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Using Surface Pressures for Pressure Transient Testing in Shale Gas and/or Gas Condensate Producers via Pressure build-ups and multi-rate tests or Surface Pressure Transient Testing (SPTT)

By R. Kelly | Mon, 6 Oct 2014

Surface Pressure Transient Testing (SPTT) was developed several years ago to capture high resolution/high frequency surface pressure for use in pressure transient analysis in self-unloading (above critical velocity) producers. The technology was born in the US Gulf Coast onshore and US Gulf of Mexico geo pressured gas and gas condensate producers in conventional reservoirs with high permeabilities (50-1000 md.), an ideal environment for its implementation and development.

This technology and technique has inherent and obvious advantages over running wire and pressure gauges downhole. It is RISK FREE (no opportunity to lose/stick equipment in the tubing or casing), COST EFFECTIVE (no need for personnel, wireline trucks, etc.), and has reduced HSE EXPOSURE.

Accurately converting WHP to BHP in high permeability wells with elevated temperatures is more challenging than in lower permeability reservoirs. Pressure changes, which occur when flow rates are changed or the well is shut-in, occur much slower in ultra-low permeability shales and are less problematic in the conversion because of the slower rate of change. Temperature plays a significant role on the overall quality of the pressure data. When those changes occur more slowly the conversion process is greatly simplified. Of course, it’s important to have gas compositional information along with a PVT analysis (for gas condensate producers) that aids the technology in accounting for condensate “drop out” when pressures transition from lower (flowing) to higher (shut-in), and those transitions thru the dew point, if applicable.

The shale producers today are almost universally horizontal wellbores. If you are running wire and gauges downhole (DHG) to acquire pressure data, you are more than likely deploying to no deeper than approximately a 60 degree angle which is still usually hundreds of feet from TVD (see example) or reservoir depth. Our contention has always been that if the DHG will not be at TVD or at/below the perforations, it will make little difference whether you are collecting measurements at that depth or at the surface. If liquid production is an issue it will be the same for both surface and DHG gauge (see Diagram 1 & 2). A vertical well is depicted in Diagram 1, but you can easily understand that if the gauge is not located in the lateral section of the HZ wellbore it can be subject to a liquid level below the gauge. Conversely, the advantage that surface pressure data acquisition experienced personnel have is the ability to recognize and identify liquid/wellbore related issues and appropriately separate out that response as opposed to that which is only from the reservoir.

We believe there is a much greater future opportunity to utilize surface measurements in gas or gas condensate shale reservoirs such as: Utica, Haynesville, gas and gas condensate window of the Eagleford, Marcellus, Fayetteville and Woodford,  to name the more active plays where this technology has significant opportunities.

There are known challenges to this technology (see Diagram 3), however solutions and best practices have been developed in response to each challenge. For PBU’s, friction loss is a non-issue, which removes a large challenge from the conversion process and makes PBU’s easier to convert. It can generally be said that performing surface PBU’s in dry gas producers (<10 BBLS/MMSCFD) is the least challenging for this technology, while conversely, surface transient testing of high rate, high permeability with significant liquids production offers more challenges. As mentioned previously, known solutions can be applied to solve them.

With all of the obvious and overt advantages for this technology, the question becomes why isn’t this technology utilized more often? The reasons:

  1. Even though the technology has been around for quite some time and is well proven, general industry exposure remains relatively low.
  2. Operators may apply the technology to unqualified wells that do not unload fluids (standing liquid column) or to wells that are not performing, which typically mean they are not flowing above critical unloading velocity.
  3. Input information (rate/gas composition/PVT) for accurate WHP to BHP conversion is lacking or inaccurate.
  4. Many reservoir engineers still hold the belief that it is not possible to accurately convert WHP to BHP or mid-point completion on wells other than dry gas because of the typical thermal decay effect (decreasing pressure during PBU) previously witnessed in surface pressure data.

Ultimately the reasons for not using this technology more frequently are founded in inaccuracies of both information and industry beliefs. Given the noted benefits and proven data, implementing this technology to applicable wells is a sound strategy for routine reservoir/production surveillance needs as either a supplement to conventional methods (slickline) or a stand alone solution.

Diagram 1 – Wellbore Perspective


Diagram 2 – Cartesian & Semilog plot Perspective



Diagram 3

Diagram 3_1

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