Successful Flow Profiling of Gas Wells Using Distributed Temperature Sensing
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Johnson, David H.; Sierra, Josep M.; Kaura, Jiten; Gualtieri, Dan

doi:10.2523/103097-ms

Cited by 26 publications

(11 citation statements)

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“…Regional factors may need to be accounted for in the simulator design. Distributed temperature sensing (DTS) enables continuous wellbore temperature measurement with the deployment of fiber-optic cable into the wellbore (Johnson et al 2006). However, any flow profiling analysis program must rely on an accurate geothermal gradient.…”

Section: Discussionmentioning

confidence: 99%

Enhanced Production Profiling of Gas Wells Using a New Method to Model the Geothermal Temperature Gradient

Johnson

Briceno

Hutchings

et al. 2010

SPE Annual Technical Conference and Exhibition

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Quantitative gas and water production profiling is very useful in completion and production performance evaluation. Production profile analysis that incorporates mass rate modeling of the flowing temperature has dramatically increased confidence in profiling results. Accurate mass rate modeling requires an accurate estimate of the geothermal temperature gradient. The conventional technique of estimating a linear geothermal gradient is not reasonable in producing regions with long completion intervals and complex lithologies. This paper will detail a new method of simulating the geothermal temperature gradient and advances in quantitative production profiling.A multi-well study was conducted in the Piceance Basin in Northwestern Colorado because of the unique effect of lithology on the geothermal gradient. Coal, sand and shale sequences which impact the geothermal gradient must be taken into consideration. The study includes open and cased hole log data to define lithology and shut-in temperature data to characterize the geothermal gradient. An analytical simulator was developed to model the geothermal gradient. Research in rock, mineral and fluid thermal conductivities is utilized to qualify the field data and analytical model.Results demonstrate that higher shale volume and coal beds increase the geothermal gradient above clean sand layer gradients. Measured geothermal gradients across coal bearing intervals are an order of magnitude higher than clean sand intervals. Geothermal gradients from the simulator were used as constraints in production profile analyses. The analyses will illustrate the identification and quantification of zonal gas and water production, even when some of the wells were flowing under adverse conditions of low gas rate, severe slug flow and high water production.Enhanced production profiling has enabled the operator to enhance their reservoir characterization, completion strategies and production performance of future offset wells. Other applications for the technology include: 1) production profiling in similar regions with complex lithology and non-linear geothermal gradient, and 2) distributed temperature sensing used for continuous temperature and production profile monitoring.

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Section: Discussionmentioning

confidence: 99%

Enhanced Production Profiling of Gas Wells Using a New Method to Model the Geothermal Temperature Gradient

Johnson

Briceno

Hutchings

et al. 2010

SPE Annual Technical Conference and Exhibition

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“…Johnson 13 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.…”

Section: Discussionmentioning

confidence: 99%

Monitoring Inflow Distribution in Multi-zone, Velocity String Gas Wells Using Slickline Deployed Fiber Optic Distributed Temperature Measurements

Huebsch¹,

Moss²,

Trilsbeck³

et al. 2008

SPE Annual Technical Conference and Exhibition

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Fiber-optic systems are able to generate a temperature log along an optical fiber using a laser source and analysis of the backscattered light. This paper details a novel application of this technology using an optic fiber embedded in a 1/8 th inch slickline cable to calculate the inflow distribution of multi-zone gas wells with velocity strings.EnCana's multi-zone gas wells in the Deep Basin of Western Canada are often completed with production tubing landed near the lowest perforated interval to act as a velocity string and lift produced water to surface. This completion technique makes spinner production logs impossible to run without initially performing a wellsite operation to lift the tubing shoe above the reservoir, requiring either a workover rig or a snubbing unit. Running a slickline containing an optical fiber to the bottom of the tubing and producing the well up the annulus for a short period allows the temperature profile of the well to be measured and therefore, the inflow distribution of the well can be calculated.Determining the inflow distribution of multi-zone gas wells now becomes a simple slickline operation with no tubing shift required. Additional benefits are the detection of crossflow on shut-in and the measurement of flowing bottomhole pressure when a gauge is run at the end of the slickline. The process is cost effective, less risky than conventional production logging, and the slickline can be safely employed where there is significant surface pressure.The paper uses case studies validated by spinner log comparisons to demonstrate that slickline fiber optic distributed temperature sensor measurements are a viable method for performing reservoir surveillance in multi-zone gas wells with velocity strings in Western Canada. Utilizing fiber optic measurements in these wells reduces operating costs and should ultimately lead to increased efficiency of reservoir stimulation practices.

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“…Papers describing zonal-rate inferences from DTS are many. For instance, successful field results have been reported in both production and injection wells in steamfloods (Nath et al, 2007), in gas wells (Johnson et al, 2006), and in oil wells (Brown et al, 2004;Brown, 2006). Unfortunately, interpretation models are lacking in most publications; Ouyang and Belanger (2006), Brown (2006), and Wang et al (2008) are exceptions in this regard.…”

Section: Introductionmentioning

confidence: 88%

Computing flow profiles and total flow rate with temperature surveys in gas wells

Kabir

Izgec

Hasan

et al. 2012

Journal of Natural Gas Science and Engineering

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Successful Flow Profiling of Gas Wells Using Distributed Temperature Sensing Data

Cited by 26 publications

References 0 publications

Enhanced Production Profiling of Gas Wells Using a New Method to Model the Geothermal Temperature Gradient

Enhanced Production Profiling of Gas Wells Using a New Method to Model the Geothermal Temperature Gradient

Monitoring Inflow Distribution in Multi-zone, Velocity String Gas Wells Using Slickline Deployed Fiber Optic Distributed Temperature Measurements

Computing flow profiles and total flow rate with temperature surveys in gas wells

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