© DTC Energy Group, Inc. 2014
By Heather Siegel – Denver, CO
This is a tremendous increase over a very short period of time, with maximum total well depths being 21,000 feet with 10,000-foot laterals just three years ago. Today, total well depths are reaching up to 27,000 feet or more with 16,000-foot laterals.
DTC Energy Group’s own drilling consultants have been active on such types of extended-reach horizontal wells in the Bakken, specifically in Williams, McKenzie, Divide, Mountrail and Dunn Counties.
The main drivers for such enhanced drilling capabilities have been the utilization of top drives, the higher experience level of drilling teams, and advancements in drill string design, drilling fluids and lubricants.
With extensive rig upgrades that have taken place in the Bakken over the past few years, the addition of top drives has been one of the primary reasons operators are able to drill such extended-reach laterals, explains Luke Clausen, DTC Energy Group chief operating officer.
“Top drives make the drilling process much faster and more efficient,” Clausen stated. “They cut out a majority of the problems associated with making connections and are a solution to many of challenges associated with extended-reach directional wells.”
Some of the key benefits of using top drives include the enabling of longer drilling intervals, better steering of the bottom hole assembly, the ability to handle higher amounts of torque, and a significant reduction in the frequency of stuck pipe.
“With a top drive, you’re able to drill with three joints per stand, 90 feet at a time,” Clausen said. “With a Kelly rig, you’re only able to drill 30 feet, one joint at a time.”
He continued, “A top drive also gives you a greatly enhanced ability to steer the bottom hole assembly, making drill pipe connections just a few feet from the bottom versus 45 feet with a Kelly rig.”
This ability to drill 90 feet at a time while making significantly quicker and fewer drill pipe connections allows for a much faster, more efficient process.
A way to quantify the efficiency of using a top drive over a Kelly rig is to compare the total distance the drill bit travels throughout the entire drilling process – including lifting up and down while making connections.
“On a 27,000-foot well, for example, a drill bit will have to travel an extra 3,000 feet to make connections,” he continued. “With a Kelly rig, that number is 54,000 feet.”
A top drive will have to make 300 connections on a 27,000-foot well, or one connection every 90 feet. During each connection, the drill bit will lift up and back down 5 feet, for a total travel distance of 10 feet per connection. Traveling 10 feet for each of the 300 connections equates to a total of 3,000 feet of connection travel for the drill bit.
On the same well, a Kelly rig would require 900 connections, or one connection every 30 feet. During each connection, the drill bit would lift up 45 feet and lower back down 15 feet, for a total travel distance of 60 feet per connection. Traveling 60 feet during each of the 900 connections results in a total of 54,000 feet of connection travel for the drill bit.
“When you do the math, the difference is surprising,” Clausen summarized. “It really shows how much more efficient top drives are.”
Top drives are also able to handle higher amounts of torque.
“Greater depths require much greater torque to get the bit to start turning,” Clausen explained. “Top drives let torque in and out much more easily. And they allow you to hold the direction and angle you need for a longer period of time than with a Kelly rig, keeping you better on target.”
Top drive efficiencies also help reduce the frequency of stuck pipe, saving time and reducing costs.
“Top drives enable shorter drilling times and 51,000 feet less travel distance for the bit,” Clausen stated. “There are two-thirds fewer connections, and they offer the ability to quickly engage the pump or rotate the string at any time during tripping operations.”
The experience level of drilling teams is increasing, and that higher experience level has been one of the biggest keys to greatly enhanced drilling capabilities.
“When the oil boom in North Dakota first began about five years ago, there was some labor infrastructure here, but nothing even remotely close to what was needed,” Clausen said. “We’re about half way through that battle.”
As a necessity due to demand, oilfield workers are learning and advancing into supervisory roles more quickly than ever before. They are gaining experience with new equipment and technology and applying what they’ve learned to improve the drilling process.
Having an in-depth knowledge of not only the capabilities but also the liabilities of your drilling equipment is essential to a successful drill,” Clausen stated.
As the experience level of oilfield workers continues to increase, so will the drilling capabilities.
DRILL STRING DESIGN
Advancements in drill string design have also played a significant role in the ability to drill longer laterals.
“New drill pipe connections that are high torque and utilize double shoulder connections have enabled the ability to reach lateral lengths that, just a few years ago, would permanently damage a drill string,” explained Clausen. “In addition, new hardbanding techniques and materials have enabled tool joints to be laid on their side and not experience catastrophic wear that would otherwise occur.”
Recent changes in drilling fluids are helping to increase tool life and productivity, thus contributing to the ability to drill longer laterals.
One of the biggest changes has resulted from the realization that low gravity solids, which were previously commonplace in drilling fluids, not only slow the drilling process by not cleaning the hole correctly, but also significantly reduce the life of MWD assemblies and mud motors.
While not a significant issue with shorter laterals, it is essential to address the issue of low gravity solids in drilling today’s extended-reach laterals.
The utilization of drilling lubricants, whether liquid or solid, has helped reduce frictional issues that affect well design and operations. Mud lubricants are greatly enhancing the management of torque due to cuttings beds, filter cake, hole instability, doglegs, keyseating and bit balling.
With economic and environmental demands as the driving factor, continued advancements in technology will lead to the development of new drilling techniques, progressively longer laterals and better production.
By Heather Siegel – Denver, CO
Heather Siegel, assistant director of marketing at DTC Energy Group, Inc., is also a meteorologist with a degree from the University of Oklahoma and member of the Society of Petroleum Engineers. Prior to joining DTC Energy Group, she worked as a meteorologist and online journalist for AccuWeather. Some of her previous articles and research include long-range seasonal forecasts for the United States and Europe, as well as outlooks on the effects of hurricanes on oil and gas prices. In her position at DTC Energy Group, Ms. Siegel is continuing her passion for forecasting and trends by writing about the oil and gas industry.