The Aghar gas field is among large onshore gas fields in Iran. It is currently producing 20 mcm/d of gas. The Iran Central Oil Fields Company (ICOFC), which supplies more than 40% of Iran"s total gas, is in charge of development of the Aghar field.
Aghar was introduced along with other fields to foreign investors to undergo development under the newly-coined Iran Petroleum Contract (IOC) model. The second phase of the Aghar field, with a recovery rate of 71.5%, is an attractive investment project.
The annual growth in domestic consumption, as well as international obligations for gas exports to Turkey, Iraq and other neighboring countries has always led the Iran"s Petroleum Ministry to envisage gas production hike as a priority.
The Aghar gas field is located 110 kilometers southeast of Shiraz and 35 kilometers southeast of Firouzabad in Fars Province.
Discovered in 1972, the Aghar field has now 16 wells, 13 of which are producing gas.
Gas production from Aghar began in 1999. Natural gas and condensate are separated after production to be delivered to the Farashband gas refinery for processing through two pipelines. Each pipeline is 90 kilometers long.
The second phase of the Aghar gas field is to undergo development to double production to 40 mcm/d. Planning has been done for the second phase development of the Aghar gas field.
Aghar Gas Output Up
In parallel with the plan to double the Aghar gas output, installations would be built near the Farashband gas refinery for processing.
The gas produced at the Aghar field is planned to be injected into southern oil fields, including Maroun. This gas field has wellhead facilities, four gas gathering centers, pipeline to carry gas from wells to central facilities and finally the Farashband refinery, a gathering and separating center, controlling room, pumping station, and pigging systems.
The Aghar gas production capacity stands at 95.22 mcm/d of natural gas. It also supplied 4,300 b/d of gas condensate.
Studying the Aghar gas field implemented with a view to updating previously conducted studies, incorporating new findings and completing previous studies through interpreting and assessing petrophysical diagram, and modelling of fractures. The studies, which lasted four years, were led by the Department of Reservoirs Studies. The main finding of these studies is that the field"s in-place gas deposits are up 40%.
The final recovery of over 71% of in-place reserves of this field has been done. In the natural depletion scenario, in light of wellhead pressure restrictions, the final recovery rate is set at 34.7% with a production ceiling of 22 mcm/d by 2023, when the installation of a compressor would bring the recovery rate to 71.5%.
Chief among studies conducted are: drilling operations to enhance recovery and preserve the production ceiling, carrying out periodical static tests, appraisal wells drilling, PGF output phase increase to 30 mcm/d and the optimal scenario after installing compressor and spudding six new wells for reaching the production ceiling of 30 mcm/d.