Successful Flow Profiling of Gas Wells Using Distributed Temperature Sensing Data

Abstract

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractDistributed 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. Nonproducing, thick zones are particularly useful when calibrating partial flow rates and verifying fluid and formation properties.The flow-profiling model was built around an analyticalnumerical, 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 DTSderived flow profiles and the traditional production logging tool (PLT) profiles as well as the value DTS can provide for multilayered gas-reservoir monitoring.

Field Application of an Interpretation Method of Downhole Temperature and Pressure Data for Detecting Water Entry in Inclined Gas Wells

“…Their tool displays monitored downhole data without the inversion of the downhole data to flow profile in the wellbore. Studies done by other authors (Wang et al 2008;Johnson et al 2006b;Ouyang and Belanger 2004) have also shown promising results in downhole data interpretation. However, in the course of their study, most of these authors ascertained that the complexity of the interpretation process and current lack of userfriendly interpretation software are some of the application challenges in the oil and gas industry today.…”

Determining Multilayer Formation Properties from Transient Temperature and Pressure Measurements

“…The DTS system has the advantage of making the distributed sensing for temperature along the wellbore in real time, and numerous works about DTS applications have been published in recent years (Carnahan et al, 1999;Kragas et al, 2001;Johnson et al, 2006;Nath et al, 2007;Mahrooqi et al, 2007.). Although the temperature sensors with the FBG technique can only measure temperature at specific points instead of distributed sensing, the FBG technique is also attractive in some situations due to a higher temperature resolution and accuracy it can realize.…”

Sustaining Production by Managing Annular-Pressure Buildup

“…Rate validation in integrated-asset modeling is a case in point. In contrast, temperature measurements have not found routine usage, but are gaining increased attention in connection with transientpressure testing (Sui et al 2008;Duru and Horne 2008;Izgec et al 2007;Hasan et al 2005;Kabir et al 1996), downhole flow profiling Nath et al 2007;Johnson et al 2006;Ouyang and Belanger 2006), and flow-rate estimation (Izgec et al 2009;Kabir et al 2008). This paper shows that both pressure and temperature responses at the tubinghead and annuli are strongly related to flow rates and that these measured values can be used to alert the operator of possible APB.…”