An old saying goes, if you always do what you always did, you will always get what you always got. Now, more than any time in the history of the oil and gas business, E&P teams are developing new technologies and fresh innovations to drive down costs, increase well productivity and boost returns. It’s easier said than done, but we’ve found three companies—all of which will be presenting at EnerCom’s upcoming conference in Denver this month—continue to push the envelope.

High flyer in the Eagle Ford


Sundance Energy Australia Ltd. is leading the way on drilling and completion designs in the Western Eagle Ford. Eric McCrady, Sundance CEO, said his company implements one of the largest fracture stimulation jobs in the area.


“We have been and will continue to be aggressive in our completion design, proppant concentration, stage spacing, etc., adjusting our design to maximize value under prevailing market conditions,” McCrady said. “Our completion design is driving higher initial production rates and overall improvements to our EURs [estimated ultimate recoveries].”


The enhanced completion techniques led to a 70% increase in Sundance’s EURs in three years. And, according to McCrady, the Denver-based company with an Australian headquarters recorded the second best 180-day initial production rates out of all the operators in the area. Sundance holds approximately 40,000 net acres in McMullen, Atascosa and Dimmit counties, Texas, near operators such as EOG Resources Inc., Marathon Oil Co., Pioneer Natural Resources Co. and Carrizo Oil & Gas Inc.


Sundance has approximately 225 net undrilled locations across its Dimmit County asset where McCrady believes the company could soon realize a significant increase in its proved reserves by leveraging knowledge and experience gained from its McMullen County operations. “Utilizing our experience in McMullen, along with recent technical data acquired from our science well, we could see a significant uplift in the value of our undeveloped Eagle Ford assets in Dimmit.”


Getting more resources out of the ground is one key component to the oil and gas business. Another is cost control. Advancements on the drilling side are also generating efficiencies for Sundance.


“We’ve been among the first to drill extended reach laterals at shallower depths in the Eagle Ford,” McCrady explained. “In Dimmit County, we are drilling and completing 10,000 foot lateral wells at an average true vertical depth of 6,000 feet.” The extended reach laterals save Sundance $1.2 million to $1.4 million per well versus having to drill two 5,000 foot laterals.


Sundance reported a 60% reduction in development costs since 2014 through a mix of drilling and completing wells more efficiently and service cost reductions. More impressively, Sundance expects its lease operating costs, production taxes and general and administrative costs will total just $9 to $10 per barrel of oil equivalent (boe) in 2016. This represents a 40% to 50% reduction in cash costs compared to six months ago.


From a capital standpoint, Sundance was nimble and responded quickly to the declining commodity environment by cutting its capex program from approximately $300 million in 2014 to approximately $50 million in 2016. Sundance plans to drill a handful of new wells this year but to focus more on completing wells previously drilled over the past six to 18 months.


“The drilling capital is already sunk, so it’s more efficient to bring those wells online,” he said. Sundance plans to bring 12 horizontal wells online in the second half of 2016 and see its exit rate production grow to range between 9,000 and 10,000 boe/d.


In addition to organic growth, McCrady has proven he can add value to Sundance through accretive transactions. Earlier this year, Sundance added 650 barrels of oil per day (bbl/d) and 3 million barrels (MMbbl) of proved reserves for $16 million.


“The acquisition was in our McMullen County core development area,” he said. “We operate a portion of the production already so we understand the assets very well, and from a cost standpoint, it doesn’t add any fixed G&A costs and allows us to grow the scale of our business with very little risk.”


When asked if he believed there were other attractive bolt-on acquisition candidates at today’s prices, he simply replied “Yes.” In addition to potentially pursuing other small bolt-on transactions this year, McCrady said Sundance will remain focused on the development of its Eagle Ford inventory in McMullen and Dimmit counties.


Even though Sundance is listed on the Australian Stock Exchange (ASX), the company is 100% focused on U.S. resource plays. McCrady said the company listed on the ASX back in 2004 when it had Australian assets. Now that they exclusively operate in the U.S., he said they’re considering a level two ADR to trade on the Nasdaq.


“We have a handful of investors in the U.S. today that have suggested we move toward a U.S. dual-listing,” he said. “Given the time and market differences between here and Australia, it’s hard for investors to make the international trade, so a Nasdaq listing provides U.S. investors the opportunity to invest in Sundance’s growth.”

Innovation without borders


Innovation isn’t always achieved through invention. Sometimes, innovation can be accomplished by applying existing technologies in new places.


Tamarack Valley Energy Ltd. is considered one of Canada’s best tight-oil specialists, and for good reason. The company was founded in 2009 with $2.5 million of seed capital and has grown to C$500 million in market cap by applying existing technologies to bypassed tight-oil reservoirs.


At Wilson Creek, the company’s flagship asset in Alberta, Tamarack Valley started drilling two-mile laterals in the Cardium Formation in 2016.


“The previous operator at Wilson Creek was spending $4 million to drill and complete a one-mile-long lateral with eight stages, and it produced 140 bbl/d on a 30-day test,” said Tamarack’s CEO Brian Schmidt. “Now, we’re doubling the length of the horizontal lateral, going from eight stages to 55 stages, and producing 560 bbl/d, all for $3.5 million.”


The oil and gas business is all about finding ways to do more with less. To put that in perspective, Tamarack Valley is able to generate the same returns at $48/bbl that were previously generated at $80 to $90/bbl.


Additionally, Schmidt said Tamarack Valley is experimenting with a waterflood project on its Redwater Field asset. “Early waterflood tests done by other operators, including us, were not very successful,” he said. “However, we think we’ve found a proprietary way to apply new and innovative technologies to the asset and get it working for us.”


As commodity prices continue to stabilize, Tamarack Valley also plans to implement new technology on a recompletion program over the summer of 2016. Schmidt said they’ll be going back into older wells originally completed with six to eight fracs and refrack them using new designs and technology.


Schmidt learned how to manage through industry downturns during his tenure at Apache Corp.


“Those guys really know how to manage downturns,” he said. “I went through a few cycles with them, not to the extent of this cycle, but I learned very good habits.”


Tamarack was an early mover and reduced its capital spending in November 2014, a few months earlier than most its Canadian peers, and then started paying down debt. “We stopped drilling wells in the first half of 2015,” he said. “We took our engineers and focused their efforts on redesign so when things turned around we could come out with sustainable cost levels.”


As a result, Schmidt said they’ve reduced operating costs by approximately 28% and well costs by 38% at Wilson Creek. “These are permanent design changes, not services cost reductions,” Schmidt explained. “These reductions improve our netbacks, meaning we can keep growing production on a per share basis.”


Looking back to 2015, Tamarack Valley was one of very few companies that grew production per share while also paying down debt. Schmidt is pleased with his company’s decision to pay down debt early and maintain a clean balance sheet, because it positioned Tamarack Valley to acquire quality assets at historically low prices.


Last year, the company purchased assets from ConocoPhillips and PennWest Exploration Co. In June of 2016, the company announced the acquisition of 1,900 boe/d, including 60 net sections of land, for $85 million. Through a combination of acquisitions and organic development, Tamarack Valley has increased its drilling inventory by more than 10 times since 2013 while simultaneously adding key infrastructure to help get their resource to market.


“Our recent acquisition does a number of things for us,” Schmidt explained. “It adds to our core assets in both Wilson Creek and Redwater, and it introduces a new core area in the Penny Field.” The purchase brings key infrastructure and adds seven net locations at Wilson Creek.


Schmidt said the infrastructure was vital because it reduces processing fees which ultimately improves netbacks. He said the marginal cost of processing gas is $0.20/Mcf, and the previous operator was paying somewhere around $1.00 to $1.50/Mcf to get their gas processed.


The Redwater portion of the acquisition adds significant oil exposure, as well as existing infrastructure that will reduce Tamarack’s lifting costs. “The acquisition was almost like a checkerboard the way it wraps around Tamarack’s current acreage,” Schmidt said. “The previous operator has pipelines to all of the wells and tank batteries, which will enable us to take production that’s currently being trucked and bring it into these 80% owned gathering systems.”


Schmidt believes the industry is now in the part of the cycle where some companies will get aggressive with drilling.


“Even though our assets can generate acceptable rates of returns at today prices, we’re not going to get too aggressive on drilling, yet,” he said. “For now, I’d still rather put our dollars toward acquisitions than the drillbit—there are bargains out here I won’t ever see again in my career. Companies that outperform coming out of downturns do so by positively positioning themselves during the low point in the cycle.”

The first of firsts


If you ask Garth Braun, Blackbird Energy Inc. CEO, about innovation, he’s quick to give credit to U.S. operators for carrying the baton early on in the most recent downturn.


“The cost reduction and well innovation leadership really came from the States during the latest oil price pullback,” said Braun. “Companies started to look at how they can continue to operate and achieve greater, long-term capital efficiencies, not just because of service cost compression.”


Even though he gives credit to U.S. operators for driving innovation, Braun and his team are doing their part by applying new techniques to more efficiently develop the liquids rich corridor of the Montney Shale, regardless of commodity prices.


“We set out to implement policies and practices that give us the ability to sustain the cost reductions we’ve been able to produce,” Braun explained. “As crude oil prices move up, service costs will go up, so our focus has been on sustainable cost reductions and well efficiencies.”


In fact, Blackbird was the first company to drill a mono-bore well in the Elmworth Montney. A mono-bore well is drilled by setting the surface casing and drilling the entire well without intermediate casing.


“We bypass the intermediate casing,” Braun said. “We drill the whole way to total measured depth, and then come back uphole to run the entire production casing.” All in all, it saved Blackbird approximately C$500,000 on the 2-20 Middle Montney well it drilled at the end of 2015.


Presently, Blackbird is getting ready to drill its second mono-bore well. This time it’ll drill with a 6¾-inch bit, and switch to 6¼-inch for the horizontal leg. They expect this will further accelerate their drilling program, reducing drill times from 24 days to between 17 and 19 days. The total measured depths of these wells are approximately 6,500 feet to 7,500 feet.


Building off its mono-bore success, Blackbird implemented one of the largest sliding sleeve completion jobs in the Montney. The plug and perf has been widely adopted in this area of the Montney, like many plays in the U.S., but Blackbird wanted to experiment with something different.


“We are using a service provider’s proprietary technology to help us pinpoint completions during the sliding sleeve process, but it still uses a coil tubing unit,” Braun explained. “We’re actually looking at a sliding sleeve system right now that does not require a coil tubing unit.”


Braun believes it could accelerate completion times from two hours per sleeve to approximately 20 minutes per sleeve. Longer term, he believes it could produce $1.7 million to $2 million in cost savings compared to the traditional method.


Technical advancements aside, as the Montney continues to be developed by operators like Blackbird, Encana Corp., Seven Generations Energy Ltd. and others, the understanding of the subsurface and size of the prize continues to grow. Encana just announced it believes the superrich condensate areas of the Montney can be developed with 12 wells per interval per section, up from estimates ranging from four to eight wells per interval per section. This means operators can drill and complete more wells and recover the same amount of resources.


Using a US$50/bbl WTI price and a US$3 natural gas price, Braun said Encana is projecting IRRs in the 139% range. Returns at that level make it one of the most attractive plays in North America. In first-quarter 2016, the Montney was running 54 rigs compared to 46 in the Marcellus/Utica, 33 in the Rockies and 17 in the Haynesville, according to Braun.


“For Blackbird, the superrich corridor has already been mapped through at least 40 sections of our 76 total sections,” Braun said. “We clearly see three intervals that will produce in excess of 100 barrels of condensate per million cubic feet of gas. Multiple, clearly defined zones drastically increase our future well inventory.”


Using this new methodology, Blackbird calculates it has the potential for 2,304 unrisked drilling locations, up more than 300% from its previously estimated 900 locations. He believes this new understanding is a fundamental shift in how investor and industry experts will value Montney assets.


The liquids yield is a critical component for the industry to understand. “A dry gas play will never have the advantages of a liquids rich play,” Braun explained. “Condensate in Canada trades at a premium to WTI—we get up to a 25% premium to WTI, and future demand for the product continues to grow.”


Braun said demand for condensate over the next three years will grow to range between 600,000 to 800,000 bbl/d. The condensate is mixed with heavy oil sands crude so that it can flow through pipelines, making it essential to oilsands producers. Right now, the country is only producing approximately 200,000 bbl/d of condensate.

Brian R. Brooks is an associate director at EnerCom Inc. Founded in 1994, EnerCom provides oil and gas branding, marketing and valuation solutions to the entire oil and gas industry. The firm also produces two annual oil and gas investment conferences in Denver and Dallas.

Comments