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Total Abandoning Joslyn SAGD After Steam Injection Blew Hole In Ground

Total E&P Canada Ltd. was exceeding the approved steam injection pressure at its Joslyn Creek thermal bitumen project in 2006 when the reservoir cap rock was breached, blasting a huge crater into the ground and hurling rocks hundreds of metres into the air.

That was the finding of what the Alberta Energy Resources Conservation Board described as one of the most comprehensive investigations in ERCB history. It may also have been the longest -- the report on the May 18, 2006 incident was released on Tuesday.

No one was hurt and no harmful gases were emitted when the blast occurred around 5:15 a.m. at the steam assisted gravity (SAGD) project northwest of Fort McMurray, Alberta. Total E&P Canada is a unit of Paris-based Total S.A.

Total bought the Joslyn property -- which also includes a mining lease -- though the acquisition of Deer Creek Energy Limited. Total's application to develop a mining project on another part of the property is currently wending its way through the regulatory process.

[Figure 1]

The ERCB's 177-page report found the steam release occurred near the heel of the first well pair in pad 204, creating a 125-by-75 -metre "surface disturbance" and hurling rocks "up to 300 metres horizontally from the main crater." A one-kilometre-long dust plume extended to the southwest after the blast.

"The majority of this displaced material was deposited in the immediate area, but there was evidence of a fine dusting of material and rock across an area about one kilometre long by 100 metres wide to the southwest of the release point," the report says.

Joslyn SAGD reserves were debooked at the end of 2008 and last June Total received ERCB approval to suspend operations. Last month, the company applied to abandon the project, said Elizabeth Cordeau-Chatelain, a Total Canada spokeswoman.

Total was shutting down the project "based largely on the poor scheme economics due to operating pressure restrictions, monitoring requirements and shut-in well pairs," the ERCB report says. Cordeau-Chatelain said the decision was based on "a variety of" economic factors, including world oil prices.

Joslyn Creek was approved to produce 12,000 bbls a day of bitumen but output never exceeded a small fraction of that volume.

The ERCB approved the SAGD scheme to operate below the fracture pressure of the bitumen-bearing McMurray formation. Joslyn Creek has 17 well pairs drilled from four surface pads. The steam release occurred above the injector/producer well pair 1 of pad 204 (well pair 204-I1P1, injector 03/01-33-095-12 W4M and producer 05/01- 33/095-12 W4M).

ERCB investigators concluded Total was in non-compliance with its regulatory approval conditions by:

--Operating at bottomhole pressures significantly higher than the 1400 kilopascals (absolute) proposed in its scheme application;

--Failing to implement alarms and automatic shutdown of wells exceeding the 1 800-kilopascal bottomhole reservoir fracture pressure; and

--Exceeding the Directive 051 approved maximum wellhead injection pressure of 1 800 kilopascals.

According to the report, Total believed that the Clearwater shale (the approved cap rock for Joslyn Creek) had a consistent thickness of 20 to 30 metres in the scheme area, had no pre-existing fractures, and was a barrier to vertical flow. Total also believed that the five-metre-thick Wabiskaw A shale, located a few metres below the Clearwater cap rock, was also a barrier to flow.

The report agreed with Total that the Clearwater shale varies in thickness from 20 to 30 metres, but noted the presence of surface casing within the Clearwater interval makes log readings subject to a greater degree of interpretation.

ERCB staff interpreted the Clearwater cap rock to be a non-lithified, silty mudstone, with some sandy interbeds and some vertical burrows filled with sand.

The Joslyn Creek area was subject to the effects of post-depositional karsting in the Clearwater and below, which may have resulted in some fracturing and faulting of the cap rock and bitumen reservoir.

"Staff interprets the Wabiskaw A shale to be a continuous seal to gas in the steam release area, but too thin to be an effective cap rock for a SAGD steam chamber," the report said.

According to the report, Total concluded the most likely steam release scenario was the rapid development of a steam chamber, or "chimney," at the top of the SAGD pay zone, probably involving sand dilation. Total alleged this occurred during the four months when the well pair was on steam circulation.

(Total used high-density, three-dimensional seismic, analytical work, dilation theory and a simple reservoir simulation to support this conclusion.)

ERCB staff rejected this conclusion, saying it is unlikely that a dilation chimney would develop during the four-month circulation period of the well pair.

The investigators agreed that Total's high density 3-D seismic interpretation showed the adjacent vertical wells were not within the narrow disturbed zone that extended down to injector well. However, the vertical wells were within 20 metres of the injector well, and ERCB staff expressed concern about the accuracy of the seismic over such short distances.

The ERCB agreed with Total that the explosive nature of the steam release required storage of steam and hot water below the cap rock.

"Therefore, the steam release did not likely occur as a single fracturing event from the wellbore to surface on May 18, 2006. This is supported by pressure and injection data that indicate an initial fracturing event on April 12, 2006," the report says.

Board investigators concluded the following is the most likely steam release scenario:

--The underlying cause of the steam release was the injection of steam at excessively high pressures.

--The conversion of the well pair from steam circulation to semi-SAGD forced high-pressure steam into the bitumen reservoir. Eighteen days later, on April 12, 2006, a vertical fracture was initiated near the heel of the injector and established communication with the Wabiskaw C gas sand.

--High-pressure steam and water pooled under the Wabiskaw A shale, causing it to fail on April 21, 2006, and establishing communication between the injector and the Wabiskaw A water sand directly underlying the Clearwater cap rock.

--Between April 21 and May 18, 2006, high-pressure steam and water pooled under the Clearwater cap rock, causing it to fail.

--Once the Clearwater was breached, pressure fell rapidly.

"This pressure drop caused hot water that had accumulated in the Wabiskaw A water sand and the Wabiskaw C gas sand to flash to vapour. This provided the energy for a catastrophic explosion that disturbed a large surface area and subsurface volume and threw rocks several hundred metres into the air."

The ERCB report said the following actions have been taken since the mishap:

--An ongoing rewrite of ERCB Directive 051: Injection and Disposal Well--Well Classifications, Completions, Logging, and Testing Requirements to address thermal in situ operations;

--Development of specific application requirements to investigate cap rock integrity and maximum operating bottomhole pressures; and

--An ongoing joint study of cap rock integrity by the ERCB's geology and reserves group and Alberta Geological Survey.

Meanwhile, the experience hasn't soured Total on SAGD. Last month, Total and operator ConocoPhillips Company announced they are proceeding with an 83,000-bbl-a-day expansion of their 50/50 owned Surmont SAGD project in northeastern Alberta (DOB, Jan. 19, 2010).

At the time this story was published the full ERCB report and the December 2007 report Total submitted to the board were both available on the ERCB's website.