2 minute read
These are challenging times for upstream oil and gas, as the industry navigates unprecedented uncertainty. But the pain is not distributed equally. Growth from deepwater is much faster than from upstream overall, with production set to rise from 10 mmboe per day in 2021 (6% of global supply) to over 17 mmboe per day by 2030 (10%). We expect almost half of the oil and gas reserves being sanctioned for development over the next five years to be in deepwater. Exploration will doubtless add more.
The sector’s outperformance stems from its reservoir fundamentals. Deepwater is no place to tackle marginal rock properties or difficult fluids. With few exceptions, the industry has chosen to develop only its best reservoirs. These allow high flow rates and exceptional estimated ultimate recovery (EUR) per well.
So, how significant is deepwater’s upstream outperformance? Where are the most advantaged oil and gas basins? And what could impact the sector’s cost-effectiveness in the future?
This is the second in a series of insights using the power of our new Lens Subsurface Discovery solution to analyse the critical subsurface factors that correlate with reservoir performance and value. If you’ve yet to read it, you may want to check out our examination of reservoir properties’ influence on recovery factors in Advantaged resources need advantaged reservoirs.
A growing deepwater advantage
Deepwater's advantage over non-deepwater is spectacular, with each well producing substantially more reserves than development wells in shallow water or onshore. EUR in deepwater averages 12 mmboe for oil wells and 43 mmboe for gas wells. That compares with the global industry average EUR of less than 1 mmboe per well.
This advantage is about to get even better. Future deepwater oil fields will enjoy twice the average EUR of fields already onstream. And this is not a symptom of over-optimistic project plans overdue for a dose of reality. Instead, it largely reflects the industry’s recent exploration success, which has led to opening reservoirs in new basins such as Guyana and Brazil’s Santos which are the best EUR performers in the industry. Technology gains and portfolio highgrading are also contributing factors.
Higher EUR means fewer wells are needed. That’s critically important because deepwater wells and associated subsea equipment are expensive and typically amount to more than half of project capital expenditure. Fields with fewer wells enjoy lower costs, faster cycle times and better breakeven prices.
This economic advantage also correlates with carbon advantage. Most flagship, high-EUR deepwater developments now contribute strongly to corporate emissions intensity targets.