The practice of drilling multiple wells on single pads, commonly known as “pad drilling,” is changing the dynamics of exploration and production in the Bakken and by all indications will continue to do so.
Advancements in directional drilling and hydraulic fracturing have made pad drilling feasible. With these advancements, a series of vertical well bores can be drilled in very close proximity, typically 25 to 30 feet apart, followed by long horizontal laterals drilled and fracked in multiple parallel and/or diverging directions, opening up large portions of tight formations from a single surface location. The technique is particularly well suited to plays such as the Bakken where reservoirs are thin but laterally extensive.
Although pad drilling has only come into widespread application in the Bakken in the last two to three years, the method dates back to the early days of production in Prudhoe Bay, according to Denny Smith, director of corporate development for Nabors Drilling, the largest drilling contractor in the Williston Basin. Smith said true commercial pad drilling began in Prudhoe Bay in response to environmental concerns and the need to minimize surface impacts.
While the same fundamental method is used for offshore production, Smith said for years it simply was not cost effective on land in the Lower 48 states. However, as technologies advanced, pad drilling eventually became more feasible and found application in places like the Piceance Basin of Colorado where wells were clustered on single pads in rough, mountainous terrain.
Now, coupled with North Dakota’s standard 1,280-acre spacing unit, pad drilling is facilitating production while minimizing surface impacts in the Bakken.
ND’s 1,280-acre spacings
Alison Ritter, public information officer for the Oil and Gas Division of the North Dakota Industrial Commission, said North Dakota set standardized, north-south 1,280-acre well spacings in early 2010, not only to minimize surface impacts but also to organize those impacts. She said knowing that laterals can be successfully drilled up to two miles long, it made sense for the state to set the spacing units that combine two sections in a one- by two-mile unit.
But Ritter said it also made sense to arrange those two-section spacing units into an organized grid. The state’s preference was to configure two sections, one on top of the other, into a single 1,280-acre “standup” spacing unit. The standups were then arranged in side-by-side patterns and accessed either from the north or the south via east-west trending service roads.
“If you’re just randomizing where you’re placing these 1,280 acres, you’re probably not going to have the best desired outcome on the landscape. But if you can take a giant puzzle and put the pieces together first, and then go back and draw your picture, you have a better idea of how things are going to look when everything’s done.” Ritter uses several aerial photographs of energy corridors and multi-well pads to illustrate this concept when she gives presentations to the public.
Ritter said the reduction of surface impacts is one of greatest benefits of pad drilling. With conventional drilling, surface impacts from oil production were almost 10 percent of a spacing unit, but with pad drilling, she said, those impacts can now be less than 0.4 percent. Being able to maximize the recovery of oil while minimizing impacts on the landscape is part of North Dakota’s mission statement, she said, adding “we want to realize the greater good from this resource, but we want to minimize the impact that it has on our landscape and our people.”
Allowing for green spaces
Drew Combs of North Dakota’s Trust Lands Minerals Management Division agrees that pad drilling is a good management plan for energy corridors that allow for large green spaces. “The Industrial Commission is managing not only for the producers but also for the people that utilize the surface.” The larger spacing units, Combs said, allow for the production of oil from a tract while maintaining a minimal surface footprint. “Smaller footprint, more production,” he said.
Combs said he sees 1,280-acre spacing continuing as the trend for future production, but he said his concern is for areas where those spacings are not feasible due to terrain constraints such as in the Bad Lands. Where feasible, Combs said, he would promote larger spacing units in such areas.
Maximizing recovery
Rick Muncrief, senior vice president of operations for Continental Resources, said his company worked with the North Dakota officials to develop spacing units that would maximize recovery. In conventional plays, Muncrief said, “setbacks” or buffer zones are implemented to prevent a producer in one spacing unit from extending into and draining the reservoir from an adjacent spacing unit. A setback of 600 feet, which is not uncommon in conventional plays where oil is mobile, results in 1,200 total feet of reservoir that is not developed.
However, Muncrief said North Dakota had the foresight to realize that in tight, unconventional reservoirs such as the Bakken where the oil is immobile, reservoir drainage from an adjacent spacing unit was not the issue it is within conventional reservoirs, and he said the state regulators worked with all the stakeholders to deliver appropriately reduced setbacks to allow as much of the reservoir to be drained as possible within the confines of a single spacing unit.
Continental was one of the first companies to employ pad drilling and coined the term “ECO-Pad” accounting for the ecological advantages from minimizing the surface footprint, as well as the economic benefits associated with centralized locations. The ECO-pad, Muncrief said, “gives you a relaxed setback, and that’s what differentiates it from other pad drilling in more traditional development.”
Statoil’s Lance Langford, vice president for development and production in North America, agrees that one of the biggest reasons for pad drilling on larger spacings is a much smaller surface footprint. Langford said that Statoil is currently looking to drill up to seven wells per pad in some areas, and that a seven well pad is only approximately 1.7 times the area of a single well pad. Having seven wells with less than twice the additional surface disturbance of a single well provides additional efficiency, according to Langford.
Another added efficiency, according to Langford, is that twice as much reservoir can be accessed in a 1,280-acre unit as in a 640-acre unit, with the only additional cost drilling the extra approximately 5,000 feet of lateral, which he said is “fast drilling.”
Less infrastructure
Not only does pad drilling result in a smaller surface footprint, but it can also result in less infrastructure, according to the Oil and Gas Division’s Ritter. She said pad drilling on a large spacing unit allows producers to install infrastructure such as pipelines and electricity only once rather than having to install multiple lines to multiple locations in the unit, “dotting all over the landscape.”
According to Statoil’s Langford, a further advantage is that oil is often transported from the wellhead to major transportation hubs via truck, but with multiple wells in close proximity there can be sufficient volumes of oil to justify installation of gathering pipelines. The same can hold true for water, and at many sites, Langford said, Statoil brings fresh water in and takes production water out through pipelines.
Langford also said that more contiguous acreage helps to justify the cost of installing pipelines. The most favorable economics, he said, result from a combination of having multiple wells on single pads and having multiple pads in a given geographic area.
Langford pointed out that with such pipelines in place, the number of truck service trips decreases significantly over the lifetime of a well. He said with the oil and water pipeline systems that Statoil has installed to date, the company has eliminated more than 100 round truck trips per day in the basin. That number, he said, is growing and he is hopeful that by the end of 2013 Statoil will be able to eliminate upwards of 300 truck trips a day.
And another advantage that Smith of Nabors saw with pad drilling in Prudhoe Bay was the positive economics associated with downspacing as well as with additional exploration. As production in an area matures, companies begin looking at capturing more of the marginal resources, whether that is through downspacing or looking at shallower or deeper sources. With all of the infrastructure and processing capability already in place, Smith said, the additional cost to develop those other resources becomes economically feasible.
Zipper fracking
Another benefit to pad drilling is in what Statoil’s Langford calls “zipper” fracking, where one crew fracks multiple wells on a pad in a single operation by manifolding the wells together. With this process, Langford said, four wells can be fracked in the time it used to take to frack a single well.
In zipper fracking, the first zone in the first well is perforated and fracked after which the well is isolated from the other wells with the manifold. Then the first zone in the second well is perforated and fracked. While the second well is being fracked, a plug is placed in the first well so that the second zone in the first well can be fracked. These simultaneous tasks continue in succession until all zones in all wells are fracked. According to Langford, this zipper fracking process has been one of the biggest cost savings associated with pad drilling.
Specialized rigs
Efficient pad drilling also requires specialized “walking” rigs that can readily move from one well location to another on a pad, according to Smith. Only a small percentage of the rigs currently operating in the U.S. have that specialized design, but Smith believes that as pad drilling becomes the norm, more and more specialized rigs will be built. He said Nabors currently has approximately 90 drills either in service or being built that are capable of pad drilling, most of which are true walking rigs. A large number of these rigs, he said, are in or headed to the Williston Basin.
Continental’s Muncrief said his company currently has 20 contract drill rigs operating in the basin, about two thirds of which are walking rigs. While there will probably always be some market for conventional drill rigs, Muncrief believes that over time the drilling contractors that have the walking capabilities “are the ones that are going to truly provide producers with the flexibility that they need and the efficiency that they need.”
Backup of rig orders
In his monthly webinar on Dec. 17, Oil and Gas Division Director Lynn Helms said there are large numbers of walking rigs currently under construction. Several operators with whom he has spoken said they plan to replace conventional rigs with walking rigs over the next few months. He added that there is a backlog of rig orders but those new walking rigs should be delivered in the next six to 12 weeks.
Most walking rigs have stationary “backyards,” the part of the rig that houses such ancillary equipment as electrical generators, fuel tanks, water tanks and mud pumps. These rigs, according to Helms, can drill a maximum of four wells without having to stop, break down and move the backyard. He added that one company is already looking at a walking rig with a mobile backyard that walks with it.
Helms estimated that approximately 50 percent of the rigs currently operating in the Bakken are walking rigs. “Most of the companies want to get to the point where they only have one or two conventional rigs in their portfolio, and all of the rest walk.” He said by the end of 2013 the goal of many operators is to be at 75 percent walking rigs, and eventually reach 80 or 90 percent by sometime in 2014.
More wells and longer laterals
According to Muncrief, Continental continues to increase the number of wells per pad and just started on its first 14-well pad with plans for another 14-well and a 16-well pad in 2013. In addition, Continental is experimenting with three-mile laterals and has already drilled and completed one three-mile lateral in Montana, which is now on production. Continental is currently drilling two other three-mile laterals in North Dakota.
Being able to drill two miles down and three out and have successful completions, Muncrief said, is another step change in oil and gas production. “It just shows you the power of the technology with horizontal drilling.”
Downsides
According to Ritter, while the good definitely outweighs the bad, there are some downsides, the biggest of which she said is for people living on service roads. On an east-west road where an energy corridor is being developed there are traffic impacts “that, you cannot escape.” She said the larger spacings are the best management strategy, “but try telling that to somebody who lives there.”
Another issue with pad drilling according to Muncrief is that a single well can go on production as soon as it is completed. With multiple wells on a single pad, however, they all have to be drilled and completed before any go on production, resulting in some delay, although Muncrief said that is really a minor issue and he doesn’t see any significant downsides to pad drilling.
Langford said a potential downside that he sees is in having sufficient takeaway capacity for all the wells on a pad when they all come on production at the same time and initial production rates are high. He said if there isn’t sufficient pipeline capacity, then trucks have to be used to handle the initial volumes.
The way of the future
Increasingly, other Bakken operators are moving to pad drilling as well. For example, Oasis Petroleum is transitioning to pad drilling and is looking for full pad development in 2013; Hess Energy announced in its third quarter 2012 production results that the company is transitioning to pad drilling; WPX Energy is converting is drill rig fleet for pad drilling; SM Energy began transitioning to pad drilling early in 2012; and Pioneer Drilling is planning to add 10 walking rigs to its fleet in the coming year.
Statoil’s Langford believes that multi-well pads will be the norm, even though, as he said, they are a huge capital investment. By early 2013, Statoil hopes that all of its 12 contract Bakken rigs will be walking systems. “Even in slow times, the preference for operators will be for the new walking rigs, so that’s incentive for drilling contractors as well.”
Continental’s Muncrief said he believes the drilling technologies being used in the Williston Basin are driving the technological advances in pad drilling, and he also believes that pad drilling will become the norm in the Bakken. “We’re to the point we’re getting far enough down the road where the pad-type drilling will be more of the norm as you go forward.”
Smith of Nabors also agrees and believes pad drilling will become the norm in the Bakken and similar plays. “My sense is that for the total population of wells out there it’s relatively early, but it’s emerging fast.”
