Synopsis

Stability has come to the pressure pumping market in the traditional dry gas basins of the Cotton Valley, Fayetteville, Barnett and Haynesville. This might only be caused by a market where many operators have already left.

Pressure pumping operations continue to leave the region, including two bigger firms which plan to vacate the area. One smaller pressure pumping firm is moving in.

Survey respondents pointed to the large component of idled equipment and crews as the cause of the abandonment.

Regional effective capacity was pegged at 500,000 in hydraulic horsepower (HHP) on a fleet of 750,000 HHP. Effective capacity remains unchanged since the first quarter of 2015.

Operators are sticking with programs into 2016, buoyed to a large extent by the new focus on the stacked Cotton Valley tight sands horizontal effort. Consequently, there shouldn’t be additional cuts in demand for well stimulation services, barring some event external to the industry.

Service providers reported an average per stage price of $61,000 in the Cotton Valley. This is due to enhanced completions and more use of gel as opposed to the move outside the region to high volume slickwater treatment with large sand volumes and lower per stage pricing.

Another reason for the higher cost is that wells in the region tend to be over-pressured. Service providers say they are operating below cost currently.

Operators continue to delay completing drilled wells. Drilled but uncompleted wells represent about half of the market, according to survey respondents.

Watch for the next traditional dry gas basin update on the pressure pumping market in April 2016.

Part I. – Survey Findings

Among Survey Participants:

  • Demand Flat Quarter-To-Quarter In The Region
    [See Question 1a and 1b on Statistical Review]
    ​Nearly all respondents reported that demand for pressure pumping services remains flat quarter-to-quarter because of the low oil price. Most respondents expect demand to be stable at current levels until 2016.
    • Mid-Tier Service Provider: “Demand should remain stable now, as fewer operators are remaining in the region.”
  • HHP Supply Sufficient
    [See Question 2 on Statistical Review]
    ​Seven of eight respondents moved from an excessive supply of HHP capacity to sufficient since two major frack providers exited the region.
    • Mid-Tier Service Provider: “Most operators are sticking with current drilling and completions rate into 2016.”
  • Effective Fracking Capacity Estimated To Be ~550,000 HHP
    [See Question 3a, 3b, and 3c on Statistical Review]
    ​Among respondents, HHP capacity in the region is estimated to be 550,000 HHP, similar to April findings. Two service providers are reported to be leaving the area and one small provider is entering the area. Meanwhile, there continues to be a high number of idled fleets along with underutilized active fleets as well.
    • Mid-Tier Service Provider: “We are staying busy, but are fracking at a loss trying to maintain or grow market share.”
  • Dry Gas Basin Well Metrics: Vertical Depth Averages ~8,600 Feet; Laterals Average 5,100 Feet
    [See Question 4 on Statistical Review]
    ​Across the broad dry gas basin region, the average vertical depth reported is to be about 8600 feet. However, several respondents are working in the Cotton Valley area and the overall average is weighted towards that formation. The average lateral length is 5,125 feet. Average number of stages is 21. Injection rates average 71 barrels per minute with about six stages completed daily on a 24-hour schedule.
    • Mid Tier Operator: “We are doing lots of fracks in Cotton Valley that are only 3000- to 5000 feet on laterals with 15 to 20 stages.”
  • Average Cost Per Stage In Region ~$61,000
    [See Question 5a and 5b on the Statistical Review]
    ​The average per stage price is reported at $61,000. This is higher than the prices estimated in most Texas wells, but similar to findings in the April report. Half of respondents expect prices to remain the same over the next three months. These respondents explained that some wells in the area tend to have high pressure, which often requires some supplementary gel to reduce pressures. In addition, large sand volumes and some resin-coated sand are needed in these frack jobs.
    • Mid-Tier Service Provider: “Prices are at or below margin now. These wells are a little more expensive for a good frack, but the prices are much lower than last year.”
  • Delayed Completions Increasing In Dry Gas Basin
    [See Question 6b on the Statistical Review]
    ​Delayed frack jobs are increasing in the area as many operators are postponing completing wells until oil prices recover. Operators want better returns from completed wells to offset the cost of enhanced completions, which are now standard in dry gas basin. Rig counts are down, completions continue to be delayed on up to 50% of wells drilled in the play. One respondent reported there are up to 1,000 wells in the queue to be fracked when completions resume.
    • Top-Tier Operator: “We are still delaying and restricting drilling and completions due to the [oil] price.”

End Survey Findings

Survey Demographics

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 dry gas regions. Participants included six managers or sales personnel with well service companies, a completion consultant and one engineer working for E&P companies. Interviews were conducted during the third week of September 2015.

Part II. – Statistical Review

Well Stimulation/Pressure Pumping

[Dry Gas Regions]

Total Respondents = 8

[Fracking Service Providers = 6, Operators = 1, Completions Consultants = 1]

1. Do you expect demand for pressure pumping equipment to grow, remain the same or shrink in third-quarter 2015 compared to the second quarter?

Remain the same:

8


2. Would you characterize the supply of pressure pumping equipment in your area as excessive, sufficient or insufficient to meet late 2015 demand?

Sufficient:

7

Excessive:

1


3a. How would you estimate total HHP capacity for the region?

Average total:

~ 750,000 HHP active


3b. How many total crews (spreads) do you think are active in the area?

10-12:

1

15-20:

2

No response:

5


3c. Have any service providers left the play in the last 90 days?

Yes:

6

Not sure:

2


4. 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?

Average vertical depth:

8,600 feet

Average horizontal lateral length:

5,125 feet

Average number of frack stages:

21

Injection rates (barrels per minute):

71

Average number of frack stages per day:

6

12-hour or 24-hour:

24-hour

*Averages shown are for the broad dry gas basin. However, several respondents’ answers were heavily weighted towards the Cotton Valley Formation.


5a. What is the average cost per stage in your area now?

$30,000-60,000:

3

$60,000-70,000:

5

Average cost per stage:

~$61,000*

*Slickwater fracks were reported by all respondents, but several frack jobs are being supplemented with gel to reduce pressures. These frack jobs use 300,000 pounds of sand per stage with some resin-coated sand as well. The price for these fracks cost up to $70,000 per stage.


5b. Do you expect fracking prices to increase, remain the same, or decrease over the next three months?

Remain the same (0%):

8


6a. What strategies are companies putting into place to cope with a low price environment?

Negotiating pricing, buying sand and chemicals direct:

3

Delaying drilling and frack jobs:

5


6b. What are you seeing in terms of the number of wells drilled but not completed in your area?

All respondents report many delayed fracks.


End Statistical Survey

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