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David Yager

David Yager

Based in Calgary, David Yager is a former oilfield services executive and the principal of Yager Management Ltd., an oilfield services management consultancy. He has…

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Why Is Well Decommissioning So Slow In Canada?

Why Is Well Decommissioning So Slow In Canada?

The task of abandoning suspended or depleted wellbores and reclaiming the surface location - the modern title of which is well decommissioning (WD) - is back in the news, thanks to Saskatchewan Premier Brad Wall. On February 8, a news release indicated that the province had approached the federal government for $156 million in cash to facilitate WD on about 1,000 inactive wells in Saskatchewan.

Called the Accelerated Well Cleanup Program (AWCP), it was estimated that the expenditure would create about 1,200 direct and indirect jobs in an oilfield services (OFS) sector desperately looking for something to do in the face of massive capital expenditure reductions caused by the oil price collapse.

It was primarily pitched as a job creation program, however it certainly touched a nerve among those in Alberta who are watching the growing number of inactive wells in this province, from a variety of perspectives, for a variety of reasons.

The idea was the brainchild of Dan Cugnet, chairman of Valleyview Petroleums Ltd., an independent exploration and production (E&P) company from Weyburn. The news release touted the obvious environmental benefits resulting from WD. Premier Brad Wall added, “The federal government has indicated they are considering this proposal and I look forward to a favourable response”. The Prime Minister and Minister of Natural Resources were in western Canada earlier this month, promising financial assistance to oil producing provinces battered by low oil prices. This would be a job creation program which would create great work for OFS that would not otherwise exist and help E&P companies stay on top of their WD obligations at a time when they cannot afford to vigorously pursue this activity.

This announcement caused the media in Alberta to begin asking the provincial government if it would also be asking Ottawa for financial assistance for WD activities. That Saskatchewan would be requesting federal financial assistance for activities well-known to be the responsibility of the E&P company mineral rights lessee seemed to take everyone by surprise.

Clearly the Alberta government had not thought of this when it issued the traditional response that WD is the responsibility of the holder of mineral license. Landowners and rural surface rights activists took the opportunity to talk about the growing number of inactive wells and happily posed for photos nearby wellheads on their property. The challenge of cleaning up so called “orphan wells” (wells whose owners went broke before WD commenced), again made the news.

Also intensely interested in the level of WD activity, is the entire OFS industry which for years has been helping customers abandon wellbores and clean up surface locations. OFS regards WD as one last trip to the well and over the years, it has been good business. Dirt contractors build the lease, then they reclaim it. Service rig contractors complete the well, keep it producing as long as it is economically viable, then get one last job pulling out the tubing (along with rods and pump on oilwells) before running a cement plug. WD requires the full range of OFS services, from wellsite supervision to wireline to cementing plus downhole tools and depending on the well and location, health and safety services. Related: Germany Hails Landmark Achievement In Fusion Energy

The services sector has recognized the commercial opportunities for years. It was in the 1980s, that for the first time the number of oil wells being abandoned each year was greater than the number being drilled. Companies have tried to establish themselves as WDs specialists, providing everything from specialized engineering and expertise to specialized equipment. For example, OFS entrepreneurs have equipped a service rig with cased hole electric line and a pressure pump to be able to perform multiple operations such as plug setting, bond logs and cement squeezes from a single unit with significantly reduced mobilization and demobilization costs. After all, E&P companies try to compliantly decommission wells with minimal investment because there is no upside beyond the settlement of an existing liability on their balance sheet. The serial entrepreneurs who characterize Canada’s OFS industries are eager to help.

WD acceptable to provincial regulators is a legal liability of the mineral rights licensee. E&P companies carry the license and the estimated value of the oil and gas production on their balance sheets as an asset and the WD costs as a liability. However, over the years the amount of actual WD work being done relative to the number of wellbores requiring, it have been disappointing to OFS. A look at the number of inactive wellbores in Alberta in January, 2016 might lead one to believe there was a well decommissioning bonanza just around the corner. But the amount of work that actually materializes remains below anticipated levels. That the Saskatchewan government asked the feds for money, is but one illustration of the challenge.

Source: Alberta Energy Regulator

Of the nearly 450,000 wells ever drilled in Alberta, 44 percent are still producing or in active service (example injection and observation wells), while 38 percent have been either partially or completely decommissioned. A whopping 77,658 are inactive. That doesn’t mean all of these wells must be decommissioned. There are several reasons good commercial reasons why a well can be inactive but not yet deemed ready for the graveyard. These include:

• oil and gas prices lower than cash operating costs, a situation the operator consider possibly temporary
• mechanical or other production problems requiring significant investment not currently economically justifiable
• reservoir pressure depletion requiring some manner of enhanced recovery procedure not currently economically justifiable
• lack of commercially viable access to pipelines (natural gas) or oil delivery terminals (oil)
• single wells drilled and tested during the winter when access costs are low which may not be sufficiently economically viable to justify construction of year-round access roads to facilitate production

For example, many wells are shut in due to very low natural gas prices. Gas wells with formation water often cost more to operate than the produced methane will fetch. Low productivity oil wells with high operating costs fall into this category. Some conventional heavy oil producers have shut in production in the past few months for this reason. Related: Storage Problems Could Cause A Rout In Oil Prices

But there is no doubt there are more wells requiring WD than E&P companies appear to be undertaking, even in years like 2014 when oil prices and the economy were much stronger. Regardless of when this is done and why, Alberta’s current active and inactive well inventory will require WD on nearly 275,000 wellbore in the next 20 to 30 years, depending how long they produce for. The potential opportunity for OFS these wellbores will create when decommissioned is charted below at average costs of $100,000, $200,000 and $300,000 per well. This generates really big numbers.


Source: MNP LLP

At $100,000 for every inactive well, the total requirement is close to $8 billion. If all the active and inactive wells cost $300,000 each to close the file forever, the total rises to about $83 billion. This is more than three times the total estimated upstream cash flow from oil and gas production in the country in 2016, as estimated by ARC Financial Corp. in February 9 version of their weekly macro upstream financial estimates. That’s just for Alberta. Don’t forget B.C., Saskatchewan and Manitoba.

Research into increasingly strict WD regulations, legislation and procedures necessary to receive a final site reclamation certificate (the well file is closed and WD liability provisions can come off the balance sheet) indicate E&P companies are being continually pushed into the upper end of the cost scale. In 1990, new regulations for groundwater isolation required more cement than wells drilled before that date.

It is not that this is a bad idea it is just according to CAPP (Canadian Association of Petroleum Producers) there were 181,735 wells drilled before 1990 under different regulations. How many of those are in Alberta’s inactive well inventory, is not known. Cement to surface to ensure groundwater isolation was not necessarily required in the past. Therefore, abandoning older wells becomes more expensive as operators are forced to perforate and squeeze cement to be fully compliant.

Another area where costs are rising rapidly and the total is often unknown, is surface site reclamation. Not using an excavated sump for drilling fluids and cuttings containment is a relatively new development. Depending upon what fluids were used for drilling or what reservoir fluids may have been brought to surface during routine procedures like a drill stem test, it may be required that the old sump and flare pit be sampled for environmental contamination and possibly excavated with the fill hauled to a safe disposal site. Contouring the land so it looks like it did before the well was drilled is now required. In agricultural areas, crop analysis must be performed to ensure the reclaimed wellsite and the nearby land yield the same plant density. Even grain seeds must be of the same size and weight. Otherwise, regulators may require the site to be reclaimed again. Often it can be several years from the time site reclamation begins before a final reclamation certificate is received. Related: Why OPEC Production Freeze Could Pave The Way For Actual Cuts


Wells with surface casing vent flows outside the production casing are in a category of their own. Regulators require these to be sealed whether the wellbore is inactive or not. There is at least one case in central Alberta where the operator had a service rig on the well for 170 days over a three-year period and spent in excess of $1.7 million before regulators were satisfied. Containing this problem on a well in B.C. is reported to have cost $8 million.

The foregoing leads to the conclusion that on complex WD files – particularly on wells drilled prior to the major regulation changes which surely includes tens of thousands of wells - operators are dealing with the expense they know versus the unknown total cost of acceptable WD. In these cases the lessee may choose to keep the subsurface and surface leases alive by paying the rent and push WD down the road. When economics becomes squeezed like today the decision to deal with this another day looks very attractive.

Which is fine for the well owner, but not for OFS. With capital spending and drilling new wells slashed dramatically, getting one last chance to work on the old ones is pretty good business, even at cost. For OFS skilled and trained staff are as important an asset as the equipment itself. Having a chance to keep the team busy doing anything this market is of great value. When E&P companies quit spending money they build cash. When E&P companies quit spending money OFS companies go broke.

The government of Alberta is apparently looking at economic stimulus investments. Surely finding ways to help E&P and OFS companies by revisiting the WD file and finding ways to help makes as much or more sense than trying to foster the development of entirely new industries which might take years to prove commercial, if they work at all. Royalty or tax credits for operators tackling WD files would make a lot of sense because the province could recover OFS payroll taxes and OFS equipment fuel taxes that would not otherwise be paid.

Hopefully, the industry associations will take some of these ideas to Edmonton and try to find some ways to accelerate WD across the province and in doing so put struggling OFS companies and their staff back to work.

By David Yager for Oilprice.com

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