In some of Iranian oil reservoirs gas is injected for pressure maintenance as well as displacement of oil by gas. In some of these fields, it comes to a premature breakthrough of injected gas due to high permeability in some regions of the reservoir or because of the geometry of the reservoir.

Foam injection appears to be a promising tool in solving the problem with thief zones and low recovery from EOR methods such as immiscible gas injection in Iranian oil reservoirs. It can also mitigate the effect of gravity override and achieve increased displacement efficiency in these reservoirs.


Field application of foam is becoming a proven technology, surfactant costs withstanding, to control the mobility of gaseous phases in porous media. Foam has been employed in large number of documented field trials world wide [1].

Typical applications span from steam and co2 foam to alleviate gravity override and channeling, production well treatments to reduce GOR, to gelled-foams for long-lasting plugging of high permeability channels. Foam processes have also been studied and field tested for use as groundwater aquifer clean up methods [1].

Foam has been employed in more than 30 documented field trials world wide, mainly in the USA. In the North Sea, foam has been tested in production well treatments both on the Oseberg field and on the Snorre field in the Norwegian sector, and on the Beryl-field in the British sector. Late in 1998, a large injector treatment started on Snorre, involving injection of almost 1000 tonnes surfactant [2].

In the present work, foam is injected into the reservoir and then using a field-scale simulation study, we investigate the effect of foam injection on gas mobility and oil recovery improvement. The obtained results reveal a significant incremental recovery. Gas breakthrough is also retarded remarkably.

Geological Overview of the Field

The M field was discovered in 1962/63 and subsequent drilling has confirmed two reservoirs (Asmari and Bangestan). This simulation study is concerned only with the shallower Asmari reservoir.

It was put on production in 1974. A total of 47 wells have now been drilled on the field, of which 12 are dedicated to producing the Asmari reservoir and one well utilized as an observation well.

The Asmari formation is recognized as a regionally extensive geological unit, and it is known to contain a number of large oil accumulations; one of these is located at M field. Despite some complex reservoir lithology, there is good evidence of pressure communication within the Asmari between some of the different accumulations around the Ahwaz area. This is associated with a strong subsurface aquifer system.

The structure is a northwest-southeast trending asymmetric anticline. It is defined by seismic with no surface expression, and it is located on the Khuzestan plain. This area slopes gently at a rate of 1 m in 5 km to the southwest between Ahwaz and Khorramshahr. The M structure is located some 60 km north of the Persian Gulf.

The Asmari structure covers an area 42 x 5.5 km at the mapped spill point (around 2,400 mss). The hydrocarbon- bearing reservoir covers an area 30 x 3 km with the reservoir crest located at 2,144 mss.

The M structure has a dip of 6 to 8° and 5 to 6° on the northeast and southwest flanks respectively. However, the dip decreases toward the southeastern and northwestern extremities.

The first field study for the Asmari was prepared by BP in 1974 using 3 wells. That study divided the Asmari into 5 units.

  • Zone 1: Upper carbonate

  • Zone 2: Upper sandstone

  • Zone 3: Middle carbonate

  • Zone 4: Lower sandstone

  • Zone 5: Lower carbonate

In 1978 Shir Mohammadi reviewed the reservoir and separated it into 8 zones. Zones 1, 6 and 8 were mainly carbonate whereas Zones 2, 3, 4 and 5 were mainly sandstone, and Zone 7 was locally sandy.

Zone 1: Carbonate rocks.

Zone 2: Sandstone (mainly).

This content is only available via PDF.
You can access this article if you purchase or spend a download.