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This paper discusses the effectiveness of the third-generation (Gen3) Production Logging Tool (PLT) technology which incorporates the use of co-located digital sensors for simultaneous acquisition of flow data. Case studies are provided which demonstrate that this technology is a step-change in the application of digitalization to a down-hole sensor platform which provides the most accurate characterization of the flow condition at each depth surveyed. The resulting data allows for much improved processing which is also described. The probabilistic interpretive model used in the processing has been updated to incorporate this and future developments in PLT architecture. Planning, execution, and analysis of data for the wells is described in detail. Due to the significantly shorter configuration of Gen3 tools, safety at the wellsite is enhanced by allowing for a much-simplified surface rig-up. One well was logged in surface readout (SRO) mode while data in the other two were recorded in the downhole tool's memory for retrieval at the surface at the end of operations. This flexibility in logging modes optimizes operations by addressing the needs of the operation teams. Three Deepwater Gulf of Mexico producers logged with the Gen3 PLT are described. In each case, a clear path forward is provided for optimal management of the reservoirs through effective production management. The first generation (Gen1) of PLT provided a single discrete measurement for each sensor along the tool assembly's length, resulting in long tool assemblies and measurements taken at different points along the flow path. This approach had several drawbacks: long toolstrings, point sensors only provided a measurement at a single point in the cross-section of the flow, and measurements were not acquired simultaneously at each depth logged. The second generation (Gen2) of PLT was an improvement as sensors were arranged as an array enabling multiple measurements to be made at a single depth but were still long and not all were optimally arranged to capture data in the path of flow. The Gen3 PLT is one-tenth the length of the Gen1 versions and roughly one-third of the shortest Gen2 tools. Digitization allows for direct measurement of flow conditions and rapid interpretation of results. In multi-phase flow and deviated wells, the co-location of sensors in a spatial geometry provides the optimal information with which to create a fully accurate picture of the downhole flow.

Logging hydrocarbon production potential of wells has been at the forefront of enhancing oil and gas exploration and maximize productivity from oil and gas reservoirs. A major challenge is accurate downhole fluid phases flow velocity measurements in production logging (PLT) due to the criticality of mechanical spinner-based sensor devices. Ultrasonic Doppler-based sensors are more robust and deployable either in wireline or logging while drilling (LWD) conditions; however, due to the different sensing physics, the measurement results may vary. Ultrasonic Doppler flow meters utilize the Doppler effect that is a change in frequency of the sound waves that are reflected on a moving target. A common example is the change in pitch when a vehicle sounding a horn approaches and recedes from an observer. The frequency shift is in direct proportion of the relative velocity of the fluid with respect to the emitter-receiver and allows to infer the speed of the flowing fluid. Doppler flow meters offer many advantages over mechanical spinners such as the ability to measure without requiring calibration passes, the absence of mechanical moving parts, the sensors robustness to shocks and hits, easy installation and minimal affection by changes in temperature, density and viscosity of the fluid thus capability to work even in highly contaminated conditions such as tar, asphaltene deposits on equipment. Despite being widely used in surface flow metering, ultrasonic Doppler sensor applications to downhole environment have been so far very limited. We present in this work an innovative deep learning framework to estimate spinner phase velocities from Doppler based sensor velocities. Tests of the framework on a benchmark data set displayed strong estimation results, in particular outlining the ability to utilize Doppler-based sensors for downhole phase velocity measurements and allows the comparison of the estimates with previously recorded spinner velocity measurements. This allows for the real-time automated interpretative framework implementation and flow velocity estimations either in conventional wireline production logging technologies and potentially also in LWD conditions, when the well is flowing in underbalanced conditions.

The objective of this paper is to depict the quantification of the production rates of the different phases in deviated wells with high gas-liquid relation using the Flow Array Sensing Tool (FAST). The readings of standard Production Logging Tools (fullbore flowmeter, density, and capacitance) are centralized, therefore they are affected if there is re-circulation of the heavy phase (liquid). The phase segregation and possible apparent down flow of the heavy phase makes it very difficult to determine the distribution of the produced fluids, and in some cases the spinner flowmeter tends to stop or gives inaccurate readings. The cause of these inaccurate readings is that the centralized spinner is affected by positive flow in the high side and negative flow in the low side of the wellbore, and the spinner shows no flow or even apparent downhole flow, when there is a real positive flow. The FAST tool used during the acquisition of the production logs is an ultracompact production logging tool (3 ft long) that is capable to measure multiphase flows with an array of 8 sensors, two in each arm and located 90° apart. These sensors are based on MEMS (Microelectromechanichal Systems), and among the interchangeable sensors we have optical probes that takes ultra-rapid measurements of the refractive index and can determine hold-up of water, oil and gas; the electrical probes that measures conductivity to differentiate hydrocarbons from water, and magnetic probes with micro-spinners to determine the flow rate. Both the three phase optical probes and the electrical probes have excellent response including water hold-ups over 90% that cannot be measured with a standard capacitance tool. The data logged with FAST in deviated wells was processed and interpreted to obtain the apparent flow velocity profiles of each of the 4 micro-spinners and with the three phase optical probes, and the relative bearing curves the velocity maps, and hold-up maps where obtained. The velocity map showed that there was negative flow in the low side of the well and positive flow in the high side while the hold-up map showed the light phase (gas) in the high side of the well. Both maps showed clearly the flow pattern and were used to quantify the production of each perforation and the total rate matched closely the surface rate (within 2% deviation). With the hold-up and velocity maps, the real flow rates were obtained with high confidence, and the flow pattern were shown clearly in deviated wells. The three phase optical probes, and electrical probes are excellent indicators of water and hydrocarbons inflow in a wide range of hold-ups.

The well design with long lateral section and multistage frac completion has been proven effective for development of the unconventional reservoirs. Top-tier well production in unconventional reservoir can be achieved by optimizing hydraulic completion and stimulation design, which necessitates an understanding of flow behavior and hydrocarbon contribution allocation.  Historically, conventional production logging (PL) surveys were scarcely used in unconventional reservoirs due to limited and often expensive conveyance options, as well as complicated and non-unique inflow interpretations caused by intricate and changing multi-phase flow behavior (Prakash et al., 2008). The assessment of the cluster performance gradually shifted towards distributed acoustic (DAS) and temperature (DTS) sensing methods using fiber optics cable, which continuously gained popularity in the industry. Fiber optics measurements were anticipated to generate production profiles along the lateral with sub-cluster resolution to assist with optimal completions design selection. Encapsulation of the fiber in the carbon rod provided alternative conveyance method for retrievable DFO measurements, which gained popularity due to cost-efficiency and operational convenience (Gardner et al., 2015). Recent utilization of micro-sensor technology in PL tools, (Abbassi et al, 2018, Donovan et al, 2019) allowed dramatic reduction of the size and the weight of the PL toolstring without compromising wellbore coverage by sensor array. Such ultra-compact PL toolstring could utilize the carbon rod as a taxi and provide mutually beneficial and innovative surveillance combination to evaluate production profile in the unconventional reservoirs. Array holdup and velocity measurements across wellbore from PL would reveal more details regarding multi-phase flow behavior, which could be used for cross-validation and constraining of production inflow interpretation based on DFO measurements. This paper summarizes the lessons learned, key observations and best practices from the unique 4 well program, where such innovative combination was tested in gas rich Duvernay shale reservoir.