SPE-115816-MS-P

Selected temperature curves during the flowing period

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Unformatted text preview: Joule-Thomson cooling events indicating inflow intervals are evident at 2900, 3040 and 3330 m. Selected temperature curves during the flowing period, immediately after shut-in, and 12 hours after shut-in are shown in Fig 15. Two producing zones at 2900 and 3040 m reflect the inflowing Joule-Thomson temperature immediately after shut-in. The shape of the shut-in DTS curves shows cross flow from these zones to an interval at 3300 m. The lowest reservoir zone at 3330 m also appears to be cross-flowing up into the same interval at 3300 m during shut-in. This information defines the reservoir pressure distribution as cross flow only occurs from zones of higher to lower reservoir pressure. Simulation Analysis. The simulation flow analysis is shown in Fig 16, after the well had been flowing for six hours with a 2.5 MPa drawdown. Model reservoir pressures and “pseudo” permeabilities were adjusted until the correct flowing drawdown was achieved and inflow temperatures matched the flowing DTS measured data. The modeled pressure drawdown also predicted the observed cross flow into the interval at 3300 m. The reservoir zone pressures and flowing well pressures used in the analysis are shown in Fig 17. SPE 115816 5 Discussion Early papers2,3 on gas well temperature interpretation suggest a method of calculating the gas flow rate above each individual contributing zone where the temperature difference between the geothermal and measured value divided by the slope of the tangent to the temperature curve at that particular depth is a function of the flow rate and a constant: V = K (Tg – Tw) / δTw/δh …………………………….(2) This function is a constant from the top of a particular producing zone to the bottom of the following zone. However, we have demonstrated that similar temperature profiles can be generated from two completely different inflow scenarios, one that has lower flow but higher Joule-Thomson inflow cooled temperature and the other with a higher flow rate and lower Joule-Thomson inflow temperature. The assumption inherent in Equation 2 above is all the producing zones do so with the same Joule-Thomson inflow cooling, i.e. the approach does not allow for reservoir zones having different reservoir pressures which is common in producing partially depleted reservoirs. Later papers employ more rigorous thermal equations solving for transient wellbore pressure and temperature and match the shape of the curve above a producing reservoir zone by identifying a Joule-Thomson inflow temperature and flow rate which will give a good match to the temperature curve. Johnson13 suggests that having defined an appropriate Joule-Thomson inflow temperature yields an estimate of the actual reservoir zone pressure. However, this paper has demonstrated that the definition of the Joule-Thomson inflow temperature is not unique using this approach in a depleting reservoir scenario. The thermal simulator used in this paper allows for different reservoir pressures for individual zones and calculates each zone drawdown as a function of the zone “pseudo” permeability. This solution has the advantage of calcu...
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This note was uploaded on 02/04/2014 for the course PGE 312 taught by Professor Peters during the Spring '08 term at University of Texas at Austin.

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