Well stimulation activity levels have bottomed in the Greater Rockies’ market, not including the Bakken, after an 18-month period of decline.
It’s a low bar for positive news, but an important marker nonetheless.
Although the bottom is in, well stimulation providers tell Hart Energy that significant activity expansion is not likely in the oilier basins until oil prices stabilize above $55. Meanwhile, the traditional dry gas basins need $3.40 gas, or higher, to attract operators back to the field.
Operators have sustained a low-but-steady pace on drilled wells during the second and third quarters at a run rate of about 35 wells per month since April.
The overwhelming majority of activity is split almost evenly between the Denver-Julesburg (D-J) Basin at 45% and the combined dry gas Greater Green River and Piceance basins at roughly 46% of regional totals.
Service providers indicate the backlog of drilled but uncompleted wells (DUCs) is unchanged in the region. For one, fewer active operators are adding to the backlog.
Some active operators are completing everything they drill, even if they aren’t drilling much. A few operators are not drilling at all, but are slowly working through their own DUC backlog.
D-J Basin service providers report that operators indicate a need for $60 oil before completing everything that’s drilled.
Regional pressure pumping capacity, calculated as hydraulic horsepower (hhp), is listed as 235,000 hhp. This is about half the level at the beginning of the year.
Crew counts are down to eight vs. more than 20 as 2016 began. Although, there are some overlap with spreads also servicing the Bakken.
Average price per stage price in the Greater Rockies is $28,125, down from $34,000 in January 2016.
Part I. – Survey Findings
Among Survey Participants:
- Demand Flat 3Q 2016 Quarter-To-Quarter
[See Question 1 on Statistical Review]
All eight respondents reported that third-quarter demand is expected to remain flat quarter-to-quarter. Demand for pressure pumping services is not expected to increase until oil prices stabilize near the $60 mark.
- Mid-Tier Service Provider: “There are few players expecting increased demand until prices stabilize above $55. Most feel that it will take $60 oil to motivate Rocky operators.”
- DUCs Stable Now
[See Question 2 on Statistical Review]
All eight respondents reported the number of DUCs has remained stable quarter-to-quarter. There are fewer operators adding to the backlog and at least one operator is only completing wells that were in its backlog queue and has quit drilling for now.
- Top-Tier Service Provider: “There is still some backlog of DUC wells, but fewer operators are delaying now. One of operator is not drilling at all but is focused on continuing to complete existing inventory.”
- Higher Prices Needed For More Activity
[See Question 3 on Statistical Review]
Among respondents, a stable average oil price of $58 and average natural gas price of $3.40 would be required for fracking demand to increase. Greater Green River respondents reported there are few DUCs currently, while Niobrara respondents said that area does have a backlog, though fewer wells are being added to the backlog inventory.
- Top-Tier Service Provider: “In the D-J Basin, there needs to be a stable $60 oil price before every well is completed."
- DUC Completions Average ~8 Days
[See Question 4a and 4b on Statistical Review]
Among respondents, the average time to complete a DUC is eight days. Utilizing a multiwell zipper frack approach to those completions will reduce that time per well by an average 10% to 15% per well, respondents agreed.
- Mid-Tier Service Provider: “A well can be completed in an average seven days here in the D-J Basin.”
- Regional Hydraulic Horsepower Estimates Drop Further
[See Question 5 on Statistical Review]
Average estimated hhp in the region is 235,000 with about eight fleets now available to frack wells in the Rockies. Capacity of hhp in the area is down almost 50% since last reported in January. Crew count is down as well from the 20 to 25 reported in January. Some of these fleets serve the Bakken as needed.
- Well Metrics: Vertical Depth Averages 8,875 Feet Across Region
[See Question 7 on Statistical Review]
Average vertical depth reported is 8,875 feet across the region, which included wells in the Greater Green River and D-J basins. Average lateral length is 7,938 feet. Average number of stages is 38. Injection rates average 70 barrels per minute with about six stages completed daily on a 24-hour schedule.
- Cost Per Stage Averages ~$28,125
[See Question 8 and 9 on the Statistical Review]
The average per stage price is reported at $28,125, down from $34,000 in January 2016. One service provider is even charging a flat pumping fee only with the operator buying all sand and chemicals. The fee is only $10,000 per stage but keeps the crews busy and pays overhead while waiting for recovery. Respondents agreed that pricing is likely to remain flat during the next three months.
- Top-Tier Service Provider: “We are the main service provider who has kept a fleet here in Uinta Basin, and we work three out of every four weeks fracking the largest operator still working here. We sometimes bring another fleet in like others do from D-J or elsewhere to try and stay busy and break even until recovery comes.”
End Survey Findings
H A R T E N E R G Y researchers completed interviews with eight industry participants in the well stimulation/pressure pumping service segment in the Rocky Mountain area outside of the Bakken shale play. Participants included seven managers or sales personnel with well service companies and one completions manager for an E&P company. Interviews were conducted during mid to late July.
Part II. – Statistical Review
Well Stimulation/Pressure Pumping
Total Respondents = 8
[Fracking service providers = 7, Operators = 1]
1. Do you expect demand for pressure pumping equipment to grow, remain the same or shrink this quarter compared to last quarter?
Remain the same:
2. Are the number of DUCs increasing, decreasing or remaining the same compared with three months ago?
Remain the same:
3. What oil price (per barrel) and what natural gas price (per thousand cubic feet) is needed for demand for fracking services to improve?
4a. On average in this formation, how long does it take to bring a DUC online?
4b. Does the time to bring a DUC online differ between wells drilled on a pad vs. a single well?
Yes, with 10%-15% time saved per well:
5. In your estimation, what is the total hhp in your area?
6. How many total crews (spreads) do you estimate are active in the area?
7. What is the average vertical drilling depth, average horizontal lateral length, number of frack stages and injection rates (barrels per minute) in this play? What are the average frack stages per day? Is this a 12-hour or 24-hour shift?
Area-Wide Averages For Greater Green River & D-J Basin
Average vertical depth:
Average horizontal lateral length:
Average number of frack stages:
Injection rates (barrels per minute):
Average number of frack stages per day:
12-hour or 24-hour:
Required hhp to frack an average well:
8. What is the average cost per stage in your area now?
Average cost per stage:
~$28,125 per stage
9. Do you expect fracking prices to increase, remain the same, or decrease over the next three months?
Remain the same: