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Measuring the flow of water, mud, and cuttings from a well is critical, and difficult. A new flowmeter design that promises to be both accurate and durable is one of three technologies featured in a JPT series on drilling measurement innovation. The complete paper discusses the advancements in mud-displacement simulation that overcome the limitations of the previous-generation simulator and provide a more-realistic simulation in highly deviated and horizontal wells.
Saudi Aramco studied such algorithms to produce images simulating the flow inside a pipe’s cross section, possibly reducing the need for separator-based multiphase flowmeters. A former technical manager with Petrobras discusses the development of the company’s flow assurance philosophies and strategies. Looped lines are used to reduce pressure drop and increase flow capacity, but information on the flow behavior or predictive methods are not available for these systems. Bypass pigging has advantages over conventional approaches. Its application to multi-phase flow with high wax content crude is discussed.
E&P operators are aggressively looking to increase production with operational efficiency gains. Proactive well and field production management requires digital enablement of operations, with no data silos and data flowing seamlessly from the subsurface to the hands of the operator. With huge amounts of data being collected, it is imperative to apply data-driven techniques to gain more insights that can be utilized to better manage production. A data-driven approach can provide huge benefits for organisations holding vast amount of reservoir, production, and facilities data. It could provide insights into non-linear multidimensional relationships between parameters so that the field development is better understood and optimized. It could allow companies using a proactive approach towards field operations and equipment maintenance resulting in additional cost savings.
This paper presents various case studies where operators improved operational efficiency and optimize production utilizing edge-driven Industrial Internet of Things (IIoT) solutions. These edge IIoT solutions enable fast-loop control through a combination of physics and data-driven workflows, which empowers the operator to proactively manage their assets and focus attention on potentially problematic wells. The solution's architectural setup and ability to deliver fast-loop control workflows at the edge enables operators to successfully detect and manage potential issues such as artificial lift pumps, ultimately improving the performance. Additionally, this approach reduces the dependency upon domain experts to frequently analyze data. The high-frequency data capturing resulted in predicting equipment performance with confidence and allowing remote well management to reduce health, safety and environment (HSE) risks while decreasing logistics and maintenance costs.
The litmus test for downhole multiphase flowmeters is to compare the measured phase flow rates with the test-separator rates. In most cases, the composition of the measurand is required for flowmeters and is typically obtained from bottomhole fluid samples. Extracting and analyzing fluid samples is an expensive process mostly done at the initial stages of field development. Because the composition is not always available and is usually old, flowmeters may have subpar performances when compared to test separators. In this work, it is shown that once the test-separator data are available, measuring mixture sound speed downhole will ensure the optimization of a multiphase flowmeter system without needing to obtain new fluid samples. This novel method is demonstrated in a North Sea case history.
This method of optimizing flow rates is independent of the measurement device because the required flow velocity and sound speed measurements could be obtained from separate and generic devices. For example, the fluid bulk velocity and mixture sound speed could be measured by a point measurement device and a distributed acoustic sensing (DAS) system, respectively. The main challenge in a flow-velocity/sound-speed measurement system is to determine individual phase sound speeds so that the mixture phase fraction could be correctly modeled using Wood's mixture sound speed model. The phase fraction from the separator tests could be used as the target value to optimize the performance of the system. This is done with a backward calculation of the sound speed of individual phases. Pressure and temperature variations at measurement locations as well as the pipe compliance effects are also accounted for in this approach. Following the adjustment of individual phase sound speeds, a forward calculation using the same model yields a phase fraction close to the actual value, which could be improved further by an iterative approach.
A downhole optical flowmeter in a North Sea field measured mixture velocity and sound speed. Well test results indicated that the water cut was underreported and phase flow rates did not match the test-separator rates. Instead of halting production and going through a fluid sample analysis cycle, the test-separator water cut was used as the target value to optimize oil phase sound speed using Wood's model with a backward calculation. The difference in oil sound speeds was extrapolated to other pressure and temperature conditions, and forward calculation showed that separator tests and flowmeter measurements closely matched. Subsequent flowmeter and test-separator data confirmed excellent agreement.
Using well test data and sound speed to optimize phase flow rates is a novel method that has not been previously demonstrated. This method is independent of device type, broadly applicable, and furthers the understanding of multiphase flow measurement.
Modern directional wellbore trajectories are more complex now with some wells having an undulating trajectory. When installing artificial lift devices such as an electric submersible pump (ESP), the pump must be submerged in the liquid phase of the hydrocarbon in order to avoid gas-lock issues, including in shut-in conditions. Incorrect placement of such device would require a very costly remedy. In an undulating trajectory well, it is possible that the fluid in the well is in the gas phase at some of the downhole upper elbow locations during shut-in. This paper presents a method to calculate the water/oil/gas settling interface during shut-in conditions for an undulating trajectory well.
In this method, the well is divided into multiple uphill and downhill sections. For each section, it is assumed that the GOR (Gas Oil Ratio) and WOR (Water Oil Ratio) are the same as the production GOR and WOR. The pressure at the elbow turning point of two uphill and downhill sections is assumed to be the same to ensure the pressure continuity. Then, by the given surface or bottom (reservoir) pressure, the gas/oil and oil/water interfaces are calculated with iterations with a numerical method to match the GOR and WOR considering the wellbore pressure and temperature effect for each section. Once all the sections are calculated, the final results are combined to achieve the global gas/oil and oil/water interfaces and the pressure and temperature profiles.
This method has been implemented in an advanced casing and tubing design application to calculate the well pressure and temperature profiles, and then these profile results are applied later for further stress analysis. A typical undulating well is presented for case study to explain the calculation steps and results. As expected, the gas/oil and oil/water interfaces are obtained where the water is settling at the lower elbow of the well, the gas phase is accumulated at the upper elbow of the well, and the oil phase stays in the middle between the gas and water. The pressure profile is achieved showing different pressure gradients of the gas/oil/water settling intervals and pressure is continuous along the whole well. The temperature profile is also obtained, showing different temperature behavior for gas, oil, and water intervals with different shut-in duration, which is useful for stress analysis in the string at different depths.
This paper fills a gap that has not yet been discussed in the industry literature. It is an important for field application, especially for choosing the artificial lift device installation depth. Further, the calculated pressure and temperature profiles are useful for casing and tubing design stress analysis purposes.
Barbariol, Tommaso (University of Padova) | Feltresi, Enrico (Pietro Fiorentini) | Susto, Gian Antonio (University of Padova) | Tescaro, Diego (Pietro Fiorentini) | Galvanin, Silvia (Pietro Fiorentini)
A Multi-Phase Flow Meter (MPFM) performs Water Liquid Ratio (WLR) estimations using a dedicated sensor relying on one physical principle (e.g. electrical impedance). The accuracy of the WLR sensor might also be dependent on the flow properties. An approach based on Machine Learning techniques and multi-sensors data fusion has been implemented to enhance the reliability and accuracy of the WLR estimations in Multi Phase application using onboard sensor measurements of a MPFM.
In order to improve the estimations of multi-phase applications, we exploit the availability of historical data collected with heterogeneous sensors; the underlying idea of the proposed approach is to exploit such data with Machine Learning supervised techniques to provide accurate measures. In this work we compare modern supervised learning approaches like Random Forest, Gradient Boosting techniques and Kernel methods. The proposed methods have a relatively simple form that can be deployed also in embedded applications.
In this work, we will show through extensive experiments that the proposed approach could improve the original estimations. The algorithms underlying the proposed approach have been trained using data collected at flow loops test facilities with different flow conditions. The best model has been chosen not only for its predictive performances, but also looking at the computational time needed to make a prediction and considering its robustness to outliers. As expected, depending on the dataset numerosity, the best performing model can change: we provide experimental results for various dataset sizes in order to help practitioners choose the best regression method depending on the available data numerosity. An additional considered aspect is the computational time of the various approaches, which may be a relevant characteristic to be evaluated before rolling out productive solutions.
To increase the accuracy of MPFM, a sensor fusion technique that benefits from the many measurements collected by the MPFM, has been developed. Many different models have been compared on: prediction performances, confidence interval, robustness to outliers, execution time. The resulting model provides enhanced estimations equipped with confidence intervals that can be used for prediction quality assessment and associated risk management.
Multiphase flow behavior in a wellbore is inherently coupled with a reservoir, which is controlled by pressure boundaries. Most of the previous experimental studies in the laboratory have been performed at constant liquid and gas mass flow rates boundary conditions. This study experimentally compares the gas-liquid flow behaviors between constant pressure and constant mass flow rates boundary conditions in a toe-down horizontal well and investigates the effect of constant pressure boundary on the system stability.
The experiments were conducted in a large-scale experimental facility to study the flow behavior in a toe-down horizontal well. They were performed at two different permeabilities for a constant pressure boundary (CPB) condition. Results were compared against experiments with constant mass boundary (CMB) conditions from different aspects, including outflow performance relationship (OPR), liquid holdup, and dynamic analysis. The experimental study on system stability was analyzed for three different operating conditions, namely, constant flow rate, constant gas liquid ratio (GLR), and constant liquid permeability. Similar tests were also studied using a numerical simulator.
The results show that the time-averaged OPR and liquid holdup from constant mass and constant pressure boundary conditions match well. However, the amplitude of pressure and flow rate fluctuations are different, which causes the instabilities on the left side of the minimum of the OPR for high gas permeability reservoir at CPB conditions, where production persists for the CMB. The amplitude of pressure and gas rate fluctuation depends on reservoir permeability. It is found that the multiphase flow behavior in the wellbore for a constant mass boundary is closer to that for low permeability reservoirs, which commonly occur in shale plays. The total liquid inventory decreases as superficial gas velocity increases, and the fluctuations in superficial gas velocity have no evident impact on its behavior. Both experiments and numerical simulations show that system instability also depends on reservoir permeability. Stable production still exists on the left of the minimum OPR if the permeability is sufficiently low.
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