Shifting The Focus To An Optimal Oil Recovery Strategy. Dr. John D.M. Belgrave, Belgrave Oil And Gas Corp. 13th International Oil And Gas Conference & Exhibition, Delhi, India...
The failures of air injection (fireflooding, in-situ combustion) as an oil recovery process are legendary. Most of the failures have been in shallow heavy oil experimental pilots and occurred because of:
A lack of understanding of the process dynamics and poor reservoir characterization are largely to blame.
A coherent examination of air injection projects, however, gives a completely different picture from the prevailing perception regarding the efficacy of this technology. Air injection has worked in almost every reservoir setting and is arguably the most versatile EOR process!
Where initial oil mobility has not been an issue (deep light-oil reservoirs) air injection has had remarkable success (Buffalo, Medicine Pole Hills, West Hackberry, Bellevue). Where gravity stable displacement has been implemented in both heavy and light oil reservoirs, oil recovery factors from 50% to as high as 90% have been achieved (Suplacu de Barcau, West Hackberry). Several field projects have demonstrated the ability of air injection to recover additional oil from watered-out reservoirs (Sloss, West Hackberry, Countess "B"). Air injection has also been successful where the reservoir was too tight to be waterflooded (Medicine Pole Hills, 1-5 md.). flooding are actually favorable for air injection. Reservoir permeability, depth, pressure, and connate water salinity has minimal impact on the process.
The BP Canada Wolf Lake combustion project is an edifying example of where a fundamental understanding of process mechanics led to the development and implementation of a successful exploitation strategy in a reservoir that conventional wisdom deemed unsuitable. BP overcame the mobility and injectivity issues by fracturing the bitumen reservoir with steam injection, then implementing "Pressure-Up Blow-Down" in-situ combustion in the channeled reservoir to alleviate fire-front breakthrough at the producing wells. By using in-situ combustion as a follow-up to steam injection, BP was able to reduce the full-cycle steam-oil ratio from 6.3 to a commercial value 2.3, and increase recovery factor from 15% to 30%.
Another iconoclastic application of air injection technology to overcome exploitation challenges is EnCana's EnCAID process. EnCana has implemented in-situ combustion in a gas-cap (overlying bitumen in the Wabiskaw formation) to maintain reservoir pressure while the methane gas is produced. Maintaining reservoir pressure in top gas is an Alberta Government regulation instituted to ensure that bitumen recovery is not impacted by gas production. The fuel for combustion is a small bitumen saturation in the gas-cap which consumed the oxygen, generating CO2 and N2 (flue gas) to displace the methane. To date, the displacement has been almost "piston-like", and, no, the methane does not burn. The demonstration project has produced over 2 BCF of natural gas in response to a single air injection well, and a positive externality has been the conductive heating of the underlying bitumen which will reduce the cost of its exploitation.
Much ado has also been made of the CO2 (and H2S in the case of heavy oils) generated by the air injection process. There is no reason why air injection cannot be included amongst zero emissions oil recovery technologies. The deepest air injection operation, West Heidelberg Cotton Valley Field (3,600 m), is considered a great technical and economic success. Here produced flue gases were reinjected into one of the producing zones for pressure maintenance.
As the EnCAID project demonstrated, there are also flue gas reinjection opportunities for Enhanced Gas Recovery. Flue gas can be collected and used to increase the ultimate gas recovery of mature volumetric gas reservoirs suffering from low productivity due to low reservoir pressure, by maintaining gas production rates and preventing premature well abandonment. Flue gas can also be used retard aquifer influx and water coning in water-drive gas reservoirs.
A cross-sectional schematic of the air injection process is shown in Figure 1. For simplicity, the common scenario involving horizontal oil displacement between two vertical wells is considered. Note: Other configurations using horizontal producers, dipping reservoirs, and gravity stable displacement are feasible.
If the crude oil is sufficiently reactive at the near wellbore reservoir temperature, then exothermic oxidation reactions will cause the oil to spontaneously ignite provided that the air is injected at a rate high enough to overcome convective and conductive heat losses. Once created, continued injection of air will move this high temperature (~400oC - 600oC) reaction/combustion zone through the reservoir.
Properly maintained by adequate air injection, the combustion zone (front) is a very narrow region (usually no more than a few inches thick) where high temperature oxidation (burning) takes place to produce primarily water and combustion gases (CO2 and CO). Several significant displacement mechanisms working in concert are generated by the combustion zone: gas drive (combustion or flue gases), steam drive, water drive (re-condensed formation water and water of combustion), miscible gas and solvent drive. Unit oil displacement efficiency as high as 95% is achievable and is one of the reasons for continued interest in air injection despite the high technical barriers to its implementation.
The importance of the air injection rate cannot be overstated. Insufficient air injection results in less vigorous burning (low temperature oxidation, less carbon oxides generated, a "spreading-out" of the combustion zone, formation of difficult emulsions, and a loss of displacement efficiency. Reservoir injectivity and sizing of the compression facilities are important design considerations.
In spite of the fact that the combustion reactions generate significant heat, it is important to recognize that air injection as described above is primarily a displacement process, as opposed to a thermal process. This means that the reservoir oil must be mobile prior to the start of air injection for its displacement to be feasible. If there is no natural oil mobility it needs to be first established (by injecting steam for example).
The injection of water with the air, either simultaneously or with alternating cycles of air injection can have a significant impact on the economics of air injection.
In "dry" combustion, much of the heat generated during burning is stored in the burned sand behind the front and does not assist oil displacement.
Injected water absorbs heat from the burned zone and vaporizes. As steam, it passes through the combustion front and releases the heat as it condenses in the cooler regions of the reservoir. This causes the growth of the steam and water banks ahead of the combustion front to accelerate, resulting in faster heat movement and oil displacement.
Wet combustion reduces the quantity of oil burned and air required for the process by as much as 30 to 50 percent. An additional benefit is that the producing wells have a longer period of warm production from the first heat-front breakthrough (steam/hot water) until the arrival of the burning-front.
A question frequently posed is: Can injection of some other gas such as nitrogen, methane or carbon dioxide achieve the same results? If the gas injection process is not being conducted is a miscible fashion then the displacement efficiency will be substantially lower than that associated with a healthy combustion front. A similar apparent incongruity exists with steam and hot water injection. Steam flooding has higher displacement efficiency than hot water flooding at the same temperature. The difference in displacement efficiency in both cases is due to improvement in frontal stability created by the combustion and condensing fronts.
It is useful to compare the displacement efficiencies of different enhanced oil recovery processes (see Table 1).
Table 1 - EOR Displacement Efficiency
Considering its versatility (refer, if necessary, to the Overview) and superior displacement efficiency (Table 1), air injection should seriously be considered for implementation in all mature oil provinces.
The air injection process is initiated by ignited the oil in the reservoir. It is the key phase of the operation. If the formation fails to ignite or ignition cannot be sustained for an extended period, there will be poor oil displacement, premature breakthrough of oxygen, and the project will not be successful.
As mentioned previously, if the reservoir temperature is high enough and the crude oil sufficiently reactive, then the oil will spontaneously ignite after a period of air injection without any assistance. Formations that spontaneously ignite typically contain medium- to high-API gravity crudes (which are more reactive), and are situated deeper (higher temperatures).
Where spontaneous ignition is not feasible, artificial ignition methods are necessary:
Cyclic Air Injection: Stimulation, Sand Control, Upgraded Oil
On Irrational the Resistance to Air Injection EOR
Carbon Dioxide Emission Intensity from Steam Versus Air Injection EOR
Air Injection for Sand Control
On the Application of Horizontal Wells in Air Injection EOR
Energy Efficiency Comparison: Air Injection vs. SAGD