Kumar, Kamlesh (Petroleum Development Oman) | Awang, Zaidi (Petroleum Development Oman) | Azzazi, Mohamed (Petroleum Development Oman) | Hamdi, Abdullah (Petroleum Development Oman) | Hughes, Brendan (Petroleum Development Oman) | Abri, Said (Petroleum Development Oman)
The microporous rock types in Upper Shuaiba are low permeability ( 1mD) rocks occurring in thin (2-5 m) formations within the extensive Upper Shuaiba carbonate formations in Lekhwair. These microporous rocks constitute a significant volume of hydrocarbon in-place. Unlike the higher quality rudist-rich and grainstone rock types, appraisal pilots in the microporous areas have shown poor performance with waterflood development, which is the preferred development concept in the entire Lekhwair field. Two work streams are active in parallel to identify a technically and commercially feasible development option: Phase 1, technology trials to enable a successful waterflood implementation, and Phase 2, further studies to screen the potential of enhanced oil recovery (EOR) techniques and other light tight oil development. The technology trial work stream, initially considered four initiatives targeting injectivity improvement. To date, trials are complete for abrasive jetting and designer acid stimulation, early results are available for Directional Acid Jetting, and evaluation of Fracture Aligned Sweep Technology (FAST) is ongoing with hydraulic fracturing evaluation accelerated to Phase 1 due to synergies with the FAST evaluation.
It is well established that some of the carbonate fields in the Central Luconia Gas Province, Sarawak, Malaysia, have been subjected to karstification as demonstrated by sometimes severe drilling losses. Although significant progress has been made mapping and predicting these karstification features on seismic, there is quite some uncertainty left on the exact size and occurrence of these features. Furthermore there is little known about the impact of karstification on GIIP and water breakthrough.
For the field with the largest discovered GIIP in the Central Luconia Province, karstification was seen as the largest contributor to GIIP uncertainty. GIIP uncertainty was large, with a 40% difference between high and low cases, despite a long history of production. The field has been on production since 1987 and more than 60 % of the GIIP have been produced to date.
For the redevelopment study that kicked off in 2007, a 2006 repeat 3D seismic swath study gave information on the 2006 Gas Water Contact. Good quality 3D seismic attribute data enabled identification of karst features that were incorporated in reservoir modelling. This, together with the good reservoir surveillance data, made this field the ideal candidate for studying different aspects of karstification that are also relevant to the other fields in the area. Important questions are when did karstification occur, what is its morphology and most importantly, what is its impact on ultimate recovery?
Dynamic history matching and synthetic seismic data provided a means to sense check assumptions for karst dimensions and associated reservoir properties. As a result this detailed study work has not only reduced the uncertainty in GIIP and ultimate recovery for the field but will also help to improve understanding of the impact of karstification on reservoir performance of other Miocene carbonate fields.
Air injection is an Enhanced Oil Recovery (EOR) technique with limited exposure in the Asia-Pacific region and no previous application in Australia. Analogy with successful air injection projects in the USA, suggests that it could be a suitable EOR process for onshore light oil fields in Australia; no evaluation has been conducted to date.
Using open file data, high level screening criteria are used in this study to identify prospective petroleum basins, and an individual candidate reservoir is examined through a simulation study. Key issues in the application of the technique are discussed, as are directions for implementation in Australia.
Air injection involves the continuous injection of high-pressure air into the reservoir. The oxygen in the air reacts with the reservoir crude, consuming 5-10 % of the Original-Oil-In-Place (OOIP) and generating flue gases in-situ. This creates a gas drive process and acts to re-pressurize the reservoir. The process does not require water as a mobility control agent; a significant advantage in water-scarce Australia. It could also replace hydrocarbon (HC) miscible floods, freeing cleaner HC gases for energy use. Ideally the process is suited to deep, high-temperature, light oil reservoirs, and is applicable to both secondary and tertiary recovery.
The Cooper-Eromanga Basin, Carnarvon Basin (Barrow Island) and the Surat-Bowen Basin were identified as the most prospective. The simulation study conducted for ‘Reservoir A' in the Cooper Basin indicated the potential for spontaneous ignition and propagation of a stable combustion front within the reservoir; hence it is a potentially good candidate for EOR by air injection.
Given the ‘high' oil price and maturity of Australia's oil provinces, significant value is associated with EOR. Air injection is potentially suitable for Australian onshore application. The process warrants further evaluation and consideration as an alternative to accepted EOR techniques.