Prospectus re Admission to the Official List - Heritage Oil

RPS EnergyHeritage Oil – Competent Persons Report3.3.4.4. Impact of Operations on the Iranian Side and Unitisation.Following the drilling of the last Iranian well in the field (Henjam-2 in 2006), there has been no furtheractivity. However, NIOC representatives have placed in the public domain, comments and suggestionsconcerning the development as follows: The field is ‘‘jointly owned’’ by Iran and Oman; ‘‘85 per cent. of the produced oil should belong to Iran’’ depending on well locations.Other reports from the NIOC in Iran have provided details of an imminent development of the Henjamside as follows (published in a late 2007 article (5) ): It is planned to drill two wells and workover and compete well #2 as soon as possible. A 16’’, 40-kmpipeline is to be constructed from Henjam to Gheshm Island. Drilling operations would start soon with one rig, with a second rig would be provided in thenear future; Gas would be transferred to Gheshm. The oil would be separated on Gheshm Island and then wouldbe sent via 25-km pipeline to the 112-km line going to Siri Island. It was said that equipment and materials were en route to the field zone.We believe that negotiations on joint development continue (this was confirmed by the West BukhaOperator at the September, 2007 OCM). We believe and have assumed that: The Operator, Rak, has permission from the Omani authorities to proceed with the development ofthe Omani side of the field (6)The sides will eventually agree on a unitisation or a production splitThis split will be more like our distribution of STOIIP, namely: 62.5:37.5 Iran: Oman;Iran will eventually drill up its side the field or, if it does not, it will still receive some form of‘‘compensation’’.The stretch target for first oil is 3Q, 2008; we have assumed for our evaluation a range of start datesbetween 2Q 2008 in the p10 case and 1Q 2009 in the p90 case.3.3.4.5. Recovery MechanismsThe dominant recovery mechanisms in the reservoir are likely to be solution gas drive, fracturecompaction, oil expansion and a degree of aquifer influx. Such reservoirs are not good candidates for wateror gas injection because of the presence of pervasive fractures.RPS has used a range of technical recovery factors (‘‘RF’’s) ranging from 10 to 25 per cent. to reflect therecovery from similar reservoirs under natural depletion in the region, with slightly better RFs. RPS isaware of reservoirs in time-equivalent formations in the region that have recovered less than 10 per cent.over several decades, but these were developed inefficiently and intermittently using only vertical wells.3.3.4.6. Production ProfilesThe Operator commissioned a consultant to generate the profiles for its development plan using numericalreservoir simulation (7) . We have examined this work in detail and find that the p90 profile, in particular theinitial sustainable rate, is not supportable, as the location of the second well and the reservoir quality atthat location are as yet unknown, and the variation in same can be great. In addition, reservoir simulationnot corroborated by sustained production, and with limited data to constrain the model, is not whollyunique or dependable. To mitigate this risk, the Operator has studied fracturing and facies to optimise thelocation of the second well, but the deliverability (particularly long-term) of future wells remains uncertain.(5) Source: NIOC website article, 27 November 2007; this could of course be propaganda or posturing(6) There is precedent in the region, such as the giant North Field (Qatar) and South Pars field (Iran), which straddles the Iran/Qatar border and has been developed independently by each country.(7) The latest SPE et al. guidelines & auditing standards state that simulation is an accepted method of estimating futureproduction; however the validity of same is enhanced when there is sufficient production history to validate the model, andestimators must have an understanding of the limitations of simulation.90