Case Study:

Eagle Ford Shale, Texas

Retrograde fluids.
No problem.


Ely was working on one of the first fracture jobs in deep, high-temperature shale, where the operator was faced with extremely foreboding conditions. The PVT analysis had revealed that fluids in the reservoir were retrograde. Permeability was less than one hundred nanodarcies.

We knew from experience that hydrocarbons in this type of formation didn’t come primarily from the matrix. A successful well in low-permeability, fractured rock relies on interconnected fracture systems, and if treated effectively, this well would, indeed, produce.

The treatment we designed would need to deliver proppant evenly throughout a vast fracture system. By utilizing a process unique to Ely, we avoided creating tortuous paths through the formation, and were able to open up large amounts of surface area. The well outperformed most others in the area by a multiple of ten and gave birth to hundreds of similar wells in the area.

The type of design process that we pioneered has spread throughout the industry and is the dominant technique in achieving not only the maximum initial production, but sustained productivity over the life of the well. Additionally, lessons learned from this project have shaped our understanding of fluid dynamics and proppant delivery, and are crucial to developing effective, low-chemical treatments that dominate fracture treatment today.

Because of our experience and capability, many of the most impermeable, difficult shale and conventional plays are completely viable.

Adding Value

Every rock formation has different physical properties. Every region has different resources available. Prescribing the wrong treatment, either because of a lack of knowledge or misinterpretation of data, can result in a failed well and the loss of the investment. At Ely, we strongly believe the opposite is also true. There is no substitute for knowledge and experience, and utilizing them properly can mean millions in savings to operators.

Savings Realized



$50 million

by eliminating unnecessary chemicals that were not contributing to production

Case Study:


21,000 ft
deep formation

3.5” tubing
restricted rate

30% H2S
corrosive environment

330° F
high temperatures

15 million

The operator was in Chapter 7 bankruptcy when Ely came on the job, and the simple statistics of the well promised a very challenging treatment. The formation was nearly four miles deep and extremely hot, and the high hydrogen sulfide content (30%) created a dangerous and corrosive environment. To complicate matters, the well had already been completed with 3.5” tubing, causing high friction pressure.

On the bright side, the local infrastructure allowed for the processing of sulfur from existing hydrogen sulfide, and successful wells in the area made more money from this sulfur than from the hydrocarbons.

Our data and our experience with the play told us that only a vast, complex fracture system that opened up ample surface area in the formation would yield the results we needed. We pulled out all the stops.

The well was treated with complex fluids containing bauxite at pressures approaching 19,000 PSI and immediately began producing 15 million cubic feet per day. Successfully treating this type of well brought the operator out of bankruptcy, and we spent several years treating wells in the area with consistent results.

Case Study:

Scoop and Stack Formations

Erratic pressure spikes:


Some well issues cannot be solved by testing alone. This is where Ely’s experience can make the difference. An operator experiencing erratic spikes in treating pressure over multiple stages spent weeks checking that the appropriate concentrations of chemical were being pumped at each stage and sending samples to a lab in Houston. The lab tested the formation, the individual chemicals being used, the mixture, and even the source water. When no anomalies could be found, the operator called Ely and we went to work.

Here’s what we found:

The single polymer friction reducer the operator was using was separating in the totes prior to being pumped. Ely specified a co-polymer friction reducer with a longer shelf life and the problem was solved–for good.