Real-Time Fluid Distribution Determination in Matrix Treatments Using DTS

Glasbergen, Gerard; Gualtieri, Dan; Domelen, Mary Susan Van; Sierra, Jose R.

doi:10.2118/107775-pa

Cited by 33 publications

(10 citation statements)

References 25 publications

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“…Most of these have been discussed in previous publications (Glasbergen et al 2009). In summary, four main techniques can be used: (1) Temperatures lower than the baseline temperature at a certain depth in the profile indicate that fluid flows until that depth at a velocity high enough to cause cooling; (2) migration of these lower temperatures to deeper depths is an indication that fluid flows to deeper depths;…”

Section: Diversion Monitoring Using Dtsmentioning

confidence: 97%

“…Thus, the created velocity profile can be transformed relatively easily to a leakoff profile. This quantitative analysis is described in detail in the literature (Glasbergen et al 2009;Glasbergen et al 2007;Sierra et al 2008).…”

Section: Diversion Monitoring Using Dtsmentioning

confidence: 99%

“…It is the method to solve the inverse problem that is described in previous publications (Glasbergen et al 2009;Sierra et al 2008). In this quantification method, a forward temperature model is used to determine a temperature profile for a given, hypothetical leakoff distribution.…”

Section: Diversion Monitoring Using Dtsmentioning

confidence: 99%

See 2 more Smart Citations

Fluid-Diversion Monitoring: The Key to Treatment Optimization

Glasbergen

Yeager

Reyes

et al. 2010

SPE Production &Amp; Operations

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In stimulation and injection treatments for removing or preventing formation damage, placement of the injected fluids is essential. Throughout the years, several diversion and placement techniques have been applied to obtain a desired fluid placement. A recent development is the application of distributed temperature sensing (DTS) to monitor the temperature profiles along the wellbore in real time during these treatments. Recent case histories showed that fluid placement can be quantified. Quantification of fluid distribution enables one to determine the flow distribution both before and after a diverter stage so that the diversion effect can be quantified.This paper discusses several case histories where DTS was applied to quantify the effectiveness of different diverters. The effects of chemical diverters, such as relative permeability modifiers (RPMs) and in-situ-crosslinked acids (ICAs), and moretraditional diverters, such as rock salt, are discussed. Because of the advanced monitoring used with the temperature profiles, both the immediate and the sustained effect of the diverters can be measured. The changes in the flow distribution are not limited to diverters. Reactive fluid or changes in flow rate can change the flow distribution as well. These effects were measured during the stimulation treatments.The post-treatment analysis of the measured temperature profiles in combination with treatment pressures and flow-rate information resulted in accurate knowledge of the effectiveness of the different diverters and stimulation effects over time. This knowledge will be used in future treatments to help optimize volumes, rates, fluid systems, and the selection of the appropriate diverter.

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Section: Diversion Monitoring Using Dtsmentioning

confidence: 97%

Section: Diversion Monitoring Using Dtsmentioning

confidence: 99%

See 1 more Smart Citation

Fluid-Diversion Monitoring: The Key to Treatment Optimization

Glasbergen

Yeager

Reyes

et al. 2010

SPE Production &Amp; Operations

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“…While real-time downhole temperature measurement is a developing technology and attracts people's interests due to its inherent characteristics. In the past five years, the industry reported various field applications of downhole temperature sensors from conventional flow profiling (Achnivu and Zhu, 2008), SAGD temperature observations (Wang, 2008) to stimulation treatments (Glasbergen et al, 2009;Huckabee, 2009).…”

Section: Introductionmentioning

confidence: 99%

Determining multilayer formation properties from transient temperature and pressure measurements in gas wells with commingled zones

Sui

Zhu

2012

Journal of Natural Gas Science and Engineering

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“…While real-time downhole temperature measurement is a developing technology and attracts people's interests due to its inherent characteristics. In the past five years, the industry reported various field applications of downhole temperature sensors from conventional flow profiling (Achnivu et al, 2008), SAGD temperature observations (Wang, 2008) to stimulation treatments (Glasbergen et al, 2009;Huckabee et al, 2009).…”

Section: Introductionmentioning

confidence: 99%

Determining Multilayer Formation Properties from Transient Temperature and Pressure Measurements in Commingled Gas Wells

Sui

Ehlig-Economides

Zhu

et al. 2010

International Oil and Gas Conference and Exhibition in China

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With the evolution of downhole permanent monitoring techniques, transient temperature and pressure data can play an important role in reservoir description due to their inherent real-time characteristics. Previous studies presented a completely new analysis technique for quantifying permeability and altered zone permeability and radius for multiple commingled layers. However, the previous model mainly applies for single-phase oil flow.A new wellbore/reservoir coupled flow model has been developed for multilayer commingled gas reservoirs including both damage and non-Darcy skin in each commingled layer. The non-Darcy effects are considered as permeability alteration and are incorporated to the reservoir flow model by using Forchheimer equation. Additionally, this coupled flow model can consider the pressure drop due to friction and kinetic energy changes in wellbore over the producing layers, which yields more accurate transient layer flow rate allocation. This coupled flow model is used to provide the wellbore pressure distribution and the radial reservoir pressure gradient for the coupled wellbore/reservoir temperature model. The temperature model is formulated using wellbore and reservoir energy balance equations considering subtle thermal factors such as Joule-Thomson effect and also using fluid properties which are dependent on in-situ pressure and temperature. The inverse method is adopted from previous study directly and is used for determining formation properties by doing nonlinear regression.The mathematical model is solved numerically and used to study the sensitivity of transient temperature behavior to formation properties. The results show that transient temperature behavior in the wellbore at strategic locations is very sensitive to formation property values, and has some interesting characteristics similar to oil reservoirs. However, due to the non-Darcy effects, each producing layer in multilayer gas reservoirs has non-Darcy skin more or less, which makes the transient temperature behavior in gas reservoirs show more complexities than the oil reservoir case. In the end, two hypothetical examples are presented to show the performance of the inverse method. The regression results show that the damage skin location and magnitude can be determined correctly using the proposed testing method.

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Real-Time Fluid Distribution Determination in Matrix Treatments Using DTS

Cited by 33 publications

References 25 publications

Fluid-Diversion Monitoring: The Key to Treatment Optimization

Fluid-Diversion Monitoring: The Key to Treatment Optimization

Determining multilayer formation properties from transient temperature and pressure measurements in gas wells with commingled zones

Determining Multilayer Formation Properties from Transient Temperature and Pressure Measurements in Commingled Gas Wells

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