Distributed temperature sensing (DTS) is a fiber-optic technology that provides continuous temperature profiles along the length of a well. When placing the fiber inside a coiled tubing (CT), one can monitor the temperature evolution while pumping as well as during a shut-in period. This evolution, in turn, yields some indications about the fluid-placement performance or zonal coverage. So far, interpretation of such DTS traces has been mostly qualitative. The work presented here demonstrates how DTS data can be used, coupled with an inversion algorithm and a forward model of fluid injection into a reservoir, to quantify the intake profile of treatment fluid along the wellbore. Recent field cases of matrix acidizing treatments in carbonate reservoirs are analyzed to illustrate the workflow and how it may yield valuable information. from Universidad de los Andes, Colombia.Kaveh Yekta-Ganjeh, P. Eng., SPE, is a senior technical engineer in coiled-tubing services at Schlumberger in Calgary. He has 10 years of experience in oilfield industry, all in coiled-tubing services. Yekta-Ganjeh joined Schlumberger in 2001 and has held different positions in field operation and technical support. He has worked in Iran, UAE, Libya, and Canada in land and offshore operations. Yekta-Ganjeh holds a BS degree in mechanical engineering from Sharif University of Technology, Iran.
This paper presents a case study of a matrix acidizing treatment in a well located at the neutral zone between Kuwait and Saudi Arabia, whereby the combination of a "smart fluid" in a stimulation treatment pumped through a Coiled-Tubing (CT) with the real time distributed temperature sensing (DTS) technology helped improve the real-time decision process of fluid placement, temporary plugging placement, and treatment efficiency evaluation. As part of the analysis process and to facilitate the onsite decision-making process, a temperature inversion technique was also used to translate the actual temperature profiles into fluid invasion profiles across the horizontal open-hole section of the well. Additionally, a full scale acid placement and thermal modeling is proposed in order to perform an in-depth post-treatment evaluation. The bottom hole data evaluation further confirmed the benefits of using a smart fluid. Following the treatment, the well produced at a rate of 1500 bbl/day with 17% water cut, which is well below the field average of ~50%.
When performing matrix stimulation treatments, coiled tubing (CT) is a preferred placement technique due to the ability to spot fluid in front of the target zone(s). This method becomes a key solution when formation heterogeneities require a very selective fluid placement strategy.In today's industry, the most common approach is to design a treatment with volumes of stimulation and diverter fluids that are determined largely based on local practices. Often, it amounts to targeting a uniform stimulation, thus requiring a predefined amount of treatment fluid per length of total pay zone. That approach, although widely used and accepted, may not necessarily yield an optimum stimulation.We present an alternative technique that relies on the accurate quantification of fluid placement along the formation in order to define the respective volumes of stimulation and diverter fluids to be pumped. This method relies on the analysis of the distributed temperature sensing (DTS) data recorded by a fiber-optic line enclosed inside the CT and data processing through a fast interpretation algorithm to yield a zonal coverage profile. During a job, DTS data corresponding to the preflush can be used to estimate the initial placement distribution across the pay zone. This allows stimulation engineers to determine the best strategy for the subsequent well stimulation treatment, including fluid volumes and placement sequence. After every major pumping stage, a new DTS analysis assesses how the formation reacted to the treatment, improving placement strategy.This method has been used in multiple matrix stimulation treatments of injector and producer wells. The described innovative approach allows engineers to make more informed decisions between stages, optimizing fluid resources, fluid placement and, ultimately, stimulation effectiveness. It also leads to noteworthy advantages when designing new acidizing treatments, as companies can build on previous experience from similar wells and fields.
The production curve of the main Mexican offshore fields has been decreasing rapidly year-on-year, representing a challenge to the eighth-largest oil producer country and an opportunity to implement new techniques for workover (WO) operations to increase production recovery.Within the most common WO activities developed in offshore Mexico is acid stimulation of carbonates, which was developed as pumping a large volume of fluids (solvents, HCl 15%, etc.) with minimum control for zonal coverage. Conventional coiled tubing (CT) jobs have improved this technique with the use of impact jetting tools to remove damage at the tubular and perforation holes and placing the treatment in the desired area. The estimation of fluid injection per zone has been evaluated using radioactive traces. However, the estimates of where the fluids go lack accuracy, and the radioactivity poses additional risks related to hazardous material handling.In 2009, a new interpretation technique to evaluate the treatment zonal coverage appeared that used CT with fiber optics. This distributed temperature sensing (DTS) enables the equipment to record temperature readings at several predetermined depths over time creating a survey that identifies, qualitatively, the admittance of the treated pay zones based on the formation's cold-down/heat-up effects. Unfortunately, this technique had some limitations as the data recorded needed to be converted, interpreted, and then translated into common oilfield language in the form of graphics and data tables. The time to get a final result from the readings to the customer was so long that the window to modify the current treatment to improve the well response was, on most occasions, already closed. DTS inversion brings a "real-time DTS matrix stimulation evaluation product" by using an inversion algorithm coupled with a fluid placement model to accurately quantify the amount of treatment placed across the treated zones of the well. A detailed case history from an offshore Mexico well describes the first worldwide real-time DTS inversion job and illustrates the workflow and advantages of this technique. The results from the technique showed a direct match with a previous evaluation of the formation through production logging conveyed on Wireline tools.
Matrix stimulation treatments executed with coiled tubing (CT) face various challenges in terms of design, execution, and evaluation. The design phase typically relies on information that is frequently poorly known (e.g., extent of damage). Treatment pumping schedules and fluid concentrations are often determined based on previous experience and accepted local practices. For the execution to be completed within a safe framework, the standard is to keep pumping pressures below the fracturing pressure. In some cases, tools like high pressure differential jetting nozzles are used to provide deeper penetration and lower breakdown pressures. The depths at which those tools are operated usually depend on a prior log interpretation. Finally, treatment evaluation is typically limited to the comparison of pre and post-stimulation wellhead pressures and rates.Over the past decade, numerical modeling has allowed the industry to address some of the design and evaluation challenges. Yet, the same question often remains: has the design been effectively executed and was the intervention successful? The answer depends on the choice of success criteria such as efficiency, safety, and economics.CT enabled with fiber optic telemetry-which consists of downhole gauges providing real-time data of pressure, temperature, gamma ray, and casing collar locator-has proven a game-changing technology with respect to treatment execution, improving both intervention efficiency and safety (Jacobsen et al. 2010). The provided measurements, along with the possibility to acquire distributed temperature surveys (DTS), have also shown to be the most effective solution for treatment evaluation to date.The case study presented here not only describes how CT with downhole sensors was used to optimize the acidizing treatment of an oil well producer and ensure its effective stimulation, but it also demonstrates how the real-time and DTS data were analyzed both during the intervention and through post-job numerical modeling, in order to refine the understanding of the well and that of its formation characteristics.
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