LOW PRESSURE WELL DEFINITION

BACKGROUND:

Formation pore pressures are defined as normal or abnormal. Abnormal formation pressures (overpressure or under-pressure) are determined with respect to the freshwater pressure gradient. If a reservoir 

rock is found at 2000 feet, the freshwater gradient or normal pressure, would be equivalent to 2000 feet x 

0.433 psi/ft = 866 psi. To put the term “freshwater gradient” into context and to define 0.433 psi/ft in 

layman terms, consider a swimming pool that is 10 feet deep. The pressure will increase as one goes deeper 

and be noticeable by the pressure exerted on the inner ear. This pressure is due to the weight of water 

(8.33 lbs/gal) which is stacked on top of itself- known as hydrostatic pressure. 

 Freshwater Hydrostatic Gradient = 8.33 lb/gal X 0.052 = 0.433 psi/ft 

(0.052 is a conversion factor that changes from units of lbs/gal to psi/ft)

 Freshwater Hydrostatic Pressure = 0.433 psi/ft X depth (ft)

 To find Hydrostatic Pressure at the bottom of a 10 foot swimming pool:

0.433 psi/ft x 10 ft = 4.33 psi exerted on the inner ear

In normally pressured formations, it is assumed that the rock matrix itself is supporting the entirety 

of the overburden forces. This support of the overburden by the matrix itself allows pore pressures to exist 

at no more than a typical hydrostatic column of fluid at a particular depth. When the rock matrix itself is not 

the sole support of the overburden, the pore fluids take on part of the load causing the fluids to be in an 

over-pressured environment. Other naturally occurring geological conditions can also contribute to an overpressured formation. 

Some of the reasons for formation pore pressure to be under-pressured or “sub-pressured” could be from:

 Fluids withdrawal (past production) indicating depletion;

 Geological event where some degree of overburden erosion has taken place; and

 Naturally occurring pore fluids migration has taken place.

For many years the oil and gas industry, along with other governmental bodies and professional 

organizations, have recognized the freshwater hydrostatic gradient. Determining the fresh water hydrostatic 

gradient and the pressure regime associated with the field is a simple mathematical equation and concept 

accepted by the industry and the Department of Energy. It has also been used and accepted by industry and 

governmental agencies to be the basis of well control and blow out calculations. The freshwater hydrostatic 

gradient pressure is considered to be the base line of normal pore pressure. A well whose reservoir(s) 

pressure is less that the freshwater hydrostatic gradient is defined as under-pressure or low pressure. A well 

whose reservoir(s) pressure is greater that the freshwater hydrostatic gradient is defined as over-pressure or 

high pressure. In basins throughout the country, engineers, geologists, and stimulation companies have used 

the freshwater gradient and the resulting well head pressure not only to design artificial stimulation 

treatments, but to position casing strings to support environmentally sound drilling methods. (See 

referenced articles attached). These formations, due to their under-pressured nature, must be drilled and 
completed in a fashion that is not detrimental to its productive capabilities (typically, the less fluid the 

better). 

A low or under-pressured reservoir in many instances requires the use of inert gases to afford the 

operator the ability to economically produce natural gas. A well that is under-pressured will not have the 

energy to clean up, or flow-back a column of water due to the lack of pore pressure. Thus, inert gases are 

often used to dramatically reduce the hydrostatic pressure during flow-back operations. Inert gases bring on 

challenges to the small producer with the regulations and the ability to strip these gases to meet required 

pipeline quality. Nitrogen and CO2 are commonly used inert gases. In high concentrations they will not flare. 

Pipeline standards are typically capped at 4% of total molecular content for inert gases. 

Under-pressured wells in most cases are economically marginal wells. The following characteristics

are indicative of a low or under-pressure well:

 Foot print is very small 1 to 3 acres.

 Flow-back times are less than three days, with much smaller amounts of hydrocarbons being 

produced. 

 Stimulated with inert gases or a mixture of gas and water that use less than 5000 barrels of water 

(see West Virginia Department of Environmental Protection regulations).

 Total costs are $400,000 to $1,000,000 compared to $7,000,000 to $12,000,000 for the larger

unconventional wells with horizontal components.

 Smaller producers are primarily found in the under-pressure areas primarily because of the volumes 

each well produces. Prior to the new unconventional plays, these small producers were the 

backbone of the US natural gas industry.

Subpart OOOO states that any well meeting the definition of a low pressure gas well will be exempt 

from green completion requirements utilizing REC. This exemption is in place due to the inadequate bottom 

hole pressure to lift fluids to surface, move through surface equipment, and overcome pipeline pressures. 

The formula used by the Environmental Protection Agency to define a “low pressure well” utilizes models and 

makes numerous assumptions and estimations to determine a usable standard to relate fluid velocities and 

pressure drops. The EPA’s development of the low pressure formula includes the following assumptions or 

values:

 Pressure decreases in reservoirs;

 Pressure decreases along well tubulars;

 Tubular diameters;

 Multiphase fluid densities;

 Temperatures, gas molecular weights and compressibility;

 Changing flow regimes;

 Pressure decreases along REC equipment; and

 Pressures at sales and or gas gathering system (which can be very dynamic).

The EPA derivation and formula for calculating a “low pressure” well is overly complicated, rife with 

assumptions, and ultimately fails to capture what the industry has historically considered a low pressure well. 
As mentioned above, a critical difference between low pressure wells and other wells is the length of 

flow-back – with a low pressure well flow-back period being less than three days. In EPA’s cost-effectiveness 

evaluation of RECs, it assumed an average of seven days – over twice the length of the flow-back for low 

pressure wells. Additionally, the period of flow-back where the flow is gas dominant is very short – perhaps a 

number of hours. RECs on low pressure wells are simply not cost-effective, and if required, would likely make 

a significant portion of the low pressure wells uneconomical. Not only are the “benefits” over exaggerated

for RECs on low pressure wells, but also the environmental “costs.” With the flow-back period less than half

of what EPA assumed, the potential to emit VOCs is also less than half. 

PROPOSED DEFINITION OF A "LOW PRESSURE WELL"

A low pressure well should be defined as: A well where the field pressure is less than 0.433 times 

the vertical depth of the deepest target reservoir and the flow-back period will be less than three days in 

duration

Example

o If a well that is 4500 feet TVD has a reservoir pressure of 1200 psi , the corresponding 

pressure gradient is 0.27 psi/ft, this gradient is less than the .433 psi/ft freshwater column,

thus, indicating an under-pressure reservoir, i.e., a low pressure well.