10 lessons from a decade of exploration
Finding big oil has got harder. An industry veteran has some advice
International conventional exploration over the past decade has been a rollercoaster ride, beginning with optimism fuelled by an oil-price bonanza and new oil provinces opening in Brazil, Ghana and Uganda. This stimulated a frontier exploration drilling boom, and the creation of a new generation of exploration companies. It has ended with an oil-price crash, dramatic cuts in exploration budgets and soul searching across the industry.
Reflecting on the past 10 years, the following are 10 lessons this observer has learned from watching and analysing the industry. Few are new and many may sound obvious but collectively, the industry seemed to forget or ignore them. The lessons have been grouped under the headings of business environment, technology, exploration processes and philosophy and creating commercial value.
1. The next big oil province is proving very elusive
Of the 13 significant oil plays to emerge since the 30bn-barrel pre-salt find in Brazil in 2006, from more than 330 frontier-play tests, only five have so far resulted in oil discoveries exceeding 1bn barrels and none has yet bettered 3bn.
Does this reflect the scale of remaining oil plays left to find (leaving aside the Arctic). Has the industry been looking in the wrong places and does it not have the technology to find them or are they simply not there? If it's the last of these then exploration strategy should be adjusted accordingly. A fast-follower strategy, capturing acreage after frontier discoveries are made is not possible if new emerging plays are small and already licensed pre-drill. Companies will either take the frontier risk or choose to buy their way into frontier discoveries, like Woodside did recently in the SNE play in Mauritania.
2. Try not to follow the herd: it is expensive
The inability to invest counter-cyclically in exploration leads to inflated access and exploration costs and over-commitment to drilling with consequent degradation of performance.
A good example was the industry behaviour in the Kwanza Basin in Angola. In the pre-salt Kwanza play, 14 separate 5,000-square-km licenses were awarded and tested in the Kwanza Basin in 2010-2011 hoping to find an analogue to Brazil's pre-salt Santos Basin play on the conjugate margin in Africa. The Cameia discovery in 2012 looked promising but the play turned out to be restricted to only two licenses and commitments to drill wells were made outside the working play fairway. More than $4bn has been spent drilling 28 exploration and appraisal (E&A) wells (likely more than $8bn in total) and over 1bn barrels discovered for as yet no commercial return.
A second example is the 31 wells committed in Brazil's 11th licensing round in 2013. The round took place following initially promising well results on trend at Zaedyus, in French Guiana, but before several further unsuccessful E&A wells were drilled there, effectively writing off the analogue play.
3. Picking the winners is extraordinarily hard
Several specialist exploration start-ups played important roles in opening new plays, including Kosmos in Ghana and Cairn Energy, which blew $1bn in Greenland before discovering SNE in Mauritania. A few new super explorers were created, funded to be able to compete to access the best acreage. OGX, Cobalt, HRT and African Petroleum between them raised $10bn in equity but all failed either technically or commercially or both. OGX raised $4.2bn at an IPO in 2008, claiming over 4bn barrels of discoveries, which turned out to be less than 200m, and was declared bankrupt in 2013. Cobalt raised over $4bn and was successful technically, finding a net 1bn barrels in the US and Angola, but has not been able to realise any value from the discoveries and struggles with $2.7bn of debt.
4. There are no silver bullets
High-tech geophysics and geology need to be better integrated and too many wells were drilled with apparent geophysical support but without a convincing geological model. Both are needed for success.
There is an old saying that a drunk uses a lamp post more for support than illumination. At times, it has felt the same for explorers and seismic attributes. Some direct hydrocarbon indicators are effective in reducing exploration risk-notably flat spots and amplitude conformance to structure. Others like amplitudes and AVO have proved unreliable.
5. More gas than models predicted in deep-water basins
The big new emerging deep-water gas provinces were in basins where frontier explorers were hoping to find oil—East Africa, Mauritania/Senegal, the Eastern Mediterranean, and Colombia. Partly this is due to the geophysical techniques used in deep-water exploration, which tend to highlight gas rather than oil. Partly it reflects weaknesses in basin models with heat flow higher than expected or oil-prone source rocks being absent.
Exploration process and philosophy
6. Quality through choice
It has become a mantra, but exploration performance has improved markedly as the drilling count has fallen in 2016-2017. As the exploration budget has fallen dramatically in the downturn, the industry had to be more selective on the quality of the prospects to drill. During the boom, the industry was drilling too many wells for the quality of the prospect portfolio available to it. Increased competition made it harder to capture sufficient acreage to build up the size and quality of prospect inventory required for the desired level of drilling. The well count should reflect the quality of the prospect portfolio and not be driven by over-commitments or rig contracts.
7. Challenge conventional wisdom with good geoscience
Witness Johan Sverdrup, a 2bn-barrel discovery made in 2010—40 years after the first license ever issued in Norway. Or take Jubilee, a 1bn-barrel discovery on the transform margin in Africa; or Eni's discovery of Zohr's 16 trillion-cubic-foot of gas in an isolated carbonate build-up offshore Egypt. Each involved the use of a sound integrated geological model before drilling.
8. A lookalike is not the same as an analogue
Following the Jubilee discovery in 2007, 40 frontier-play tests were drilled in prospects that "looked like" Jubilee, at a drilling cost of $4.2bn, before the Liza oil discovery was made in Guyana. The industry piled into the Kwanza Basin in 2010 chasing a Santos Basin pre-salt carbonate analogue. Understanding why the discovery worked in the first place is the key to repeating success.
9. Know when to pause
Recognise early when a play is not working commercially, even when the geology initially looks promising. Exploration success is difficult to sustain. Some of the least successful explorers in recent years were feted as the best explorers a few years ago. Lundin Petroleum discovered the giant Johan Sverdrup field in 2010 and has just drilled its 22nd consecutive dry or non-commercial wildcat. Tullow Oil, successful in frontier exploration in Ghana and Uganda in 2007 went on to record exploration write-offs between 2012 and 2016 of $4.7bn, roughly equal to its net debt at the end of 2016.
10. Focus on commercial success
There has been an alarming gap between technical and commercial success: only one in six discoveries made in prospects judged high-risk pre-drill were potentially commercial. Better pre-drill calibration of risk and volumetric uncertainty is needed. In some cases, turning commercial discoveries into revenue has also been a struggle, for example in Uganda and Kurdistan.
A lot of capital and human effort was wasted in the past decade through ignoring these lessons. In the weaker oil-price world of today, with competition from low-cost unconventional oil and gas, the industry no longer has that luxury.
Keith Myers is president of research at Westwood Global Energy Group