Back to Resources

PetraCat Surface Pressure Transient Testing


PetraCat Surface Pressure Transient Testing Related Terms

PetraCat Surface Pressure Transient Testing, DFIT, Frac Monitoring, Surface Pressure Transient Testing

Overview of Surface Pressure Transient Testing (SPTT) for Self-Unloading Gas or Gas Condensate producers

What is Surface Pressure Transient Testing (SPTT)?

A method was developed that would provide an alternative to the conventional method of capturing pressure at mid-perforation depth for purposes of Pressure Transient Analysis (PTA) in both Pressure Build-ups (PBU) and flowing or Drawdown (DD) tests in gas and gas condensate wells. In this method pressure is captured at the wellhead with a high frequency, high-resolution surface pressure gauge that is packaged, installed and calibrated to minimize ambient temperature effects at the surface. Once collected, that pressure data is accurately converted to BHP and conventional pressure transient analysis is performed to derive common reservoir parameters such as skin, permeability and P*.

In many areas of the world, production horizons are being explored at ever more increasing depths. With increased depths come increased pressure and temperatures along with the likelihood of sour gases (CO˛ or H˛S) being produced in the flow stream. By testing at the wellhead you eliminate the risk of losing equipment in the wellbore, which can cause a potentially costly retrieval, or worse, the loss of the well altogether. Also, running wireline inside tubulars can expedite corrosion problems or damage plastic coatings.  Additionally, downhole restrictions may not permit the running of equipment down the bore. It is also understood that as these depths and pressures increase, the cost to run equipment goes up dramatically, especially in an offshore or remote environment.

Surface Pressure Transient Testing Accuracy

In order to accurately process surface acquired data to BHP, information about the gas stream (gravity and composition), accurate measurements of the liquids being produced, and a completion diagram along with a deviation survey (if deviated or horizontal) are needed. A modified Cullendar & Smith equation is used to perform the conversion of surface pressure to BHP for analysis.

Accurately converting surface pressures requires the minimization of temperature effects during the acquisition of the pressure data while having a method or algorithm to account for the phenomena of ‘thermal decay’. Thermal decay is commonly seen during build-ups where large amounts of heat are transferred to the wellhead during production but gradually decrease during the PBU causing the pressure at the surface to fall instead of buildup. This is a common phenomenon and it is handled with a specific algorithm that accounts for this temperature change taking place at the wellhead.

Another important issue to note is liquid re-injection. This is the phenomenon of liquids being produced falling into the wellbore when the well is shut in for the buildup. As the gas displaces the liquids, and the liquids are re-injected back into the formation, the surface gauge reading is inaccurate because of the presence of two phases in the wellbore (liquid near the perforations and gas near the surface). Once the liquid is re-injected and the top perforation is uncovered, communication is established with the wellbore once again and the pressure response is valid. The time for re-injection to occur is dependent on permeability and amount of liquid to be re-injected. It is typically recommended to perform a drawdown test after a PBU when liquid re-injection is suspected. If a boundary is reached while the liquids are re-injecting, surface measurements will not detect it and thus will invalidate the slope and analysis. A subsequent drawdown test would be required in order to compare the analysis of the PBU with the drawdown. If the analyses match or are similar we could say with confidence that a boundary was not reached. However, if the numbers are dissimilar we would have more confidence in the drawdown analysis.


The limitations to this method of testing are:  1) The well has to be unloading all produced liquids (critical flow); and 2) Flowing at the wellhead without slugging. If these two parameters are met it is highly likely that the well can be tested at the surface regardless of how much liquid (oil and/or water) is being produced. In order to determine if gas or gas wells are suitable for this technology one of the first things to be done is to determine if the well is unloading its liquids. A common Dukler unloading chart is the first screening tool used. By knowing the production tubing I.D., the Flowing Tubing Pressure (FTP) along with the gas production rate (MMSCFD) we can easily determine if the well is unloading all liquids or not.

In summary, this technology is accepted in the Gulf Coast and Gulf of Mexico area of the US and many other areas of the world. It is employed by operators large and small as a RISK-free and low-COST alternative to running wire and gauges downhole for the purpose of pressure transient analysis.

Ask A Question