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.
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.
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 mostly been 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.
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.
Field development costs have risen with oil price. A resulting challenge with Arab heavy oil development remains how to generate competitive advantages through deploying efficient technological innovations and making cost-effective solutions a crucial part of a firm's strategy for rigless interventions. With strict commitments to environmental protection, the need for operational excellence and several process improvements necessary to yield dividends in the form of safe project delivery and to overcome several technical difficulties is vital. The scope of the paper is to examine coiled tubing (CT) stimulation and logging technologies used in the timely project execution of one of Saudi Arabia's largest field developments to cost effectively enhance matrix stimulation success. Some of these solutions include technologies for CT reach, CT access for dual laterals, acid placement optimization, and treatment effectiveness monitoring. CT extended reach solutions comprised tapered CT strings designed for ultradeep wells, drag reducers, tractors, and vibrators. Technologies for CT access for dual laterals include a flow activated multilateral tool for CT matrix stimulation employing pressure variation telemetry with bottom hole pressure (BHP) and casing collar locator / gamma ray (CCL/GR) for high success lateral identification. To optimize acid placements, distributed temperature survey and pressure measurements are used to enhance diversion and acid placements. A blend of tools assisted to monitor, analyze, and adjust in real-time the reservoir and stimulation fluids interaction. Viscoelastic diverting acid is designed to viscosify in situ as the fluid spends on the reacted formation for chemical diversion in carbonates. The concentration of the diverter was optimized from 20% HCl to 15% HCl. A unique solution for monitoring treatment effectiveness evolved to include real time production logging using single strings for CT stimulation and real time profiling instead of memory logging. This solution required less equipment mobilization and no wireline unit. Intervention from 99 producers and injectors reveals operational and cost benefits from deploying technological solutions and justifies the degree to which each technology solution fits the overall field development strategy. The implications of deploying these solutions include reduction of well counts from the original estimates in this field development to offer manageable total field development costs.
With the growing demand for oil production, and pressure maintenance for giant fields, more horizontal wells has been drilled as power water injectors and oil producers to increase the contact with the reservoirs. In M-field, many wells are drilled as mega-reach with a measured total depth up to 33,000 ft. This present a big challenge for coiled tubing intervention to reach TD and stimulate or perform logging. Even with the use of hydraulic tractors, CT Pipe Locks up before TD, and it has been difficult to understand the root cause as it is not possible to differentiate between a hydraulic tractor malfunction and downhole obstruction causing the CT to tag. Here in this paper we are going to illustrate the reach challenges, analysis performed on the un-anticipated lockups, and how could we utilize recent technologies in understanding the lockup occurrence, as well as quantifying the how can we improve the prejob tubing force model simulation to fine-tune well accessibility in real-time while on the job. With the implementation of the real-time tension-compression tool, it becomes possible to detect any malfunction of the hydraulic tractor. With the real-time reading of the tractor pull downhole, the coiled tubing force model simulation can be adjusted during the operating to match the real coiled tubing weight and have better estimation of the expected lockup depth. Real-time informed decisions can optimize the CT reach. Being in ultra heavy oil formation and barefoot completion, the following questions come to the scene: Are we tagging in tar? or it is just the excessive drag force that is causing an early lockup?; What if the tractor fails? and how to diagnose the failure?; Shall we use solvents? at what quantities if any?; Is it feasible to run more than once? or it is a challenge that we cannot overcome? All the above questions are answered in details in the paper with illustrated troubleshooting, and problem solving workflow that is aided by case studies, jobs results, and success stories from one of the biggest fields in the Middle East. Exploring more in this direction would successfully change the face of the tubing force model simulation algorithms and take the on-site operational excellence to a significantly advanced level.
Fiber optic enabled coiled tubing (FOECT) has been commonly used in qualitatively evaluating reservoir matrix chemical treatment in real time during the past couple of years. During this period, attempts of transforming qualitative evaluations to quantitative ones were made. The quantitative evaluation is based on two simultaneous criterions. The first one is a downhole pressure diagnostic plot (pressure transient analysis) created instantinuously using real-time acquired data by the downhole gauges. The second is an estimate of the zonal coverage based on the resulting temperature profile plot before, during and after a pumping treatment. Pressure transient analysis gives the skin as a direct output, while the cooling down/warming up DTS profiles identifies where the treatment fluids went in the formation, hence identifying the damaged zones. It is strongly recommended to combine well testing analysis techniques with zone coverage evaluation in highly deviated and horizontal completed wells in both clastic and non-clastic rocks. Basically, deriving the skin from the injectivity test (pretreatment) and the skin from the post flush (post-treatment) provides an evaluation matrix treatment effectiveness. A comparison between formation damage "skin" before and after the treatment was performed on the spot, revealing positive results of nearly uniform distribution of treatment fluids, and skin value reduction across the 3400 ft horizontal section. Following the innovative procedures executed in well-A, different techniques were proposed, providing time and cost savings; raising the operational excellence expectations levels higher than expected for an offshore environment. The application of FOECT technology helped to minimize uncertainties during treatmentevaluation, and enhanced treatment distribution and placement. In addition to establishing more accurate and reliable Nodal Analysis and production forecast models.
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