Well stimulation in the Eagle Ford Shale remains stable in terms of flat demand, though pricing is expected to drop further as operators pressure the supply chain for reduced sand and chemical costs.

Hart Energy survey respondents place the average price per stage at $43,000, down modestly from the $47,000 per stage reported in the June survey. Slickwater fracks now average under $40,000 per stage. Meanwhile, gel fracks average a little more than $50,000 per stage.

According to survey respondents, slickwater fracks make up about half of the jobs and is more common in the central Eagle Ford. Operators in the Eaglebine play are more likely to use crosslinked gel.

The fight for marketshare continues with mid-tier pressure pumpers accusing the larger firms of pricing below cost to capture the market in a low demand environment.

The volume of drilled but uncompleted wells is estimated at 50% by Hart Energy survey participants, exasperating the oversupply in pressure pumping capacity. Estimated regional well stimulation effective capacity is 1.1 million hydraulic horsepower (HHP), according to survey respondents, down from the 1.27 million HHP in June.

However, the market remains dynamic and estimates on effective capacity vary significantly depending on the survey respondent. While drilling is down, the volume of drilled but uncompleted wells continues rising as operators postpone expenditures in anticipation of improved oil prices.

Watch for the next Eagle Ford Shale well stimulation report in December 2015.

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 remains flat quarter-to-quarter because of the low oil price, though one said it continues to shrink. Most respondents expect demand to be stable at low levels, but pricing will continue to be under pressure as operators attempt to reduce costs even more.
    • Mid-Tier Service Provider: “Demand should remain stable, but operators are fighting to get sand and chemical costs down even further.”
  • HHP Supply Excessive
    [See Question 2 on Statistical Review]
    ​Five respondents agreed there is an excessive supply of HHP capacity even though many fleets have been idled, but three said supply was sufficient to meet demand.
    • Mid-Tier Service Provider: “Most operators are delaying up to 50% of completions now so most fleets are underutilized across the play.”
  • Fracking Capacity Estimated To Be ~1.1 Million HHP
    [See Question 3a, 3b, and 3c on Statistical Review]
    ​Among respondents, HHP capacity in the region is estimated to range between 1 million- to 1.5 million HHP in the play, similar to ranges estimated in the June report. However, the overall average has slipped somewhat from 1.27 million HHP in June to about 1.1 million HHP currently. While there were no providers reported as leaving the area, the number of active fleets has fallen to 30-40, according to survey participants who remarked there are a high number of idled fleets along with underutilized active fleets.
    • Mid-Tier Service Provider: “Many mid-tier companies have several fleets active, but all are underutilized now as many completions are delayed, and several big players are fracking at a loss trying to maintain or grow market share.”
  • Eagle Ford Well Metrics: Vertical Depth ~9,037 Feet, Horizontal Laterals ~6,234 Feet
    [See Question 4 on Statistical Review]
    ​Average vertical depth reported is about 9,037 feet in the Eagle Ford with an average of 6,234 feet of horizontal lateral. Average number of stages is 26. Injection rates average 65 barrels per minute with about six stages completed daily on a 24-hour schedule.
    • Mid Tier Operator: “We are running mostly two string completions now with about 6,000-foot laterals and about 300,000 pounds of sand in each of about 25 stages.”
  • Average Cost Per Stage In Eagle Ford ~$43,000
    [See Question 5a and 5b on the Statistical Review]
    ​The average per stage price is reported at $43,000, similar to the $47,000 estimated in June. Half of respondents expect prices to remain the same over the next three months, but the other half expect prices to decline further due to falling sand prices.
    • Mid-Tier Service Provider: “Prices are at or below margin now. There is room for further reduction in sand prices as stockpiles of sand at old prices are reduced.”
  • Some Operators Buying Frack Materials Direct
    [See Question 6a on the Statistical Review]
    Some operators have begun buying sand and chemicals direct as another way of saving bottom-line well costs and many continue to put downward pressure on fracking providers to lower service pricing.
  • Delayed Completions Increasing In Eagle Ford
    [See Question 6b on the Statistical Review]
    ​Delayed frack jobs are increasing in the area as many operators are postponing well completion until the oil price recovers. Operators want better returns from completed wells to help offset the cost of the enhanced completions that are now standard in Eagle Ford. Rig counts are down, completions continue to be delayed on up to 50% of wells drilled in the play, and one respondent reported there are up to 1,000 wells in the queue to be fracked when completions resume. Meanwhile, operators continue to see production efficiencies keep wells producing during the oil price slump.
    • 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 Eagle Ford area. Participants included five managers or sales personnel with well service companies, a completion consultant and two engineers working for E&P companies. Interviews were conducted during the third week of August 2015.

Part II. – Statistical Review

Well Stimulation/Pressure Pumping

[Eagle Ford Shale]

Total Respondents = 8

[Fracking Service Providers = 5, Operators = 2, 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:


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





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

Avg. total HHP:

~1.1 million HHP active

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



Over 30:


No response:


*Four respondents reported these fleets are active, but underutilized.

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



Not sure:


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:

9,036 feet

Average horizontal lateral length:

6,234 feet

Average number of frack stages:


Injection rates (barrels per minute):

65 bpm

Average number of frack stages per day:


12-hour or 24-hour:


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





Average cost per stage:

~$43,000 per stage*

*Slickwater fracks all reported to be $30,000-40,000, but up to 50% of frack jobs are now gel fracks with 300,000-400,000 pounds of sand per stage and range $45,000-60,000 per stage.

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

Remain the same (0%):


Decrease again (no percent estimated):


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

Negotiating pricing, buying sand and chemicals direct:


Delaying drilling and frack jobs:


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

1,000 delayed fracks:


Increased completion delays:


*Some respondents reported delaying completions on up to 50% of wells drilled.

End Statistical Survey