Summary The integration of horizontal wells and thermal-oil-recovery methods, such as steam-assisted gravity drainage (SAGD), has enabled the economic exploitation of extraheavy-oil resources, mainly in Canada. The use of passive outflow-control devices (OCDs) in SAGD wells adds steam-injection points along the horizontal wellbore, influencing steam placement and chamber growth, thus potentially reducing the steam/oil ratio, minimizing productivity uncertainty, and accelerating production. To design OCD installations in SAGD, we need to address two main aspects. The first is the interface between horizontal-wellbore hydraulics and reservoir injectivity, which allows for the determination of the number and location of steam-injection points for improved performance. The other aspect is the design of the OCD itself, which involves selecting and configuring the device with a hydraulic performance that is fit for purpose. For this study, we will focus specifically on straight-orifice-choke passive OCDs. This paper presents a comprehensive design methodology for tubing-deployed passive OCDs in SAGD. The completion design is carried out with a steady-state model of the injection well from a commercial thermal wellbore simulator. The field-performance evaluation of tubing-deployed passive OCDs is critical for verifying the effectiveness of the design methodology and the hydraulic performance of the devices under real field conditions. The field evaluation is performed by history matching the injection pressure vs. the steam-rate data with a model developed in the thermal wellbore simulator. A dynamic pressure gradient (under flowing conditions) inside the injection string carrying the OCDs is obtained with a temperature log, taken with fiber-optic technology, in which the temperature data are converted to pressure by virtue of the properties of saturated steam. This method for measuring the dynamic pressure gradient during steam injection is novel for the SAGD industry. The hydraulic field performance of the OCDs was matched successfully with the simulated model, which indicates the effectiveness of the design methodology, the field-performance-evaluation techniques, and the OCDs in delivering the desired amount of steam at each location.
Tech 101 - Steam-assisted gravity drainage: R&D for unlocking unconventional heavy oil resources.
Temperature fall-off logs are routinely performed on a number of operating wells at Statoil's Leismer field to monitor well integrity. So far, all wells have demonstrated normal temperatures in formations overlying the steam chamber, less than steam temperatures, and with fall-offs according to typical heat conduction. However, one injector well did not fall-off as expected after a 24 hour shut-in; instead showed temperatures exceeding 200°C in formations above the steam chamber. An investigation was launched and a multidisciplinary team evaluated possible causes for the high temperatures. A review of 4D seismic data showed that a neighbouring steam chamber was intersecting the wellbore. This led to the hypothesis that the high temperatures were the result of wellbore heating from the neighbouring steam chamber, and a follow-up, extended temperature fall-off log confirmed the hypothesis. The extended logging period confirmed that temperatures outside casing did fall-off, albeit at a slower rate than other wells, due to the heating effect of the neighbouring steam chamber. The temperature log measurements indicate that heat from an intersecting steam chamber can cause a counter-intuitive segregation of steam and water in the wellbore, with condensed liquid water held above steam in the upper section of the well. This case study highlights strategies for interpreting downhole temperature anomalies using temperature logs and 4D seismic, and also the benefits of a well integrity investigation with strong cross-discipline collaboration.
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