usually miscible with reservoir oil upon initial contact, however it may create a miscible front like the lean gas process. So, there are two major types of CO2 floods; miscible flood in which the gas is injected at or above the MMP, and immiscible flood in which flooding by the gas is conducted below the MMP. Miscibility is initiated by the extraction of large amounts of heavier hydrocarbons (C5 to C30) by CO2.
Secondary recovery techniques extend a field's productive life generally by injecting water or gas to displace oil and drive it to a production wellbore, resulting in the recovery of 20 to 40 percent of the original oil in place.
However, with much of the easy-to-produce oil already recovered from oil fields, producers have attempted several tertiary, or enhanced oil recovery (EOR), techniques that offer prospects for ultimately producing 30 to 60 percent, or more, of the reservoir's original oil in place.
Cost Estimation and Fasibility Analysis models for the EOR's are very complicated matter. Adding oil recovery methods adds to the cost of oil — in the case of CO2 typically between 0.5-8.0 US$ per tonne of CO2. The increased extraction of oil on the other hand, is an economic benefit with the revenue depending on prevailing oil prices. Onshore EOR has paid in the range of a net 10-16 US$ per tonne of CO2 injected for oil prices of 15-20 US$/barrel. Prevailing prices depend on many factors but can determine the economic suitability of any procedure, with more procedures and more expensive procedures being economically viable at higher prices.
NoDoC models for this sector are developed based on the Three major categories of EOR that have been found to be commercially successful to varying degrees:
- Thermal recovery
- Non-Thermal Recovery
- ESP
Each of these techniques has been hampered by its relatively high cost and, in some cases, by the unpredictability of its effectiveness. NoDoC cost simulation for this part always include probability and statistical analysis such that can extract the result for different alternatives.
Therefore NoDoC estimate the cost for enhanced oil recovery process in three stages or categories which are:
1- Primary Oil Recovery
2- Secondary Oil Recovery
3- Tertiary Oil Recovery
Except for artificail lift, and for easy use, NoDoC divides the EOR to two groups: Non-Thermal Recovery and Thermal recovery.
Non-Thermal Recovery
Non-thermal recovery techniques can be broken down into the following:
Pressure Maintenance. More complete recovery of oil is achieved by special technological methods. A common method employed today is artificial maintenance of formation pressure. This traditional step for increasing oil recovery involves the injection of fluid into (or near) an oil reservoir for the purpose of delaying the pressure decline during oil production. Pressure maintenance can significantly increase the amount of economically recoverable oil over that to be expected with no pressure maintenance.
Water flooding. Production can be increased after a decline in pressure from the water drive or pressure maintenance by a technique called waterflooding, which is the injection of water through injection wells to push crude oil toward producing wells. Water is pumped into the productive layer at injection pressure through bore holes in a volume equal to (or greater than) the volume of oil extracted. So, the formation energy in the deposit is kept at the optimum level. The original lifetime of the well is prolonged, which greatly reduces the amount of drilling operations and consequently reduces the cost of the oil.
Gas Injection. There are two major types of gas injection, miscible gas injection and immiscible gas injection. In miscible gas injection, the gas is injected at or above minimum miscibility pressure (MMP) which causes the gas to be miscible in the oil. On the other hand in immiscible gas injection, flooding by the gas is conducted below MMP. This low pressure injection of gas is used to maintain reservoir pressure to prevent production cut-off and thereby increase the rate of production. Gas injection processes can be broken down into the following techniques:
Liquefied Petroleum Gas Miscible Slug. Displacement by miscible slug usually refers to the injection of some liquid solvent that is miscible upon first contact with the resident crude oil. In particular, this process uses a slug of propane or other liquefied petroleum gas (2 to 5% PV [pore volume]) tailed by natural gas, inert gas, and/or water. Thus, the solvent will bank oil and water ahead of it and fully displace all contacted oil.
Enriched Gas Miscible Process. In the enriched gas process,a slug of methane enriched with ethane, propane, or butane (10 to 20% PV) and tailed by lean gas and/or water is injected into the reservoir. When the injected gas contacts virgin reservoir oil,the enriching components are slaked from the injected gas and absorbed into the oil.
High Pressure Lean Gas Miscible Process. This process involves the continuous injection of high pressure methane, ethane, nitrogen,or flue gas into the reservoir. The lean gas process, similar to enriched gas, involves multiple contacts between reservoir oil and lean gas before forming a miscible bank. But, there is a difference in the enriched gas process where light components condense out of the injected gas and into the oil, then intermediate hydrocarbon fractions (C2 to C6) are stripped from the oil into the lean gas phase.
Carbon Dioxide Process. Oil displacement may be initiated by a number of mechanisms due to injection of CO2 into oil reservoirs. Carbon dioxide is not usually miscible with reservoir oil upon initial contact, however it may create a miscible front like the lean gas process. So, there are two major types of CO2 floods; miscible flood in which the gas is injected at or above the MMP, and immiscible flood in which flooding by the gas is conducted below the MMP. Miscibility is initiated by the extraction of large amounts of heavier hydrocarbons (C5 to C30) by CO2.