After the initial excitement following an oil or gas discovery, the new field is appraised to see if it meets the volume & production rates required for commercial viability. If it does (and many don’t) the discovery is sanctioned for development. This is a major hurdle, often involving a commitment to spend billions of dollars, and can take years. Eventually, the payback starts with “First Oil”, that first drop from the new facility. Production is then gradually built up to a plateau rate – the main, middle-age, of a field. Over time subsurface conditions will no longer be able to support this rate of extraction, even with a host of man-made assistance, and the production decline phase begins. In most cases this decline is managed carefully to extract every last drop of oil possible, yet eventually, in every field, the economic limit is reached and the field is abandoned.
Such is the life of an oilfield.
- As of the latest reliable figures (2005) there were around 47,500 oilfields globally.
- Approximately 35,000 of these are in the US (these figures predate the shale plays), and 12,500 are outside of the USA.
- Of the total, only 507 are considered Giant Fields (>500mmbbls recoverable).
- Of the 507 Giants, just 100 account for over 50% of daily global production, and nearly all of these fields are old and in a mature decline phase.
In aggregate, many countries, including Nigeria, Venezuela, Mexico, the UK, Oman, and Egypt are in decline. It should be noted that until the Unconventionals revolution, the US was also considered in terminal decline. Unconventionals are an important and fascinating story, but beware the hype – they’re not the answer to all our ills.
The global rate of decline strongly defines the required rate of future discovery and production if global oil and gas demand is to be met.
Whilst it is generally easy to define the decline rate of an individual oilfield, the data is not widely available. As a result, the global decline rate is a matter of genuine debate. With multiple types of field, different Operators, different fiscal, technical, and commercial regimes, and different decline management methods, there are many variables.
Can anything be confidently stated about the average rate of conventional oilfield decline?
- A commonly quoted global decline rate is from CERA: 4.5%. This figure was calculated from an analysis of 811 large to giant size fields, covering ~66% of global production.
- CERA notes that most production is from large fields, and that these fields tend to produce on-plateau for longer and to decline at a slower rate than smaller fields. Additionally, they state that offshore fields decline faster than onshore fields.
- CERA calculate that 41% of modern production comes from fields that are in build-up or on-plateau. They use complex averaging with the 59% of fields that are in decline to create the future 4.5% decline rate.
- The IEA 2008 World Oil Report concentrated on defining future decline rates. They published a production-weighted average decline rate worldwide of 6.7% as of 2007. This is predicted to rise to 8.6% by 2030 as more and more old giant fields pass their plateau and start to decline, and the long tail of global production shifts to smaller more rapidly depleted oilfields. As of the IEA 2010 World Oil Report (the latest freely availble) the IEA stood by these predictions.
- IEA uses IHS data. Decline rates are calculated for all fields in the database (including 798 “giants”). The overall decline prediction method may over-state decline rates, as pre- plateau fields have an assumed rate.
- The IEA differentiate between Natural Decline (9%) and Observed Decline (6.7%), the difference being attributed to field interventions such as infill drilling. In total they calculate a 5.1% decline for 580 fields post-peak, and 5.8% for 479 fields post-plateau. The total is adjusted to account for thousands of smaller fields not included in their dataset to reach the 6.7% number.
- IEA observe that Non-OPEC fields, with fewer Giant and Super-Giant fields, decline at a faster rate than OPEC fields. Additionally, offshore fields decline at faster rates than onshore, and deep-water fields decline at a faster rate than shelfal fields.
- Another data source containing decline rate analysis is a PhD thesis by Fredrik Robelius from the University of Uppsala in Sweden: Giant Oil Fields – The Highway to Oil, Giant Oil Fields and Their Importance for Future Oil Production (2007). Some of the diagrams on this page come from this thesis and subsequent papers.
- A recent paper of Robelius’ in Energy Policy (Giant oil field decline rates and their influence on world oil production) states that currently the average (mean) annual decline for the world’s giant oil fields is ~6.5%, with a production weighted average of 5.5%. He also notes that offshore giant fields decline at almost 3 times the rate of onshore fields. Another key observation is that average decline rates increase over time, as more and more oil fields reach the depletion stage (note that this is less marked on a production weighted basis, as, by definition, the best producing fields decline the least…). Robelius states that the difference between using a static decline rate vs. an increasing decline rate is as much as 7Mb/d by 2030.
What About Unconventionals?
Unconventional hydrocarbon resources are still a new segment of the industry, and the industry is still learning. However, some information regarding well depletion rates is escaping into the public domain and this suggests that, in the absence of significant drilling, Unconventional fields decline at much higher rates than conventional fields.
David Hughes of the Post Carbon Institute has published an analysis of Unconventional Production called Drill, Baby, Drill. Whilst some in the oilfield and on the Right may suspect this work simply based on its association with the Institute (and its somewhat political title) it is a serious analysis and contains a number of interesting illustrations. Currently it is one of the best documents in the public domain describing Unconventional decline rates from various plays, and it indicates some significant decline rates.
One example of Unconventional oilfield decline is illustrated by wells drilled in the Haynesville play prior to 2011, which exhibit an overall decline of 52% to 2012. In the absence of additional 2011-2012 drilling the Haynesville play would today be producing half of its 2011 production.
The result of these incredibly fast decline rates is that the industry needs to keep drilling, at pace and scale, for the play to continue to deliver hydrocarbons. Eventually the industry will simply run out of new wellsite locations, and in the absence of re-fracking technology, subsequent production will drop off extremely rapidly. When these plays shut down, they will shut down quickly, and from a policy and commercial point of view almost without warning.
Average decline rates for US Shale Gas plays, again analysing wells drilled prior to 2011 yield similarly fast decline rates.
A similar story is illustrated for Shale Oil plays such as the Bakken.
In short, the decline rates for Unconventional “fields” are significant in the absence of drilling. These plays are contributing significant volumes into the US and world energy markets, but the industry and the economy should be mindful that the boom can quickly turn to bust.
Production Decline Rates: Conclusions
- Current analysis suggests that global oilfield decline rates range from 4.5% – 6.7% per year.
- The rate of decline is increasing with time.
- Non OPEC fields decline faster than OPEC fields.
- Offshore fields decline much faster than onshore fields.
- Deepwater fields decline faster than shallow water fields.
- Unconventional fields decline much faster than conventional fields.
What can be done to arrest conventional oilfield production decline?
There are a number of methods that can be used to arrest the production decline of mature conventional oilfields, including careful management of production, infill drilling, workovers, and secondary recovery.
An additional benefit of these decline management techniques is that they not only minimise the decline profile, but they also increase the effective size of the field. Whilst it will never be possible for all of the oil present in a discovered oilfield to be produced (Original Oil In Place, OOIP), the recovery rate can increase and that increase means that more oil will be produced over the life of the field. Thus if you increase the recovery rate, the field effectively gets bigger…
There have been many backward looking field size changes in the modern history of the oil industry. One average from the UK illustrates an approximate 20% backward uplift to booked reserves at development sanction.
In public presentations BP has implied a global recovery factor of 33%. Increasing this to 40% (enhanced oil recovery (EOR)) would be quite effective “exploration”…
- Thermal/Steam can recover heavy oils in good reservoirs above 900 metres depth. These methods can increase reserves considerably (add up to 40% of OIIP to recovery). California, Oman, some Persian Gulf fields, Venezuela (not tar sands) and Brazil are examples. Chevron is a technology leader among the western major oil companies.
- Miscible non-hydrocarbon gas injection (CO2, N2) can recover light to medium oils in poor reservoirs (few fractures). These methods can add 8-17% of OIIP to recovery to reserves. Permian Basin USA, & some Persian Gulf oil fields are good examples.
- Water and gas injection can recover light-medium oils in good quality reservoirs. High recovery rates are achievable (>65%). These techniques are already in widespread use.
- An additional technique is LoSal (low salinity water injection) that is currently being deployed by western majors such as BP.
To meet future global demand, some of the most important work will actually be in getting more oil from existing fields.
BP have published a Prudhoe Bay example, illustrating the effectiveness of the techniques.
Prudhoe Bay peaked in 1989, twelve years after it began production. Since then, the number of wells in the reservoir has almost tripled. Prudhoe Bay currently uses gas injection and other secondary recovery techniques to keep production as high as possible. Decline rates at the wellhead average about 20% and the net decline of the entire field is now about 10%, thanks to an exponential increase in the number of producing wells. In 2001, Prudhoe Bay’s production was estimated to be around 550,000 barrels per day, 12 years after it peaked at a production rate of 1.5 million barrels per day.
EOR at Prudhoe Bay
Prudhoe Bay Production (Simmons)
Saudi Aramco’s 2002 budget called for spending $1.5 billion on development drilling, a 50% increase over its 2001 budget. This money was spent drilling 324 wells, over half of which, 125 of a total of 211 wells, were at the giant Ghawar field.
EOR Potential in OPEC
It’s worth noting that, even in BP’s cherry-picked Prudhoe bay example above, EOR added significant reserve volume but did not reverse production decline decline. In fact, fields that have experienced extensive EOR techniques tend to decline very rapidly when the bell finally tolls. In Mexico, Cantarell declined faster than the government’s (and industry’s) most pessimistic forecasts when it finally reached decline.
Enhanced Oil Recovery in Conventional Oilfields – Conclusion
Enhanced oil recovery techniques in conventional fields are often quoted as a large component of future supply. However, any decline arrest upside has to be an additional, new technology as the tried and tested techniques already in use at many fields are captured by the existing global decline statistics…
Furthermore, if technological breakthroughs are made, the industry must remain vigilant for extremely rapid declines at the tail end of fields that undergo marked EOR intervention.
What can be done to arrest Unconventional oilfield production decline?
The short answer is that we don’t know yet. Technological progress is made every month in the Unconventionals sector, with advances in propant and fracking technology. However, the clear long term goal is re-fracking. Is it possible to re-frack an existing Unconventional well, and if you do, what sort of production rate and decline do you get? How many times can you re-frac? What are the environmental considerations?
The answers to these questions will be critical to both long term Unconventional economics and the future of global oil supply…