Waterflood technology is advancing Saskatchewan’s tight oil plays

Waterflood technology is advancing Saskatchewan’s tight oil plays

By Elsie Ross

April 21, 2017, 2:31 p.m.

http://www.jwnenergy.com/article/2017/4/waterflood-technology-advancing-saskatchewans-tight-oil-plays/

 

 

The horizontal drilling and multistage fracture stimulation revolution has opened up billions of barrels of resources in Saskatchewan to development. But the technology comes with one big downside—decline rates.

Decline rates on individual wells in the Bakken and Shaunavon plays can reach as high as 85 per cent in the first year, according to the Saskatchewan Research Council (SRC).

Viking declines are in the 60–70 per cent range during the same time period. This means operators ran a treadmill drilling new wells to manage corporate declines and add production.

Efforts are underway in all these plays to stem decline rates, allowing for more stable growth and reserve recovery through improved waterflood technologies.

A new technology that Crescent Point Energy is developing in Saskatchewan could potentially enable the company to maintain a steady annual decline rate even as it continues to grow, says a company official.

“If this technology works the way we think it is going to work, it’s not out of reach to have a 26–28 per cent decline rate that is holding in relatively steady even as we are growing at five to 10 per cent production, even with higher activity levels,” Trent Stangl, former senior vice-president of investor relations and communications, told a recent CIBC investment conference. The company “is not going back up to those 31 per cent to 32 per cent declines.”

Crescent Point has calculated that a reduction in the decline rate to 28 per cent from 35 per cent saved the company about $250 million, all other things being equal. “So it’s pretty significant.”

Three or four years ago, the decline rate would have been 35 per cent and this year with the incremental capital, it will be 28 per cent, he said.

The drop, though, isn’t due entirely to the waterflood. There also has been reduced activity, Stangl said, noting that at its peak, Crescent Point was running 29 rigs compared to 20–22 rigs for much of last year.

“But it’s not like there is a massive drop in activity levels,” said Stangl. “There certainly is a good component of that reduction in the waterflood.”

With the new technology, the company is able to put tools downhole to control the amount of water that is going into each of the ports. “It’s almost like a soaker hose for your lawn where you have the even distribution across the laterals.”

In the first couple of wells that it has done, Crescent Point has been able to get three times as much water into the wells, which is improving the reservoir pressure more quickly and is accelerating the response with production from the offset producer well actually going up after six months, he said.

“If we can prove this up with incremental wells, those same kind of results, that will have a dramatic effect on our waterflood,” said Stangl. “It will increase the response time, which will improve the economics.”

The company, he said, has about 300 wells currently injecting water into the Bakken and Shaunavon plays. By the end of the first quarter of 2017, it expected to put the new system in 45 of those wells so that by the second and third quarters of this year, Crescent Point will have a good idea of the response. “If that all works the way we think it is, we are going to have another 250 existing injection wells that we can convert.”

Stangl noted that in addition to the cost of the injection for the waterflood, there also is the cost of shutting in a producer well producing 10 bbls/d or 20 bbls/d in order to convert it to an injection well. “In the past, we have shut in 2,000–3,000 bbls/d every year to accelerate the waterflood.”

In the future, Crescent Point has another 250 wells it could do before it needs to shut in any more producers. “By that time, you’ll have that much more decline suppression, improving the economics.”

With the existing waterfloods, the decline rate on primary production has declined to 20 per cent from 30 per cent and in the Shaunavon Play, the decline rate is 14 per cent from 28 per cent. In the Bakken, the recovery factor is expected to improve to more than 30 per cent from 17–19 per cent.

waterflood oil extraction
New Viking waterflood shows promise

Although it’s early days, water injection into the Viking Formation in Saskatchewan seems to be working well for Raging River Exploration, which expects better recovery factors than achieved by earlier waterfloods in the same formation.

That was the message Jesse Barlow, Raging River’s vice-president of engineering, delivered recently at a joint Petroleum Technology Alliance of Canada (PTAC)-SRC workshop on light tight oil innovation.

To get better results than the old Viking waterfloods, Raging River uses saline-source water, better injector/producer ratios, tighter injector/producer spacing and higher-productivity multi-frac horizontal wells.

First waterflood reserves 

Raging River is focused entirely on the Dodsland Viking light tight oil play in west-central Saskatchewan. According to the January 2017 presentation on its website, the company is spending $35 million in waterflood capital this year.

The Saskatchewan-focused producer hopes to gradually reduce its production decline rate to 17 per cent in 2026 from a projected 38 per cent this year.

In its reserves and operations update, Raging River said waterflood execution continues to be a priority in the first quarter with an estimated $20 million being spent on facilities.

The company’s first waterflood reserves were recorded in 2016 by its independent reserves evaluator, Sproule Associates, with about 700,000 barrels of oil being booked attributable to the ongoing waterfloods.

During the question period after his presentation at the PTAC-SRC workshop, Barlow said jokingly, “We want everyone in this room to implement as many waterfloods as possible so there’s lots of examples of successful waterfloods for the evaluators.”

He said evaluators like to see a bit more production history than Raging River currently has before booking a lot of reserves attributable to waterflooding.

Barlow discussed the primary causes of old waterflood failures in the Viking and what Raging River is doing to avoid those pitfalls.

One cause of past failure was the use of fresh-source water. He said the Viking has swelling clays, which makes fresh water extremely damaging to the formation.

Another cause of past failures was the use of too few water-injection wells.

“We look at some of these old historic waterfloods and they’re on three-to-one producer-to-injector ratios,” Barlow said. “That just doesn’t work—you don’t have enough injectivity into a single well to make that work.”

So what happened historically was operators would try to compensate for too few injection wells by injecting at too high a pressure.

Excessive spacing in well patterns was another issue.

“The patterns were too widely spaced on those old waterfloods—the distance between injectors and producers was just way too big,” Barlow said. “You could never have achieved a fully implemented waterflood in an economic timeframe.”

Low-rate wells were another challenge. Since the original Viking producers were vertical wells with low oil rates, they hit their economic limit at relatively low water cuts, which greatly reduced the recovery factors achieved.

In such situations, “you’re just going to leave a ton of reserves behind,” Barlow said.

Variable permeability also impeded the success of traditional Viking waterfloods with some floods failing because permeability streaks caused premature water breakthrough.

“If you look at some of the old waterfloods that were failures, they ended up having the water just cycle right through to some of the producers,” the Raging River vice-president noted.

Raging River is avoiding the past Viking waterflood problems in several ways.

Along with obviously recycling produced water, the company is sourcing saline make-up water from the Mannville Formation. This water is more compatible with the Viking formation than make-up water from freshwater sources.

“What we have is a few Mannville source wells that are working really well for us. We don’t seem to have any injectivity problems,” Barlow said.

Raging River is also maintaining a one-to-one producer to injector ratio. In other words, its preferred Viking waterflood patterns consist of horizontal injector-producer well pairs. This provides “great injectivity and you’re not ending up in an over-pressure situation,” Barlow told the PTAC-SRC workshop.

The company is also using tighter well spacing.

In the past, the spacing between injectors and producers was typically 400 metres. The inter-well spacing in the injector-producer pairs in Raging River’s patterns is between 100 and 200 metres.

Since horizontal wells have much higher productivity, they also have a much higher water cut, which will improve the potential recovery factor in areas under waterflood.

Horizontal wells also allow greater conformance, or distribution of injected water across the wellbore.

Instead of single-point injection into a vertical well, water is injected into a horizontal section with about 15–20 fracs, so conformance should improve. “Any conformance issues should be mitigated with diversion treatments isolating problem zones,” Barlow said.

 

 

 

About prosperitysaskatchewan

Consultant on Saskatchewan's natural resources.

Posted on April 24, 2017, in economic impact, oil. Bookmark the permalink. Leave a comment.

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