Production Profile

The semi logarithmic graph below shows the production performance history since first oil in 1992 and the forecast from year 2008. Theoretically, in year 2030, the cumulative production would be 57 million barrels. However, that figure may never be reached due to higher operational cost and fields reaching their economic limit much earlier than technically predicted.





Kutubu Field (PDL2)

The Kutubu oil production started in June 1992 after the first oil discovery in Iagifu-8x well by Chevron in 1986. Since production started, the PRK's share of 17 years oil production reached a total of 20 million barrels. The production continues to experience natural decline and producing at an average rate of 1,148 bbl/d. This rate is expected to increase or sustained after a number of work-over on existing wells and infill drilling over the next 6 to 12 months.

Gobe Field (PDL3 & 4)

The Gobe Main and SEGobe oil production started in 1998 to feed into a designed production capacity of 50,000 bbls/d. Unfortunately, after a short period of operation, the oil production was severely affected by early production of sand and this necessitated installment of sand controlled techniques which meant the production rate had to be reduced to produce at a critical rate of pure oil production. The PRG's share of the produced to date reached a total 1.2 million barrels of crude oil. The fields are expected to reach their economic limit and ready for field abandonment before the first shipment of LNG cargo in 2013, while Kutubu and Moran fields will continue to produce oil. The current average oil production is 150 bbl/d. The two fields are experiencing rapid production decline while water production reached an average 90%. This water production has impacted oil production while operational cost of handling water has increased which in turn has affected the cash flow situation for both fields. The Gobe Main field is expected to reach its economic limit much earlier than the SEG fields but both fields will be shut down before the LNG operation begins. The trigger point for field abandonment is expected in 2009.

Moran Field (PDL5)

The Moran reservoir is different to Kutubu or Gobe fields in terms of the type of oil deposit and its stored natural energy for oil production. The field had no initial gas cap or free gas when the wells were first drilled into the reservoir. All the gas were in solution with the oil. When the field was put on production in 1998, the reservoir pressure declined rapidly until it reached the bubble point pressure. As production continued below the bubble point pressure, more gas has come out of solution with the oil. The released gas has migrated to the top of the reservoir forming secondary gas-cap and this resulted in slowing the rapid pressure decline of the field. However, the secondary gas-cap is not big enough to push oil into the well bore so most of the injection gas for Moran fields comes from Agogo field. The Agogo gas volume injected in Moran is well documented and accounting is updated on a regular basis to avoid gas ownership dispute in the future, particularly during LNG development and operation.

Like other oil fields, Moran's oil production has started to decline. Continued oil production is dependant on gas injection because the wells cannot produce on their own as they need the energy support from gas injection. Since first oil, the PRM's share of production has reached 1.06 million barrels and currently producing at the maximum rate of 400 bbl/d. Moran has more remaining oil reserves than the rest of the oil fields but production rate is similar to the daily rate in Kutubu field. About 95% of the production is supported by gas injection into the crest of the reservoir structure. Really, this field is on life support by gas injection even though it has the largest remaining oil reserves.

North West Moran Field (PDL6)

The NWMoran oil field is economically very marginal and initially contained far less than 1% of the total Moran Field oil. Most of the oil has been produced and there is not much oil left for continued production. There is also not much gas available to meaningfully contribute to the LNG Project. The PDL6 was granted by DPE not because of any meaningful oil or gas deposit there but done in response to landowner demands because a separate PDL attracts development grants and other benefits by law which they witnessed happening in other fields. If NWMoran were to come into this project, it can only contribute 0.00046% of the total gas envisaged for the PNG LNG Project. In 30 years its total net cash revenue would be no more than US$0.3 Million. That's how big this field is in terms of gas reserves.