CNRL incident(s) at Primrose

I read Dan Healing’s article on the CNRL surface emulsion release incident at Primrose/Wolf LakeEmma Pullman’s DeSmog Blog piece, and the Alberta Energy Regulator’s news release release. I’ll admit I dismissed it all at the time – sounds like an isolated incident, I thought – and I assumed it was from a well-head or pipeline. I didn’t make much of it. Today, Ms. Pullman called me for a comment on her story in the Toronto Star, and that triggered me to dig into this a little more. What I have found so far is not encouraging. I think I should have paid a little more attention a while ago.

First, a little background.  Primrose and Wolf Lake is an in situ oil sands production facility. Unlike many new facilities which use steam-assisted gravity drainage (SAGD) technology, Primrose and Wolf Lake relies on cyclic steam stimulation (CSS), or huff and puff technology, where a single well is used both to inject steam to heat the bitumen and for bitumen production, in cycles. A variant of this technology, high pressure CSS (HPCSS), uses pressurized steam to penetrate deeper into the reservoir, accessing more bitumen.

It turns out that the issues at Primrose with respect to surface emulsion releases are not new.  As Dan Healing points out, this incident, “appears similar to one that occurred at the same project on Jan. 3, 2009.” If you dig into CNRL’s performance presentations, you can get a timeline for this first event. Here are the key events for the previous incident:

  • Jan. 1,2009 – steaming / producing 1st cycle in 4 pad ( 80 well ) development
  • Jan. 3, 2009 – bitumen emulsion flow to surface discovered on Pad 74 ; steam injection shut in and ERCB notified ( ERCB Incident 20090005 ) Note – ERCB’s role has now been assumed by Alberta’s Energy Regulator.
  • May 4,2009 – submitted Pad 74 Interim Investigation Report

After completing the Interim Investigation Report, CNRL continued to undertake a series of diagnostic steaming tests to try to diagnose the issue which was allowing bitumen to escape to the surface. All of the results of these tests were shared with the regulator and new rounds of testing were periodically approved through 2009.  This so-called static investigation was followed up with a more detailed dynamic investigation which lasted through August 2010. At the end of this investigation, in February 2011, CNRL submitted its final incident report to the then-regulator, the ERCB.  The ERCB completed its analysis and the ERCB (PDF) and CNRL reports were released to the public (PDF) in January, 2013 (the link to the CNRL investigation report appears to be broken). The ERCB’s key regulatory action was to put limits on the steam injection volumes allowed at Primrose East.

Yesterday, the regulator announced that it was imposing further steaming restrictions and increased monitoring requirements on CNRL at Primrose South in response to the recent emulsion release.  From what I can tell from the documents I’ve gone through this evening, this incident has the potential to have significant implications for both the regulator and for CNRL. The important caveat here is that you’re dealing with an economist with no training in geology (I took a computer programming class instead of Intro to Geology), so take what follows for what it’s worth.

First, we still don’t really know what happened the first time. The ERCB’s report makes it clear that, while CNRL proposed three scenarios for what might have allowed the initial bitumen emulsion release in 2009, “a detailed flow path could not be determined with certainty.”  The ERCB concludes, based on the evidence, that, “it is likely that the Clearwater shale was breached by high-pressure steam injection not related to a wellbore issue,” and that a pathway to the surface, “likely involved a wellbore or a series of pre-existing faults.” My reading of this is that the investigation was inconclusive, so it was not possible to say whether similar incidents would occur in the future under similar conditions.  The ERCB eludes to this in its conclusions, saying that, “the ERCB continues to review and assess its requirements with respect to both caprock and wellbore integrity issues,” broadly in similar production facilities.

Second, the ERCB concludes that there were likely some operational decisions which contributed to the 2009 release. In particular, the ERCB found that, “steam volume injected…was significantly higher…than past HPCSS operations at Primrose due to reduced well spacing. This likely contributed to the bitumen emulsion surface release.” The ERCB reports that, “CNRL stated that a localized weakness in the Clearwater shale may increase the potential for a breach by high-pressure steam when the injection volume is larger.”  So, this leads to a couple of further questions: was the injection volume again increased above that of past operations at Pad 22, involved in the most recent release, and/or does this release indicate that caprock integrity issues are more pervasive in the Primrose subsurface?

In its report, the ERCB found that, “HPCSS can be safely conducted at Primrose East.”  Hopefully we will not have to wait 4 years to find out what’s happened this time, what the causes may be, and what implications that has for future production at Primrose and for in situ production in Alberta in general.

 

 

One response to “CNRL incident(s) at Primrose”

  1. peter johnston

    I think something similar happened in the 90’s near cold lake. In that case the casing had sheared due to stresses caused by stream injection. The stream basically went straight up alongside the casing dissolving the formation as it went. Eventually a lake was created where the wellhead used to be and the operator had to redesign their casings and monitoring programs to account for the stresses. Without much to go on it sounds as if the stream injection pressure have exceeded the rock strengths of the cap rock allowing bitumen to seep thru the fractures – just speculation on my part. Other possibilities could be poor cementing between the casing and the formation. Considering that tools exist nowadays to measure rock strengths in situ I would be curious to know if such measurements we made by CNRL when designing their production plan.

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