--> Deepwater Exploration and Production in Crisis — Impact and Solutions

AAPG/SEG International Conference & Exhibition

Datapages, Inc.Print this page

Deepwater Exploration and Production in Crisis — Impact and Solutions

Abstract

Abstract

Deepwater exploration had been on the ascendency – but its dominance is now threatened. We estimate that 29 large greenfield deepwater projects, representing over US$200 billion in capital spend, are being deferred across the globe because they do not meet stringent hurdle rates at lower oil prices. Why explore for more deepwater resource if the fields already found cannot be developed?

Over the decade 2005-2014, deepwater spend escalated more than three-fold from less than $15 billion to over $45 billion, while well numbers increased by less than 50%. Giant discoveries and high global oil and gas prices drove this increasing interest.

Ten years ago, deepwater volumes were discovered mostly in the giant tertiary deltas of West Africa and the US Gulf of Mexico. As these well-understood basins matured, explorers ventured into deeper waters, and targeted increasingly complex and deep reservoirs. As a result, costs rose and success rates in deepwater fell.

Falling oil prices led to cut-backs in exploration budgets. Deepwater E&A spend is estimated to be slashed from its 2014 peak of $45 billion to around $18 billion in 2016.

While this cut in exploration spend is dramatic, it is small in comparison with the cuts in future deepwater capital expenditure as operators defer final investment decisions (FID) on 29 major projects. These deferrals leave in the ground close to 16 billion barrels of oil equivalent (boe). Oil production is impacted by around 1 million barrels per day (mmb/d) by 2021, rising to 1.7 mmb/d by 2024.

Operators are aiming to reduce the costs of projects to ensure healthy returns at hurdle rates of 15% at lower prices, with planning assumptions shifting to US$60/bbl in the long term. Cost reductions are sought through the supply chain, by reducing the scope of projects, and by re-engineering. While we did not expect the sector to match the rapid deflation in US shale plays, many deepwater equipment costs, aside from rig rates, have proved to be more ‘sticky’ than anticipated. Safety standards and long lead-times are partly the cause. Local content rules and remoteness of location also hindered deflation in some regions.

To achieve the cost reductions that they are seeking, operators will need to do more to embrace standardisation. They will also consider reducing the scope of projects by just targeting the reservoir sweet-spots and leaving marginal barrels in the ground.

Shell's Appomattox field achieved FID in 2015. A new benchmark was set for deepwater breakeven price. It has an estimated NPV10 breakeven of $50/bbl, while the average for pre-FID deepwater projects is $65/bbl. The impetus for reducing costs has never been greater.