Successful Flow Profiling of Gas Wells Using Distributed Temperature Sensing Data
- David Oliver Johnson (Halliburton Energy Services Group) | Jose R. Sierra (Halliburton Energy Services Group) | Jiten D. Kaura (Halliburton Energy Services Group) | Dan Gualtieri (Halliburton Energy Services)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 24-27 September, San Antonio, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2006. Society of Petroleum Engineers
- 5.1.5 Geologic Modeling, 5.4.6 Thermal Methods, 4.1.2 Separation and Treating, 3.3.1 Production Logging, 3 Production and Well Operations, 5.6.1 Open hole/cased hole log analysis, 2.5.1 Fracture design and containment, 4.6 Natural Gas, 2 Well Completion, 5.5 Reservoir Simulation, 2.4.5 Gravel pack design & evaluation, 5.6.11 Reservoir monitoring with permanent sensors, 5.9.2 Geothermal Resources, 2.2.2 Perforating, 5.6.4 Drillstem/Well Testing, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 2.4.3 Sand/Solids Control, 4.1.4 Gas Processing, 3.3 Well & Reservoir Surveillance and Monitoring, 5.3.1 Flow in Porous Media
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Distributed temperature sensing (DTS) coupled with a temperature-pressure simulator has been used successfully to determine flow profiles from multilayered commingled reservoirs in production gas wells. This technology has enabled quantitative individual-layer contributions to gas flow rates and main water entries to be determined, which in turn, has helped engineers to evaluate production conditions, track individual layer recovery, identify problem zones, and plan remedial actions.
DTS technology uses fiber-optic cables to measure continuous temperature profiles along the entire wellbore without any cable movement.
The real cases presented here include producing gas wells ranging from very low-permeability, hydraulically fractured tight reservoirs to high permeability sands with production rates from one (1) to tens of MMscf/d and over 50 layers per well at depths between 7,000 to 15,000 ft.
The analyses have shown that some of the key parameters required to obtain representative flow profiles using DTS can be extracted from the flowing and shut-in DTS transient profiles.
Those parameters, which are generally not available in conventional temperature logs, include: (i) geothermal profile; (ii) wellbore and near-wellbore Joule-Thomson effects, and (iii), thermal properties of fluids and formation. Non-producing, thick zones are particularly useful when calibrating partial flow rates and verifying fluid and formation properties.
The flow-profiling model was built around an analytical-numerical, pressure-temperature simulator that predicts wellbore temperature profiles as a response to individual layer flow rates and sandface fluid-entry temperatures. An interactive error-minimizing technique was used to match the simulated temperatures with the actual DTS profiles.
This paper also presents comparisons between the DTS-derived flow profiles and the traditional production logging tool (PLT) profiles as well as the value DTS can provide for multilayered gas-reservoir monitoring.
The development of flow profiling methods using DTS technology has been driven by the need for real-time wellbore monitoring of fluid flow. While other techniques such as PLT and single-point flowmeters can provide flow information, no single technique has the capability to offer continuous real-time, wellbore flow allocation. DTS not only appears to be the front-runner to offering continuous real-time flow information for the entire wellbore, it also can provide this at a reasonable cost; its primary limitations, however, are the complexity of the DTS analysis and the current lack of user-friendly interpretation software.
As more and more wells are now being completed to produce commingled reservoirs, better methods are being developed to determine zonal flow contributions and location of unwanted fluid breakthrough in order to optimize recovery and drive down production costs. Additionally, production optimization with high oil and gas prices requires continuous information on the production performance of each layer to design and plan preventive or remedial actions.
PLT, the main flow allocation solution, is a snapshot-type survey, but it is impractical and uneconomical for continuous monitoring and cannot be deployed in a number of completion scenarios. Furthermore, the quality of PLT results in low rate or unstable downhole environments can be misleading. Other methods such as mixed fluid signatures (gravity, salt content, etc), are quasi-continuous, but their application is very restrictive, requires special contrasting fluid properties, and for practical purposes, cannot handle more than three layers.
DTS systems generally do not interfere with flow, have much more flexibility for deployment in restricted downhole environments, and can be used for short-term as well as permanent monitoring scenarios.
This paper will discuss the process of flow profiling for gas wells using distributed temperature data. The actual temperature profiles and analysis results, which include zonal production rates, water entry locations, and production variation at different flow rates, will illustrate the value of this flow profiling method.
|File Size||1 MB||Number of Pages||16|