Case Study - Bualuang Oil Field (Gulf of Thailand)
13-year Fallow Discovery – Transformed to Developed Reserves >80 MMstb

Situation

The Bualuang field was discovered and tested by Sun International by the B7/32-2 well in 1993 and relinquished that same year. Soco International relicensed the block in 1997 and drilled 2 dry exploration wells to deeper targets. One of Advance’s team secured access to the field data from Soco in 2005 to re-evaluate the discovery. The evaluation showed that this flat, sandstone structure with a net:gross of 90% had a maximum oil column of just 21 m. Importantly the well test had been carried out with a downhole shut-in tool, which meant that critical transient pressure data was captured over 10 minutes between 2 and 12 minutes after the well was test shut-in[1]. Re-analysis of the test demonstrated that the reservoir had suffered skin damage[2] during 6 days of mechanical problems installing the tubing for the test. This explained why the well had produced at a maximum rate of only 750 stb/d, when combined with an in-situ oil viscosity of 9 cP and a very low GOR of 10 scf/stb.

 

This low maximum oil rate in an offshore location coupled with a small oil column led to the asset being dismissed as a potential commercial development for 13 years.

The STOIIP of the Bualuang discovery was re-evaluated at 70 MMstb. It was determined that the discovery well had penetrated the structure at the crest, with the deeper section of the well having encountered oil on the eastern side of the Bualuang bounding fault. This implied that there was another, separate oil accumulation on the eastern side of that fault that merited appraisal.

Solution

Those critical, early 10 minutes of pressure data unequivocally demonstrated that the reservoir permeability was 6 Darcies, and that with zero reservoir damage the productivity index (PI) of the discovery well would have been ~20 stb/d/psi. This meant that with a pressure drop at the reservoir of 500 psi using an ESP[3] the discovery well had the potential to produce at 10,000 stb/d – more than 10x the maximum rate achieved via natural flow during the actual discovery well test.

A reservoir simulation model was built to develop a production forecast by placing horizontal producers along the crest of the structure[4] with ESPs installed from 1st oil. The combination of a flat structure, a relatively small oil column and an in-situ oil viscosity ~10x that of water meant that the development plan would have to cater for early water production, which would increase quickly. Hence, the horizontal producers were designed to be able to produce up to 10,000 bbls/d, with an initial, gross facility fluid throughput of 35,000 bbls/d. In effect, Bualuang was going to be a ‘water’ field with some oil production, exactly as expected.

The re-evaluated reserves for the Bualuang accumulation were ~20 MMstb.

On this basis a farmin deal was concluded in 2006 by the Advance party with Soco in conjunction with a Canadian listed company to develop the field.

Result

The field came on production in 2008 and quickly ramped up to 10,000 bopd, as predicted.

In time Salamander became the Operator and 100% owner of the Bualuang field, followed by Ophir and more recently Medco.

The oil accumulation on the eastern side of the Bualuang bounding fault identified as part of our 2005 re-evaluation was eventually appraised, proving the presence of additional reserves. Further, the reserves in the original Bualuang accumulation increased in time towards the P10 volume estimated by our 2005 re-evaluation.

Ophir reported in 2020 that the combined ultimate recovery for the asset would exceed 80 MMstb. At that time the field production was 12,500 bopd with a gross throughput that had been increased to 75,000 b/d (i.e. >63,000 bwpd).

If one assumes an average oil price of $50 across the life of the Bualuang field that translates to >$4 billion of gross value creation from what was a 13-year old fallow oil discovery in 2005. This case study defines Advance’s strategy in terms of unlocking value by applying a deep technical approach to deliver a fit-for-purpose development designed to maximise oil recovery from an overlooked asset.


[1] None of the previous evaluations available from Soco had noted this critical insight.
[2] The technical term is ‘skin’, which, if positive, reduces well productivity.
[3] ESP – Electrical Submersible Pump
[4] There was provision for water injection wells if the expected infinite aquifer was found to be insufficient.