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Communication Testing For Observation Well Having a Liquid Column

By Nathan Waldman | Wed, 10 Mar 2010

Figure one is a plot of the pressure response in an observation well having both a downhole gauge and a surface gauge.  The observation well had a depth of 11,500 ft with a liquid level at 8,500 ft.  An adjacent well was being stimulated and the operator was concerned with communication at the observation well.  The operator simultaneously ran downhole and surface gauges to determine if future interference tests could rely on just the surface gauge.

As can be seen in the attached Figure, the pressure data (blue) from the surface gauge is showing a +/- 5 psi night time/day time pressure response.  Data from the downhole gauge (red) is showing a similar response but of smaller amplitude and with less "noise".  The explanation for the observed pressure cycling is that the gas cap above the liquid column is expanding and contracting as the well head heats and cools from ambient temperature changes.   

There are three observations from the attached figure that require explanation;

1. Why is the surface data noisier than the down hole data?
2. Why is the amplitude of the day time/night time pressure swings greater in the surface gauge  than in the downhole gauge?
3. Over the course of observation period, why does the downhole gauge record a 51 psi decline while the surface gauge only declines 9 psi?

The explanation for points 1 and 2 are related.  The surface gauge is connected to the well head via a 20 ft long oil filled capillary tube that is 1/16" diameter (0.062 " i.d).  When the ambient temperature changes, the oil in the capillary tube expands or contracts and the friction of the oil moving in the capillary tube is seen as increasing or decreasing pressure until the temperature stabilizes.  This pressure response is magnified in cold weather as the oil becomes more viscous.  In this example, the data was acquired in December!  The extremely high resolution surface gauge is measuring the movement of the oil in the capillary tube which is seen as "noise" in the acquired data.  This effect could have been minimized or eliminated had the capillary tube been purged of oil before the test.  In contrast, the liquid and gas columns in the well are not only warmer than the oil in the capillary tube, they are also in a tubing string of very large diameter relative to the capillary tube connecting the surface gauge to the well.  Had the capillary tube been dry, the magnitude of the day time/night time pressure swings would have been the same for both gauges.  Future communication tests will employ "dry" capillary tubes.    

During the 6 day observation period of this communication test, the surface pressure declined 9 psi while the downhole pressure declined 51 psi.  This is explained by the fact that the liquid column in the well bore was slowly re-injecting into the formation therefore changing the relative heights of the gas and liquid columns.  When the downhole gauge was retrieved from the well, gradient stops were obtained that showed that the liquid gradient was 0.69 psi/ft.  Dividing the 51 psi pressure change in the downhole gauge by the liquid gradient of .69 psi/ft shows that the liquid column decreased by 51psi/.69 psi/ft = 74 ft. This means that the gas column grew by 74 ft.  Increasing volume of the gas at constant temperature means that the pressure must decline.  The gradient survey showed that the gas column has a density of .13 psi/ft which when multiplied by the 74 ft drop in liquid levels, equals the observed decline of 9 psi in the well head gauge.

In conclusion, neither gauge saw communication with the stimulation process, which was the objective of the test.  Both gauges responded in identical fashion to both ambient and reservoir changes.  The magnitude of the responses were different in this instance but had there been communication, the surface gauge would have detected the response as readily as the downhole gauge.  This test demonstrates that communication testing can be done from the surface without the risks and expense associated with downhole gauges, regardless if there is a fluid level in the well.

Figure 1