Puzzle solving involves decisions about where to put the pieces, and in the Bakken, tighter placement of wells has been the strategic mantra at Denver-based Kodiak Oil and Gas Corp. since the company undertook a downspacing push in 2013.
Kodiak is pleased with the results of its program to drill, complete, and evaluate higher density lateral spacing, Lynn Peterson, Kodiak CEO said in a February conference call.
“We delivered outstanding production and reserve growth, grew the size of our asset base both organically and through acquisitions, and continue to be one of the industry leaders and proving out downspacing in the basin, which ultimately lead to additional organic growth and drilling inventory,” Peterson said.
Based on the initial results of its downspacing project, Kodiak expects to significantly improve the estimated ultimate recovery factor from each drilling spacing unit, or DSU, maximizing net present value and dramatically increasing overall well inventory across its acreage, said Ron Finch, Kodiak completions manager.
“The evaluation of the optimum lateral density for the Middle Bakken and Three Forks system is analogous to determine how many straws will be used to drain a punchbowl when each straw cost nearly $9 million,” Finch said. “It is a balance between acceleration of recovery versus the cost.”
The production response in the pilot well project has been very similar to the offset DSUs with conventional two to four well spacing, he said.
The pilot projects appear to extrapolate across the core Kodiak acreage, particularly two 12 well pilot projects in the Polar and Smokey areas, and a six well high density project including three each Middle Bakken and Three Forks wells within a DSU in the Charging Eagle area of Dunn County, Finch said.
Downspacing upside
What are the limits for downspacing? Finch thinks those limits have yet to be reached.
“We believe that the ultimate development would probably result in even more higher density wells than are being considered in the pilot or experimental programs today,” Finch said.
Finch compared the current stage of development in the Bakken petroleum system to the early times of the Jonah and Pinedale Anticline fields.
Wyoming State Historical Society records indicate that at the Jonah and Pinedale Anticline fields, downspacing and infill drilling tripled the number of wells that were actually drilled compared to initial estimates of wells needed to fully extract natural gas from the fields. Accordingly, the total projected lifetime of the fields dropped to 25 years, half of the original estimate.
It is a bit early to forecast the limits of downspacing in the Bakken, but so far the future looks promising.
With only a half-year of production on the books out of the 30-plus year life of the wells, initial work confirms that increased lateral density should increase the early time rate with more wells, improve the overall expected ultimate recovery from each DSU, optimize the overall recovery factor, maximize the net present value from each DSU, and significantly increase overall well inventory, Finch said.
For 2014, the company is embarking on its Polar Pilot Project 2.0, a downspacing program to analyze 16 wells per 1,280-acre DSU. It will feature 600 to 650 foot spacing between well bores, eight Middle Bakken wells, six Upper/Middle Three Forks wells, and two Lower Three Forks wells.
Additionally, Finch said, most of Kodiak’s infill wells in its core areas are on 600 to 700 foot spacing, achieving higher density in each DSU going forward.
“In addition to production compressions, Kodiak has used several tools to evaluate the effect of the increased lateral density that include reservoir simulation, login core analysis from the pilot holes, tracer studies, diagnostic injection fracture tests and micro seismic evaluation,” Finch said. “The result of all this has been incorporated in simulation production - in reservoir simulation, and so far we have a positive match between a reservoir simulation and the actual production history.”
Performance management
As production rises, Kodiak is reducing its costs and increasing its operating efficiency.
Kodiak was able to reduce its 2014 capital expenditure budget to $940 million - approximately $60 million lower than its 2013 total capex of $1 billion - while still drilling the same number of wells.
The entire $940 million 2014 capex will go into the Bakken-focused independent’s Williston Basin operations; $890 million is earmarked for the drilling and completion of an estimated 100 Bakken and Three Forks wells, while the remaining $50 million is going into the building of infrastructure as well as the acquisition of new, small acreages.
On the completion side, Kodiak has seen efficiencies through performance management. The company has successfully employed the zipper frack technique on its wells, decreasing the average frack time from 7.5 days to 5.4 days per well, said Russell Branting, Kodiak vice president of operations.
“The record time so far is 2.7 days per well,” he said. “The zipper frack technique also allows the optimization of water management.”
“We continue to produce water more efficiently and we have increased our water gathering pipeline to 65 percent of the total daily volume,” Branting said. “This has helped decrease our lease operating expenses as water handling disposal is one of the highest costs for a producing well.”
Building our infrastructure
Kodiak will continue to build out its infrastructure in 2014, adding additional salt water disposal wells and gathering systems, he said.
In the second and third quarters of 2014, Kodiak will upgrade its rig fleet with two new BOSS rigs - a new design AC drive rig capable of the high loads necessary to move the rig, which will translate into quicker rig move times and less costs, Branting said. “The new rigs will have a dual fuel capacity, so they can run green on natural gas.
“We are also permitting eight-well pads in our Polar area, which with the addition of BOSS rigs and pump-up rigs, we should be able to drive additional efficiencies in our drilling operations,” he said.
Augmenting its internal efficiencies, the company now enjoys an emerging low cost environment in the Williston Basin featuring a wealth of third party services now more readily available in the area, Branting said.
“A few years ago, when the service was really taking off, third party services were few and far between and they were difficult to secure in a timely manner,” Branting said. “What a difference a few years has made; today we believe the supply of available services in North Dakota competes with any other play in North America.
“We were able to contract spot completions in a matter of days instead of months, making it no longer necessary to enter into long-term agreement for our pressure pumping services’” he said. “There are workover rigs and cold tubing units to service our wells whereas two or three years ago, they were almost impossible to come by.”
In 2013 well costs declined by 15 percent to 20 percent from earlier years through the combination of service cost decreases and field level efficiencies, he said.
Current well costs, assuming a well in the deep part of the basin and completed with 100 percent intermediate strength proppant, range between $8.7 million and $9.1 million, Branting said. “With additional efficiency gains and cost reductions, we hope to realize an additional cost savings of 5 percent as we move throughout the year”
A new chapter
Peterson said he believes Kodiak is transitioning into a new era, moving to a focus on development and maximizing its return in the Bakken.
“As we continue to move toward full-scale development of our core Williston Basin properties, we believe we are transitioning to a new chapter for Kodiak,” Peterson said. “Moving beyond the leasing, exploration, and delineation stages, we are excited to focus on development and maximizing recoveries and returns.”
Kodiak said its total proved reserves on Dec. 31, 2013, were approximately 167.3 million barrels of oil equivalent, as compared to 94.7 million boe at the end of 2012.
The 2013 total represents a 77 percent increase from its 2012 estimated proved reserves on an equivalent basis, comprised of 138.2 million barrels of crude oil and 174 billion cubic feet of natural gas, the company said in a Feb. 11 preliminary unaudited operational and financial report. The 2013 reserve mix is 83 percent crude oil, along with 17 percent associated natural gas.
Approximately 46 percent of the 2013 total proved reserves are categorized as proved developed producing and approximately 54 percent are classified as proved undeveloped, which represents approximately 2.5 years of future drilling activity, the company said.
Reserve estimates for 2013 and 2012 were prepared by independent reservoir engineering consultant Netherland, Sewell & Associates Inc., Kodiak said.
Kodiak said its average daily sales volumes were 36,100 barrels of oil equivalent per day for the fourth quarter 2013, a 98 percent increase over sales volumes of 18,200 boepd for the fourth quarter 2012 and a 2 percent increase over third quarter 2013 sales volumes of 35,400 boepd. Crude oil accounted for 89 percent of fourth quarter 2013 sales volumes.
Average daily sales volumes were 29,200 boepd for 2013, representing a 103 percent increase over average daily sales volumes of 14,400 boepd in 2012, Kodiak said.
Kodiak expects its first quarter 2014 sales volumes to average between 36,000 and 38,000 boepd which is on pace to achieve the company’s stated full year guidance of 42,000-44,000 boepd.
Kodiak holds approximately 192,000 net acres in the Williston Basin, and is moving into full development mode in its core areas in Williams, McKenzie and Dunn counties.
