New Oil Technologies
- What new technologies are there that will increase recovery factors further?
- What is primary, secondary and tertiary oil recovery?
What new technologies are there that will increase recovery factors further?
In the 1970s, close spaced 2D seismic data/interpretation and water injection boosted production rates and recovery factors. In the 1980s – it was offshore technology, 3D seismic data/interpretation which boosted rates. In the 1990s it was horizontal drilling technology, electrical submersible pumps and deepwater / sub-sea technology.
The problem this decade is, there is no big new technology that is likely to have such an impact as the technologies that were implemented in the 1970s-1990s. Enhanced 3D and 4D seismic, ultra-deepwater, remote operations technology will only provide incremental gains in the most demanding environments.
For many IOCs, all the good technology that was developed and implemented in the last 30 years has accelerated oil production and increased recovery factors from some 20-30% to up to 60% - but this will also cause higher decline rates and IOCs have to work harder and faster to stop this decline.
Access by IOCs to new oil reserves is becoming increasingly difficult because the bulk of the remaining oil reserves are governed by state oil companies, many of whom feel they do not need a lot of help. This is not likely to change since these companies can buy in the technologies and expertise from contractors to increase recovery factors and production rates. The nationals have to a large extent trained themselves up to manage the fields in most mature developing provinces.
There is no particularly exciting new technology that will have the impact that either deepwater, horizontal wells and/or 3D seismic has on recovery factors or production rates. The IOCs are “at the top of the creaming curve” whilst the NOCs in OPEC countries have most of the remaining opportunities and optimisation to boost recovery factors.
What is primary, secondary and tertiary oil recovery?
Primary oil recovery is the recovery of oil through normal drilling and production depletion. Commonly, vertical and horizontal oil production wells are drilled to depths of 500 to 5000 metres and are cased with pipe cemented in place. Pumps are installed – either beam pumps (“nodding donkeys”), electrical submersible pumps, gas lift completions or normal depletion completions. The wells are then brought on stream and produce until the reservoir pressure drops to a low level. Sometimes, pressure is maintained naturally by “natural water drive” where an influx of water from adjacent reservoir rocks keeps the pressure up – this can lead to high and sustained production rates until water breaks through, thence the wells will commonly 'water out' very quickly.
Where no natural water drive exists, wells will normally produce until the pressure declines to a fairly low level. If only low levels of water are being produced with the oil at this stage, then water injection wells are drilled and water injected – to boost the reservoir pressure back up – this is termed secondary oil recovery – the injection of water and/or gas into oil reservoirs to boost pressures and/or increase oil sweep efficiencies. The process can start immediately after first production, but normally is implemented some years after start-up – hence the term, secondary oil recovery. Two main types of water injection occur - water injection in a grid pattern called “pattern flood” in complex reservoirs with poor lateral communication or wells drilled on the flanks of the field called “edge water injection” – normally in simpler sandstone and carbonate reservoirs with good communication. Such water injection can sometimes increase recovery factors by double (say 15% to 30%, or 30% to 60%).
Missible gas injection is a process of injecting natural gas or carbon dioxide which then percolates through the reservoir, thereby increasing the sweep efficiency and recovery factor. This process is far less common than water injection.
Tertiary oil recovery is a third stage. The two main types of process are steam injection and chemical injection. Steam injection is far more common and consists of injecting super-heated water in the form of steam down wells which then floods through heavy oil accumulations – thereby heating up the reservoir, reducing the viscosity of the heavy oil and increasing the production rates along with the recovery factor. The process often has relatively high unit technical costs of $10-$14 per barrel to produce such tertiary oil – because of the high capital and operating costs of the steam plants, infra-structure and closely spaced production wells. As long as the heavy oil accumulation is relatively large and shallow with high permeability, if the oil price is over $20 per barrel, economics are often attractive.
Good examples of successful heavy oil steam injection developments come from Venezuela and USA (California). Projects slated for development include fields in Oman, Holland and Iran. The projects rely on excellence in reservoir surveillance - monitoring the data and acting appropriately on the results. The process is labour, capital and operating cost intensive – some companies have a niche in these activities and are rewarded handsomely for their efforts at prices over $20 per barrel.
Chemical injection was tried in the early 1980s – it normally involves pumping polymer into a depleted, highly permeable and medium-light oil reservoir. The polymer is flushed through and picks up residual oil – which is then extracted from the polymer at the surface. The polymer is then recycled/cleaned, dehydrated and re-injected again. The process is very expensive – costing some $30 per barrel and is technically challenging and resource intensive. In summary – there are far easier ways of obtaining oil at lower costs – few if any projects are proceeding, despite the high oil prices. Many petroleum engineers were disappointed with results years ago – and there is not much evidence things have changed since the early 1980s.
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