Deliquification techniques and prevention: A case study for the southern Pannonian basin

This paper describes how liquid loading in gas wells inhibited gas production in the Intermediate Shelf gas play in southwest Texas. Actual production in the Intermediate Shelf gas play in southwest Texas. Actual case histories are used to illustrate how to identify and remedy liquid loading in low-volume gas wells. Methods such as plunger lift, beam pump, small-ID tubing, foam injection, and flow controllers are discussed and illustrated. Introduction In the Intermediate Shelf area of southwest Texas, Amoco Production Co. drilled more than 200 gas wells from 1974 through 1976. The wells were drilled to develop Wolfcamp- and Canyon-age sands in Crockett, Schleicher, Sutton, and Edwards counties. The producing sands occur at depths ranging from 3,000 to more than 7,500 ft and are characterized by very low permeability. Many of the wells produce small volumes of water along with the gas. The majority of the wells produce at gas rates too low to unload continually even small water production rates. As a result, gas well productivity is restricted. This paper describes the results of efforts to define the liquid-loading problem and to develop corrective measures to maximize producing rates.Generally, field experience has confirmed that critical velocities occur near 1,000 ft/min as cited in the literature. Case histories will be presented to demonstrate minimum gas producing rates required to unload produced liquids at various tubing pressures. Field data and graphs of wellhead pressure pressures. Field data and graphs of wellhead pressure vs. critical gas rates will be presented for various tubing sizes, which will illustrate operating conditions where liquid loading can become a factor.To eliminate or minimize liquid loading, several methods have been used. Plunger lifts, small-ID tubing, and beam pumping equipment have been used extensively. Operating conditions where each was found to have application will be outlined along with documentation of results. Other methods of liquid unloading that have been attempted include soap injection, downhole flow controllers, and intermitting well flow. These results are presented.In gas reservoirs where a liquid phase is associated with a gas phase, the presence of the liquid phase can affect significantly a gas well's flowing characteristics. Liquid loading in gas wells occurs when formation water and/or condensate are not removed continuously from the wellbore. To initiate mist or drop flow in the wellbore, the gas phase must provide an adequate amount of transport energy for the continuous removal of liquids. Hydrostatic back-pressure exerted by even small accumulations of liquid in the wellbore can restrict gas well productivity severely. productivity severely. Five basic methods were implemented to remedy liquid loading in the Intermediate Shelf gas play (Fig. 1): pumping units, plunger lifts, small-ID tubing, soap injection, and flow controllers. This paper presents several case histories and discusses the presents several case histories and discusses the various means used to identify and remedy liquid loading on gas wells in the play.At the time of this study, Amoco's portion of the Intermediate Shelf gas play consisted of 137 producing wells located near Sonora, TX, in the producing wells located near Sonora, TX, in the southeastern portion of the Permian basin. JPT P. 685

As the search for natural gas becomes increasingly high due to its high demand worldwide, the oil and gas industry is faced with the challenge of liquid loading in gas or condensate wells. It is imperative to properly design and predict the operational parameters necessary for handling flow assurance challenges due to simultaneous flow of gas with liquid. The model of Guo et al is the most recent systematic approach for predicting liquid loading in gas well. However, it did not account for the accumulation and kinetic terms in the momentum energy equation used to estimate bottom-hole pressure in a gas/oil/water/solid four phase flowing well. The two neglected terms in Guo et al formulation have significant effects on the gas well operational parameters such as the minimum gas flow rate for preventing liquid loading. This paper presents an improved model that describes a systematic approach for estimating liquid loading in a gas well without neglecting any term in the fundamental momentum equation. The results obtained showed that at the early production time where initial transience at the onset of flow is experienced, the critical gas flow rate obtained from the new model is lower than that predicted from Guo et al model due to inclusion of accumulation term while at the later production time, the critical gas flow rate obtained becomes higher than that predicted from Guo et al model and increases as the transient period elapses. Results further show that at some point during production, the minimum energy required to lift liquids out of the wellbore is more than that required at the earlier stage of production. The new model is reasonable, reliable and better when compare with Turner et al and Guo et al models. It is useful for operators to refine their procedures and better manage the risk of liquid loading during natural gas production.

The Changbei gas field, which initially exhibited high gas-production performance, is dominated by large-displacement horizontal wells. With the decrease in reservoir pressure, the liquid loading in the gas well is currently severe, and production has been rapidly decreasing. Thus, recognizing the gas-well liquid loading to maintain stable gas-well production is necessary. A method was established to identify the water source of the liquid loading in the Changbei gas field. First, formation water and condensate water were identified based on the mineralization of the recovered water and the mass concentration of Cl− and K+ + Na+, and then the condensate content of the water produced in the gas well was qualitatively evaluated. The water–gas ratio curve for the gas well was plotted to determine whether the produced water was edge-bottom water, pore water, or condensate. Then a method was established to distinguish the start time of liquid loading in the gas well using a curve depicting a decrease in production; the method was also used to estimate the depth of the gas well where liquid loading occurs, according to the bottomhole pressure. First, based on the available production data, the Arps decline model was applied to fit the production curve for the entire production phase; the resulting curve was compared with the actual production curve of the gas well, and the two curves diverged when fluid accumulation began in the gas well. Finally, the liquid-loading depth of the gas well was estimated based on the bottomhole pressure. This method can be used to determine the fluid accumulation and calculate the liquid-loading depth of gas wells with unconnected oil jackets. The analysis revealed that in the Changbei gas field, condensate was the type of water primarily produced in 35 gas wells, accounting for 62.5% of the total number of gas wells. Edge-bottom water was the type of water primarily produced in 16 gas wells, accounting for 28.6% of the total number of gas wells. In the remainder of the gas wells, pore water was the water primarily produced; the calculations of accumulation time and accumulation volume of typical gas wells in the block revealed that some gas wells started to accumulate liquid after 45–50 months, and the amount of accumulation could reach several tens of meters, while others were in good production condition. The method established in this paper could enhance our understanding of liquid loading in gas wells in the Changbei gas field and lay a foundation for the development of gas-well deliquification techniques.

The ability to predict liquid loading in horizontal gas wells is of great importance for determining the time of drainage and optimizing the related production technology. In the present work, we describe the outcomes of experiments conducted using air-water mixtures in a horizontal well. The results show that the configuration with an inclined section is the most susceptible to liquid loading. Laboratory experiments in an inclined pipe were also conducted to analyze the variation of the critical gas flow rate under different angles, pressure and liquid volume (taking the equal liquid volume at inlet and outlet as the criterion for judging on the critical state). According to these results, the related angle of the inclined section ranges from 45° to 60°. Finally, a modified approach based on the Belfroid model has been used to predict the critical gas flow rate for the inclined section. After comparison with field data, this modified model shows an accuracy of 96%, indicating that it has better performances with respect to other models used in the past to predict liquid loading.

The Changbei gas field is dominated by wells with large horizontal displacement, which have exhibited high gas production performance at an early stage of development. With the decrease in reservoir pressure, the liquid loading in the gas well is relatively high and gas production rapidly decreases. Therefore, suitable drainage measures are required to maintain stable gas production. Based on the characteristics of the unconnected oil jacket of gas wells in Changbei, a velocity string was used for drainage. A critical liquid-carrying model was established to determine the location of liquid loading in horizontal gas wells in Changbei. First, the coefficients of the liquid-carrying model were determined through theoretical analysis of the characteristics of the gas well formation. Then, the depth setting of the velocity string was analyzed. The critical liquid-carrying model was employed to calculate the liquid-carrying flow rate of each section; the calculated flow rates were compared with the actual flow rates to determine whether fluid accumulation occurred in each section of the gas well. Thereafter, with the help of the oil and casing position, the suitable setting position of the velocity string was determined. The formation fluid was driven from the tubing into the casing owing to the increase in the overflow area, based on the principle of reducer fluid mechanics. The fluid velocity in the larger overflow cross-section decreased, thereby reducing the drainage capacity of the gas well and resulting in liquid loading. Finally, a timing analysis was performed. After the formation pressure decreased, the well production and flow rate changes were analyzed by placing two velocity strings of different sizes at different wellhead pressures in the gas well with fluid accumulation. The results indicated that although the velocity string was set at a position suitable for fluid drainage, fluid accumulation still occurred after a production period, thus necessitating replacement deliquification.

Abnormal liquid loading in gas wells of the Samandepe Gasfield in Turkmenistan and countermeasures

Experimental study on the effect of liquid properties on fluid behavior and liquid loading in vertical natural gas wells

A simplified model to predict transient liquid loading in gas wells

Liquid loading is an undesired phenomenon in gas wells that occurs when producing wells attain a flow rate below which liquid will not be able to flow to the surface. The inability of the energy from the gas to transport the liquid to the surface causes back flow and eventual accumulation of liquid at the wellbore. This is characterised by intermittent flow, which, if left unchecked, can eventually kill the well. An effective and reliable predictive method must therefore, be employed. In this study, improved models based on data set from condensate/water in a gas well were developed by applying firefly (FA) and particle swarm optimisation (PSO) algorithms. The results showed that the model developed out perform many of the existing models. The models predicted liquid loading in gas well at 86% level of accuracy compared to the 81% highest possible from published models. Although, the FA and PSO models predicted liquid loading at higher accuracy compared with Turner and Coleman models for higher wellhead pressure systems, the Coleman model appeared to perform better in the prediction of critical gas rate for low-pressure systems. However, the developed model can significantly improve the prediction of liquid loading in gas wells at a higher reliability and accuracy levels. Thus, the proposed models can be a veritable tool for accurately predicting liquid loading in gas wells.

Summary The critical gas velocity and flow rate for unloading liquids from a gas well has been the subject of much interest, especially in old gas-producing fields with declining reservoir pressures. For low-pressure gas wells, Turner's model (also called Coleman's model) is judged as more suitable for predicting liquid loading in gas wells. However, field practice proves that there are still a number of low-pressure gas wells producing without loadup when the production rate is lower than Turner's minimum production rate. On the basis of experimental results, a new approach for calculating the critical gas-flow rate is introduced in this paper, which adopts Li's basic concepts, while taking into account the impact of the changes of gas-lifting efficiency caused by the rollover of droplets in the process of rising. A dimensionless parameter, loss factor S, is introduced in the new model to characterize the extent of the loss of gas energy. Well data from Coleman's paper (Coleman et al. 1991) were used in this paper for validation of the new model. The predicted results from the new model are better than those from Li's model, and even better than Turner's model. The new model is simple and can be evaluated at the wellhead when the pressure is less than 500 psia and the liquid/gas ratios range from 1 to 130 bbl/MMscf, which is suggested by Turner et al. (1969) to ensure a mist flow in gas wells.

Summary Existing models to predict and analyze liquid loading in gas wells are based on steady-state flow. Even when transient-multiphase- wellbore models are employed, steady-state or pseudosteady-state inflow-performance relationships are used to characterize the reservoir. A more-reliable approach consists of modeling the dynamics in the near-wellbore region with its transient boundary conditions for the wellbore. The development of new models to mimic the dynamic interaction between reservoir and wellbore requires a purpose-built flow loop. We have developed a design to construct such a facility. This new facility will be the first to integrate pipe representing the wellbore with a porous medium that will fully mimic the formation surrounding the wellbore. This design will account not only for flow into the wellbore, but also for any reverse flow from the pipe into the medium. We used integrated wellbore/reservoir system analysis to screen the parameters required to recreate liquid loading under laboratory conditions. Our results suggested using a compressed-air system with a discharge pressure between 470 and 650 psi with gas rates of 400 to 650 scf/min along with water injected at a rate of 100 gal/min. Once the range in operating conditions was defined, the equipment and mechanical components for the facility were selected and designed. Our results showed that three reciprocating compressors working in parallel provide the smallest, most economic, and most flexible configuration for the TowerLab facility at Texas A&M University (TAMU). The design of the pressure vessel hosting the porous medium will require a cylindrical body with top- and bottom-welded flathead covers with multiple openings to minimize weight. The required superficial velocities for air and water indicate the system will need independent injection into the porous medium through two manifolds. Optimally, the system will use digital pressure gauges, coriolis or vortex technology to measure air flow, and turbine meters for water flow. A joint-industry project (JIP) on liquid loading in gas wells was initiated in January 2009, which includes the implementation of the proposed design for the TowerLab facility to generate experimental data that will significantly improve our ability to mimic the physics of multiphase flow, and so develop and validate flow models for the characterization of liquid loading in gas wells. It is anticipated that a preliminary version of the new loop, including an inlet multiphase-flow pump, has been assembled and will be operational early in Fall 2010, with plans for the full design to be implemented in 2010-11.

Decision matrix for liquid loading in gas wells for cost/benefit analyses of lifting options

The main objective of this paper is to identify any current and future bottlenecks in the production system while honoring operational constraints on wells, production separators, pipelines, and total field gas/liquid processing capacity. It also concerns with identifying any flow assurance issues taking in consideration different field development scenarios for an offshore gas condensate field in the Mediterranean (Abu Qir Field). Liquid loading in gas wells occur when the gas flow rate falls below a critical rate due to reservoir depletion where the accompanying liquids cannot be lifted to surface. Such liquid accumulations at the wellbore can cause the gas well to cease production eventually. Severe slug flow (i.e., terrain-dominated slug flow) was studied. Severe slug flow is characterized by extremely long liquid slugs generated at the base of the vertical riser. This phenomenon occurs at low gas and liquid flow rates and for negative pipeline inclinations. To evaluate future development options and to provide a monitoring tool and realistic results, a multi-disciplinary Petroleum Engineering study was carried out. Unknown reservoir parameters were estimated using the modern production data analysis method, which was also used as a reliable forecasting tool. Steady state multiphase flow simulator and the forecast from production data analysis and numerical reservoir simulator were used to identify any current and future bottlenecks and also optimize the production taking in considerations field's constraints. Transient multiphase flow simulator was used to identify and mitigate transient flow assurance issues i.e. liquid loading in gas wells and slugs in the pipelines. Other scenarios were also studied include: platform start-up and shutdown; production Ramp up due to the introduced platform; and Hydrates no show time due to any shutdown. This helped us to determine the proper design envelope of the new system. This integrated workflow helped in optimizing the current operating conditions and decreasing field operating cost by increasing the current gas production rate by 6%. We managed to prevent the decline in reserves by more than 10% in the future caused by production system bottlenecks. Choke size for each well was identified honoring existing constrains (reservoir pressure, flow velocity limits, etc.) to increase field gas production. Outlet pressure of a surface network was maximized in order to minimize operational costs of gas processing while maintaining required gas production level. Different scenarios were carried out to come with procedures to prevent and mitigate production instabilities and also decreasing the deferred production. This work can subsequently propose an integrated field management workflow on addressing various production issues especially in case of limited data availability and how different domains can co-operate to reach the optimum operating scenarios.

Liquid loading is one of the major flow assurance challenges in gas wells, causing production problems and reducing the ultimate recovery. Liquid loading is defined as the inability of a well to carry all the co-produced liquid up the tubing. This leads to liquid accumulation in the well resulting in increased bottomhole pressure and decline of gas flow rate. Although many studies have been performed on liquid loading phenomena, available models generally lack the ability to capture transient behavior of liquid loading in gas wells. We have developed a computational fluid dynamics (CFD) model using Ansys Fluent 19.1 R3 version to model the transient features of liquid loading. In this study, the CFD model is developed and validated with data from 42 meter long vertical pipe lab at Texas A&M University. The Eulerian multiphase approach combined with volume of fluid approach (VOF) - Multi-fluid VOF model with realizable k-Є turbulence closure is used to study the flow behavior. In addition, hexahedral mesh is utilized and compared to tetrahedron mesh to test accuracy and computational time. The developed CFD model has unique parameters combinations that shows an acceptable agreement with the experimental work. Model accuracy and computational time is improved by using hexahedral mesh. Liquid film flow reversal mechanism is expected to be the root cause of liquid loading in gas wells rather than droplet fall back mechanism. The CFD model captures the transition from one phase to another that is crucial for determining well end life. Model novelty is based on the ability to be a reliable predictive tool that can help in the remediation of liquid loading and give a precise representation of liquid loading transient behavior in gas wells.

Liquid loading in gas wells is triggered when the produced gas loses the ability to lift the co-produced liquids up the tubing. These co-produced liquids accumulate at the bottom of the wellbore, causing a higher back-pressure on the formation which reduces production from the reservoir, and may ultimately kill the well. As this phenomenon is transient in nature, it requires transient modeling for proper characterization of its associated flow features and prediction of future well performance. However, there is a lack of dedicated models that can mimic the transient behavior which is typical of liquid loading. This paper describes the modeling effort carried out to investigate the liquid loading sequence in a synthetic gas well using a commercial package for transient multiphase flow modeling and two research codes (one for steady-state flow, and one for transient flow). The results of the simulations for the pressure gradient were compared against experimental data. The experimental runs were performed using a facility which has a transparent vertical test section of 43 m in length, and 0.04859 m ID. Air and water were used as working fluids. The results highlighted the capabilities and limitations of these simulators when evaluating liquid loading in gas wells. While good agreement was observed among all three codes for the modeled pressure drop, considerable divergence was noted in terms of the recognized flow regimes and the modeled liquid holdup. According to the literature and field observations, liquid loading is fundamentally related to the transitions between flow regimes and the associated transient flow mechanisms; thus, miscalculating them would inevitably lead to an erroneous prediction of well performance. Based on the results from the simulations, the potential effect of mis-modeling liquid loading on flow assurance and production optimization are investigated, and the need for further developments in transient multiphase modeling is discussed.