4 Petroleum production
4.3 Production techniques
In order to develop offshore fields economically, numerous directional wells radiate out from a single platform or from several sub-sea wellheads to drain a large area of the reservoir. This allows each well to produce as much petroleum as possible at economic rates. Wells which deviate at more than 65° from the vertical and reach out horizontally more than twice their vertical depth are known as extended reach wells (Figure 10). Where reservoirs are thin or suffer from low permeability it may be appropriate to drill production wells at more than 80° from the vertical and these are called horizontal wells. The flow rate from a horizontal well may be more than five times that from a vertical well, thereby justifying the higher cost of drilling a well with a complex geometry. In order that wells that deviate from the ‘standard’ vertical drilling can be guided precisely through layered reservoirs, real-time information about the location and inclination of the drill bit is transmitted back to surface. This allows the driller to ‘steer’ the bit assembly to intersect particularly productive zones.
All fluid petroleum is confined underground at high pressure, which provides a natural ‘drive’ for production, rather like artesian water supplies (Smith, 2005).
Figure 10: (a) Wells at a variety of angles extract petroleum from all parts of a large, saturated reservoir, (b) Superimposition of the plan of the wells shown in (a) over central London gives a graphic expression of the area that can be exploited from a single production platform by deviated drilling into a reservoir.
During the early stages of production, getting these fluids to the surface safely means allowing a controlled release of fluids under pressure. To prolong extraction later in the life of an oil or gas field, it usually becomes necessary to maintain the pressure underground by injecting pressurised water or gas, or both, into the reservoir.
When production begins, during primary recovery, pressurised fluids within the reservoir rise up the borehole and reach the surface. As the pressure is released, any gas dissolved in the oil comes out of solution, to rise and escape along with the oil. As production continues, the pressure of the petroleum remaining in the reservoir begins to fall. This fall in pressure and the loss of dissolved gas increases the viscosity of the oil, so that it will not flow so readily. Typically only 5–30% of the petroleum in the reservoir is brought to the surface during the primary recovery stage.
As the natural drive of the petroleum dwindles, secondary recovery techniques are needed for continued production. These techniques maintain reservoir pressure by injecting gas into the gas cap that often lies above the oil, thus forcing the oil downwards (Figure 11a), or by flooding water into the aquifer below the oil to force it upwards (Figure 11b). In some reservoirs both gas and water may be injected at the same time or alternately, increasing the recovery of petroleum to 25–65% of the volume contained in the reservoir. The gas required for injection may be derived from the production stream (the fluids that emerge from the well, which comprises gas, oil and water) itself, or from an adjacent field. Similarly, the water for injection may be water from a producing well or sea water.
Figure 11: Oil and gas production techniques. When the natural pressure within the reservoir has dissipated, the drive can be maintained by injecting (a) gas into the gas cap at the top of the reservoir, or (b) water into the aquifer beneath the oil. In some reservoirs both techniques are used at the same time.
In order to improve recovery still further, chemical or biological additives may be added to the injected water, or steam may be pumped into the reservoir, in order to reduce the viscosity of the crude oil (tertiary recovery). Secondary and tertiary recovery methods can result in over 70% of the initial oil being recovered, but the processes are expensive and for many smaller fields the amount of extra oil recovered may not be worth the investment.
The percentage of petroleum that can actually be recovered from a reservoir is a function of both fluid and reservoir properties, as well as the method of extraction. Viscous, waxy oils are more difficult to extract than light, mobile oils, and low-permeability, segmented reservoirs yield less petroleum than good quality, homogeneous ones, even using secondary recovery. Much oil can be left behind if the displacing fluids follow a few discrete pathways rather than flushing out the oil uniformly from the bulk rock. Even with modern techniques the percentage of recovered petroleum varies enormously: in North Sea oil fields it varies from around 10% up to 70% for the best reservoirs, with the average typically in the range of 30–40%. For gas fields, percentage recovery is generally much higher, with figures in the 70–80% range, because gas is many orders of magnitude less viscous than oil.
Imagine that you are the Managing Director of Spoof Oil, a small, entrepreneurial company that owns a 100 million barrel oil field with a primary recovery of 25%. Studies indicate that an alternating water and gas injection scheme would cost $80 million to install, but would increase recovery to 45%. Would you make the investment if forecasts of future oil prices are likely to remain above $30 per barrel?
Yes. Spoof Oil can access a further (0.45–0.25)×100 = 20 million barrels by installing the secondary recovery scheme for $80 million, a cost of $4 per barrel. Allowing for operating costs and taxes there are still very significant profits to be made while oil price remains high.
During the course of field production the amount of new dynamic data that becomes available rises exponentially and it allows an improved description and visualisation of the reservoir. Constant interaction between reservoir engineers and geoscientists is required to ensure that modelled outcomes are matched by production performance. Specific initiatives such as novel drilling strategies, time-lapse (4-D) seismic surveys and well-stimulation programmes may be used to maximise recovery and manage the long-term decline. It should be clear that the incentive to produce an additional 5% of reserves from a large field is very significant, particularly in an environment of rising petroleum prices.