Distributed Temperature Sensing (DTS) technology uses fiber-optic cable to measure continuous temperature profile along the wellbore. Measurement interpretation can provide valuable information, and one of them is real time flow profiling that helps to monitor the fluid flow in wells. This valuable information can assist real time production decision with no well intervention. However, the complexity of the data analysis limits the use of DTS as a flow allocation technique. This paper presents a new flow-profiling model using DTS technology. The model is based on steady-state energy balance equation and it handles multiple production zones with its own zonal fluid properties. The model is applicable for gas and oil wells in onshore and offshore environment. The model is integrated into easy-to-use software and it can be run in two modes: forward simulation and flow profiling. The forward simulation calculates temperature distribution along the wellbore for any given production profile, and this mode is critical for the model calibration. It is also very useful for emulating what-if scenarios, like water breakthrough. The flow profiling estimates production profile based on measured temperatures, which is the base for the real time well monitoring. Our studies with the model show that geothermal profile, fluid properties, formation properties, well completion, and deviation as well as Joule-Thomson effect all play key roles for the model accuracy. Joule Thomson gas cooling effect only occurs at lower pressure while reversal appears at higher pressure region. The model is tested against synthetic, literature and field examples and good agreements have been obtained. Test results have been presented. Introduction Distributed Temperature Sensor (DTS) is the name of the class of instruments that measure temperature continuously through the optic fiber installed along the entire wellbore length. DTS comprises concentric layers of materials: core and cladding. DTS uses physical phenomena such as Raman scattering which transduces temperature into an optical signal. Laser light pulses are generated by the DTS instrument (DTS box) and launched down the fiber sensor. As laser pulses travel down, portion of the light reflects back to the DTS box. Raman backscatter is caused by molecular vibration in the fiber resulting in the emission of photons, which are shifted in wavelength from the incident light1. Positively shifted Stokes backscatter is temperature independent, while the negatively shifted Anti-Stokes Raman backscatter is temperature dependent. The intensity ratio of Stocks/Anti-Stokes can be used to calculate temperature. DTS technology is not new. It was used in fire detection decades ago. Only in recent years, DTS technology has emerged as a valuable tool in the oil and gas industry. Initial applications are for steam flooding and geothermal application. As DTS technology advances, the temperature measurement has become very accurate and reliable. The temporal temperature resolution is 0.1°C at a distance up to 10 km, with a spatial resolution of 2 meters. DTS system generally don't 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.

Flow Control Devices (FCDs) have demonstrated significant potential for improving recovery in Steam Assisted Gravity Drainage (SAGD) production wells. One initial hypothesis was that steam breakthrough was delayed because the FCDs better homogenized injection and production by equalizing flow and compensating for pressure changes along the wellbore. However, in many cases, the field results were far greater than such an approach would have justified. The actual physics for this process are unclear, and not demonstrated in literature. Upon review of field data published by ConocoPhillips, the possibility of a steam blocking effect was proposed (Stalder, 2012), although the physical basis for this effect was not explored. This paper proposes an updated hypothesis to explain this effect, presents preliminary data to support the assumption, and introduces a new apparatus and methodology to characterize FCDs for SAGD applications. The traditional approach to steam control states that steam flashing at the producer should be avoided, as it will eventually lead to a completion failure. Alternatively, the proposed hypothesis contemplates using steam flashing at the producer to regulate flow in various segments of the completion, thus better enforcing conformance. The physics of this process will primarily be described analytically; however, this effect was also observed qualitatively in a small-scale experiment where water was flashed across an orifice. In order to design SAGD completions that leverage FCDs (and this effect), it was necessary to accurately characterize different FCDs under these challenging multiphase flow conditions. Since vendors use a variety of approaches when designing their FCDs, a protocol was developed to create a characterization procedure which was independent of the underlying FCD design and architecture, resulting in a direct comparison of the overall performance of each FCD. Part of this protocol required the construction of a new, high temperature multiphase flow loop capable of subjecting FCDs to representative SAGD operating conditions. Through fine control of the relevant test parameters, accurate performance measurements can be obtained for each FCD. This paper will present some information regarding the design and specifications of this new flow loop, as well as impart some of the lessons learned from its commissioning and initial operation.

TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract This paper summarizes the findings of the SPE Forum held in September 2005 on "Making our Mature Fields Smarter".

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAccelerated production, increased ultimate recovery, and reduced interventions are goals of any operating company. It is now possible to attain all of these goals simultaneously by retrofitting intelligent well technology to an existing, conventional completion. This task is much more complex when the new technology must be installed in conjunction with artificial lift, such as an electric submersible pump (ESP). However, new technology and procedures have overcome this complexity and offer a viable option for optimizing production in existing completions that use artificial lift.Commingled or selective production from two or more zones is an ideal method of accelerating production from a single well. Traditional designs require interventions into the well to select the intervals to be produced. In most ESP wells, commingling is achieved by using "Y" blocks which allow production tubing to be run from the tubing hanger to the zones of interest. The ESP must then be downsized to accommodate this side-string, which significantly reduces available pump horsepower. This paper focuses on single-ESP wells producing from multiple pay zones. Various application patterns for use of intelligent well technology beneath ESPs are presented, especially focusing on immediate and future benefits. Theoretical examples are presented to illustrate how intelligent completions can enhance the ESP performance, add flexibility, and extend the range of application for a given pump.

Distributed Temperature Sensor (DTS) technology uses fiber-optic cable to measure a continuous temperature profile along the wellbore. Compared to conventional production logging tools (PLT), DTS can provide operators real-time well information without intervention. Applications, from flow profiling to gas lift surveillance, have grown steadily in recently years. DTS applications require reliable data modeling and analysis or measurement interpretation. The complexity of the data analysis has been a barrier to DTS usage. This paper presents software tools developed for DTS interpretation. The model behind the software is based on steady-state energy balance, and it is applicable for gas and oil wells in both onshore and offshore environments. The software allows users to run in two modes: forward simulation and flow profiling. The forward simulation mode calculates the temperature distribution along the wellbore for any given production profile, and this mode is critical for the model calibration. It is also very useful for emulating "what-if" scenarios, such as forecast and gas lift surveillance. The flow profiling estimates the production profile based on measured temperatures, which is the basis for the real-time well monitoring. The model is tested against other models and good agreement has been obtained. This paper presents two examples: result comparison against TIPP, a computer program package developed by Chevron Corp, and a field example to verify gas lift valve operation. Introduction DTS is the name of the class of instruments that measure temperature continuously through the optic fiber installed along the entire wellbore length. DTS most commonly operates on the same principles as an Optical Time-Domain Reflectometer (OTDR). It uses physical phenomena such as Raman scattering, which transduces temperature into an optical signal. Laser light pulses are generated by the DTS instrument (DTS box) and launched down the fiber sensor. As laser pulses travel down, a portion of the light is scattered away. The light that is scattered back towards the source (DTS box) is called backscatter. Raman backscatter is caused by molecular vibration in the fiber, resulting in the emission of photons, which are shifted in wavelength from the incident light.1 Positively shifted Stokes backscatter is temperature independent, while the negatively shifted Anti-Stokes Raman backscatter is temperature dependent. The intensity ratio of Stokes/Anti-Stokes is used to calculate temperature. Since pulses become weaker after the scattering loss, the calculated temperature accuracy depends on calibration and fiber loss stability.