Lateral Moves

Longer laterals, faster completion times, and tightening budgets have pushed downhole tools to their limits in the last five years. Innovators at service companies like Neo Oil Tools, NOV, and Baker Hughes are also pushing the research envelope to adapt their equipment and procedures to the demands of today’s oilfield. In every case they’re finding ways to help equipment last longer and to reduce unproductive trips downhole.

Reducing Vibrations

Neo Oiltools Chief Executive Officer Robert Borne says, “As we’re drilling longer and deeper through the less homogeneous lithology of the Permian Basin, the stress on bottom hole assemblies [BHAs] and on drill bits is much higher than it used to be,” especially as Permian activity moves farther to the basin’s western zones.

A big part of the speed boost is achieved by increasing weight on bit. In a vertical well, the drill string itself naturally increases the weight on bit as it lengthens with every section added. But in a well’s laterals, every additional foot works against the weight on bit.

Additional length also adds to the torque required on the drill pipe, causing it to wind up somewhat like a spring in a rotary steerable procedure—the torque must build up all along the string to the point at which it overcomes the rock’s resistance at the bit. This stopping and starting is called stick/slip. When the bit overcomes the rock’s friction and spins suddenly, “it rattles or vibrates the entire drill string,” he explained.

That vibration, over time, damages the drill bit, the bottom hole assembly (BHA), the complex electronics in management-while-drilling (MWD), logging-while-drilling (LWD), and other components. If the bit’s damage increases to the point that it’s ineffective, the whole drill string must be pulled to replace the bit, costing thousands in equipment and in delays.

The goal of Neo Oiltools’ anti-vibration tool, called neotork, is to keep the bit turning and reduce stick/slip’s vibrations, extending the life of the bit and the BHA as a whole. “This allows operators and drillers to increase the weight-on-bit and get their wells into production faster,” he said.

 

How It Works

The neotork tool consists of an upper assembly with a box connection and a lower assembly reinforced with a shaft that secures a pin connection. Cables and springs open and close the tool, depending upon the amount of torque.

Cables are bolted to either end of the tool, set at a 30 degree angle. When torque becomes greater than a set level, it contracts the tool and the cables wrap around it. By reducing bit engagement in the hole, the tool’s contraction releases some torque demand and stops torsional vibration. When the torque drops, springs act to open the tool, returning it to full length and returning the bit to full engagement.

Developed in 2015, the company’s patented tool has been used successfully in the Permian and in other basins since then.

 

Factory Drilling

Borne said the drive to factory drilling, where one rig drills multiple wells from one drill pad and all the procedures are normalized across each well, is a significant factor in the stretching of BHA and bit limits. “The laterals are getting longer because more produceable rock is exposed, which makes the well more economical.” To further maximize returns, “One of the biggest pieces of drilling a long lateral is that you want to do all that in one run. You don’t want to have to drill a portion of it, then pull the entire string out of the hole to replace/repair/renew any part of it, then go back into the well.”

 

Do You Know What That’s Worth?

The cost for even a short delay is staggering, coming from field interviews. “I was in the Permian [recently] and I heard a major operator quote to me that every second on location was worth more than a dollar.” One dollar sounds small, but at one second that’s $60 per minute and $3,600 per hour—multiplied by dozens of wells over 365 days in a year.

Because of that, scheduling of every component—drilling, laying out casing, pumping cement, completion crews, and everything—“is getting tighter and tighter.” And then, therefore, the business model is changing for downhole tools.

“What we’ve seen in the directional drilling space over the last number of years, is that the business model has really been changing from the large technology creators, the big oilfield service companies that invented a lot of these rotary steerable directional tools. For them the model’s changed to where they rent, lease, or sell these tools to smaller directional drilling companies. Then they end up servicing the tools.”

 

Reaching Greater Depths More Efficiently

Roman Che, global business development manager at NOV Downhole Technologies, says the idea is to deliver 100 percent of the weight and torque to the bit—in a perfect world. Down the depths and across the miles, however, the side forces and friction, among other factors, make this goal unattainable. But every increment in the right direction saves some more energy and reduces BHA, allowing the driller to drill farther and faster.

Che says longer laterals result in higher frictional pressure losses requiring increased standpipe pressures (SPP) to maintain mud circulation, make a hole, power the downhole tools, stabilize the wellbore, and clean out the drilled cuttings. But that can tax the pump’s pressure limits. The limit for most of today’s common mud pumps is 7500 psi, he said, but due to safety factors “most operators will want to stay below 7,000 psi.” Upon venturing past the two-mile point, available standpipe pressure often becomes insufficient. One option is to dial back the flow rate, but this can impair hole cleaning and decrease motor sliding efficiency, potentially leading to more significant issues if not addressed.

 

Conventional Solution that Comes with Limitations

To solve that, Che said “most of the conventional BHAs in the Permian use friction reduction tools like agitators. These tools are highly effective at breaking up static friction, which is vital for sliding on conventional motor BHAs, but there is a caveat: every agitator in the drill string requires about 500-600 psi of SPP.”

That pressure requirement strains the available SPP, which some drillers attempt to mitigate this by reducing the flow rate. But says Che, “Once you reduce your flow rate because of the standby pressure limitations, not only may the hole-cleaning efficiency be reduced, but the pressure drop across the agitator will drop because it’s pretty much a linear relationship between the pressure drop across the agitator and the flow rate.”

 

NOV’s Better Idea

NOV’s Agitator™ZP (patent pending) agitates the pipe, Che said, without requiring 500-600 psi of pressure. Because some longer laterals require two agitators, which would typically total 1,000-1,200 psi, the AgitatorZP used in tandem with a standard agitator reduces the pressure requirement by half. This way, Che explained, “It requires less loading and strain on the mud pumps and offers a unique opportunity to enhance sliding efficiency.” Reducing mud pump horsepower, along with lowering drilling and circulation time, also reduces carbon emissions and aligns with NOV’s ESG commitments.

 

Baker Hughes and the Push for Speed and Accuracy

Baker Hughes’s Permian Basin Director Jeremy Hess offers a simple explanation of the company’s goal in drilling and completing wells of any length. “If I were going to drive my brand new Cadillac Escalade from here [Midland] to Houston, I’d rather be on a smooth highway than go down some bumpy dirt roads. That means we want to get the well on a smooth drilling highway, and that just means getting rid of vibrations as we’re drilling.”

Staying on the right road is also important and Lucida, the company’s newly released upgrade to their Rotary Steering System (RSS), uses auto-correct systems to drill virtually autonomously on the longer laterals that are becoming the norm, said Hess.

He pointed out that longer laterals “introduce additional challenges and costs, but they also introduce additional production, so that’s where I think the operators have to make the right decision.” Company figures show that, over the last three years, lengths for wells they drilled were up by around 20 percent year-over-year.

Longer laterals increase the cost-per-foot, he said, because “It’s going to drive the need to introduce some technology in the way you’re constructing the well. You’re going to have to  have higher torque, higher torque-and-drag.” That being so, drillers will have to raise the bar on specifications for rigs, drill pipe, casing designs, and more. So part of the equation involves whether the additional production will overcome the extra costs. In most cases, said Hess, companies decide that it will indeed pay off.

Speed vs accuracy is a delicate balance. While drilling crews may push for speed, that can’t be their only focus. “If there are drillers that don’t have their production counterparts in mind, it can create some problems. So whenever we drill these wells we need to be mindful of the fact that they need to be out there producing and functioning with equipment that needs to be run in the cased hole for years to come.”

 

Bad Vibrations vs Smooth Operators

Baker Hughes’s way of reducing vibrations is by using an increasingly popular option, RSS, because it “allows you to directionally drill while you rotate the entire drill string. Because if you don’t have a rotary steerable system, then you ultimately have to shut down the rotation of the entire drill string, which might be 3-4 miles long. That creates torque-and-drag that could be broken with rotations.” Constant rotation improves wellbore quality—and it reduces issues like vibrations and stick/slip (VSS in Baker Hughes vernacular).

Hess says the system uses downhole sensors providing real-time data to manage vibrations as it goes along. That way, “We know exactly what vibrations are happening, when they’re happening. Then we address those vibrations with drilling parameter changes. We also have dampening subs down hole that absorb and mitigate vibrations, allowing the bottomhole assembly to drill more smoothly.”

Basically, Lucida is getting that Cadillac on a smooth road to Houston.

Push Me, Pull You

The two-headed horse of speed versus quality has been mired in conflict in the past, but new systems like those listed here are getting closer to moving that animal in one direction.

 

Paul Wiseman is a freelance energy writer.

 

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