Liquid Unloading Research Articles

Feasibility of Using Polymers to Improve Foam Flow Performance in Vertical Pipes: Application to Liquid Unloading in Gas Wells

Foam unloading is a cost-effective technique for removing liquid from low-energy gas wells, but it faces challenges due to the instability of foam at the wellbore. Surfactants alone struggle to create and maintain durable foam films under wellbore conditions. Polymers are known to enhance foam stability by increasing lamella thickness and viscosity, but their impact on foam unloading has not been well explored. This study investigates the effects of Xanthan Gum (XG) and Polyvinylpyrrolidone (PVP) polymers on stability and unloading efficiency of the foams made by Alkyl Polyglycoside surfactant. The research evaluates foam stability and examines the bubble size and lamella thickness under varying salinity conditions. Additionally, the study evaluates foam unloading efficiency by determining unloaded mass rate, critical gas velocity and Weber number. Results show that polymer concentration, type and molecular weight significantly affect foam morphology and stability. Xanthan Gum at 1000 ppm demonstrated the smallest bubble size and greatest foam stability. This concentration also achieved the highest unloaded mass, 30% more than the surfactant-only case. Regarding the molecular weight of the polymers, HPVP demonstrated an ability to generate smaller bubbles in comparison with LPVP. Consequently, HPVP exhibited superior performance in liquid unloading, surpassing LPVP by a margin of 8.5%. The addition of polymers reduced critical gas velocity, with 1000 ppm of XG yielding the lowest value. Initially, the Weber numbers for polymer-stabilised foams were higher than the surfactant-only case (XG: 208.01, LPVP: 17.70, HPVP: 26.38 vs. APG: 2.25) due to the Marangoni effect but decreased during the unloading process (XG: 788.58, LPVP: 1850.26, HPVP: 1702.01 vs. base case: 4046.42), indicating improved stability and performance. Overall, the study demonstrates that polymers can significantly improve foam stability and performance, maintaining foam integrity throughout the unloading process if engineered properly prior to their application.

Experimental investigation of well deliquification using the partial tubing restrictions

Liquid loading is one of the main challenges in the later life of natural gas wells. Several methods have been tested to remedy this issue and unload gas wells, with various efficiencies. Preliminary studies on the impact of partial restrictions reveals that they improve liquid lifting by generating droplets and preventing the liquid film from falling back. These restrictions are commonly in shape of orifice rings or inserts. This study evaluates liquid unloading by employing such restrictions to improve liquid lifting. The restrictions can be incorporated into the tubing joint design, making them cheaper and easier to install compared to other techniques. Comprehensive experiments are conducted to understand the effect of inserts and liquid properties on two-phase flow behavior. The tests are performed in a 0.0508-m (2-inches) inner diameter vertical flow loop, using water or oil as the liquid phase and air as the gas phase. The tests are conducted with insert opening inner diameters of 0.0381 and 0.0445 m (1.5 and 1.75 inches.)The inserts cause significant mixing and generate high amplitude waves, which facilitate droplet generation. In churn flow with inserts, a thin liquid film is observed traveling downward, while liquid droplets travel upward. The results show that the inserts have the most positive effect at lower gas rates of churn flow and at lower liquid rates. Moreover, inserts provide the largest reduction in the liquid holdup for oil-air flow, due to lower density and surface tension compared to water. The results show that the inserts may enhance the liquid lifting by lowering the liquid holdup, while also increase the pressure drop by increasing the frictional losses. This indicates the need to choose the optimum insert diameter to minimize frictional losses and enhance liquid lifting.

Investigation of a highly efficient foaming mixture compromising cationic Gemini-zwitterionic-anionic surfactants for gas well deliquification

Abstract Foamers with high resistance to condensate, salinity and high temperature play a crucial role in gas well deliquification. In this study, we developed an efficient foaming mixture containing a Gemini surfactant (CAGB), a betaine surfactant (CAPB) and sodium lauroyl glutamate (SLG), which exhibited excellent foaming performance (at a molar ratio of 3:3:4 and a dosage of 20 mmol L−1) with a foam volume of 440 mL and a half-life of 11 min. The optimized CAGB/CAPB/SLG mixture showed exceptional liquid unloading and foaming ability under high methanol (up to 40 vol.%) and condensate (up to 50 vol.%) content conditions. Trisodium aminotriacetate (NTA) facilitated the liquid unloading performance at a salinity of 90 g L−1. With 10 vol.% methanol, the liquid unloading rate of CAGB/CAPB/SLG foam at 90 °C could be increased to 90 %. Furthermore, surface tension and morphology analysis confirmed the presence of synergy within the CAGB/CAPB/SLG mixture in foaming, foam stabilizing and liquid unloading ability.

Experimental studies and computational exploration on an exceptionally salt/condensate resistant gas well foaming mixture compromising amino-betaine-ammonium surfactants and dodecanol

Liquid accumulation in natural gas wells is typically addressed by foam-based deliquification. This study systematically investigated the development of a green and cost-effective foaming mixture comprising lauramidopropyl trimethylammonium chloride (LATC), lauramidopropyl betaine (LAPB), sodium lauroyl glutamate (SLG) and dodecanol (LA). Properly combined LATC/SLG/LAPB/LA mixture demonstrated synergistic effects in enhancing foam generation, foam stabilization and liquid unloading. Remarkably, the LATC/SLG/LAPB/LA foam exhibited exceptional performance in unloading liquid, even at a condensate fraction of up to 50 %. Adding a chelator (NTA) to LATC/SLG/LAPB/LA further improved the foaming efficiency and liquid unloading performance at salinity levels of up to 33 × 104 mg/L, which was likely the highest salt tolerance according to the available literature. The negative effect of temperature on the performance of LATC/SLG/LAPB/LA foam was resolved by adding 15 % methanol. At 90 °C, almost all the liquid can be removed from the column by the LATC/SLG/LAPB/LA foam, which produced a liquid unloading efficiency of 90 % and a foaming efficiency of 100 %. Surface tension, viscosity and morphological analysis supported the observed synergistic effects, while molecular dynamic simulations revealed the mechanisms of the excellent salt/condensate resistance of the LATC/SLG/LAPB/LA foam. These findings demonstrated the promising potential of the LATC/SLG/LAPB/LA foam in gas well deliquification.

Methane emission and influencing factors of China's oil and natural gas sector in 2020–2060: A source level analysis

The Chinese oil and gas industry requires targeted policies to reduce methane emissions. To achieve this goal, it is necessary to predict future methane emission trends and analyze the factors that influence them. However, changing economic development patterns, insufficient analysis of various factors influencing emissions, and inadequate resolution of methane emission inventories have made these goals difficult to achieve. Accordingly, this study aims to expand the methane emission estimation method to compile source-level emission inventories for future emissions, analyze the factors influencing them, and form a mechanistic understanding of the methane emissions from the local oil and gas industry. The research results indicate that methane emissions deriving from this industry will increase rapidly before 2030, after which they will decline slowly in all scenarios. The production and utilization processes in the natural gas supply chain, i.e., compressors and liquid unloading, include the main sources of methane emissions. Emissions are affected significantly by total production and consumption. Change in the overall supply and demand of natural gas affects change in methane emissions more significantly than adopting new technologies and strengthening facility maintenance, i.e., the overall supply and demand of natural gas are the dominant factors in controlling methane emissions. This study suggests that controlling the total demand for oil and gas should be at the core of the methane emission control policy for the local oil and gas industry. Moreover, equipment maintenance and emission reduction technologies should be used more effectively to reduce total emissions.

Experimental study of swirling flow pneumatic liquid-carrying characteristics in the vortex tool inserted tube under liquid loading conditions

Liquid unloading by vortex tool is one of the most important applications of swirling flow pneumatic conveying. However, due to swirl decay, the evolution of gas–liquid flow patterns and the dynamic characteristics of pressure drop downstream of the vortex tool are much more complex than those in non-swirling flow. In this study, the gas–liquid flow patterns and pressure drop inside the vortex tool inserted tube (ID = 60 mm) under liquid loading conditions were experimentally studied and compared with those of the plain tube. With the superficial gas velocities ranging from 0.5 to 6.0 m/s and superficial liquid velocities of 0.01, 0.02, and 0.04 m/s, the effects of the structural parameters and stages of vortex tools on the pressure drop were discussed. The experimental results reveal that three distinct swirling flow patterns can be identified downstream of the vortex tool, namely swirling gas column flow, swirling churn flow and swirling annular flow. The insertion of vortex tool facilitates an earlier transition of the churn flow to the annular flow, and the induced swirling flow can restrain the liquid from falling back. The helix angle of the corkscrew deflector has a more significant effect on the pressure drop than its length. By reducing the helix angle from 54° to 45°, the total pressure drop and downstream pressure gradient are significantly decreased, even lower than those of the plain tube. But the series combination of 54° and 45° vortex tools results in a significant increase in the downstream pressure gradient. Additionally, at low gas flow rate, negative frictional pressure drop occurs in both plain tube and vortex tool inserted tube. Hence, the new friction factor correlations were established respectively for the positive and negative friction regions in the cases of the tube with and without vortex tool, and most of the frictional pressure gradient predictions are within an error band less than 20%.

Foams stabilized with silica nanoparticles derived from sodium silicate for gas well liquid unloading

Foams stabilized with silica nanoparticles derived from sodium silicate for gas well liquid unloading

Mechanism of liquid unloading by single flowing plunger lift in gas wells

The plunger lift is one of the main methods to release liquid loading in gas wells. Due to the leakage in the process of moving for plunger, the efficiency of liquid unloading is decreased. In recent years, the single flowing plunger was invented and has been used in many gas fields. However, the mechanism of enhanced liquid unloading is still unclear. In this paper, a full-size visible plunger lift equipment was built to study the process of single flowing plunger lift (SFPL) and normal plunger lift (NPL). Moreover, a transient model was built to simulate SFPL and NPL in different situation. Results show that the SFPL can prevent the liquid from dropping, decrease the bottom-hole pressure, and enhance gas production. The SFPL performs well in a certain range, and the SFPL would be out of operation first. A plate has been built to help engineers optimize the SFPL. The paper helps clear the situation of SFPL and provides the theoretical basis for researchers.

A Methane Emission Estimation Tool (MEET) for predictions of emissions from upstream oil and gas well sites with fine scale temporal and spatial resolution: Model structure and applications

In comparing observation based methane emission estimates for oil and gas well sites to routine emissions reported in inventories, the time scale of the measurement should match the time scale over which the inventoried emissions are estimated. Since many measurements are of relatively short duration (seconds to hours), a tool is needed to estimate emissions over these time scales rather than the annual totals reported in most emission inventories. This work presents a tool for estimating routine emissions from oil and gas well sites at multiple time scales; emissions at well sites vary over time due to changes in oil and gas production rates, operating practices and operational modes at the sites. Distributions of routine emissions (expected and inventoried) from well sites are generally skewed, and the nature and degree to which the distributions are skewed depends on the time scales over which emissions are aggregated. Abnormal emissions can create additional skew in these distributions. At very short time scales (emissions aggregated over 1 min) case study distributions presented in this work are both skewed and bimodal, with the modes depending on whether liquid storage tanks are flashing at the time of the measurement and whether abnormal emissions are occurring. At longer time scales (emissions aggregated over 1 day) distributions of routine emissions simulated in this work can have multiple modes if short duration, high emission rate events, such as liquid unloadings or large abnormal emissions, occur at the site. Multiple applications of the methane emission estimation tool (MEET), developed in this work, are presented. These results emphasize the importance of developing detailed emission inventories, which incorporate operational data, when comparing measurements to routine emissions. The model described in this work supports such comparisons and is freely available.

Development, Application and Effect Evaluation of the Remote-controlled Automated Needle Valve Intermittent Production System in the L Well Block in China

In order to solve the problem of liquid loading, some water-produced gas wells use intermittent production mode to produce: shut in gas wells to restore energy during the closing phase, and open up to carry the liquid to surface by the high velocity gas during well opening phase, which is cost effective. However, some wells need frequent opening and closing or adjusting gas flow, manual opening and closing is easily influenced by external interference factors (road conditions, weather, public relation issue, etc.), and cannot guarantee production time for intermittent producing well. In order to realize the remote-control and automation for these wells, the remote-control automated needle valve intermittent production system was developed and successfully applied to the L well block. The gas rate, production time and economy before and after the smart needle valve installed was compared to do the performance assessment. The results show that: (1) the stability of the remote-control automated needle valve intermittent production system is good, and it can meet the requirments of the remote automated opening and closing of gas wells. (2) After the installation of the remote-controlled automated needle valve system, 71% of the gas wells have a stable gas increase, 100% of the gas wells have a higher well opening time, and the liquid unloading in the gas wells has been significantly improved. The average gas production increased from 1.75×10⁴ m³/d to 1.87×10⁴ m³/d, which was 6.86% higher than that before installation. The well opening time of 7 wells increased by 5.16% on average. (3) Compared with manual operation, the comprehensive economic performance of the remote-controlled automated needle valve opening system is more excellent. The remote-controlled automated needle valve opening system can remotely intelligently control the intermittent production of gas wells, which has significant economic benefits and high application value and worth further spreading.

A simple analytical model to predict liquid unloading in the horizontal gas well

A simple analytical model to predict liquid unloading in the horizontal gas well

A new transient model to simulate and optimize liquid unloading with coiled tubing conveyed gas lift

Nowadays, unloading gas wells with coiled tubing is a common application to the field. However, it still lacks of adequate understanding of dynamic behavior of the unloading process. This paper investigates the process of liquid unloading by gas lift with coiled tubing under transient conditions. This unloading process can be divided into three stages: liquid rising in tubing, liquid slug production, and liquid production by entrainment. In each stage, the mass and conversation equations are applied as governing equations. The components of each stage include coiled tubing, coiled tubing-tubing annulus, liquid slug, gas bubble, and liquid film. Empirical correlations have been used for surface gas injection choke, check valve, friction factor, the relationship between the gas bubble and the liquid slug velocity, inflow performance relationship, and black oil fluid properties. From the above, the dynamic model coupling real-time change of inflow performance relationship is developed. The lower upper (LU) factorization and Euler's method are applied to solve the proposed dynamic model in time domain. Among all these variables, the most important ones include gas injection rates, pressures at various locations, length of the liquid slug and gas bubble, and phase velocities. Through the simulation efforts, the mechanism of liquid unloading process is revealed.Gas lift is commonly constrained by gas availability. This is a pioneering study on liquid unloading with coiled tubing. The results can be applied to design coiled tubing gas lift to optimize the usage of injected gas, choose appropriate pump, and save the energy consumed in gas lift operation.

An experimental study of liquid unloading in the curve section of horizontal gas wells

Liquid unloading is a very common and important issue in horizontal gas wells, and the presence of curve sections increases the complexity of the phenomenon and its study. Liquid loading in a gas well will sharply reduce production, therefore, the liquid-unloading onset of different curved pipes is essential to gas production. In this work, liquid-unloading onset experiments were conducted in curved pipes with different curvatures. Then, the critical gas velocityVsgCRcan be determined according to the measured pressure gradients, liquid holdup, and liquid film reversal. This work analyzes the factors which will lead to the liquid unloading and explores the trend of the pipe curvature’s influence on the liquid unloading under laboratory conditions. The experimental results show that the critical gas velocity rises with the increase of pipe curvature, the increase is mainly due to the centrifugal force. The present work also compares the predicted results of the OLGA model and Beggs–Brill model with experimental data. The comparison results indicate that both models fit relatively well to the experimental data at the low superficial gas velocity, and both models have poor performance at high superficial gas velocity. The OLGA model fits the experimental data better than the Beggs–Brill model at high superficial gas velocity. The error analysis shows that most of the predicted data is not in good agreement with experimental data. Some errors between experimental data and calculation results are out of the range of 50%.

Projecting the Temporal Evolution of Methane Emissions from Oil and Gas Production Sites

Many recent studies have reported methane emissions from oil and gas production regions, often reporting results as a methane emission intensity (methane emitted as a percentage of natural gas produced or methane produced). Almost all of these studies have been instantaneous snapshots of methane emissions; however, total methane emissions from a production site and the methane emission intensity would be expected to evolve over time. A detailed site-level methane emission estimation model is used to estimate the temporal evolution of methane emissions and the methane emission intensity for a variety of well configurations with and without emission mitigation measures in place. The general pattern predicted is that total emissions decrease over time as production declines. Methane emission intensity shows complex behavior because production-dependent emissions decline at different rates and some emissions do not decline over time. Prototypical uncontrolled wet gas wells can have approximately half of their emissions over a 10 year period occur in the first year; instantaneous wellsite methane emission intensities range over a factor of 3 (0.62-2.00%) in the same period, with a 10 year production weighted-average lifecycle methane emission intensity of 0.79%. Including emission control in the form of a flare can decrease the average lifecycle methane emission intensity to 0.23%. Emissions from liquid unloadings, which are observed in subsets of wells, can increase the lifecycle methane emission intensity by up to a factor of 2-3, between 1.2 and 2.3%, depending on the characteristics of the unloadings. Emissions from well completion flowbacks raise the average lifecycle methane emission intensity from 0.79 to 0.81% for flowbacks with emission controls; for flowbacks with uncontrolled emissions, lifecycle methane emissions increase to 1.26%. Dry gas and oil wells show qualitatively similar temporal behavior but different absolute emission rates.

Subsurface Compression Lifts Liquids, Increases Gas Production in Unconventional Well Trial

It is well known that liquid loading in unconventional gas wells can dramatically reduce production and lead to premature abandonment. Liquid loading creates a “vicious cycle” that occurs when liquid blockage creates backpressure in the wellbore or pore space in the formation, resulting in reduced gas velocity and leading to more liquid accumulation over time. Electrical submersible pumps (ESPs) and other artificial lift technologies are typically unable to remove liquids in both the vertical and horizontal sections of the well. A new downhole compressor solution, based on advanced magnetic technologies, was developed by Upwing Energy and recently completed its first field trials in an unconventional gas well operated by Riverside Petroleum. Analysis of results during the trial revealed a 62% increase in gas production and significant increase in liquid production over its steady­state performance using a rod pump prior to the subsurface compressor system (SCS) installation. Subsurface Compressor System The SCS is designed to provide reliable performance in the downhole environment by eliminating the common points of failure in conventional ESPs. It is based on proven magnetic technologies used in topside and subsea oil and gas applications (Fig. 1), which were deployed downhole successfully for the first time during the Riverside trial, including: A high­speed permanent magnet (PM) motor A shaftless magnetic coupling between the motor and compressor Passive noncontact magnetic bearings with electronic dampers A sensorless wide­frequency variable speed drive at the surface controls the motor at speeds up to 50,000 rpm via a long stepout. The hybrid axial wet­gas compressor is driven by the hermetically sealed high­speed PM motor. Torque is conveyed from the motor to the compressor with no mechanical shaft or seals, eliminating the need for a motor protector to isolate the motor from downhole fluids. This “protector­less” architecture eliminates a frequent source of vulnerability for conventional downhole artificial lift systems. The SCS lowers the bottomhole well pressure, increasing the velocity of the gas stream, removing liquids from the vertical and horizontal sections of the well, and preventing vapor condensation by increasing the temperature of the gas when exiting the compressor. Decreased backpressure from liquid loading results in increased gas production, which in turn accelerates liquid unloading. Once the liquid is carried by the gas stream, the lower pressure at the compressor intake and the higher temperature at the compressor discharge prevents vapor condensation and enhances the carryover of liquids to the surface by the gas stream. Field Trial The SCS was deployed in an unconventional shale gas well owned by Riverside Petroleum in Indiana. The trial period started at the end of October 2019, and the SCS was removed in early December. The well has a 2,000-ft vertical wellbore and a 5,000-ft horizontal wellbore, where liquid had accumulated (Fig. 2). The compressor was installed at the bottom of the vertical section with a tail pipe extending approximately 1,000 ft into the horizontal section to provide sufficient velocity to carry liquids while minimizing friction losses. A shroud was used to be able to carry the extended length of the tail pipe.

Transient Plunger-Lift Model Improves Prediction of Liquid Unloading From Gas Wells

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 19211, “A Transient Plunger-Lift Model for Liquid Unloading From Gas Wells,” by Jianjun Zhu, SPE, Haiwen Zhu, and Qingqi Zhao, The University of Tulsa, et al., prepared for the 2019 International Petroleum Technology Conference, Beijing, 26–28 March. The paper has not been peer reviewed. Copyright 2019 International Petroleum Technology Conference. Reproduced by permission. Natural-gas wells suffer from liquid loading if the gas-flow rate is insufficient to carry liquids to the surface. Because of the technique’s many advantages, plunger lift has been used widely in gas wells for the removal of liquid columns and the rescue of dying gas wells from liquid loading. Existing plunger-lift models in the literature are imperfect either because of limited field applications or oversimplified assumptions. Several components in the cyclic movement of a plunger can be identified, with each comprising a set of specific governing equations. In this paper, a new model is described that considers the gas flow with the plunger moving in the tubing, and accounts for instant velocities during plunger rise and fall. Introduction A typical plunger-lift system mainly comprises a piston or plunger, a surface control valve (SCV), a catcher, a lubricator or shock spring, a bumper spring, and a plunger sensor. In addition, casing and tubing serve as key components during the plunger-lifting process. Existing plunger-lift models can be categorized broadly into static and dynamic models. Although many dynamic plunger-lift models have been studied in the literature, a universally validated model with thorough understanding of the transient behaviors of gas and liquid still is unavailable. Because of incomplete consideration of plunger dynamics or over-simplified assumptions, most existing models suffer from questionable applicability. This problem can be remedied by incorporating or proposing in-depth closure relationships and performing para-metric studies to find the most-suitable one. In this study, based on previous modeling frameworks, a new transient plunger-lift model for liquid unloading in gas wells is presented. Compared with previous models, improvements have been made in the equations of plunger rising and falling velocities. The present model also accounts for different reservoir performances, which provides more-accurate and -reasonable predictions of these velocities. Model Development The plunger-lift model can be divided into six components: plunger up-stroke, gas blowout, plunger fall, pressure buildup, gas flows above and below the plunger, and reservoir performance. Reservoir performance is a component included in all stages of the plunger-lift processes. In the energy-buildup stage, reservoir performance contributes to restoring energy below the plunger. Basic mass and momentum-conservation equations are used to derive the plunger-lift simulation model. Model descriptions, assumptions, and related equations are discussed in detail in the complete paper. Results and Discussions The calculated results from the proposed plunger-lift model are presented and discussed in the complete paper, which also presents the input parameters used in the model.

Characterizing Regional Methane Emissions from Natural Gas Liquid Unloading.

A "bottom-up" probabilistic model was developed using engineering first-principles to quantify annualized throughput normalized methane emissions (TNME) from natural gas liquid unloading activities for 18 basins in the United States in 2016. For each basin, six discrete liquid-unloading scenarios are considered, consisting of combinations of well types (conventional and unconventional) and liquid-unloading systems (nonplunger, manual plunger lift, and automatic plunger lift). Analysis reveals that methane emissions from liquids unloading are highly variable, with mean TNMEs ranging from 0.0093% to 0.38% across basins. Automatic plunger-lift systems are found to have significantly higher per-well methane emissions rates relative to manual plunger-lift or non-plunger systems and on average constitute 28% of annual methane emissions from liquids unloading over all basins despite representing only ∼0.43% of total natural gas well count. While previous work has advocated that operational malfunctions and abnormal process conditions explain the existence of super-emitters in the natural gas supply chain, this work finds that super-emitters can arise naturally due to variability in underlying component processes. Additionally, average cumulative methane emissions from liquids unloading, attributed to the natural gas supply chain, across all basins are ∼4.8 times higher than those inferred from the 2016 Greenhouse Gas Reporting Program (GHGRP). Our new model highlights the importance of technological disaggregation, uncertainty quantification, and regionalization in estimating episodic methane emissions from liquids unloading. These insights can help reconcile discrepancies between "top-down" (regional or atmospheric studies) and "bottom-up" (component or facility-level) studies.

Study on the gas–liquid annular vortex flow for liquid unloading of gas well

Vortex tool is a new technique for the liquid unloading in gas wells. But it lacks a mathematical model to describe and predict the effect of vortex tools. In the present work, according to the axial, radial and circumferential momentum balance of the gas phase and liquid phase, the governing equations of vortex flow model have been established. Then thickness of liquid film and gas and liquid vortex flow intensity as well as the pressure drop gradient can be calculated. The calculation results and the previous experiments indicate that the pressure drop of the gas–liquid flow can be reduced by 5% ~ 25% with the vortex tool, and the vortex flow model has an average relative difference of 6.01%. The model results show that there are two mechanisms for reducing the pressure drop under the vortex flow condition. In addition, the research results show that vortex tools with bigger helical angle will lead to higher vortex flow intensity. The decay rate of vortex flow intensity decreases along the pipe as liquid velocity increases and the vortex flow working distance can be calculated by the vortex intensity gradient and initial vortex flow intensity.

Temporal variability largely explains top-down/bottom-up difference in methane emission estimates from a natural gas production region

This study spatially and temporally aligns top-down and bottom-up methane emission estimates for a natural gas production basin, using multiscale emission measurements and detailed activity data reporting. We show that episodic venting from manual liquid unloadings, which occur at a small fraction of natural gas well pads, drives a factor-of-two temporal variation in the basin-scale emission rate of a US dry shale gas play. The midafternoon peak emission rate aligns with the sampling time of all regional aircraft emission studies, which target well-mixed boundary layer conditions present in the afternoon. A mechanistic understanding of emission estimates derived from various methods is critical for unbiased emission verification and effective greenhouse gas emission mitigation. Our results demonstrate that direct comparison of emission estimates from methods covering widely different timescales can be misleading.

A Novel Intermittent Gas Lifting and Monitoring System Toward Liquid Unloading for Deviated Wells in Mature Gas Field

For liquid-loading gas wells, effective deliquification operation is needed but current liquid-lifting technology is not able to meet the requirements of high efficiency as well as low cost especially in large-deviated wells. This paper proposes a hybrid deliquification technology combining plunger lift, chemical foamer injection, and down-hole monitoring to unload liquid in deviated gas wells. The system comprised multipart plunger body, deployment-retrieving integrating assembly (DRIA) and operation canisters. By means of flexible plunger body, the system performs deliquification normally in deviated wellbore. The operation canisters are carried with plunger body through tubing onto the bottom of deviated section to operate in terms of four modes: long-term down-hole monitoring, foamer injection, mobile data acquisition, and wireless data exchange with the wellhead. The key components of DRIA and injection valve are made of improved disintegrating alloy with the rating temperature of 100 °C, compressive strength of 370 MPa, and disintegrating rate of 170.9 mg/(cm2 h) characterized by lab test. Field trials were successfully performed in two liquid-loading tight gas wells, and the maximal deviated angle of the wells was 68 deg. It indicates that the new technology is a cost-effective way contributing to automatic production and management of mature gas wells in the remote area instead of traditional rigid plunger and wire-line logging.