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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 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 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.
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.
Of the nearly 450,000 wells ever drilled in Alberta, 44% are still producing or in active service (example injection and observation wells), while 38% 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:
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.
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.
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.
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.
Sandwiched between seemingly endless bad news stories about oil prices in the oilpatch were two articles about the draft review released by the Canadian Environmental Assessment Agency (CEAA) on February 3, 2016 regarding the proposed $36 billion Petronas Northwest LNG project.
On February 9 the
Vancouver Sun wrote a story about how CEAA had concluded the controversial structure to carry liquefied natural gas from the plant on the mainland to the loading terminal on Lelu Island would not have an adverse effect on salmon stocks. The issue is submerged tall grass over which the LNG pipe would pass. The impact of these facilities on juvenile salmon has been a major issue among some aboriginal groups opposed to the project. The headline read, “Federal draft review concludes salmon not adversely affected by leading LNG project”.
Bloomberg News article on February 11 chose to highlight different areas of the CEAA report. This title read, “Agency raises concern or greenhouse gases, porpoises, in review of Petronas LNG project”. The first paragraph finished with the words, “…development led by Petronas would probably cause ‘significant adverse environmental effects’”. This article chose to highlight greenhouse gas emissions and the destruction of porpoise habitat. That said, the article said the project would not likely negatively affect the environment in other ways.
The different approaches to the same story might be affected by geography. Writers in British Columbia could be inclined to focus on the victories while others further away write about the challenges. That’s certainly common in media coverage about the oil and gas industry nowadays. B.C. Natural Gas Minister Rich Coleman said in the
Sun article his province would have to respond to Ottawa on how that province will handle an estimated 8.5% increase in B.C.’s greenhouse gas output. Carbon emissions by the oil and gas industry have become a major political issue in many parts of Canada.
The report is open for comments until March 11, after which CEAA will issue its final report. There is not enough information in either of these news stories to become more optimistic or more pessimistic about whether or not NorthWest LNG will proceed. But the natural gas supply arm of Petronas - Progress Energy Canada Ltd. – remains the number two driller in Canada on February 16 operating 12 big drilling rigs in the Montney formation.
One of the more discouraging aspects of current OFS activity, is how much money companies have had to invest in the past eight years to provide the new generation of services and equipment required for extended reach horizontal drilling and multistage hydraulic fracturing. Parking equipment during the downturn while waiting for markets to improve would be less painful if it was paid for. But many OFS operators financed significant capital expansion with debt. While equipment can certainly wait for better times, debt providers may not.
On February 11 contract drilling and services giant Precision Drilling Corp. released its financial results the three-month period ended December 31, 2015. Like everyone else in the service business, the company reported significant losses totalling $271 million for the quarter plus eliminated its dividend conserve cash. The company mothballed another 79 of its legacy conventional drilling rigs. According to a
Calgary Herald article Precision has retired 236 of its older conventional rigs since 2009 replacing them with 238 “Tier 1” rigs, those with the depth capacity, top drives, pumping capability and mobility to be competitive in the horizontal drilling marketplace. For the 2015 fiscal year, decommissioning and asset impairment charges totaled $466 million. Using an average cost of $4 million, this is a fraction of the $944 million it cost to build these now-obsolete rigs in the first place.
Staying competitive in the retooling of OFS for new style drilling and completions has cost Precision a bundle. Capital spending in 2015 totaled $549 million with another $210 million planned for 2016. Looking through PD’s annual reports from the 2009 and 2014 fiscal years filed on SEDAR, the company has reported “net capital expenditures from continuing operations excluding business acquisitions” (2010 definition) totalling $3.4 billion. Including 2016’s estimate, this will bring the eight-year total to over $4.1 billion. While much of this has been for sustaining capital, refits, upgrades and infrastructure, the majority of the funds has been invested in a complete retooling of the company’s drilling rig fleet.
In its earlier financial reports Precision described the investment in Tier 1 rigs as essential to stay competitive in the “unconventional” drilling market. With so many of its legacy conventional rigs now mothballed, it appears in North America at least this is now the only drilling market.
Now that economic sanctions against Iran have been for the most part removed (Canada is apparently a bit behind) global E&P and OFS operators are flocking to the Middle East to get in on the action. Iran has been telling the world it needs western capital, expertise, equipment and technology to restore production to former levels. Many Canadian OFS service and equipment companies have been eager to work in Iran for years but have been prevented from doing so by western economic sanctions.
Before the overthrow of the Shah of Iran in 1979, that country was producing over five and even six million barrels of oil per day thanks to outstanding reservoirs and the investment and ingenuity of oil companies from Britain, United States, and Europe. Following nationalization in 1979, a prolonged war with Iraq that didn’t end until 1988, and more recently Western economic sanctions because of Iran’s nuclear ambitions, production has remained well below those levels. OPEC reported that in December 2014 Iran’s total production for internal use and export was on 2.9 million barrels per day, half the levels of forty years ago.
Two articles in the
Daily Oil Bulletin send mixed signals on opportunities in Iran. On February 12,
Reuters speculated Iran’s decision to cancel an investment conference in London scheduled for February 22-24 was because of differing opinions within Iran about the best path forward. Some want to modernize the industry quickly with foreign capital and expertise while traditional hardliners – and nationalized the industry once – remain suspicious of outside companies and money. The article estimates Iran will require as much as US$200 billion in investment to reach its production output ambitions. As Iran has talked up the opportunities the end of sanctions would provide for global players in the oil industry, the new story indicated this conference has now been delayed five times. The Iranian officials blamed the latest delay on obtaining visas for some participants.
Meanwhile, on February 8
Reuters reported the CEO of GE Oil and Gas, a unit of General Electric Co., recently visited Iran to explore opportunities. In the past five years GE expanded through acquisition to become a large and diversified supplier of oilfield equipment and expertise.
Closer to home, several Alberta OFS companies are awaiting final clarification from Ottawa as to when the Canadian sanctions will be removed so they can get to Tehran and start selling things. Some companies have had Iranian agents on the payroll exploring opportunities in that market for several years and are ready to go.
It looked promising for a while. In 2014 the former Party Quebecois government of Quebec not only supported drilling and fracking for oil on Anticosti Island in the Gulf of St. Lawrence but promised to invest $57 million with three local E&P companies to earn a 35% interest for the province. Junior E&P’s Corridor Resources Inc., Petrolia Inc. and Saint-Aubin E&P (Quebec) Inc. would each own 21.67% and were enthusiastic about the potential to unlock commercial quantities of shale oil using horizontal drilling and hydraulic fracturing.
But the new Premier of Québec, Phillippe Coulliard, has apparently changed his mind according to a
Financial Post article published February 2. The premier apparently said in the National Assembly, “My name will never be associated with the dilapidation of Anticosti Island. My never name will never be associated with the aggressive savaging of a natural environment like Anticosti”.
The existing development permits and financing commitment from the province of Québec are thought by the oil companies to be legally binding. The CEO of Corridor said, “Clearly our faith in Québec as a place to invest in oil and gas, or any other possible development for that matter, is shaken. We have not yet determined the amount of any damages and we and our partners have been focusing on moving the project forward”. However, the companies will be seeking compensation if the new premier backs out of the existing agreement.
Drilling activity in Canada and U.S. rigs drilling for oil declined again while the active rig count in North Dakota remained the same in the past week. Canada’s winter drilling season is already over with the weekly rig count peaking January 19 at 241 and declining every week since. North Dakota’s activity remains the most depressed percentage wise down 70% to 80% from the prior four years. These figures are likely to continue to decline if WTI remains trading in the range of US30 a barrel or lower.
Source: Baker-Hughes Rotary Rig Count February 12, 2016
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