- Category: Features
- Published on 27 January 2015
- Written by Darrell Stonehouse
Despite low prices, Duvernay development continues
- Category: Features
- Published on 02 January 2015
- Written by Darrell Stonehouse
Homegrown Deep Basin operators moving into the big leagues
Almost 40 years after Canadian Hunter drilled its discovery well at Elmworth, marking the modern age of exploration in the Deep Basin of west-central Alberta, the massive stacked gas resource estimated at 400 tcf remains a favoured target of those looking to build homegrown gas giants.
- Category: Features
- Published on 22 December 2014
- Written by Pat Roche
Although low oil prices pinch SAGD economics, game-changing technologies will cushion the blow, said Jared Wynveen, a reservoir engineer and associate at McDaniel & Associates Consultants Ltd., in a presentation at the Canadian Heavy Oil Association’s fall conference.
- Category: Features
- Published on 15 December 2014
- Written by Darrell Stonehouse
Over a decade into the unconventional resource revolution, oil and gas companies continue to use extended-reach horizontal drilling and multistage fracturing technology to open up new plays and expand existing plays.
Tight oil plays like the Bakken, the Cardium and the Viking are now well into development mode, with many moving into secondary recovery. Gas and liquids plays like the Montney, the Wilrich, and the Fahler, all in the Deep Basin, are also proven, and dry gas plays in the Horn River Liard Basin are also well established.
But new plays are emerging all the time. The technologies are increasingly being used on more conventional types of formations as well, adding more production from aging fields.
Across the Western Canadian Sedimentary Basin (WCSB) a number of new developments emerged in 2014, including the Torquay play in southeastern Saskatchewan and the Charlie Lake oil play in northwestern Alberta.
Other plays, like the Duvernay in central Alberta, are moving from exploratory to development mode. And other more conventional plays, including the Glauconite liquids play in central Alberta, are now benefiting from horizontal drilling and multistage fracturing.
Torquay discovery adds to southeastern Saskatchewan Bakken development
Crescent Point Energy announced in April that it had made a significant Torquay discovery in the Flat Lake area of southeastern Saskatchewan which it described as an extension of its Three Forks resource play in North Dakota.
The company reported that throughout 2013 and early 2014 it had delineated the discovery in the Flat Lake area, where the company has more than 220 net sections of land and 400 low-risk Torquay drilling locations on the Canadian side of the border. Crescent Point reported drilling 36 (35.2 net) horizontal wells targeting the Torquay Formation at Flat Lake, growing net production from zero to approximately 5,100 boe/d in just 12 months.
“We’re very excited about the results we’ve seen in the Torquay so far,” president and chief executive officer Scott Saxberg said. “These are high-rate-of-return wells at low capital costs relative to North Dakota that complement the Bakken production from our core Flat Lake area. To put it in context, this play has the potential to be the equivalent size of our Viewfield Bakken play.”
In 2013, the company added proved plus probable reserves of 11.2 million boe at Flat Lake in the Torquay and Bakken formations combined. Finding and development costs were $11.46 per boe, excluding changes in future development capital, which represents a recycle ratio of 6.4 times per proved plus probable boe for this area.
“The recycle ratio for Flat Lake is more than double the 2.8 recycle ratio we achieved corporately in 2013 and more than triple a recycle ratio of two times, which is considered very good in our industry,” Saxberg said.
At year-end 2013, Crescent Point’s independent reserve engineers booked estimated ultimate recoveries on producing Torquay wells as high as 275,000 bbls per mile-long well. This type of well, which has a $3.35 million capital cost, generates rates of return of approximately 300 per cent and payouts of approximately seven months.
In 2014, Crescent Point expected to spend approximately $200 million of its 2014 budget in Flat Lake, including drilling approximately 48 net wells.
In addition to its core Flat Lake Torquay land position, over the past 18 months Crescent Point has continued to accumulate a significant exploratory land position of more than 400 net sections in the southern part of southeastern Saskatchewan, targeting the Torquay and Bakken formations. These lands are in addition to the delineated core-area lands discussed above.
Later in April, Crescent Point announced it was acquiring privately held CanEra Energy Corp. and its southeastern Saskatchewan assets for a total consideration of $1.1 billion.
The CanEra assets include more than 260 net sections of land with Torquay potential, of which more than 200 net sections are exploratory land and 60 net sections are in Crescent Point’s core Flat Lake area. This gives Crescent Point more than 880 net sections of land with Torquay potential, of which more than 280 net sections are in the core Flat Lake area.
Crescent Point drilled 25 oil wells into the Torquay during the third quarter of 2014, again reporting positive results.
Charlie Lake quickly becomes commercial
Tourmaline Oil Corp. spent $53 million in 2013 consolidating land in the Charlie Lake oil play, and in aggregate, 514 sections were acquired on the trend. The company has wasted little time developing the play.
Tourmaline has drilled 84 horizontal wells into the Charlie Lake play and expects to exit 2014 producing between 18,000 and 20,000 boe/d.
The company believes that the regional pool could ultimately yield over 500 million barrels of oil equivalent. The producer said it controls over 75 per cent of the prospective trend as currently mapped. The company drilled approximately 35 new wells in 2013, and about 50–60 horizontal wells should be completed by the end of 2014. Tourmaline said Charlie Lake is a significant resource-style play, but it is not as large as the Montney, for example. The average cost to drill and complete is $3.6 million. The company has identified 1200 drilling locations in the play.
In early November, Tourmaline announced it sold a 25 per cent stake in the Charlie Lake play to Canadian Non-Operated Resources LP for $500 million. Under the deal, CNOR is taking a 25 per cent interest in all lands, wells, production, reserves and facilities in the northern Alberta play and shares all future development and acquisition costs. Tourmaline made the move to speed development in the play.
“Tourmaline will accelerate the planned exploration and development program commencing in 2015, with both an accelerated drilling program and infrastructure build-out resulting in expenditures of at least $400 million per annum over the duration of the five-year plan,” it said in announcing the deal.
Birchcliff Energy Ltd. has been working the Charlie Lake play and expanding its operations at the Worsley field since acquiring it in 2007. The company holds 181,541 net acres that are prospective for the Charlie Lake light oil resource play.
“Our main pool, holding over 400 million barrels of oil in place, is in Worsley, Alberta. Our land is mostly large blocks of 100-per-cent-owned, contiguous blocks, which helps with repeatability, pad drilling and the construction of infrastructure,” said Jeff Tonken, president and chief executive officer. “We believe the play has significant growth potential on land we currently own.”
He added that the play stretches across the Peace River Arch and has become popular because of the economics and the opportunity for growth due to the application of horizontal drilling and fracturing, which is enabling further resources to be unlocked.
“New technology, horizontal wells, completion techniques and resulting recoveries together with higher light oil prices have driven this play,” Tonken said. “This formation is only found in the Peace River Arch, so it will be limited to northwestern Alberta.”
On average, drilling and completion costs are roughly $2.5 million per well, Birchcliff says.
Duvernay advancing to commercial production
With an estimated 443 trillion cubic feet of gas, 11.3 billion barrels of natural gas liquids, and 61 billion cubic feet of oil, the Duvernay is the big prize when it comes to Alberta’s shale resource.
In 2014, a number of operators reported making progress in moving the play toward development mode.
At the end of the winter drilling season, Encana reported it had drilled 24 gross wells (12 net) in the Duvernay year-to-date and was making good progress in commercializing the play, reported chief operating officer Mike McAllister.
“We have seen tremendous progress in drilling cycle times in the play,” he said.
Ten high-intensity completion horizontal wells in Simonette are meeting or exceeding expectations, with initial production averaging about 1,300 boe/d per well. Spud-to-rig release times have improved by an average of 17 days since the first quarter, resulting in cost savings of roughly$1.5 millionper well. Five rigs are currently running in the play.
“Encana has released five Simonette horizontal wells in the second quarter with an average spud-to-rig-release of just under 30 days. This represents a reduction of 17 days or 35 per cent off our average in the first quarter of this year. It also translates into cost savings of about $1.5 million per well,” McAllister said. “These five wells are the longest horizontals in the play, with average lateral lengths of 7,000 feet.
“We have also tested five new Simonette horizontal wells in the second quarter. All five wells are meeting or outperforming expectations.”
Royal Dutch Shell plc, which describes itself as the leading Duvernay driller, says the jury is still out on the shale play’s commercial viability.
“It’s still an emerging play from our perspective. PVT [pressure, volume, temperature] and reservoir physics are not well understood yet,” said Holger Mandler, who leads the geoscience team for Shell’s Fox Creek unit.
“Profitability will still have to be proven by more tests and prolonged production data across the sweet spot,” Mandler told the 2014 Unconventional Resources Conference, which was planned and operated by the Society of Petroleum Engineers and the Canadian Society for Unconventional Resources and which took place in Calgary.
Shell entered the play in 2011, spudding its first Duvernay horizontal at Fox Creek in December 2011 and ramping up the program to five rigs by mid-2013.
“It was by far the most aggressive ramp-up of any of the operators in the area,” Mandler said. “And after that we slowed down the pace in 2014, currently with one to two rigs basically running.”
Looking at industry activity in the Duvernay as of August, Mandler said Shell had drilled and completed the most wells.
“The same thing for production,” he said, referring to January 2014 output. “At that point, Duvernay production had come up to about 20,000 boe/d with Shell basically producing roughly half of that at the time.” In any multi-fracture play in tight rock, initial production declines steeply.
Mandler said the company now has about 50 wells in the play with 40 on production producing about 7,000 boe/d from Fox Creek. At Willesden Green, the company has drilled just eight wells to date and has three on production.
Much more production history is needed before profitability can be assessed, he emphasized. “Not all the information is coming right away. You have to produce these wells for quite some time...to try to understand the potential.”
When it comes to evaluating the Duvernay’s commercial viability, one of the key challenges, in Shell’s view, is understanding the reservoir.
“PVT sampling is still a somewhat open question in our minds,” said Mandler. “You have to collect a lot of data there. But because of the nature of the Duvernay, of the variability of PVT behaviour across the sweet spot, and the difficulty or impossibility, so far, to collect downhole samples, this is a very difficult question to address technically.”
He said the absence of adequate PVT data “has a huge impact when you run dynamic models. It has a large impact in terms of per-well EURs [estimated ultimate recoveries]. So this is a key parameter for estimating, for predicting or modelling well performance. And it’s very difficult to tackle in this area.”
“Same thing with production,” he added. “Similarly, we feel that we need really extended production history to really have a high-confidence estimate of well performance. So long-term production that is half a year or longer.”
With more wells on stream, production history will obviously accumulate over time, Mandler acknowledged, but he added, “A lot of the information we have is still based on tests across the area and on short-term production.”
Another challenge is reservoir architecture. He said the Duvernay B—“a fairly massive mudstone”—and other calcareous stringers appear to be potential frac barriers.
Mandler said “a number of observations” suggest natural fractures are present across the play, and this could pose another technical challenge. “The wells are somewhat active while drilling, which you wouldn’t expect given the really low permeabilities in the play.”
One of the things Shell did last year in its initial Duvernay drilling blitz was to drill three “data pads,” four-well pads with unique configurations to help determine development parameters such as well spacing and frac fluids.
“We call them data pads because they’re not only unique configurations to test certain concepts but also have some additional technology deployment that you wouldn’t do in a regular appraisal or a development well,” he explained, citing microseismic monitors as an example.
Mandler didn’t talk about Shell’s individual Duvernay well results, but he said the industry as a whole has been reporting per-well results in the range of roughly 350–1,300 bbls/d of oil and one to seven MMcf/d of gas.
He cited third-party ultimate recovery estimates of up to 700,000 bbls of liquids per well and 4.7 bcf of gas. He said a few wells that have already produced more than 150,000 bbls of oil.
A typical Duvernay well takes between 20 and 40 days from spud to rig release, and most have been cased and cemented with plug-and-perf completions, Mandler said. “There were a number of wells that were attempted with open-hole completions with mixed results...so most operators have gone to plug-and-perf.”
He said total lateral lengths range between 900 and 2,600 metres, and the number of frac stages ranges between seven and 27. Oil gravities range between 43 and 55 degrees API.
Glauconite benefits from horizontal technology
New drilling and completion technologies are also having a significant impact on more conventional plays.
For example, Bonavista Energy is using horizontal drilling in the Hoadley Glauconite play in south-central Alberta.
The Hoadley Glauconite was originally discovered in 1977 and is estimated to contain an ultimate potential recoverable reserve of six trillion to seven trillion cubic feet of gas and 350 million to 400 million barrels of associated natural gas liquids.
“Our Hoadley Glauconite play continues to be the engine of growth representing a forecasted 65 per cent of the total expenditures in this core area for 2014 and delivering excellent economics at current prices,” Bonavista president and chief executive officer Jason Skehar said in announcing the company’s second-quarter results.
Bonavista drilled 15 net horizontal Glauconite wells in the second quarter, bringing total activity in the first half of 2014 to 27 net horizontal wells. This represents a 25 per cent increase in drilling activity when compared to 20.4 net horizontal wells drilled in the first half of 2013.
Current horizontal Glauconite production volumes are approximately 22,500 boe/d, which is modestly ahead of the company’s five-year forecast.
Bonavista said that the continued growth in its Glauconite play has warranted additional infrastructure, including a transmission line designed for 120 MMcf/d of natural gas transportation and a 30-MMcf/d compressor station.
The average cost reduction of 11 per cent per well realized to date in the company’s extended-reach horizontal program is compelling when compared to the cost to access the equivalent reservoir from two separate horizontal wells. Year-to-date, Bonavista has drilled five extended-reach horizontals with three of these wells drilled in the second quarter. Well performance is meeting expectations.