Editorial

10 factors that influence upstream production shut-in decisions

How oil and gas producers decide when to shut in production

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Global oil and gas supply is at risk from falling oil prices and deep cuts to upstream investment. Production is also increasingly being affected by government and company measures to contain the spread of the coronavirus. Supply chain disruptions and restrictions on the movement of personnel are colliding with economic and strategic considerations.

While the ultimate depth of these cuts will depend on how long current conditions persist, we expect shut-ins this time to be much more material than the 2015/16 downturn. Further announcements and downward revisions are very likely.

We monitor the impact of coronavirus and the oil price crash on global upstream projects. Learn more about the Global Upstream Tracker.  

Or explore our interactive coronavirus map. It combines WHO data on coronavirus outbreaks and fatalities with Wood Mackenzie's comprehensive global dataset of oil and gas production and assets. It shows the location of affected assets and the nature of the impact, including production curtailment, deferral and shut-ins.  

How do oil and gas producers decide when to shut in production?

Asset economics are critical, but are not the only factor leading to production being shut-in. These decisions are complex and can take some time to reach. Most other options will be explored in the meantime, including negotiating with suppliers and lowering operating costs. Due to the complexities involved, the least economic production in an operator’s portfolio may not be the production that is ultimately shut-in.

Here we look at 10 factors that influence upstream shut-in decisions

Above ground

1. Corporate-level impacts are key. These include potential financial hedges, pipeline/supply commitments, Reserve Based Lending (RBL) borrowing bases, service contracts, contribution to central overheads, corporate cash positions, debt repayment obligations, and portfolio balance decisions.

2. The operational costs of shut-in can be high. Equipment rental charges and the cost of preserving equipment can deter shuttering of production. Onshore, where decisions could be made well-by-well, decisions are often made at the field level to prevent shifting fixed opex burden to smaller group of wells.

3. Egress or physical storage limitation issues can force shut-ins if tankage capacity cannot absorb excess supply, and can cause steady-state price differentials to vary widely.

4. Supply chain where niche or regional providers would be key to restoring production, operators may choose to continue operations.

5. Facilities and pipeline concerns mothballing equipment can lead to numerous operational issues on restart, including corrosion, blockages and leaks.

6. Contractual and legal considerations, including fixed royalty clauses, must-produce obligations, take-away capacity agreements etc.

7. Governments or National Oil Companies may prioritise security of supply, making shut-in of production difficult without damaging stakeholder relationships.

8. Partner consent is needed for many project consortiums; sometimes unanimous support is required.

Below ground

9. Restart costs: wells with high water cut and no gas support will likely require intervention to de-water the wells and restore production. For more mature assets, shut-ins can incur restart capital and accelerate abandonment liabilities.

10. Reservoir performance: some wells will actually benefit from a period of shut-in and re-pressuring, depending on duration. But the long-term viability of others could be jeopardised.

How are these factors playing out across the globe?

Some of these factors have regional nuances. For example, in the US Gulf of Mexico, we see low operating costs and little reason to voluntarily shut in. Here’s a selection of more in-depth coverage from our regional teams of upstream experts.

WTI trades negative: five things to know about shut-ins in the Lower 48

Shutting in wells is risky business. We outline five key issues – some strategic and some tactical – to help understand how this might play out in the Lower 48. Why? Shut-ins moved from rhetoric to widespread reality on Monday 20 April as May WTI went into the red, closing at negative US$38/bbl. Negative. Simply put, the paper and physical markets converged, albeit at a low volume.

Curtailments were already occurring on a small scale. ConocoPhillips upped the ante when it announced the largest Lower 48 production pullback at 125,000 b/d. And Permian producers were leaning on the Texas Railroad Commission to enforce pro-rationing. But the events of Monday 20 April overshadowed all that. Numerous physical markets took a huge hit too, so curtailing individual marginal wells will expand. Entire fields will close and large-scale choking of projects will commence.

Find out more about the five shut-in considerations for Lower 48 producers.

Shutting in Canada's oil sands: like reheated leftovers, the taste isn't the same

As coronavirus destroys demand and oil prices collapse, the Canadian oil sands are once again fighting for survival. Oil sands operators like Athabasca Oil, Suncor and ConocoPhillips have already announced production reductions and we expect to see further cuts through April and May as demand drops. There are two key considerations around potential shut-ins of oil sands projects for longer duration: capital requirements to restart and reservoir damage. Read more.

Which projects are being affected by the oil price crash and coronavirus?

The Global Upstream Tracker monitors and analyses announced and assumed shut-ins, and draws upon our global upstream, macro and real-time Genscape data and analysis. 

Subscribers also have access to Fraser McKay and his team of upstream experts. 

Contact an Expert

Submit your details to find out more about how we can help you and your organisation

Fraser McKay, Vice President Upstream Research

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