Beating the Decline Curve with Water Injections via Stage-Fractured Horizontal Wells = a Lower F&D Cost than Saudi Arabia
The shale revolution has propelled North America into a global energy powerhouse. The technology driving this transformation – hydraulic fracturing – has allowed U.S. and Canadian producers to unlock tremendous energy resources, but it presents its own unique challenges compared to traditional methods of production.
Production from hydraulically fractured wells declines rapidly, typically by 60-70% in the first year, before leveling out at lower levels. Because of the rapid initial decline of new wells, companies drilled several new wells to replace the lost production from their aging wells, creating a “Red Queen Syndrome,” which is a reference to the character by the same name in Through the Looking-Glass, who tells Alice, “It takes all the running you can do, to keep in the same place.”
Since the tremendous drop in oil prices since the middle of last year, many companies have cut their drilling programs, deferred completions and put an emphasis on improving efficiencies in order to optimize the production they receive from their wells. Efficiencies derived from enhanced completion techniques and high-grading will lead to initial productivity gains per well of 24% in 2015 and 15% in 2016, leaving U.S. oil production ready for substantial growth come 2017.
While producers in the U.S. have made tremendous gains in combating the Red Queen Syndrome following the collapse of oil prices, a Canadian producer believes it has the next wave of change in the horizontal production.
“Waterflooding is as big as fracture stimulation of horizontal wells” – Neil Smith, COO Crescent Point
Crescent Point Energy (ticker: CPG) is a Canadian E&P company with operations focused in Western Canada. The company’s strategy consists of three parts: develop and exploit through increasing recovery factors, acquire large resource-in-place pools with potential for upside production, and manage risk through maintaining a strong balance sheet.
During the company’s presentation at EnerCom’s The Oil & Gas Conference® 20, Crescent Point COO Neil Smith pointed out that 14 years ago, the company had no reserves and no production. But in that time it has become a company with a market capitalization of $8.4 billion, with a debt-to-market cap of just 48%, compared to a median of 66% for Canadian E&Ps in EnerCom’s E&P Weekly Report. In 2014, the company’s year-end reserves (total proved) were 528.1 MMBOE, while its year-end reserves (total proved plus probable) was 807.4 MMBOE.
While much of the company’s breakout session following its presentation at TOGC20® focused on the potential for future acquisitions, Smith was most energized about Crescent Point’s waterflooding program, which the COO called “as big as fracture stimulating horizontal wells,” when interviewed about Crescent Point’s water flood program by Oil & Gas 360®.
Recovery factors over 30%
“The upside on this is huge,” Smith told OAG360. “Where we’re at (in Canadian Viewfield Bakken), there’s plus-or-minus 6 million barrels of oil in place. At four horizontal wells per section, we’re seeing about a 12% primary recovery [with four hydraulically fractured wells]. Down-spacing to 8 wells, we get 19%. When you look at waterflood, through empirical data, history matching and our simulation studies, we’re seeing a 31% total recovery factor,” Smith said.
The incremental recovery factor Crescent Point has realized through the use of its waterflooding program in the Viewfield has increased recovery factors by 12% from the recovery factor it was seeing with its down-spaced, 8 well program.
The use of waterflooding has shallowed out Crescent Point’s decline curves in all of the plays were the company is using the technology by about 10%, said Smith, meaning the company is realizing upside years down the road. “Waterflooding is a slower catalyst, but the economics are still very robust,” said Smith. “If I shallow my decline, then I need less capital to maintain my production. So either I spend less capital to maintain my production, or the same amount of capital accelerates my growth.”
“If you look in just the Viewfield, we’re probably affecting 15-20 thousand barrels of oil. If you reduce the decline by 10% on 20,000 barrels, that’s 2,000 barrels of production that we’ve recovered by shallowing the decline,” said Smith. “That’s just in one year. The next year it’s 4,000, then 6,000. You’re saving that decline with time.”
The process also has tremendous upside for F&D costs explained Smith. The 12% incremental recovery increase on the approximately 6 million barrels works out to 720,000 barrels; factoring in the $350,000 to conve
rt a producing well into an injection well for four wells is about $1.4 million; that divided by 720,000 barrels works out to a finding and development cost of about $1.94 per barrel.
“Our waterflood economics put us at a lower F&D cost than Saudi Arabia,” said Smith.
Improving reserves, but not overnight
With year-end approaching, OAG360® asked Smith if this technology would help the company maintain its reserves even at a lower price deck. Smith responded that it does help, but it is happening slowly.
“We’re not going to go from 19% to 31% overnight. The independent engineers need to see the injection wells change, they need more response, so it is baby steps that they’ll give you. Maybe 1-2% per year. For now, where we have injectors, they’re recognizing incremental recovery in the offset producers.”
“The common wisdom has been that you cannot waterflood tight rock because if you had a vertical well, and you wanted to inject water into that vertical well, the rock was so tight that you would have to push so hard that the injection water would fracture the injection well and the water would go straight from the injector to the producer,” said Smith. The company has worked around this by using horizontal, stage-fraced wells as injectors.
“Instead of having one, bull-head push, you have 15-20 injection points on the horizontal wells, which gives the water time to go through the matrix and push the oil towards an offsetting producer well,” Smith explained. Crescent Point uses its sliding-sleeve technology in conjunction with its horizontal injection wells in order to maximize their effect.
Water will follow the path of least resistance said Smith, so if only a handful of the injection points are receiving enough water, CPG can close part of the sleeve to push water elsewhere. “Not only has [sliding-sleeve technology] improved our primary completions, but what we’ll be able to do is open and close the injection ports. So if too much water is running into five ports, we can go and close the sleeve to make sure water is getting into the other ports.”
This is not the first time Crescent Point has brought an innovative strategy to production though, says Smith. “In 2009, we started doing cemented liners. We started telling the world we were doing cemented liners. Well, about two years ago, there was a story saying ‘here’s the new way, here’s the revolution: cemented liners.’ I took that to our completions department and they said, ‘Yep, that’s what we’ve been doing for four years already.’”
When asked if he thought the story would be the same for waterflooding, Smith said it was likely, but that he understood the hesitation to jump into a waterflooding program. “Companies have growth targets and they don’t want to convert a producing well into an injector, even for long-term value upside. They’re more quarterly driven, but I believe it’s the next wave.”
Near-term costs are likely the biggest factor keeping from more companies from following suit, said Smith. “There has been a very large push in the market for production growth … if I have a well that producing 20-50 barrels per day and decide to turn them into injectors, I’m losing production in the near-term.” A decision which the market is not always happy about, said Smith. The near-term loss is more than recovered over time by the shallowing of decline curves, however, said the COO.
“Will it work in a lot of the reservoirs in the States? They tend to be deeper, they tend to be tighter, but there’s only one way to find out: put some water in the ground. Measure and get data, and see if it works.”
Expanding the program
When asked about Crescent Point’s waterflood program outside the Viewfield, Smith said the company is seeing promising results elsewhere as well. “The Viewfield (in the southeast) is the second-largest oil field ever discovered in Western Canada. If you look to the southwest, we have the third-largest oil pool ever discovered in Western Canada, called the Shaunavon. We own 90% of that.”
“It’s a carbonate, and we are having better results than what we saw in the early days of the Viewfield. We were concerned because the rock is even tighter there, and it’s a thicker sector of pay with 10-12 million barrels of pay per section, [but] we’ve been seeing faster and more immediate response there than we saw in Viewfield.”
Smith also said that the company was looking to use waterfloods in its Uinta acreage in Utah as well.