- Category: Features
- Created on 20 May 2012
Long horizontal wells with multistage fracturing treatments have become the standard for accessing tight oil and gas resources across North America in the last five years.
Thousands of wells have been drilled, with tens of thousands of fracture stages completed. As the data is gathered, operators are fine-tuning their drilling and completion programs, custom fitting them to the formation targeted. The trend is for greater fracture density, along with a move towards slickwater fracs in many plays.
The Bakken in North Dakota and the Marcellus shale play in the northeastern United States have been ground zero in the quest to increase fracturing density along extended-reach horizontal wells.
In March of last year, Baker Hughes reported its successful installation of a 40-stage open-hole completion system in the Bakken for Whiting Petroleum Corporation. At the time the well marked the most stages ever performed in a single-lateral frac-sleeve/packer-completion system, the company said.
Baker Hughes' FracPoint EX-C multistage fracturing system was used in Whiting's horizontal well, Smith 14-29XH, in the Bakken shale.
"The industry continues to push the limits of total frac stages in horizontal completions in the Bakken Shale and other unconventional reservoirs," said Paul Butero, president of the U.S. Land region for Baker Hughes, in announcing the record well.
The company's FracPoint product features a modular design that can be optimized according to customer specifications. In many areas of the Williston Basin, for example, Baker Hughes' custom-designed reactive element packers (REPackers) are used in the FracPoint EX-C system to isolate intervals of a horizontal section, while frac sleeves are used for the precise delivery of the fracture treatment. Reactive element packers are a versatile option that allow for a wide range of open-hole sizes and improve the capabilities of packer and sleeve completions.
FracPoint EX-C extends current capabilities to 40 stages via 1/16-inch incremental stages in ball size, to achieve an increased number of ball seats. The patented design provides additional mechanical support to the ball during pumping operations.
The impact of the denser fracture treatments can be seen in the results of Brigham Exploration Company in the North Dakota Bakken. To date, based on publically available information, Brigham has the four highest initial-rate Bakken wells and seven of the top 10 initial-rate Bakken wells in the Williston Basin. Brigham has now completed 56 consecutive long-lateral high-frac-stage wells in North Dakota, with an average early 24-hour peak flow back rate of approximately 2,884 barrels of oil equivalent. The company has been applying between 30 and 40 frac stages per well in the play.
In the Marcellus Shale play, Calgary-based Packers Plus Energy Services Inc. has pushed the envelope even further, installing a 60-stage open-hole completion, the largest job to date in the prolific play. The installation used 124 tool assemblies in a row.
"This job in the Marcellus Shale demonstrates the breadth and depth of our technology," said Dan Themig, president of Packers Plus. "We had no issues sending 61 RockSEAL packers downhole in a 3,600-foot lateral. This hybrid system features our latest technological innovations in one well."
Packers Plus worked closely with the operator in the planning stages to ensure that the open-hole system met all of the operator's design requirements. This included detailed pre-job calculations and full operational contingency plans.
"Preparation before the job was key," said James Athans, U.S. general manager. "This completion included our new SF Cementor stage collar and RepeaterPORT sleeve in a hybrid of StackFRAC and QuickFRAC systems. It was a complex design that met the unique requirements of the operator."
In recent years, the move to more stages and shorter stage lengths has dominated the open-hole completions industry, according to Themig.
"We are seeing that operators want more and more stages," said Themig. "Our work in the Marcellus, James Lime, Bakken and other U.S. formations has all moved in this direction. With our most recent product launches, we have answered the need for more stages and this job demonstrates our ability in this area."
Packers Plus's RepeaterPORT sleeve, is the key technology enabling the greater fracturing density. The new stage-multiplier technology is the first of its kind in the industry, Themig says.
"The RepeaterPORT sleeve represents a great innovation within our industry. We can actually drop the same-sized ball multiple times and activate specific ports within the system," he explains. "The advantage for operators is that they can increase stage numbers, increase ultimate recovery, and increase ball-seat size, which reduces friction pressures allowing for higher rate treatments."
The RepeaterPORT effectively increases the number of stages available in the StackFRAC HD system. By using the same size ball, the RepeaterPORT sleeve multiplies the number of available stages that can be fractured, allowing for optimization of frac crews and the use of less frac fluid. There are a variety of ball-seat sizes allowing numerous stages to be run in sequence.
While the number of frac stages increases, operators are also focused on finding the most cost-effective fluids for the targeted formation. Spartan Oil Corp. has been one of the most active players in the Cardium play in Alberta, with plans to drill 46 wells this year. To date in 2012, the company has drilled a total of 12 (10.3 net) horizontal wells at its Keystone property. This brings the total well count to 27 (22.1 net) horizontal wells drilled since Spartan began operations on June 1, 2011.
The company has tested several different completion techniques in an effort to maximize the productivity of the wells, including oil-based fracs, nitrified surfactant foam fracs, gelled water fracs and slickwater fracs.
"We have seen improvements in both productivity and costs as a result of these efforts," the company said in a press release.
Of the wells drilled to date in 2012, two (1.5 net) have been completed with nitrified surfactant foam fracs, six (5.9 net) have been completed with slickwater fracs and one (0.97 net) has been completed with a gelled water frac. Results are still preliminary, but the company said it is "very encouraged" by the initial results from the slickwater fracs. There is not enough production data available to date to assess the results on the gelled water completion.
As an example of this, the company recently completed two wells in the interior of Unit 2 that are in close proximity to each other.
One of the wells was completed with a 17-stage slickwater frac and the other was completed with a 17-stage nitrified surfactant foam frac. The initial 30-day production (IP30) rate for the well that received the slickwater frac treatment was 145 barrels per day of oil, while the other well achieved an IP30 rate of 119 barrels per day.
Calgary-based GasFrac Energy Services Inc. is making major inroads with its propane-based fracturing system in the Deep Basin and other liquids rich gas plays. The company recently signed a three-year deal to provide fracture stimulation service to Husky Energy Inc. for its operations at Ansell in the Deep Basin. Its technology has also proven its worth for Artek Exploration Ltd. at its condensate play at Inga in northeastern British Columbia.
Last April Artek Exploration Ltd. reported success using a 12-stage fracture stimulation program using GasFrac's propane frac technology at Inga. The final rate after a 43-hour cleanup, and a 27-hour flow test or 70-hour flow period was restricted at five million cubic feet per day (of which approximately four million was formation gas) and approximately 1,400 barrels per day of condensate for a total rate of approximately 2,040 barrels of oil equivalent per day, at a flowing pressure of 1,070 pounds per square inch (7,373 kiloPascals).
GasFrac currently has eight sets of equipment operating (five in Canada and three in the United States) with two additional sets being delivered.
As knowledge has accumulated, operators are fine-tuning multistage fracturing programs to various plays. And probably no one has done more experimentation with horizontal wells and multistage fracturing in tight oil plays than Penn West Exploration.
In the Cardium the company reports two different drilling and completion techniques being used in its core areas. At Willesden Green and West Pembina, Penn West is drilling 1,200-1,400-metre laterals, with 14-20 fracture stages of 20-25 tonnes per stage. At Alder Flats, it is drilling monobore wells with the same length laterals but completing as many as 25 stages. Penn West is using the ball-drop system for its completions in the Cardium.
In the Swan Hills carbonate play, Penn West is drilling 1,200-1,400-metre laterals with intermediate casing and lines being used in the wellbore. It is averaging 10-12 frac stages, using 900-1,000 cubic metres of hydrochloric acid per stage.
In the Viking tight oil play in Saskatchewan, Penn West is drilling 600-metre laterals using the monobore technique. It is averaging 15 stages per well, with each stage averaging 15 tonnes. It is using the ported collar system to place frac stages in the Viking.
In the Spearfish play in Manitoba, Penn West is again drilling 600-metre horizontal laterals using the monobore technique. It is averaging 17 fracture stages per well, with each frac averaging five tonnes. Its completion technology of choice in the Spearfish is the ported collar/mongoose system.
But as drilling and completion systems take shape in existing plays, new plays are developing and the testing begins anew. Yoho Resources Inc. is in the process of developing its system in the emerging Duvernay and Montney plays in northwestern Alberta. Yoho Resources Inc. plans on drilling four or five wells strategically located across its acreage in the Duvernay this year, along with four or five wells in the Montney in northeastern British Columbia.
Yoho has completed four wells in the Duvernay so far, each with better results than the one before it. Gas test rates ranged from 2.1 million cubic feet per day, to 7.7 million cubic feet a day with free condensate production rates of 42, 71, 92 and 109 barrels per million cubic feet, as Yoho improved its completion technique. "With each subsequent attempt at completions, we've seen better results. From our first well, which we were only able to complete part of due to a ruptured liner, we have improved our techniques," Yoho president Brian McLachlan said.
Development will likely be six to eight wells per section with possibly more in the thickest part of the Duvernay, he said. Drilled from pads, the horizontal wells are expected to cost an average of roughly $10 million apiece to drill, case and complete.
In the Montney, the company is focused on increasing the density of its fracture stages going forward. At its Nig Creek play, Yoho has drilled three horizontal wells in the Upper Montney and one horizontal well in the Lower Montney.
The company's first well in the Nig Creek Upper Montney tested 6.3 million cubic feet per day a day of gas. Although it initially tested only 12 barrels per million cubic feet of free condensate, later production rates were 40 barrels of liquids per million cubic feet (including 28 barrels of condensate).
The other two wells in the Nig Creek Upper Montney tested 5.6 million cubic feet per day with 21 barrels of free condensate per million cubic feet, and 3.5 million cubic feet per day with 12 barrels of condensate per million cubic feet.
"As we progressed on each well, we cut back our frac program a little bit. We will likely reverse that trend, as earlier fracs with more stages resulted in better wells than the smaller slickwater fracs with fewer stages," McLachlan said.
"By year-end 2012 we should have an excellent quantitative evaluation of our Duvernay and Montney plays and a detailed development plan for each," McLachlan said. "2013 will be our first full year of development on both of those plays."