117 122
112
107 102
Adding Another Dimension
3,120 3,160 3,200 3,240 3,280 3,320 3,360 3,400 3,440 3,480 3,520 3,560 3,600 3,640 Depth, m
> DTS measurements from the Bunga Raya well. The temperature decrease from 116°C [240°F] in the heel to 107°C [225°F] in the toe was caused by cooling as a result of gas production.
survey provided a single-point temperature reading at the ACTive tool head and distributed temperature readings along the optical fiber that ran inside the CT. Using the newly acquired data, engineers selected the optimal location to collect representative bottom hole hydrocarbon samples and thus determine the best treatment interval. DTS data indicated that the temperature had dropped across the entire interval, but was lowest at the toe (above). The temperature data,
A
along with ACTive pressure sensor data, implied that insufficient pressure support from a nearby water injector was responsible for gas-cap expansion in this declining producer. The reason for the cooling effect was gas production from the toe section resulting from gas-cap expansion, which in turn limited liquid production. The combination of gas rates with oil and water production created a tight viscous emulsion that ultimately hindered production in this well.
Advances in DTS are providing operators with a choice of permanent or temporary wellbore- temperature sensor systems. When installed as a permanent component of a completion system, the DTS monitoring system supplies valuable temperature data in real time, allowing opera - tors to respond quickly to changes in production. During workovers or other interventions, a DTS system can be run into a wellbore by slickline or inside coiled tubing; at the end of the job, the optical fiber is retrieved from the well. A thin, flexible steel tube protects and houses the optical fiber, enabling the glass fiber to snake along the wellbore trajectory. This capability permits geoscientists to precisely locate and plot the position of downhole thermal events. Such data are valuable in their own right. However, by taking a series of temperature surveys over a given period, a geoscientist can compile a 3D display to track the progression of a thermal event in space and time (below left). Specialized programs such as THERMA modeling and analysis software for wells with distributed temperature sensing can be used to load multiple temperature traces and assess well performance. Viewing the DTS data as a series of traces allows time-based properties of the well’s performance to be identified in production, injection and acid stimulation applications.
B
> THERMA 3D temperature tracking. DTS measurements were obtained in a horizontal gas well (A). When consecutive surveys are recorded, a 3D display can be generated (B). DTS recorded the response of the reservoir interval at 1,340 to 2,200 m, which had been stimulated by nitrogen injected through CT. Cold intervals (blue) indicate reservoir zones that have taken nitrogen at time 00:02. Over the course of the next two hours (00:32 to 02:22), the DTS data track hot and cold events caused by conduction from the reservoir as fluids move along the wellbore, thereby showing which of the stimulated intervals are flowing. The data identify two major intervals where the treatment was successful and reveal that the toe of the well was not stimulated sufficiently to flow.
Winter 2008/2009
Advances in fiber technology are also helping to expand the range of DTS applications. Distributed temperature sensing systems are now being installed in heavy-oil thermal-recovery wells in Canada. These wells, known as steam- assisted gravity drainage (SAGD) wells, are inhospitable to fiber-optic systems. Most optical fibers degrade when exposed to the levels of hydrogen found in these heavy-oil wells. The rate of degradation accelerates at high tempera tures typical of SAGD wells, and this impairment can eventually prevent the transmission of laser pulses through the fiber. With the development of WellWatcher BriteBlue optical fiber for harsh environments, DTS systems are better able to withstand heat and resist hydrogen degradation. The downhole data acquired with these permanently installed fibers help operators evaluate SAGD steam-chamber profiles to gain a better understanding of the steam-injection process. This knowledge is helping operators extend the life of wells and increase overall hydrocarbon recovery.
—MV
39
00:32 01:02
42 Heel 1,200 1,400 1,600 Distance, m Stimulated intervals No-flow zone 1,800 2,000 Toe 00:02
02:02 02:22
53 01:32
Time
Reservoir interval
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