The Effect of Water Cut on the Producing Trends and Downhole Multiphase Flow Conditions in Oil-Rich Shale Plays
Abstract: The continually evolving water management practices of liquids-rich tight oil operators (for optimizing the water use and costs of their water life cycle) is a topic of major impact. One area during the produced water phase of the water life cycle, is the less understood effect of different water cut fractions of the total fluids production from the formation on both the producing three-phase flow rate trends on surface as well as the downhole multiphase flow conditions, in particular, lateral to bend slugging… Show more
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Cited by 2 publications
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Liquids Level Calculation in Loaded Gas Wells from Surface Data Using Combined Analytical Modeling of Gaseous Static Liquids Gradient: Part 2
As the second part of this series, we apply our much improved understanding of gas flow through static recirculating liquid columns and analytical countercurrent multiphase flow modeling to both conventional and unconventional horizontal gas well liquids loading and a deep dive of the process of wellbore liquids flow reversal post-loading. This part of our work focuses on a step change in understanding the aspect of multiphase flow that is most pertinent to artificial lift - countercurrent liquids loading and gas flow through liquid columns. It is shown that traditional concurrent flow principles and flow pattern maps used in prior commonly used flowing bottom hole pressure correlations do not apply and cannot explain the changing dual pressure gradient profiles in loaded gas wells as a result of flow reversal. Therefore, this work lays the foundation for a change in conversation and focus among the artificial lift community towards countercurrent and static liquid column multiphase flow behaviors prevalent in all liquids-producing gas wells. We show and field-validate a new computational ability to perform multiphase countercurrent liquids loading calculations that dynamically loads a gas well tubing/casing and the calculations of total pressure gradient that varies with the increasing gas holdup along the static liquid columns of these wells. Additionally, we analyze the process of countercurrent flow and put forward a redefinition of onset of liquids flow reversal in the proper context of prior studies in this field. Our results are used to simulate the liquid levels in loaded gas wells from only basic surface field data. This represents an advance towards low-cost, low-carbon gas well production optimization and the opportunity of simulation-based real-time downhole diagnostics to determine digital liquid levels and reliably accurate FBHP in loaded gas wells without the high-carbon costs of wellsite visits and equipment runs. In terms of reliable digital twin applications for gas wells producing liquids, our new method can be performed in an autonomous way on a wellhead - a sort of "gas well liquid level digital sensor" - a solution that takes advantage of available SCADA surface data and converts it to automated calculations of downhole pressures, flow rates and well liquid levels in response to dynamic well operating conditions. For the first time in the industry, we present in this work a simultaneous calculation of loaded gas well FBHP and gaseous liquids level from only surface data. In either cases of liquids loaded gas wells or pumping oil wells with gaseous liquid columns above them, the significant pressure gradient (delta-P) that gaseous liquid columns impose on the formation is of great importance in correctly understanding and analyzing well supply capacity and enhancing downhole production rates during production operations.
Liquids Level Calculation in Loaded Gas Wells from Surface Data Using Combined Analytical Modeling of Gaseous Static Liquids Gradient: Part 2
As the second part of this series, we apply our much improved understanding of gas flow through static recirculating liquid columns and analytical countercurrent multiphase flow modeling to both conventional and unconventional horizontal gas well liquids loading and a deep dive of the process of wellbore liquids flow reversal post-loading. This part of our work focuses on a step change in understanding the aspect of multiphase flow that is most pertinent to artificial lift - countercurrent liquids loading and gas flow through liquid columns. It is shown that traditional concurrent flow principles and flow pattern maps used in prior commonly used flowing bottom hole pressure correlations do not apply and cannot explain the changing dual pressure gradient profiles in loaded gas wells as a result of flow reversal. Therefore, this work lays the foundation for a change in conversation and focus among the artificial lift community towards countercurrent and static liquid column multiphase flow behaviors prevalent in all liquids-producing gas wells. We show and field-validate a new computational ability to perform multiphase countercurrent liquids loading calculations that dynamically loads a gas well tubing/casing and the calculations of total pressure gradient that varies with the increasing gas holdup along the static liquid columns of these wells. Additionally, we analyze the process of countercurrent flow and put forward a redefinition of onset of liquids flow reversal in the proper context of prior studies in this field. Our results are used to simulate the liquid levels in loaded gas wells from only basic surface field data. This represents an advance towards low-cost, low-carbon gas well production optimization and the opportunity of simulation-based real-time downhole diagnostics to determine digital liquid levels and reliably accurate FBHP in loaded gas wells without the high-carbon costs of wellsite visits and equipment runs. In terms of reliable digital twin applications for gas wells producing liquids, our new method can be performed in an autonomous way on a wellhead - a sort of "gas well liquid level digital sensor" - a solution that takes advantage of available SCADA surface data and converts it to automated calculations of downhole pressures, flow rates and well liquid levels in response to dynamic well operating conditions. For the first time in the industry, we present in this work a simultaneous calculation of loaded gas well FBHP and gaseous liquids level from only surface data. In either cases of liquids loaded gas wells or pumping oil wells with gaseous liquid columns above them, the significant pressure gradient (delta-P) that gaseous liquid columns impose on the formation is of great importance in correctly understanding and analyzing well supply capacity and enhancing downhole production rates during production operations.
Accurate Gas-To-Pump Calculation in Pumping Oil Wells from Surface Data Using Combined Analytical Modeling of Gaseous Static Liquids Gradient: Part 1
Among the many available methods for determining pump intake pressure and flowing bottom hole pressure in pumping wells, there remains the practical need to both reduce the input field data modeling requirements (carbon and cost reduction) and to combine the different but related concurrent, countercurrent and column multiphase flow phenomena governing the calculation (accuracy improvement). This paper furnishes both lab- and field-validated analytical multiphase modeling methods showing the various ways the discovered triangular interrelationship between pump intake pressure, gaseous static liquid level and downhole gas separation efficiency changes in response to different sensitivities. The pressure distribution along the entire multiphase flow path of the pumping oil well, including between the pump intake pressure and flowing bottomhole pressure at reservoir depths, is also modeled in detail. A notable difference in this work in reference to prior works of pump intake pressure and gas-to-pump (i.e., gas holdup at pump intake region) modeling is a more detailed physics-based understanding of how gas holdup changes and develops along the gaseous static liquid column above the downhole packer-less pump. In this way, using an easy-to-compute, zero-cost, independently reproducible, published model for bubbly to churn flow in combination with a cutting edge commercial analytical multiphase flow simulator, we first validate the simulator results with published lab datasets of developing gas flow through static liquid columns under carefully controlled conditions. Then, several published field datasets of producing oil wells with liquid levels are simulated to confirm the extensibility of our model to actual field wells and currently-active production operations. In these field validations, the transient countercurrent liquids loading feature of the simulator is utilized to determine the prevailing liquid level. We then additionally perform several important sensitivities showing the various ways that pump intake pressure, flowing bottomhole pressure, gaseous static liquid level, and downhole gas separation efficiency changes in response to different hydraulic diameters, flowing areas, casing-annulus clearances (e.g., ESP versus rod pump), liquid column flow patterns, axial developing flow lengths, and wellbore inclination. Regarding our liquid level buildup simulations, we demonstrate the effect that liquid levels have on dictating the possible operating limits on highest and lowest downhole gas separation efficiencies. This work represents a step change in our understanding of the aspect of multiphase flows that is most pertinent to artificial lift: accurate critical gas velocity prediction leading to reliable modeling of countercurrent multiphase liquid loading and gas flow along static liquid columns. We lay the foundation for a change in conversation among the artificial lift community for paying much more practical attention as well as research interest into the multiphase countercurrent and gaseous static liquid column flow behaviors prevalent in the majority pumping oil wells and liquids loaded gas wells. To this end, a new industry digital computing capability is presented and comprehensively validated in both this paper and the part-2 paper of this paper series (Nagoo et al., 2022a): the ability to perform multiphase countercurrent liquid loading simulations that dynamically loads a pumping oil well casing-annulus or gas well tubing/casing, and the reliable calculations of the total pressure gradient that varies with the increasing gas holdup along the static liquid column of these wells. This means that for pumping oil wells (SRP, ESP, PCP, etc.), the pump intake pressure, flowing bottomhole pressure at reservoir depths, downhole gas separation efficiency and static gaseous liquid level above the pump can now be simultaneously simulated from only basic surface field data. For the part-2 paper, our new method is used to calculate the static gaseous liquid levels in liquid loaded gas wells from only basic surface field data. In terms of digital twin applications for the oilfield, our new methods can be performed in real-time in an autonomous way on an IIOT-enabled (IIOT = industrial internet of things) wellhead device to continuously optimize production to create value at scale. We term this device a "wellbore liquid level digital sensor": a solution that takes in real-time SCADA (supervisory control and data acquisition) surface data and converts it to automated calculations of pump intake pressure, flowing bottomhole pressure, downhole gas separation efficiency, gaseous static liquid column height and gas holdup profile along the static liquid column. This is an industry-first, at-scale, digital oilfield solution purpose built for low-carbon downhole diagnostics and real-time autonomous production optimization calculations. Such calculations are used to drive the real-time production operations decisions needed for minimizing lifting costs and minimizing unplanned shut-downs and pump/equipment failures. Indeed, a net-zero future for the oil and gas industry on a whole relies on the digital innovations like those provided in this large body of work to empower energy transformation, and to manage/harness the immense amount of asset data in ways that was not possible before. Incorporating novel digital solutions in day-to-day oil and gas production operations will improve engineer productivity (higher value creation) as well as corporate profitability (safer, lower-carbon operations) by streamlining downhole calculations, analyses, operational performance indicators, and cutting costs for better decision-making support.
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