Drilling an oil well that stretches horizontally two miles from the well pad has become commonplace, but it wasn’t always the development option it is today.
A decade and a half ago, oil and natural gas companies began pairing horizontal drilling with multi-stage hydraulic fracturing to unlock new unconventional oil and gas resources, often in the same fields where conventional production was ongoing for decades.
In the years since, prolific new plays sprung up in old fields near places like Williston, N.D., LaSalle County, Texas, Washington, Pa., and Greeley. High oil and gas prices and reduced risk roused investors to provide companies with the financial backing to push the accepted limits of horizontal wells and frac stages.
While the sustained drop in oil prices has severely reduced activity in all domestic shale plays, the limits continue to be tested.
Now, even as companies relentlessly squeeze the last bit of excess from their budgets, implore their workers to do more with less and make sure all hatches are battened down, companies point investors to successful projects involving longer laterals and well completions with more stages and tons of proppant.
“When I drilled my first horizontal well 25 years ago, it went out 1,000 feet,” said William Fleckenstein, adjunct professor of Petroleum Engineering at the Colorado School of Mines in Golden. “Everyone thought that was a big deal. Now, companies routinely drill two miles out.”
“The technology is readily available to overcome the challenges drilling horizontally used to present,” he said.
Companies operating in the DJ Basin highlight their success with longer laterals when seeking to build interest with investors or earn approval of the public.
At an investor conference in March, Noble Energy, the second largest producer in the DJ Basin, said it had reduced the cost of drilling its long lateral wells by 40 percent and cut well development costs to less than $3 million per well.
In 2013, Noble reported it had successfully drilled a lateral well of 9,978 feet, which is 582 feet short of two miles. More recently, Noble reported drilling and completing long lateral wells at its Wells Ranch field east of Greeley for less than $3 million, among the lowest horizontal well development costs in the country.
Synergy Resources, long-time operator in the Wattenberg Field, told investors that while some wells were intentionally drilled but not completed, its plans for 2016 and beyond call for drilling longer lateral wells.
The company’s drilling plans are “shifting from standard laterals, those of 6,000 feet or less, to mid-length laterals, greater than 6,000 feet, and to long laterals, greater than 9,000 feet,” according to a Synergy report. As part of a shift toward longer reach horizontal wells, Synergy’s report refers to extended-reach laterals of greater than 11,000 feet but there were no indications that it plans to drill such wells.
Synergy concluded that drilling longer lateral wells produce more oil, provide better returns and faster payout of investments.
Anadarko, the largest producer in the DJ Basin, recently reported that its capital budget for 2016 has been reduced by 70 percent from 2015 and investment in the DJ Basin cut by more than half.
The company does not disclose a well count for lateral length but indicated it plans to drive down drilling costs for all wells to $2.7 million per well in 4,800 ft. short-lateral equivalent dollars from $3.7 million in 2015.
Even with a reduction in drill rigs to one from seven rigs operating in 2015, Anadarko reports production this year will continue at levels slightly above last year.
Extraction Oil & Gas described its plans to drill long laterals at recent hearings on its proposal to develop up to 22 wells from its Triple Creek pad in west Greeley. The company’s plan was approved by the Greeley City Council in March.
An attorney for Extraction, a privately held company, testified that its plans include drilling horizontal wells up to 2 ½ miles from the well pad.
Drilling more expensive long-lateral wells allow for development of minerals while “minimizing impact on the public,” the company representative said.
Companies have shown that drilling horizontal wells further into a formation like the Niobrara or Codell, when completed with modern, multi-stage hydraulic fracture operations (see Energy Pipeline, May 4, 2015), can result in a well that produces more oil, gas and condensate in greater daily volumes than do shorter lateral wells.
Why are today’s unconventional plays like the Niobrara able to tap resources that were largely overlooked in the past?
Conventional oil production in North Dakota’s Williston Basin, for example, began in earnest in 1951 and eventually peaked 35 years later. Once the two key techniques, horizontal drilling and fracking, were applied in the Williston’s Bakken and Three Forks formations beginning in 2000, the total amount of oil in the basin that was either already produced or was now accessible increased by more than 29 percent to 3.8 billion barrels, according to the U.S. Geological Survey.
For nearly 40 years, conventional production made the Wattenberg Field in the DJ Basin one of the top producers of natural gas in North America. Starting in 1970, companies found success by drilling vertically into the J Sandstone and applying proven fracturing techniques to complete the wells. In the early 1980s, companies, still drilling vertically, found they could fracture the rock in the shallower Codell and Niobrara formations to tap a new source of oil, gas and condensate.
Then in 2009, companies across the DJ Basin began applying horizontal drilling technology that allowed the driller to “build” a quarter-circle radius into the path of the well bore. By combining horizontal drilling with hydraulic fracturing, companies found they could tap into oil further out in the Codell and Niobrara formations and away from the conventional accumulations in hydrocarbon traps.
Combining the two keys of horizontal drilling and hydraulic fracturing opened the door to an expansion of development across north central Colorado. Assisting this expansion in a region that was also seeing an influx of new homes, businesses and public facilities, was deployment of new drilling rigs that allowed the company to drill several wells from a single well pad and reduce the number of surface locations in a spacing unit.
In Colorado, a traditional, vertically drilled oil or natural gas field was developed according to spacing units authorized by the Oil and Gas Conservation Commission. Depending on which part of the state or specific field being developed, a spacing unit, also called a drilling unit, would typically start with not more than four wells per 640-acre section, or one per 160-acre quarter section.
In applying for permission to develop all or part of a section of land, an operator files a request of the commission to allow it to form a spacing unit to share the proceeds of development fairly among all mineral owners.
A spacing unit might include a single mineral owner or, as often seen with ownership split among family members or sold piecemeal, several owners. In these cases, the spacing unit divides the proceeds, less the costs, of drilling and producing all wells within the unit.
In forming a unit, Colorado requires all mineral parcels to be included, or pooled, even if an owner refuses to lease their minerals to an operator. Often referred to as “forced pooling,” this allows all mineral owners to enjoy the benefits of production even if one or more neighbors within the unit choose not to lease.
In prolific oil or gas fields, the operator can request the commission allow additional wells to be drilled within the spacing unit to more effectively drain the resource. Any additional production is again divided proportionally among the mineral owners.
As a result, productive areas where infill spacing allowed up to one vertical well per 40 acres, or 16 wells within a square mile, were often used to illustrate what some saw as over-development. Such fields were featured in aerial photos as examples in campaigns against new drilling in undeveloped areas.
The sharp decline in commodity prices for oil had an immediate effect of reducing costs across the board for oil companies and their suppliers. Faced with lower prices, operators cut staff and squeezed oilfield service and supply companies. In turn, the service companies found ways to cut prices through efficiencies, smaller employee rosters and simply getting by with less.
Drilling costs however, were already declining before prices started dropping 18 months ago. A new report commissioned by the Energy Information Administration indicates drilling costs peaked in 2012 and have since declined by 25 to 30 percent.
The EIA report was compiled by Englewood-based IHS Inc. and released in March. It examines, among others issues, drilling and completion costs over 10 years for the five largest oil and natural gas fields and offshore Gulf of Mexico. Neither oil drilling in the Wattenberg field nor gas drilling in the Piceance were included in the study.
As development in unconventional plays progressed from 2008, lateral well bores drilled to 2,000 feet or less were steadily extended to 10,000 feet or more. Completions became more complex requiring more pumping horsepower and fracture proppant. Costs followed suit until a peak was reached in 2012 and have been on the decline since.
“For now, it seems that about 7,500 feet is the sweet spot for long laterals,” School of Mines’ Fleckenstein said. “The additional costs are incremental but drilling further requires the operator to justify the geology, the spacing unit and rig time.”
Horizontal drilling in formations such as the Niobrara requires degrees of precision unheard of 25 years ago, Fleckenstein observed.
Drills that can be “steered” have been in use for decades, he said. However, expensive problems sometimes arose where the drill might reach its target or encounter a geologic anomaly.
Now, in addition to steering the drill bit to hit the target formation, the driller is provided with vital data from a mile and a half below the surface about where the drill is, what sort of rock it is encountering and how much pressure is being exerted on the well bore.
Guiding a drill bit equipped with self-contained motors and a suite of sensors feeding back a continuous stream of data, the driller is able to hit and stay within the oil-bearing rock. The driller also has access to modern seismic scans and analysis rocks encountered in previously drilled wells.
According to one drilling services company, drilling data includes directional surveys, gamma ray measurements, changes in rock hardness, temperature, and pressure on the well bore. Such information “enables the driller to make reliable well bore decisions with less down time.”
Such information is vital if the driller expects to stay within a layer of rock that might pinch to less than 20 feet thick and continue within that layer for up to two miles.
Even as oilfield service companies have wrung every possible dollar out of their day rates, time is still money. If something happens, the drilling company has to justify to the operator why the rig was idled. Avoiding unexpected shutdowns is in everyone’s interest.
Drilling fluids also have benefited from advancements in technology. Drilling fluids, often referred to as drilling mud, are either water, oil or synthetic based. They have always been used to suspend cuttings, control pressure within the well bore, stabilize exposed rock and provide buoyancy, cooling and lubrication.
Fluids today include additives to prevent water in the mud from causing shale to swell and increasing drag on the drill string as well as special lubricants to reduce friction.
Fact and Friction
Pushing a drill through layers of rock relies on the weight of the drill string to maintain the force needed to break up the rock. Top-drive drill rigs rotate the drill string while gravity pushes the drill string against the drill bit.
Today, most horizontal wells are drilled using mud motors to rotate the drill bit rather than the drill string while gradually turning the drill in the direction needed. As the well bore turns, the drill string bends and where it comes in contact with the well casing, friction increases. Such friction can build to where it overcomes the weight of the drill string and stops further progress. The pipe and drill must then be “tripped” or removed from the hole.
Use of polycrystalline diamond cutter, or PDC, drill bits has helped overcome some of the obstacles of friction in horizontal wells, Fleckenstein said. “PDC bits can drill at lower weights, are not slowed as much by compression and can deliver good rates of penetration.”
There are limits to getting the weight needed down to the bit if the path has a lot of bends to it. “It’s like driving down a straight road versus driving with a lot of twists and turns,” he said. “You can’t go as fast. More friction means less weight on the drill.”
Fleckenstein noted that use of mechanical spacers or of vibratory tools that increase fluid pressure or create pressure waves within the casing can reduce friction and prevent lock-up.
So, what is the limit on horizontal wells?
Wells have been drilled to amazing distances. Offshore wells can be drilled in ocean depths of two miles and another four miles into the earth.
An onshore record was established in 1998 when BP announced it had drilled an extended reach well of 10.1 kilometers, or 33,136 feet. Extended reach wells are directionally drilled, frequently with more than one bend and aimed at a target reservoir rather than the way a modern horizontal well exposes the producing formation along its length.
In 2008, a well drilled for Maersk Oil in Qatar reached a total depth of 40,320 feet with a horizontal reach of 35,770 feet. This was followed last year by a well drilled for the Sakhalin Consortium on the Orlan platform off the eastern coast of Russia. This well was drilled to a total depth of 44,291 feet, with a horizontal reach of 39,478 feet, and is the current record holder for longest horizontal well.
Fleckenstein observed that companies are faced with limits other than friction and pressure in designing longer lateral wells. “The landman might have trouble securing leases in such large spacing units. Regulations designed to maintain separation between new wells and existing production might be another obstacle. There are a number of questions that longer laterals can raise for the operator.”
Published June 5, 2016.
By Dan Larson for the Greeley Tribune