Drilling for the Future

New strategies and HBP’ed acres have started the second stage of activity.
By Luke Geiver | April 22, 2013

The current state of drilling activity in the Bakken formation can be explained by a single three-word phrase: Held By Production. The phrase may sound simple––it refers to a mineral lease that has been secured for the life of the well by the lease holder through oil production or drilling activity––but its role in the transformation of the rural landscape spanning the majority of the play is incredibly complex.

The HBP lease has influenced drilling strategies, oilfield service supply inventories, logistics scheduling and any other person or industry linked to oil and gas production and the three-year lease terms typically required of a producer before that producer loses its lease. If anything has been responsible for the immense activity over the past four years, the rush of trucks, backlog of hydraulic fracturing services or even the once-unmet demand for drilling rigs, it's that phrase. A return on investment or the price of oil will always stimulate activity, but the possibility of losing a nearly guaranteed spacing unit, the legal geographical boundary in which a drilling team can operate, and its oil resources below ground, has proven to be an even greater motivator for drilling activity. 

Although the majority of leasable acres in the main core of the Bakken have been HBP’ed, understanding how the play was developed in the past can help everyone affected by the play as they plan for the future. 

The HBP Factor
"All of the operators face lease expiration issues and plan just to get that first well drilled so that the lease can be held," says Ken DeCubellis, CEO of Black Ridge Oil & Gas, a nonoperating firm that currently controls over 12,000 net Bakken and Three Forks acres. “When you are scrambling to get a rig mobilized to get a lease Held By Production, you kind of put economics on the back burner,” he says. When a spacing unit has qualified for HBP status, those acres are awarded to that producing entity for the life of the well. 

Until now, the play has been driven by the need of producers to secure their acres for future development. Tom Rolfstad, executive director of Williston, N.D.’s economic development office, says the drilling activity and strategies used can be classified into three stages: territorial, infill development, and enhanced oil recovery. The territorial stage is best described as chaotic, with producers forgetting economics as DeCubellis explains, or as Rolfstad says, it’s like being at Walmart on Christmas day. The time frame of this stage is influenced by lease-terms present in a play. For the Bakken, the majority of leases have required activity in three years. With leasing activity starting roughly five to seven years ago, most leases have now been secured and the rush to buy or lease available acres has ended, according to Rolfstad. Because of that climax in HBP activity, the landscape that once seemed to be sprinkled with randomly placed rigs, pumping units and storage tanks has begun to appear more ordered. Think of it as a housing subdivision. Before the majority of houses are in place, a single home at the end of the street seems out of place. 

The landscape is becoming industrialized, says Richard Gardner, senior fellow at the Rural Policy Research Institute Center for Rural Entrepreneurship, but with the end of the first stage of drilling activity in the region happening now, that industrialized landscape won’t mutate into a cluttered land of steel. Producers are now concerned about economics, focusing more on drilling efficiencies and resource price reduction. 

The goal of producers is not motivated by the need to secure a lease area, but is instead driven by the need to extract oil and gas to pay off investors and buy supplies, materials and services for future activity. To do that, producers are transforming their drilling strategies, taking the elements and successful approaches used to drill one well and applying them to help drill multiple wells from a single pad, or reduce costs and improve efficiencies related to extraction, gathering or transport of crude and associated gas from the wells they already have. Their efforts mean drilling sequences will be different now than in the past, and service providers, decision makers and investors will need to account and plan for the way a well comes online. 

Moving Past HBP 
HBP may have dominated the strategies of exploration and production (E&P) companies in the past, but today the term to know is: infill drilling. Like HBP, infill drilling sounds simple, but its role in the play over the next decade or more, is complex. Infill drilling programs or infill development refers to an E&P company’s plans to drill more wells as close to proven, producing wells as possible. The desire to maximize production near a proven pad, has transformed the sequence of how a well is drilled today versus four years ago. 

Craig Slawson, co-owner and vice president of Slawson Exploration, the E&P company that has been active in the Bakken since the 1980s, says change has been a constant in the play. The company has drilled 250-plus wells, with another 1,000 more to go, he says. For the industry in its infill development stage, pad drilling will be the biggest impact of change, he says. The process involves walking rigs, units that can move up to 1,000 feet per day, cutting down relocation time by more than half. The rigs can drill multiple surface holes, then move to drill kick-off points (the end of the vertical portion of a well before horizontal drilling begins) on other spudded wells (initial drilling has begun), and then move back to drill the horizontal laterals of the first wells on the pad so that a simultaneous frack job can happen all at once, he says. 

"Wells, therefore, may take longer to drill and complete at first,” Slawson says of the effects of pad drilling, but the footprint of rigs, and eventually well heads pumping on a 1,280-acre spacing unit, will be corralled into a single pad. “You cannot find oil if you don’t drill wells,” Slawson says, but a company shouldn’t act without doing its homework.

And, according to Slawson there are other changes over the past four years in the play that will affect the future. “Drilling longer-reach laterals, advances in bit technologies, more reliable mud motors, reaming tools and logging while reaming have all helped," he says. Staged frack jobs, better transport fluids and technologies, proppant size and strength and better information on harvesting density have also helped. 

Take a look at the drilling projects under development by several Bakken operators and the trend toward infill drilling is clear. Samson Oil and Gas Ltd., for example, has already announced it has taken a 60 percent working interest in Williams County, N.D., to drill six infill wells that will be drilled next to three existing wells. The use of pad drilling for the purpose of infill development has another ramification. Because the site has already been prepared and the activity level at the site will be high, Samson will construct and use production facilities and  pipeline from the site to reduce water disposal costs related to trucking. And, a gas gathering line and crude transport system are also planned. The company said it will fracture all of the wells simultaneously to develop a comprehensive fracture system. 

Gardner, who has worked for several N.D. communities to help each assess the economic impact of oil retrieval, says he has seen the trend in walking rigs, zipper fracking used to reduce fracking time and pipeline development on the well site. DeCubellis says he has seen many producers follow what he calls a best practice. “When they are ready to complete wells two, three and four, we are seeing them temporarily shut down that first well already in production. What a lot of producers are finding is that when you do that and build up the pressure in that first well,” he says, “it’s an efficient way to do a quasi-refrack of the first well.” 

What they then find, he adds, is after they restart the first well after infill development has been completed, is that production levels begin to step up. 

Operating During Infill
Infill development of the Bakken play will be impressive. According to a recent presentation from Rolfstad and his team regarding how the landscape will be shaped, or, how the subdivision of wells (not houses) will be ordered, each spacing unit in the four main western N.D. oil-producing counties, will feature four horizontal wells per 1,280 unit in the Bakken formation and four horizontal wells per 1,280 unit in the Three Forks formation. Those estimates indicate that per township per county, each township will have 288 wells. Williams County has 60 townships. 

To successfully navigate infill development, companies such as Black Ridge Oil & Gas have to take an approach that is based on economics not production, according to DeCubellis. “For Black Ridge,” he says, “the biggest challenge that we have had is making sure that we are deploying our capital in the highest return projects that we have available. We’ve taken an approach that it doesn’t matter if we are looking at a new acquisition or a drilling and completing lease that we already control. If we don’t expect to get a 30 percent return or higher on those investments, we don’t necessarily just blindly go ahead and spend the money.” 

If the return over the life of the well, roughly 25 years, can’t be projected to exceed that 30 percent mark, DeCubellis says the company will monetize the assets and move on to the next one. “We are taking a portfolio approach to the assets we have.” The company typically takes roughly up to 15 percent working interest in a well, a strategy that helps the company to take small bets on several geographies in the Williston Basin. The returns from those bets are paying off. The fiscal year of 2012 was the best ever for the company, and DeCubellis says 2013 will be even better. “It is really neat the way we manage our risk, but do it at a low cost. We just don’t need a huge overhead structure to operate this kind of business. 

Companies that operate in similar fashion to Black Ridge help indicate future trends in the industry. DeCubellis says he is starting to see operators looking to sell their nonoperating assets. From a leasehold perspective, the entire region is fragmented out beyond the top 30 to 35 leaseholders in the Basin. “We look at fragmentation as an opportunity. We are able to go and acquire small working interest leaseholds that have development,” he says. Doing so helps the company meet the needs of large operators who are focused on drilling and completion. And, given the current state of drilling activity in the Bakken, their strategy makes sense. DuCubellis says operators are looking for platforms and opportunities that have several leaseholds within a single purchasable package to help the operators reduce transaction costs and take advantage of drilling efficiencies and during the infill period. 

Slawson, who says everyone needs to remember that “big oil fields just get bigger,” believes the development of the region is working. “All in all, this has been a fine model of how everyone can work together to manage this incredible expansion in such a short time, in often challenging climates.”  

Author: Luke Geiver
Managing Editor, The Bakken magazine