Review of Stimulation Fluid Retention 

Mechanisms and Likelihood of Fluid 

Communication with Shallow Aquifers

–What’s New and Different Since the 2004 EPA Study?

By Scott Cline, petroleum engineer

Stanley, NY*

*I do not represent my primary employer in this matter; information and opinions do not represent the 

views of my employer and are presented on my own time with prior approval.
Why is it Relevant to Revisit the 2004 EPA 

Fluid Transport and Retention Discussion?

There are differences between shale gas and shallow 

coal bed development that should be distinguished and 

addressed.

Continuing Public Mistrust on the subject: Public thinks 

of this fluid as “pools” of subsurface toxic waste that will 

eventually “float” to the surface.

Public looks to EPA for assurance on this topic.

New Information and monitoring techniques have shed 

some light on mechanisms and fracture propagation.
•Where Does the Frac Fluid 

go?

•Why Does so Little Return?

•Is Retained Fluid a Risk?

•How do we Know?
Natural Fracture Generation

Because pore space did not expand during 

burial of the Marcellus Shale, the generation of 

natural gas in this organic-rich unit resulted in an 

additional increment of pore pressure to such a 

magnitude that the rock cracked in a massive 

network of fractures!1

Resulted over-pressured characteristics 

indicative of a closed system.

1 Engelder, Terry: “Unconventional Natural Gas Reservoir Could Boost U.S. Supply,” Penn 

State Live (January 17, 2008). 
Picture from November 2009 OilandGasInvestor.com Peter M. 

Duncan founding president of MicroSeismic Inc. Horizontal well 

image courtesy of Bill Kappel USGS, Ithaca, NY

J2

Fracture’s 

Strike NW

Joints 

Systematic 

and 

Widespread Faults 

Unsystematic and 

Isolated 
Shale Gas Production Mechanism

Shale - both gas source 

and “sealed” reservoir

Mechanisms by which 

gas is produced from a 

shale reservoir : 

– depletion of the free gas 

stored in the fracture 

network (natural and 

induced)

– depletion of the free gas 

stored in the matrix 

porosity, and 

– Desorption

– A dual porosity – triple 

mechanism system
Why We Fracture Shale Gas WellsHorizontal Wells are not Enough 

Even Over-pressured Sealed Naturally Fractured 

Shale System Alone Will Not Produce Economic 

Quantities of Gas

Goal is to give every gas molecule a high-speed path 

to the well-bore

The hydraulic fracturing process creates not only 

tensile fractures, but also shears existing fractures

Diagram from: 

Packer’s Plus: 

Good Fracturing 

Practices in 

Horizontal Wells 

Multi-Stage 

Fracturing System 

Solutions 
How Much Fluid Retained?

Inject Average 4+ million gallons of fresh 

water plus 4500 gallons of chemicals and 

1400 gallons HCL (Range Resources and others)

– Approximately 1000 gallons of combined scale reducer, friction 

reducer and biocide per million gallons of water

– Plus another 300 gallons of HCL per million that is expected to 

immediately react and decompose into inorganic salts and CO2

Produced Fluid?:

– Less than a million gallons of water is produced to the 

surface over the life of the well 

– Rates decline and become more saline over time
Why Does so Little Water Return 

to the Surface and Does it 

Matter?
Mini-frac (cased hole) or leak-off test (open hole) pressure test versus 

time, showing definitions of pressure terminology

http://spec2000.net/10-closurestress.htm
Mechanisms for Fluid Retention

Fluid “leak-off” into the fracture face. In formations with 

low permeability and low water saturation this fluid is 

permanently phase trapped by capillary forces.

Hydrophilic clay adsorption and swelling in pore throat.

Narrow fracture branches (shear fractures as opposed to 

tensile fractures) trap fluid by capillary forces and 

stranding.

Fluid in proppant packs may be unable to move as fluid 

prefers going around the packs. 

Fluid may move by gravity to the bottom of the fractures 

and unable to move as reservoir flow dynamics slow with 

depletion. (Daneshy, 2010)
Adapted and Modified from Penny, Pursley, Holcomb, SPE paper 94274 April, 2005

Areas of low 

porosity/perm high 

Pc – No flow
Ic.ucsc.edu/~casey/ear150/Lectures/Joints/CrackModes.jpg
Proppant Pack

Modified from Daneshy, 2010 E&P Magazine
Other 

Considerations

Vertical Separation:

– The developable formations separated 

from potential aquifers by at least 3,000 

feet (and probably more) of sandstones 

and shales (of low permeability).

Pressure Applied Limited Time

– Fracturing pressures applied for short 

duration , while the required travel time 

for fluid to flow from the shale to the 

aquifer under those pressures is 

measured in years

Pore Volume

– The volume of fluid used could only fill a 

small percentage of the void space 

between the shale and the aquifer and 

the already diluted chemicals would be 

further diluted by the formation water. 

(100 million gal/acre with 3000 ft of 

separation from aquifer - 16 billion 

gal/160 acres)
Other Considerations 

cont. Adsorption

– Some of the additives would be adsorbed by 

and bound to the organic-rich shales.

Flow Direction – Pressure Sink

– Any flow of frac fluid toward an aquifer 

through open fractures or an unplugged 

wellbore (remote) would be reversed during 

flowback, with any residual fluid further 

flushed by flow toward the production zone 

and well bore as pressures decline in the 

reservoir during production. (Pressure Sink)

Anomalous Stimulation Pressures

– The fracturing contractor would notice an 

anomaly if conditions led to the inability to 

maintain the predicted fracturing pressure.

History

– The historical experience of hydraulic 

fracturing in tens of thousands of wells is 

consistent with the analytical conclusion. 
Picture Source API Hydraulic Fracturing Operations—Well Construction and Integrity Guidelines

API GUIDANCE DOCUMENT HF1 FIRST EDITION, OCTOBER 2009-

In NY, any proposed drilling less than 2000 feet deep or 1000 feet below USDW requires site specific SEQRA 

(7.1.5 dSGEIS)

Likely Development Depths for Large Volume 

Stimulations?

1. Least Principle 

Stress Vertical 

at < 2000 ft. so 

Fractures 

Propagate 

Horizontal API

2. We Need Depth 

for the Desired 

Over-pressured 

Conditions
Packer’s Plus: Good Fracturing Practices in Horizontal Wells Multi-Stage Fracturing System Solution 

http://www.packersplus.com/pdfs/Good%20Fracturing%20Practices%20SPE%20Dallas%20July%202010.pdf

How Do We Know Fractures Height is Limited?
American Oil and Gas Reporter, July 2010 Kevin Fisher, Pinnacle Resources
American Oil and Gas Reporter July 2010 Kevin Fisher, Pinnacle Resources
Recommendations

Examine the New Literature on Fracture 

Propagation and Water Retention Mechanisms 

Since 2004 EPA Study.

Distinguish between the various types, sizes and 

depths of fracture stimulation.

Seek help from industry on simulation and 

extensive micro-seismic data already collected.

Convey conclusions decisively to public .