SAGD well production to improve with technology

New positioning technologies allow SAGD wells to be drilled cheaper and with less downtime

By Pat Roche

Aug. 16, 2016, 7:42 a.m.

http://www.jwnenergy.com/article/2016/8/new-positioning-technologies-allow-sagd-wells-be-drilled-cheaper-less-downtime/

 

They call it ranging.

One definition in the Oxford Dictionary describes ranging as “obtaining the range of a target by adjustment after firing past it or short of it.” In SAGD drilling, unlike field artillery, there’s no such luxury as multiple tries. If the horizontal wells miss their target, the cost can be millions of dollars—either in bypassed bitumen because wells aren’t in the best resource, or in wasted steam because well pairs are too close together.

SAGD, which accounted for roughly 850,000 bbls/d of Alberta bitumen production in 2015, was commercialized at the start of this century. There are now thousands of SAGD wells on commercial production in Alberta, with the oldest dating back more than a decade and a half.

As with any equipment, the older a well is, the more likely it is to fail. As more SAGD wells age, more will need to be re-drilled. The faster these re-drills can be done, and the less production downtime it involves, the less impact it will have on a producer’s bottom line.

The problem: Imperfect surveys 

Crews drilling horizontal well pairs need to know where the drill bit is relative to reservoir targets, and also relative to other wells. To do this, they take a survey every time a joint of drill pipe is added to the drill string—roughly every 10 metres.

The survey consists of three pieces of information: the inclination, or tilt, of the drill string at that point; the azimuth, or compass direction; and the measured depth, which is the length of the wellbore.

The first two values—the inclination and compass direction of the drill string—are obtained using measurement-while-drilling (MWD) tools.

The third value—the measured depth—is easily and accurately calculated from the length of pipe in the hole. These three values are integrated and used to calculate where the well is in the subsurface.

The problem is that the inclination and azimuth readings, while very accurate, are imperfect. The azimuth, or horizontal direction, may be out by as much as one degree and the inclination reading may be off by 0.1 degrees. When a well starts drilling, these errors are negligible. But with each survey reading, the position error is compounded.

Over two kilometres of drilling, this can add up. Take, for example, a 2,000-metre wellbore that was designed to be due east. At the toe, the estimated compass direction could be out by as much as 20–25 metres to the north, or 20–25 metres to the south. That’s as much as 50 metres of total discrepancy.

In the SAGD industry, this error in a well’s position is called the ellipse of uncertainty. It becomes an issue particularly when one well in a SAGD well pair fails and needs to be re-drilled.

It’s no surprise that operators would want a better ranging tool. Halliburton and Scientific Drilling International (SDI) both recently field-tested new ranging systems, which representatives described at the SPE Canada Heavy Oil Technical Conference in Calgary earlier this year.

Reducing downtime 

For the past few years, Halliburton has been developing a ranging tool that would improve on its widely used magnetic guidance tool (MGT). In SAGD, the lower well—the oil producer—is drilled first. Then the steam injection well is drilled a few metres above, and parallel to, the producer. Halliburton puts its MGT in the first well—called the target well—to maintain the correct distance while drilling the second well.

The MGT is an electromagnetic solenoid—a coil that acts as a magnet when carrying electric current. Run into the well to be twinned, the MGT creates a magnetic field that is detected by MWD sensors in the parallel well that is being drilled.

By putting a known current down the target well on the MGT coil and creating a magnetic field of a known strength and orientation, the driller of the second well can determine the distance and direction from the target well. Halliburton says its MGT has been used to drill more than 2,000 injector wells.

But the downside of the MGT and similar tools is they have to be placed inside the target well. The guidance tool is conveyed into the wellbore on either coiled tubing or wireline tractor, which means a wireline truck or coiled-tubing rig has to be brought in.

This is costly and time consuming—the more personnel and equipment on site, the higher the price tag. And if a well is being drilled to replace a failed well on a producing well pad versus on a new well pad, work has to be done to prepare the target well, increasing production downtime.

To get the MGT into a producing wellbore, the well has to be taken off production and the wellhead has to be disconnected from all the flowlines. A service rig may be brought in to pull out the completions string, production tubing and possibly downhole instrumentation and pumps.

What if the driller could determine the distance and direction from an existing well without putting the ranging tool inside the wellbore? Halliburton has devised a new ranging technique to address this issue. The so-called gradient discovery tool has undergone field trials, and the results are discussed in an SPE paper by physicist Hsu-Hsiang “Mark” Wu, electrical engineer Akram Ahmadi and mechanical engineer Sean Hinke, all with Halliburton.

With the new method, the ranging tool can simply be attached to the wellhead of the target well; it doesn’t need to be conveyed into the wellbore. For that reason, a well may have to be taken off production for only a couple of days rather than a couple of weeks with the current system.

Also, if you don’t need wellbore access, then you don’t need space to set up a wireline truck by each well pad, so potentially wellheads could be closer together, says Hinke. This would reduce upfront facilities costs, which are a significant portion of the overall spend on a new pad. Tighter wellhead spacing means less structural steel, shorter pipelines and smaller well pads, which reduces capital costs and the environmental footprint.

In its SPE paper, Halliburton thanked Cenovus Energy, Canada’s biggest SAGD producer, for supporting the field trials of the new ranging technology. However, the company declined to comment for this article. “It’s too early in the evaluation stage for us to provide any insights,” explains Reg Curren, a Cenovus spokesman.

Absolute certainty 

Houston-based SDI, a Halliburton competitor, took a different approach in building its new ranging tool.

Instead of magnetizing the wellbore or wellhead, SDI adapted a technique the construction industry has used for many years to install underground utilities. Machines such as the ubiquitous Ditch Witch routinely drill directionally under streams and streets to install cables and other underground utilities. An electromagnetic signal guides a directional drill underneath a road or river to a targeted location on the opposite side.

“So we said, okay, SAGD drilling, particularly north of Fort McMurray, is a lot deeper than what these construction people have been doing,” says Clinton Moss, president of SDI’s Calgary-based Marksman Ranging Technologies division. “We said, ‘Well, what is the limit of the technology?’ So then we set about exploring that.”

Originally an independent company started by Moss and partners in Edmonton in 2014, Marksman was acquired last year by SDI.

The question SDI’s Calgary team set out to answer was, could they create enough magnetic field on the earth’s surface that a meaningful signal could be detected downhole by an MWD sensor in the drilling assembly? The answer is yes, according to an SPE paper by Moss and Doug Ridgway, a physicist at SDI.

Coils of wire are laid out on the ground over the path of the planned horizontal well. GPS receivers pinpoint the exact location of the wires on the surface. An electric current is sent through those coils of wire, generating a magnetic field. When this magnetic field is detected by the MWD sensor, it is used to calculate the location of the drill bit.

The current SDI tool is limited to shallow horizontal wells, but Moss says the company is working on increasing the range.

“Right now, we’re quite comfortable operating at 250 metres [true vertical depth] or less,” says Moss. “350? Stretching it. 450? Currently out of reach.” The deepest SAGD wells in Canada are between 450 and 550 metres deep.

But at the depths where it works, SDI’s new ranging tool has achieved sub-metre accuracy, Moss says. “We actually did as good as 25 centimetres at a total depth of 125 metres. So you’re talking about better than one per cent accuracy.”

Like conventional survey readings, SDI’s new technique has measurement errors, however small. But unlike conventional technologies, SDI’s method doesn’t compound the error as the wellbore is extended.

“The most important thing here is…there’s no growing uncertainty,” says Moss. “It’s for all intents and purposes a very accurate measurement that has non-cumulative uncertainty.” In other words, because each survey reading is an absolute position based on the GPS, one measurement doesn’t depend on the previous one.

While Halliburton’s new ranging tool gives the drill bit’s location relative to an existing wellbore, the new SDI ranging tool is designed to provide an absolute position of any shallow horizontal wellbore.

Avoiding collisions 

As of June, SDI said its new ranging technique had been used on eight SAGD wells at depths of 100–250 metres for two different operators in northern Alberta. About half of those were for Suncor Energy.

The biggest benefits of the SDI technology are collision avoidance and knowing the exact position of the well as it is drilling, says Troy Abs, a senior drilling engineer at Suncor.

Because the SDI tool provides an absolute position via the GPS co-ordinates, Abs says the risk of collision with existing wells would be significantly reduced because the ellipse of uncertainty would be largely eliminated.

He pointed out that collision avoidance is particularly important on thermal oil developments, which are crisscrossed by observation wells and stratigraphic wells, along with steam injection and oil production wells.

The Suncor drilling engineer says the technology has some limitations, such as the depth restriction. But his overall experience with the field trials was positive. “It helped us out a lot—to get better accuracy and avoid collision. You’re certain of where you are, so it gives you a lot of confidence.”

Suncor tested the SDI technology in tandem with conventional magnetic ranging and the results compared well. “At this point, it’s not applicable to everything that we do [in SAGD drilling], but there are areas that it will definitely help,” Abs says.

The other advantage, he says, is that if an existing well has to be sidetracked or re-drilled, it can be done with more confidence and less hassle. Conventional ranging tools have to be deployed within the target well, which can mean shutting down the well, pulling the tubing and other costly and time-consuming preparations.

About prosperitysaskatchewan

Consultant on Saskatchewan's natural resources.

Posted on August 16, 2016, in economic impact, oil. Bookmark the permalink. Leave a comment.

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