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Maximising recovery rates

15th April 2013

Depleting oil from mature fields underscores the need for methods to enhance the recovery factor in onshore reservoirs. Oil & Gas Technology takes a look at the most successful EOR techniques applied in the US and which could help unlock vast new reserves

Maximising recovery rates
After primary and secondary oil recovery, up to 75 per cent of oil may be left in the well, according to the US DOE

Maximising recovery from aging fields is becoming paramount to several national and international oil companies as onshore oil-bearing reservoirs mature and production levels decline. In many of these reservoirs, waterflooding – the second stage in the oil recovery process – is reaching its production limit and further methods are required to enhance energy returns.

A vital technology for the future

Against this backdrop, the importance of tertiary phase recovery or enhanced oil recovery (EOR) becomes self-evident. After primary and secondary oil recovery, up to 75 per cent of oil may be left in the well, according to estimates released by the US Department of Energy (DOE). The same argument is made by Dr Necmettin Mungan, chair of the advisory board and EOR consultant at Calgary-based junior oil company Terrex Energy Inc.: “The average recovery from all known oil reservoirs will not exceed 30 per cent of the oil in place unless EOR processes are applied.”

EOR processes are therefore key to boost oil production. They enhance sweep efficiency by increasing the mobility of displaced fluids through the use of displacing fluids, which reduces the amount of oil trapped in the wells due to capillary forces, that is to say, the oil that remains after primary and secondary oil production stages have exhausted recovery potential.

French energy firm Total has itself put a great deal of emphasis on EOR, considering it a strategic priority. The company has established a dedicated research program and is carrying out a number of development projects to that effect.

“Improving the recovery factor of conventional oil resources will play a decisive role in offsetting the inevitable decline of oilfields and keeping step with the world’s demand for hydrocarbons,” the French giant says, estimating that global production from conventional reservoirs is declining at a rate of 5 per cent per year.

Norway will most likely turn even further to the implementation of EOR technologies, especially after Statoil announced last year its ambitious aim to reach an average recovery rate of 60 per cent from its fields along the Norwegian Continental Shelf (NCS), a staggering mark and world record, considering that standard rates are usually placed at 35 per cent.

In the US, the DOE estimates that the application of EOR techniques there could help unlock up to 89 billion barrels of additional oil trapped in onshore reservoirs, more than four times its proven domestic oil reserves, which are currently placed at 21 billion barrels.

Although all fields need to be carefully analysed and several factors taken into account to determine which process each of them is most amenable to, the two main types of EOR in the US are: gas injection, in which gases such as natural gas, nitrogen or carbon dioxide are injected into the reservoir, decreasing viscosity and increasing flow; and thermal recovery, where the same results are achieved through heat which increases the temperature of the oil.

Gas injection

Gas injection accounts for nearly half of the EOR employed in the US. One of its processes is CO2 injection, which is applicable to light oil reservoirs and has become quite popular in the US. The DOE has deemed it the “fastest-growing EOR technique” in the country, with a total of at least 1,673 sites identified as suitable for CO2 flooding.

There are two kinds of CO2 flooding processes: miscible flood, in which the gas is injected at or above the minimum miscibility pressure (MMP), becoming miscible in the oil when it begins extracting large amounts of heavier hydrocarbons; and immiscible flood, in which gas flooding takes place below the MMP, maintaining reservoir pressure and increasing the rate of production (ROP).

The pressure required to achieve dynamic miscibility with CO2 is considerably lower than the one required for other gases such as natural gas and nitrogen. In addition, CO2 injection allows for increased extraction of heavier hydrocarbons.

“Experience gained from CO2 flooding worldwide indicates that enhanced oil recovery by using CO2 as injection gas may result in additional oil ranging from 7 to 15 per cent of the oil initially in place,” a study by the Norwegian University of Science and Technology (NTNU) on the potential of CO2 injection in the NCS states.

While the future of gas injection seems to lie with CO2 injection, the process has its downsides, as big investments are required in order to build new pipelines from the gas source to the target basin as well as corresponding gas plants which separate the CO2 from the product stream. In addition, the potential threat of lower oil prices will likely keep smaller oil and gas companies at bay and force them to opt for comparable gas injection techniques which are more economically sustainable. Nonetheless, according to the DOE, CO2 flooding boasts added environmental benefits: “Utilizing an industrial source of CO2 for EOR costs more than using natural sources, but this approach adds the benefit of capturing and sequestering CO2 emissions.”

Thermal recovery

Thermal recovery is especially suitable for shallow heavier crudes (at less than 900 metres) whose levels of viscosity are a deterrent for commercial oil production rates. Heat is applied to the oil to increase its temperature, which then reduces its viscosity and increases its flow.  This technique was first applied in Venezuela in the 1960’s and now accounts for more than half of all EOR used in the US, particularly in California, North and South Dakota, Alaska, Texas and Wyoming.

The most frequently used thermal techniques include: steam injection, where hot fluids such as steam, water or gases are continuously injected into the reservoir; cyclic steam stimulation, where the well is shut in following steam injection to allow it to heat the producing formation; and in situ combustion, also known as “fireflooding”, which creates a combustion zone through air ignition that then moves toward the production wells.

In steamflooding, the high-temperature steam injected into the reservoir transfers heat to the formation and makes the heavy oil less viscous. The heavy oil suffers expansion, which enables its release from the reservoir rock. As the heat is condensed into hot water, both steam and hot water push the oil to the production wells.

With cycle steam stimulation, a certain amount of steam is injected at high rates into the wells, which are then shut in for at least 1-2 weeks to allow it to heat the area around the well bore and increase its displacement efficiency. Following this procedure, the wells are brought into production until the heat is released with the produced fluids.

Lastly, in situ combustion burns some of the oil by lowering an ignitor into the well. After this step, air is injected down the well to facilitate burning until ignition is accomplished, creating a combustion zone where temperatures reach approximately 600°C. The heater is then withdrawn while air flow is continued to maintain the advancing combustion front. Of the three processes, this is likely the most complex as it involves multiphase flow of flue gases, volatile hydrocarbons, steam, hot water, and oil.

Thermal recovery is expected to continue yielding considerable success in heavy oil and tar sands reservoirs where extraction is a challenge. However, much like CO2 injection, this technique is a process reserved for those with big pockets, as it involves expensive production facilities and leaves investors dependent on oil price volatilities.

Other less established but more economic EOR techniques are receiving increasing interest from the industry. These include microbial EOR, in which microorganisms improve the recovery factor in a given reservoir, and chemical recovery, where specific chemicals are injected to improve interfacial tension and mobility control.

In conclusion, even with recovery rates of 60 per cent, the potential for EOR is significant for large, intermediate and small scale companies alike. It falls on this technology to help the industry maximise its recovery rates, reach ambitious production targets and stabilise or even decrease oil imports, which in turn will sustain the global production of energy resources.

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