Summary After gas wells are drilled and start producing, early production rates are high enough to carry any liquid produced to the surface. However, as the reservoir pressure declines, the gas-production rate also declines. Eventually, the gas well starts experiencing liquid loading. Liquid loading starts when the current gas rate is incapable of lifting the liquid up to the surface. The liquid can be either water produced from the formation or the condensate. Several correlations in the literature predict the onset of liquid loading. The most famous equation, the Turner et al. (1969) equation, has many limitations, including the inability to account for effects such as diameter of the pipe and inclination angle of well, and incorrect physical assumptions regarding the onset of liquid loading. Belfroid et al. (2008) modified the Turner et al. (1969) equation for inclined wells; however, their expression is also dependent on incorrect physical assumptions and does not account for the diameter of the pipe. Another method, proposed by Shu et al. (2014), uses the correct physical assumption of liquid loading, but is overly conservative. This paper discusses a new modification to the original method proposed by Barnea (1986), which overcomes many limitations of the previous models. The new method is dependent on an assumption that liquid loading initiates when the liquid film starts falling backward. The proposed method accounts for the effect of diameter and inclination angle of the gas well. The method predicts the onset of liquid loading for a wide range of inclination angles, from vertical well to nearly horizontal well. The application of the method has been verified by comparing the results with both laboratory and field data. The method is observed to be better at predicting the onset of liquid loading compared with the other existing models in the literature.

Many gas wells cease producing economically long before their reservoirs have depleted and artificial lift applications for removing liquids from gas wells around the world are becoming more and more important. Proper application of artificial lift technology to a loaded up gas well can be one of the most profitable ventures that a company undertakes in its overall investment opportunity portfolio. The dollars invested relative to the dollars returned, the rapid payout, and the generally low risk to reward nature of their spend is expected to continue to propel rapid expansion of Gas Well Deliquification Technologies into the fore seeable future. This presentation will illuminate the importance of gas well deliquification technologies for the future. It will cover the basic fundamentals of the gas well liquid loading phenomena and provide a brief introduction to the Turner and Coleman equations used for critical velocity calculations. With these basic concepts covered, the presentation will then present a brief overview of the four most commonly applied artificial lift techniques used for deliquifying a gas well; reciprocating rod lift, foamer injection, plunger lift and gas lift. In conclusion, a logical artificial lift application selection process for gas well deliquification called the "Unloading Selector" will be introduced.

The interest in and demand for natural gas has dramatically shifted the focus for many operators in the past few years. Plunger lift, which for many years was viewed as a last resort, and somewhat of a nuisance, has gained an all time high in popularity, and effectiveness and applicability. Most of the guesswork in evaluating candidates has been replaced with exotic programs that combine Nodal analysis with performance based calculations. In recent years both equipment and applications have improved, and the production range of plunger lift now includes many wells previously not possible to produce with plunger lift. Here we will examine the new technology utilized in tracking, evaluating, and troubleshooting plunger lift wells. Also several case studies on where previously difficult production is now commonplace, will be presented. Introduction For years plunger lift was viewed as more of an art than a science. Selection of appropriate well candidates was as much from a "feeling" about the well's suitability. Some basic rules of thumb were often used as basic criteria. This, coupled with field experience, was the determination used in well selection. Still today, by many, rules of thumb and field knowledge are frequently used in the selection process. There are however, more and more programs and technology being utilized in the selection process. Sophisticated programs that do complex nodal analysis have been used for years for many of the other types of artificial lift, such as gas lift. Until recently, such programs have been virtually ignored for the plunger lift process. As the popularity of plunger lift continues to grow, so does the utilization of technology. It is now much more of a common practice to combine a nodal analysis with a pressure analysis to make determinations. This type analysis not only gives the operator better tools to determine a well's suitability, but also can help decide the type operation, and assist in equipment selection. The range of wells that can be improved by utilization of plunger lift is much broader today than ever. On both ends of the production scale, plunger lift is now applied to improve production and operations. From high-speed plungers in high-rate wells, to multiple plungers in the same tubing string for marginal and difficult to produce wells, the application process continues to improve and expand along with the technology used in the process of selection. Applications The typical candidates for a plunger lift system are;Gas wells with liquid loading problemsHigh ratio oil wellsIntermittent gas lift wells with fallback problemsParaffin control In North America there are 10's of thousands of wells being produced by plunger lift, outside of North America, there are very few wells produced in this manner. The principal reason is the popularity and market for Natural Gas. As the gas markets have grown and developed in other parts of the world, the applicability of plunger lift has also grown. In the life of most gas wells, there comes the time when liquid loading will occur. It is at this time in the life of a well that plunger lift becomes appropriate. Gas wells and high ratio oil wells Today, plunger lift is installed much earlier in the life of the well than had been practiced in the past. Before, it wasn't until there were significant loading problems that plunger lift was considered. Now, as wells approach critical velocity, this technique is being effectively employed.

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.

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.