Effective well control depends on the drilling teams’ knowledge of wellbore flow dynamics and their ability to predict and control influx. Unfortunately, detection of a gas influx in an offshore environment is particularly challenging, and there are no existing datasets that have been verified and validated for gas kick migration at full-scale annular conditions. This study bridges this gap and presents pioneering research in the application of fiber optic sensing for monitoring gas in riser. The proposed sensing paradigm was validated through well-scale experiments conducted at Petroleum Engineering Research & Technology Transfer lab (PERTT) facility at Louisiana State University (LSU), simulating an offshore marine riser environment with its larger than average annular space and mud circulation capability. The experimental setup instrumented with distributed fiber optic sensors and pressure/temperature gauges provides a physical model to study the dynamic gas migration in full-scale annular conditions. Current kick detection methods primarily utilize surface measurements and do not always reliably detect a gas influx. The proposed application of distributed fiber optic sensing overcomes this key limitation of conventional kick detection methods, by providing real-time distributed downhole data for accurate and reliable monitoring. The two-phase flow experiments conducted in this research provide critical insights for understanding the flow dynamics in offshore drilling riser conditions, and the results provide an indication of how quickly gas can migrate in a marine riser scenario, warranting further investigation for the sake of effective well control.
Using optical fibers to instrument hydraulically fractured wells is becoming routine in US unconventional plays. Instrumented wells facilitate understanding of proppant distribution among perforation clusters and the inefficiencies of geometric fracturing and well planning techniques. However, converting fiber-optic data into proppant distribution requires management of high volumes of data and correlation of the data to factors such as well conditions, fracturing parameters, and temperatures. A user-friendly workflow for understanding hydraulic fracturing proppant and slurry distribution among different perforation clusters over time is presented. Ideally, slurry flow is equal between perforation clusters and, at least, constant in time, but the reality is very different. The interpretation workflow is based on proprietary algorithms within a general wellbore software platform and aims to greatly expedite the analysis. We propose using distributed acoustic sensing (DAS) data (in the form of custom frequency band energy (FBE) logs), distributed temperature measurements (DTS) and surface pumping data to obtain a quantitative analysis of proppant distribution within minutes, with various options for reporting and visualizing results. The software platform selected provides data integration, visualization, and customization of in-built algorithms. The new workflow enables users to upload DAS, DTS, flow rate, pressure, and other measurements and use customized algorithms to quantitatively analyze proppant distribution, enabling decisions in real time to optimize the fracturing operation. The validity of the approach is illustrated by a case study involving a well with 28 stages and four to five clusters per stage. The workflow is automated to provide results in real time, enabling quick corrective actions and significantly improving the efficiency and economics of hydraulic fracturing.
Early detection and quantification of gas kicks during drilling and completions is essential to proper well control and in the prevention of blowouts. The utilization of distributed sensing techniques, acoustic (DAS) and temperature (DTS), enables real-time elucidation of these multiphase flow events. Identifying and validating event signatures (fingerprinting) in these sensing technologies is crucial to informing operators of how to interpret these data streams. Performing full-scale analysis allows these events to be properly characterized, given the complexities in the fluid mechanics and gas dynamics. This project utilizes a 9-5/8 inch and 5200 foot deep wellbore at the LSU PERTT Laboratory retrofit with distributed fiber optics (DAS and DTS) and 4 permanent pressure-temperature gauges to sense and visualize gas kick dynamics downhole in real time. Several experiments were performed involving the injection of nitrogen kicks through a chemical injection line and also by bullheading down 2-7/8 inch tubing in both stagnant and circulating water. Variations in flow rate, kick size, and backpressure are investigated including gas migration during shut-in. DTS and DAS data are collected downhole, along with gauge pressure and temperature at four depths along the wellbore. Data is consolidated with the rig recorded surface data to create a complete picture of the experiments. Several observations are possible with this new methodology. First, the gas kick is immediately visible (audible) entering the wellbore by the sensors and the gas front was traceable in real time as it rose to the surface, allowing for detection of a kick, improved estimation of kick size, and easy calculation of rise velocity. Second, the distribution of gas axially in the wellbore was visible and provided insights into the duration of the event. Third, the compressibility dynamics can be visualized with the DAS thus elucidating details of bubble and slugging sizes and dynamics and when discrete gas has completely circulated out of the wellbore. The frequency ban filtering of the data further augments the fidelity of gas bubble sizes and dynamics. These initial results provide a proof of concept for using downhole sensing for real time riser gas dynamic detection and characterization.
Effective well control depends on the drilling teams’ knowledge of wellbore flow dynamics and their ability to predict and control influx. Detection of a gas influx in an offshore environment is particularly challenging, and there are no existing datasets that have been verified and validated for gas kick migration at full scale annulus conditions. This study bridges this gap with the newly instrumented experimental well at PERTT (Petroleum Engineering Research & Technology Transfer Lab) at Louisiana State University (LSU) simulating an offshore marine riser environment with its larger than average annular space and mud circulation capability. The experimental setup instrumented with fiber optics and pressure/temperature gauges provides a physical model of the dynamic gas migration over large distances in full scale annular conditions. Current kick detection methods do not always reliably detect a gas influx and have not kept pace with the increasingly challenging offshore drilling conditions. Even though there have been some recent developments in offshore kick detection, all methods thus far are only qualitative in nature because they are based on measurements at the surface. This study addresses current kick detection limitations and illuminates the potential for implementing distributed fiber optic sensing (DFOS) to the marine riser as a non-invasive and effective kick detection method in both stagnant and circulating annular conditions. As North America's only academic full scale well testing center, an experimental well in the PERTT lab was utilized to monitor and characterize gas rise using DFOS to simulate well control scenarios in offshore drilling riser environments. DFOS allows for the tracking of the gas migration in both the stagnant and full-scale circulating annulus conditions. Data from pressure sensors is integrated with the distributed temperature (DTS) and acoustic (DAS) measurements, for real-time downhole monitoring of the dynamics of the gas migration and fluid front movement. By implementing time and frequency domain analysis of the fiber optic data, we show that the gas rise and water front movement can be identified. Both the water and gas injection down the tubing independently show characteristic fronts in the DTS and DAS data, which gives us confidence in our interpretation. Once the gas is present in the annulus, the DAS measurements indicate a higher than expected gas-rise velocity, and this is most probably due to the full-scale annular geometry and circulating conditions enabling a faster gas rise velocity compared to previous work in this area consisting only of small-scale experiments and experiments through tubing. The two-phase flow experiments conducted in this research provide critical insights for understanding the flow dynamics in offshore drilling riser conditions, and the results provide an indication of how quickly gas can migrate in a marine riser scenario warranting further investigation for the sake of effective well control.
Fiber Optic Systems, such as Distributed Temperature Sensing (DTS), have been used for wellbore surveillance for more than two decades. One of the traditional applications of DTS is injectivity profiling, both for hydraulically fractured and non-fractured wells. There is a long history of determining injectivity profiles using temperature profiles, usually by analyzing warm-back data with largely pure heat conduction models or by employing a so-called "hot-slug" approach that requires tracking of a temperature transient that arises at the onset of injection. In many of these attempts there is no analysis performed for the key influencing physical factors that could create significant ambiguity in the interpretation results. Among such factors we will consider in detail is the possible impact of cross-flow during the early warm-back stage, but also the temperature transient signal that is related to the location of the fiber-optic sensing cable behind the casing when the fast transient data are used for interpretation such as the "hot slug" during re-injection. In this paper it will be shown that despite all such potential complications, the high frequency and quality of the transient data that can be obtained from a continuous DTS measurement allow for a highly reliable and robust evaluation of the injectivity profile. The well-known challenge of the ambiguity of the interpretation, produced by the interpretation methods that are conventionally used, is overcome using the innovative "Pressure Rate Temperature Transient Analysis" method that takes maximum use of the complete DTS transient data set and all other available data at the level of the model-based interpretation. This method is based on conversion of field measurements into injectivity profiles taking into account the uncertainty in different parts of the data set, which includes the specifics of the DTS deployment, the uncertainty in surface flow rates, and possible data gaps in the history of the well. Several case studies will be discussed where this approach was applied to water injection wells. For the analysis, the re-injection and warmback DTS transient temperature measurements were taken from across the sandface. Furthermore, for comparison, injection profiles were also recorded by conventional PLTs in parallel. This case study will focus mostly on the advanced interpretation opportunities and the challenges related to crossflow through the wellbore during the warm-back phase, related to reservoir pressure dynamics, and finally related to the impact of the method of DTS deployment. In addition to describing the interpretation methodology, this paper will also show the final comparison of the fiber-optic evaluation with the interpretation obtained from the reference PLTs.
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