3,000 2,900 2,800 2,700 2,600 2,500
3,100 3,200 3,300 3,400
70 75
Immediate shut-in temperature
10-h shut-in temperature
Geothermal gradient
Flowing
temperature
Pivot points
Day 1 19:01:42 Day 2 10:47:40 Day 2 20:38:02
Crossflow upon shut-in
80 85 90 95 100 105 110
> DTS analysis of a flowing gas well. Deviation from the geothermal gradient (green line) is associated with fluid movement through the wellbore. DTS data were recorded while the well flowed normally (black curve) through the perforated intervals, immediately after shut-in (blue curve) and following 10 hours of shut-in (red curve). Decreases in temperature below the geothermal gradient at 3,035 and 3,320 m occur as gas flows from the reservoir and cools upon encountering a near-wellbore pressure drop, in accordance with the Joule-Thomson effect. When the well is shut in (blue curve), the relatively cold reservoir rock cools the wellbore fluid, reflecting the magnitude of the Joule-Thomson temperature effect on individual reservoir layers, which also indicates which zones have higher or lower reservoir drawdowns. Thus, after 10 hours of shut-in, instead of warming toward the geothermal line, the zone at 3,035 m remains cold (red curve), a sign that it is still producing. In fact, this zone is actually producing down the well into the zone at 3,300 m. The interval at 3,320 m also continues to flow, and its gas is also being drawn up to the zone at 3,300 m. In this manner, the data not only show which perforated intervals are flowing under normal flowing conditions, but which intervals crossflow during shut-in.
Other interesting features on this chart are the pivot points, shown where the flowing temperature curve intersects the shut-in curve. During shut-in, temperatures at most depths either warm up or cool down, but at a pivot point there is no change—indicating no heat transfer between the wellbore fluid and the reservoir. Thus, both the flowing-temperature curve and the shut-in curve are at the geothermal temperature. Identification of such points helps to define the geothermal gradient; they are the only points at the geothermal temperature irrespective of whether the well is flowing or not. This is an important and convenient tool because, under typical conditions, a well may not be shut in long enough to cool back to the actual geothermal temperature.
A flowing gas well illustrates the range of information that can be inferred from DTS measurements (above). Three snapshots taken during a 25-hour period allow a comparison of temperatures across multiple completion intervals. This type of comparison reveals that some zones—including the largest zone at about 2,680 m—exhibit unchanging temperatures, thus indicating they are not productive. Distributed temperature sensing technology was used to diagnose the cause of a drop in production from a well offshore peninsular Malaysia, in the South China Sea. When Talisman Malaysia Ltd. noticed a production problem in a well at Bunga Raya field, the operator responded with a chemical treatment to remove emulsions
and polymers previously left by drilling fluids.6 Immediately following treatment, the well—an openhole completion with a slotted liner—saw production increase from 200 to 2,200 bbl/d [32 to 350 m3/d]. However, production dropped just as dramati - cally within five hours of the treatment, finally stabilizing at pretreatment rates. Talisman engineers suspected that emulsions and asphal - tenes had formed in the wellbore during shut-in while rigging down from the treatment. The operator needed more information on the well’s formation characteristics and wellbore trajectory to under stand the cause of the post-treatment production decline and to determine where and
how the emul sions and asphaltenes were forming. Other concerns were how to dissolve the emulsions and asphaltenes and prevent their recurrence. Talisman called on Schlumberger to imple - ment a well cleanup program. An ACTive DTS temperature profile was obtained during a coiled tubing (CT) run into the hole (for more on the ACTive in-well live performance system, see “Shining a Light on Coiled Tubing,” page 24). This
6. Parta PE, Parapat A, Burgos R, Christian J, Jamaluddin A, Rae G, Foo SK, Ghani H and Musa M: “A Successful Application of Fiber-Optic-Enabled Coiled Tubing and Distributed Temperature Sensing (DTS) Along with Pressures to Diagnose Production Decline in an Offshore Oil Well,” paper SPE 121696, prepared for presentation at the SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, March 31–April 1, 2009.
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