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Abstract Distributed Fiber Optics (DFO) technology has been the new face for unconventional well diagnostics. This technology focuses on measuring Distributed Acoustic Sensing (DAS) and Distrusted Temperature Sensing (DTS) to give an in-depth understanding of well productivity pre and post stimulation. Many different completion design strategies, both on surface and downhole, are used to obtain the best fracture network outcome; however, with complex geological features, different fracture designs, and fracture driven interactions (FDIs) effecting nearby wells, it is difficult to grasp a full understanding on completion design performance for each well. Validating completion designs and improving on the learnings found in each data set should be the foundation in developing each field. Capturing a data set with strong evidence of what works and what doesn't, can help the operator make better engineering decisions to make more efficient wells as well as help gauge the spacing between each well. The focus of this paper will be on a few case studies in the Bakken which vividly show how infill wells greatly interfered with production output. A DFO deployed with a 0.6" OD, 23,000-foot-long carbon fiber rod to acquire DAS and DTS for post frac flow, completion, and interference evaluation. This paper will dive into the DFO measurements taken post frac to further explain what effects are seen on completion designs caused by interferences with infill wells; the learnings taken from the DFO post frac were applied to further escalate the understanding and awareness of how infill wells will preform on future pad sites. A showcase of three separate data sets from the Bakken will identify how effective DFO technology can be in evaluating and making informed decisions on future frac completions. In this paper we will also show and discuss how DFO can measure real time FDI events and what measures can be taken to lessen the impact on negative interference caused by infill wells.
Wu, Yinghui (Silixa LLC) | Hull, Robert (Silixa LLC) | Tucker, Andrew (Apache Corp.) | Rice, Craig (Apache Corp.) | Richter, Peter (Silixa LLC) | Wygal, Ben (Silixa LLC) | Farhadiroushan, Mahmoud (Silixa Ltd.) | Trujillo, Kirk (Silixa LLC) | Woerpel, Craig (Silixa LLC)
Abstract Distributed fiber-optic sensing (DFOS) has been utilized in unconventional reservoirs for hydraulic fracture efficiency diagnostics for many years. Downhole fiber cables can be permanently installed external to the casing to monitor and measure the uniformity and efficiency of individual clusters and stages during the completion in the near-field wellbore environment. Ideally, a second fiber or multiple fibers can be deployed in offset well(s) to monitor and characterize fracture geometries recorded by fracture-driven interactions or frac-hits in the far-field. Fracture opening and closing, stress shadow creation and relaxation, along with stage isolation can be clearly identified. Most importantly, fracture propagation from the near to far-field can be better understood and correlated. With our current technology, we can deploy cost effective retrievable fibers to record these far-field data. Our objective here is to highlight key data that can be gathered with multiple fibers in a carefully planned well-spacing study and to evaluate and understand the correspondence between far-field and near-field Distributed Acoustic Sensing (DAS) data. In this paper, we present a case study of three adjacent horizontal wells equipped with fiber in the Permian basin. We can correlate the near-field fluid allocation across a stage down to the cluster level to far-field fracture driven interactions (FDIs) with their frac-hit strain intensity. With multiple fibers we can evaluate fracture geometry, the propagation of the hydraulic fractures, changes in the deformation related to completion designs, fracture complexity characterization and then integrate the results with other data to better understand the geomechanical processes between wells. Novel frac-hit corridor (FHC) is introduced to evaluate stage isolation, azimuth, and frac-hit intensity (FHI), which is measured in far-field. Frac design can be evaluated with the correlation from near-field allocation to far-field FHC and FHI. By analyzing multiple treatment and monitor wells, the correspondence can be further calibrated and examined. We observe the far-field FHC and FHI are directly related to the activities of near-field clusters and stages. A leaking plug may directly result in FHC overlapping, gaps and variations in FHI, which also can be correlated to cluster uniformity. A near-far field correspondence can be established to evaluate FHC and FHI behaviors. By utilizing various completion designs and related measurements (e.g. Distributed Temperature Sensing (DTS), gauges, microseismic etc.), optimization can be performed to change the frac design based on far-field and near-field DFOS data based on the Decision Tree Method (DTM). In summary, hydraulic fracture propagation can be better characterized, measured, and understood by deploying multiple fibers across a lease. The correspondence between the far-field measured FHC and FHI can be utilized for completion evaluation and diagnostics. As the observed strain is directly measured, completion engineering and geoscience teams can confidently optimize their understanding of the fracture designs in real-time.
Soroush, Mohammad (RGL Reservoir Management, University of Alberta) | Mohammadtabar, Mohammad (RGL Reservoir Management, University of Alberta) | Roostaei, Morteza (RGL Reservoir Management) | Hosseini, Seyed Abolhassan (RGL Reservoir Management, University of Alberta) | Mahmoudi, Mahdi (RGL Reservoir Management) | Keough, Daniel (Precise Downhole Services Ltd) | Cheng, Li (University of Alberta) | Moez, Kambiz (University of Alberta) | Fattahpour, Vahidoddin (RGL Reservoir Management)
Abstract Distributed Temperature Sensing (DTS) system using optical fiber has been deployed for downhole monitoring over two-decades. Several technological advancements led to a wide acceptance of this technology as a reliable surveillance technique. This paper presents a comprehensive technical review of all the applications of the DTS, with focus on oil and gas industrial deployments. The paper starts with the advantages of the DTS over other methods and an overview of the DTS basics, including theory, the DTS components, deployment types, fiber types, design and limitations. Then, it is followed by the oil and gas applications of the DTS including hydraulic fracturing (during and after fracturing), well treatment/stimulation (acid injection, fluid distribution, diversion monitoring), inorganic (scaling) and organic (wax/asphaltene/hydrate) deposition detection, leak detection (in well and pipeline), flow monitoring (rate monitoring, water/steam injection and SAGD monitoring, CO2 storage monitoring, zonal contribution determination, gas lift optimization) and reservoir/fluid characterization (facies, porosity, permeability and fluid composition determination). This study reviews the historical development, applications and limitations of the DTS systems. The paper mainly focusses on deployment techniques, the application of the DTS for the prediction and surveillance of the non-thermal and thermal producer/injector wells, hydraulically fractured wells and those wells with treatments. The paper provides a concise review using several field cases from over two hundred published papers of Society of Petroleum Engineering (SPE) and journal databases. The application of the DTS in downhole monitoring can be divided into the qualitative and quantitative applications. In quantitative approaches, numerical models should be combined with the DTS data. This study discusses case by case worldwide field applications of DTS along with proposed modeling methods and interpretations. It also summarizes main challenges, including the fiber reliability, longevity, and operational limitations such as the installation and the complexity of quantitative approaches. This study is the foundation for an ongoing study on wellbore and reservoir surveillance through real-time distributed fiber optic sensing recordings along the wellbore. It summarizes the historical development and limitations to identify the existing gaps and reviews the lessons learned through the two decades of the application of the DTS in production performance.
Javaheri, Mohammad (Chevron) | Tran, Minh (University of Southern California) | Buell, Richard Scot (Chevron) | Gorham, Timothy Lee (Chevron) | Sims, Jack (Chevron) | Rivas, Stephen (Chevron) | Munoz, Juan David (Chevron)
Abstract Horizontal steam injectors can improve the efficiency of thermal operations relative to vertical injectors. However, effective in-well and reservoir surveillance is needed to understand steam conformance. Uniform steam chest development improves steam-oil-ratio (SOR) in continuous steam injection and accelerates recovery in cyclic steam injection. Conformance of the injected steam can be achieved by flow control devices (FCD) deployed on either tubing or liner. A new liner-deployed FCD was used in a horizontal steam injector in the Kern River field. The liner-deployed FCD is intended to replace the tubing-deployed FCDs while reducing capital costs, surveillance costs, and well intervention costs for conformance control. Fiber optics was used for surveillance, which is the most promising method in horizontal steam injectors considering reliability, accuracy, and cost. Fiber optic data enables monitoring the performance of liner-deployed FCDs as well as estimating the flow profile along the lateral length. Multi-mode Distributed Temperature Sensing (DTS) optical fibers and single-mode Distributed Acoustic Sensing (DAS) optical fibers were installed in the well for these objectives. Algorithms for interpreting DTS were improved to include a new technique, Shape Language Modeling (SLM), and a probabilistic approach. The configuration of the FCDs was changed during a well intervention, and it was monitored by DTS and DAS. Data from both DTS and DAS confirms the open/closed position of the sliding sleeve of FCDs initially and after the intervention. The probabilistic estimates of steam outflow in several FCD configurations match well with the theoretical outflow that is expected from the critical flow of steam through chokes installed in the FCDs.
Minggu, Nur'ain (PETRONAS Carigali Sdn Bhd) | Riyanto, Latief (PETRONAS Carigali Sdn Bhd) | Ting, Chang Siong (PETRONAS Carigali Sdn Bhd) | Kamat, Dahlila (PETRONAS Carigali Sdn Bhd) | Ho, Dylan Zhe (PETRONAS Carigali Sdn Bhd) | Zamdy, Siti Nurdyana (PETRONAS Carigali Sdn Bhd) | Kamarulzaman, Ammar (Schlumberger WTA Malaysia Sdn Bhd) | Kalidas, Sanggeetha (Schlumberger WTA Malaysia Sdn Bhd) | Tan, Chee Seong (Schlumberger WTA Malaysia Sdn Bhd) | Goh, Gordon (Schlumberger WTA Malaysia Sdn Bhd)
Abstract This study aims to validate and track valve positions for all the zones applying recorded Distributed temperature sensing (DTS) and Distributed acoustic sensing (DAS) data interpretation in order to propose the best combination of downhole inflow control valve (ICV) openings, This is required to optimize Well X-2 multizone commingled production. Fiber DTS and DAS monitoring were relied on as an innovation against downhole conditions that has compromised the three out of four downhole dual-gauges and valve position sensors. For zonal water control purpose, ICV cycling and positioning have been attempted in 2019. The valve position tracking derived from the compromised downhole dual gauges and valve position sensors does not tally with the surface flow indication overall. Consequently, the original measurement intention of the permanently installed distributed fiber-optic which served as back-up zonal-rate calculation profiling and as potential sub-layer flow-contribution indicators is brought in as contingency zonal valve-opening tracking and guides that proved valuable for subsequent production optimization. First part of study involves interpretation of Distributed Temperature Sensing (DTS) data. Downloaded DTS data is depth matched and validated against known operating conditions like time of each cycling stage and surface well test parameters (i.e. Liquid Rate, Watercut, Tubing Head Pressure (THP), Total Gas, Gas-Oil Ratio (GOR)), etc. To establish a baseline, several DTS traces of historical operating condition during a known stable period were selected, i.e. stable flowing condition at only Zone 4 stable shut-in condition at surface with only ICV Zone 4 is opened Downhole valve-position tracking can be interpreted alternatively from induced fiber temperature activities across the valve depth with a good temperature baseline benchmarking from DTS temperature profiling. Second part of study involves interpretation of Distributed Acoustic Sensing (DAS) data. The data was acquired under single flowing condition one month post-ICV cycling. Without any changes made on the well operating conditions, the well is flowing under same condition post ICV cycling. Inflow point detection using joint interpretation of DAS and DTS, where simultaneously DAS spectral content (depth-frequency) was analysed alongside DTS traces to further discriminate between inflow and other noise sources. Through i) acoustic amplitude analysis, ii) DTS inversion, iii) noise speed and flow speed computation, composite production allocation can be derived for Well X-2. Using the alternative co-interpretations based on fiber temperature and acoustic measurement, it is found and validated that Zone 1 ICV is Closed, Zone 2, 3 and 4 are in opened position and continuously producing at any cycles. This is in conflict of zonal production control understanding initially based on the compromised downhole sensors indicating that all the zonal valves are supposedly in fully closed position. In this case-study, DTS and DAS data has been proven useful and as an innovative, alternative monitoring to determine downhole valve opening with analogue to flow contribution derivation methodology. Therefore, anytime in the future where Well X-2 valves cycling is planned to be carried out, there is now a corresponding operating procedure that is incorporated onsite real-time fiber optic DTS and/or DAS data monitoring to validate tracked valves positioning.
Ting, Chang Siong (PETRONAS Carigali Sdn Bhd) | Minggu, Nur’ain (PETRONAS Carigali Sdn Bhd) | Kamat, Dahlila (PETRONAS Carigali Sdn Bhd) | Riyanto, Latief (PETRONAS Carigali Sdn Bhd) | Tan, Chee Seong (Schlumberger WTA Malaysia Sdn Bhd) | Kalidas, Sanggeetha (Schlumberger WTA Malaysia Sdn Bhd) | Kamarulzaman, Ammar (Schlumberger WTA Malaysia Sdn Bhd) | Goh, Gordon Kim (Schlumberger Technology Corporation Houston)
Abstract Well B-2 is a dual-string producers with Distributed Temperature Sensing (DTS) fiber installed along the long string (i.e. Well B-2L) across the reservoir sections. Each zone comprises of sub-layers. This system enabled the operator to continuously monitor the wellbore temperature across all the producing intervals including gas-lift monitoring, well integrity identification, zonal inflow profiling and stimulation job evaluation. This paper mainly discusses the post matrix acid stimulation job with interpreted DTS and zonal Permanent Downhole Gauge (PDG) data. Well B-2L has been selected for matrix acidizing treatment to improve the productivity due to potential formation damage, proven by the declining production over the years. Prior to the execution of the acidizing job, several conformance jobs such as injectivity test, tubing pickling were performed. This is followed by the main acid treatment and flow back. DTS & zonal PDG data were acquired throughout the operation. A transient simulator model was built incorporating all the reservoir properties including well trajectory and completion schematic to analyze the DTS profile and understand the zonal inflow profiling for each zone post treatment. A baseline temperature was acquired for the geothermal evaluation. The DTS data has been studied according to actual event schedules. Some significant findings are; i) completion accessories effect (feedthru packers) creates temperature anomalies, ii) leak points detected at top producing zone signifies cooling effect due to injected fluid. The main treatment was intended at zone 2 and 3 using nitrified acid. However, leak points at top zone caused bypassed injection into Zone 1 and 2 instead. Fiber optic DTS warmback profiles post main-treatment was analyzed to quantify the fluid intake from sub-layer in each zone. Qualitatively from the DTS-interpreted zonal profiling, the data clearly shows most of treatment fluid is being injected into Zone 1 and 2 with no intakes at Zone 3. Furthermore, warmback analysis confirmed the high intake zones from sub-layers within the main zone based on the permeability contrast. This paper will further discuss the zonal injectivity understanding for improvement from the zonal-inflow profiling evaluation by incorporating DTS, PDG and surface production data.
Summary Distributed temperature sensing (DTS) is a valuable tool to diagnose multistage hydraulic fracture treatments. When a stage interval is shut in, the clusters that take more fluid during pumping warm up more slowly. Therefore, the fluid volume injected into each cluster can be quantitatively interpreted by numerical inversion of the warm-back temperature behavior. This general concept assumes that the different warm-back behavior is controlled by only the injected fluid volume; however, recent observations of DTS data indicate that completion configurations significantly influence the warm-back behavior. This paper investigates the completion effects on the DTS interpretation. In ideal conditions, when a stage is fractured, the upstream stage intervals should show an almost uniform temperature that is close to the injected fluid temperature. This is due to the high fluid velocity of injected fluid in the wellbore, and the upstream intervals have not been perforated (noncommunicating intervals), so the only heat transfer is heat conduction between the wellbore fluid and the surrounding reservoir. But the field DTS data show considerably irregular variations in temperature along the upstream stage intervals. These variations are caused by the completion effects. The nonuniform temperature profile is caused by different heat transfer behavior induced by completion hardware along the production casing string, such as joints, clamps, and blast protectors, and by the sensing cable location in the cement, as well as the cement quality. Because the varying heat transfer behavior impacts the warm-back behavior as well as the temperature profile, the completion effects need to be considered in DTS interpretation. A method of DTS interpretation considering the completion effects to diagnose multistage fracture treatments was developed. Because the heat transfer between a wellbore and a reservoir depends on the overall heat transfer coefficient describing heat conduction through the completion in a forward model, this parameter needs to be tuned all along the wellbore. To calibrate the completion effect, the temperature inversion is conducted using the temperature measured at a stage interval that is upstream of a stage interval currently being treated. Because the interpreted stage interval is not perforated at that time, the thermal behavior at the noncommunicating interval is governed by only the heat conduction through the completion environment. Once the effective values of the overall heat transfer coefficient are estimated along the interpreted stage interval, they can be assumed to be constant physical parameters. Then, the fluid volume distribution is interpreted by using the effective overall heat transfer coefficient profile along each interval. This study provides a field application of the developed interpretation method. The new interpretation method provides more accurate diagnosis of fracture treatments by DTS interpretation.
The success of any digital oilfield project is predicated on the quality of the data structure, acquisition, communication, validation, storage, retrieval, and provenance of the data. Therefore, the mission of the digital oilfield architect is clear: Deliver the right data to the right users at the right time. This task is becoming more difficult because of the sheer variety of sensors, the multitude of data formats, challenges with data communication and synchronization, and the potentially large volume of data produced. While the advent of data analytics has increased the importance of designing fast and efficient data management systems, it is a multifaceted minefield to gather and process data to ensure production is optimized and risk is minimized in both conventional and unconventional operating environments. The existing proliferation of sensors and the projected growth rate of new sensor technology is expected to reach around $30.57 billion by 2026, a boost of 24.65% CAGR (compound annual growth rate), according to market intelligence.
In Australia's Surat Basin, gas is contained in hundreds of coal seams, which have highly variable properties and are grouped into four distinct reservoir zones of similar qualities. Economically producing these wells from multiple reservoir units is generally favored and as a result, understanding the relative contribution to production by different zones at different times in the well's life--and whether production is dominated by a single zone--adds value to planning future wells. The well designs are quite simple. A 7-in. production casing and preperforated liner with an external casing packer and a cement stage tool is run to total depth. The external casing packer is deployed at the top of the reservoir, and the 7-in.
Luo, Hongwen (Southwest Petroleum University) | Li, Ying (Southwest Petroleum University) | Li, Haitao (Southwest Petroleum University) | Cui, Xiaojiang (Southwest Petroleum University) | Chen, Zhangxin (University of Calgary)
Summary With the increasing application of distributed temperature sensing (DTS) in downhole monitoring for multifractured horizontal wells (MFHWs), well performance interpretation by inversing DTS data has become a popular topic around the world. However, because of the lack of efficient inversion models, great challenges still exist in interpreting flow rate profiles and fracture parameters for MFHWs in unconventional gas reservoirs from DTS data. In this paper, a robust inversion system is developed to interpret flow rate profiles and fracture parameters for MFHWs in unconventional gas reservoirs by inversion of DTS data. A temperature prediction model serves as a forward model to simulate the temperature behaviors of MFHWs. A new inversion model based on a simulated annealing (SA) algorithm is proposed to find inversion solutions to flow rate profiles and fracture parameters. The simulated results of temperature behaviors indicate that the temperature profile of each MFHW is irregularly serrated, and the temperature drop in each serration is positively correlated with the inflow rate and fracture halflength. These results provide an excellent method to identify and locate effective hydraulic fractures for field MFHWs. Because of the far more significant influence of fracture half-length than conductivity on a temperature profile, fracture half-length was chosen as the inversion target parameter when performing the inversion of DTS data for MFHWs. Realtime inversion error distributions indicate that this novel inversion system shows great advantages in computational efficiency. Finally, a field application in a shale gas reservoir is presented to validate the reliability of the new inversion model. Based on accurate identification of effective fractures from DTS profiles, satisfactory inversion solutions (the maximum temperature deviation of less than 0.03 K) are obtained. The SA algorithm-based inversion system proves reliable to interpret flow rate profiles and fracture parameters, which is a great help to postfracturing evaluation and productivity improvement for MFHWs in unconventional gas reservoirs. Introduction With the rapid growth of natural gas consumption, the development of unconventional gas (e.g., tight and shale gas) resources has already become a major focus in the oil and gas industry around the world. Because of their poor formation conditions, multifractured horizontal well drilling has become a necessity to improve the productivity and recovery of unconventional gas reservoirs (Yao et al. 2019; Liu et al. 2020). However, the complex downhole conditions created by fracturing treatment make it extremely complicated to diagnose hydraulic fractures and flow rate distributions quantitatively.