Low Permeability Wells

Low Permeability Wells

Defining low permeability is difficult as it has different meanings to different people.  Engineers working in the USA or Canadian Rocky Mountains, South Texas, Mid-Continent USA, or the shale plays of the USA and Canada, understand that low permeability refers to something less than 0.01 md.  While in other areas of the world, a reservoir in the range of 5 or 10 md. might be considered low permeability.  It depends on where you are and your experience levels.  When we talk about development of low permeability gas reservoirs we are almost always referring to North America.

Low permeability gas and oil plays have come to dominate the landscape in the domestic USA marketplace in recent years.  Conventional tight gas sands and increasingly,  shale gas and oil exploited via horizontal drilling and multistage stimulation are the norm in today’s environment.

Pressure Transient Testing Applications

The Applications for pressure transient testing are varied and principally include the following:

• Conventional Pressure Build-up
• DFIT or Pre-frac, injection fall-off testing sometimes referred to as a Mini or Data Frac.
• Monitoring of offset Horizontal wells during stimulation of a nearby well to determine communication / interference and the severity
• Post Frac Flowback/cleanup
• Gas Injection for pressure maintenance and disposal of acid gases.

Conventional Pressure Build-Up (PBU)

On many low permeability wells where the range of permeability is not exceedingly low (0.1 to 5 md.), operators prefer to conduct a conventional Pressure build-up as they know this will provide them the best indication of Reservoir pressure, permeability and skin.  In addition to eliminating any risk of lost wire in the wellbore, the SPIDR system has a distinct advantage over conventionally running wire and pressure gauges downhole, that advantage is minimizing shut-in time during the PBU.  We know the biggest argument against performing Pressure Transient testing is the loss of production during the time required to keep the well shut-in, in order to reach radial flow.  The SPIDR system solves that problem for the operator because you now have access to the data file at the surface and can follow the build-up over time to make an easy determination of when radial flow has been achieved.  It is not unusual for the SPIDR system to shave days of unnecessary shut-in time because of our continuous access to the data.  In addition to eliminating the risk of running tools and wire into the well and minimizing the loss of production during the test period, a SPIDR tests is typically 10% of the cost of going downhole.