Onset Of Liquid Loading Research Articles

Integrated Multiphase-Flow Modeling Technique Yields Accurate Downhole Pressure Predictions

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214855, “Integrated Multiphase-Flow Modeling for Downhole Pressure Predictions,” by Abdullah Alkhezzi and Yilin Fan, SPE, Colorado School of Mines. The paper has not been peer reviewed. _ This work presents an integrated multiphase flow model for downhole pressure predictions. The aim of the model is to produce more-accurate downhole pressure predictions under wide flowing conditions while maintaining a simple form. As a component of the integrated model, an improved two-fluid model for segregated flow is proposed. Results of the two-fluid segregated model are compared with five state-of-the-art existing models, while results of the integrated model are compared with three models. Introduction Throughout the life of the well, knowing bottomhole flowing pressure (Pwf) and the pressure profile of the wellbore are of great significance. Unfortunately, deploying downhole pressure gauges to obtain Pwfreadings is often not economical or practical. The common practice is to apply hydraulic models to predict Pwfgiven surface measurements. The prediction of such behavior is simple when dealing with single-phase fluid flow. Unfortunately, this condition is rare in the petroleum industry. The existence of multiple phases introduces multiple complexities hindering the accuracy of downhole pressure predictions. To account for such variations, fluid-property models must be integrated into the calculation procedure. The complexity, coupled with field-data scarcity, results in the deficiency of work that evaluates point models on actual wells. In this work, the authors evaluated the performance of a few widely used multiphase-flow point-based models on actual field data using a marching algorithm and developed a simplified, yet more precise, integrated model. Integrated Model Development Data Set Description. In this study, data points were collected for two main purposes. First, experimental data sets were collected to model and improve the segregated flow model. Second, field data were collected to test the integrated multiphase model. To improve the segregated flow model, 1,478 experimental data points were obtained from various sources in the literature. To evaluate the integrated multiphase flow model, 313 data points from two main sources of data were used (literature and actual field data). In total, four data sets were obtained from the literature and one was obtained from Civitas Resources. Integrated Model Description. The multiphase-flow point model incorporated in the authors’ integrated modeling consists of three main components: critical gas velocity estimation for the onset of liquid loading and hydraulic multiphase flow models before and after the onset of liquid loading. The proposed model characterizes the flow based on whether liquid loading occurs. The onset of liquid loading corresponds with the transition of the flow pattern from segregated to intermittent flow. At points where the superficial gas velocity is estimated to be lower than the critical gas velocity and the flow is considered intermittent or bubbly, the drift-flux model is to be used, which works well in flow patterns where liquid volume is high. Another strength of the model is its ability to capture countercurrent flow. The drift-flux homogeneous-like approach makes the process simple and continuous and simultaneously captures some physics through slippage. For points where the superficial gas velocity is greater than the critical gas velocity, two-fluid modeling is to be used.

A fully coupled compositional wellbore/reservoir model for predicting liquid loading in vertical and inclined gas wells

Liquid loading presents a formidable challenge for mature gas wells, often resulting in substantial economic losses. Traditional research has predominantly centered on the analysis of gas-liquid two-phase flow within the wellbore to predict critical gas velocity or rate, aiding in identifying the onset of liquid loading. This study introduces a fully coupled compositional wellbore-reservoir simulator designed to detect liquid loading in both vertical and inclined gas wells. Leveraging the drift-flux model to evaluate flow pattern transitions, this simulator employs pressure or rate constraints at the wellhead as boundary conditions. It comprehensively captures the flow dynamics in both the wellbore and reservoir, unveiling significant changes in gas production rate, water production rate, gas velocity, flow regime, and the reserved position of the liquid film under liquid-loaded conditions. Moreover, the accumulation of liquid at the bottom hole leads to increased reservoir pressure and gas saturation near the wellbore. The simulator predicts a typical unstable production period, emphasizing its crucial role in implementing effective strategies to mitigate liquid loading. This paper investigates the capability of the coupled wellbore-reservoir model to characterize transient liquid loading phenomena from a systematic perspective. The proposed model can function as a real-time tool for predicting the status of liquid loading in gas wells.

Improved Two-Fluid Model for Segregated Flow and Integrated Multiphase Flow Modeling for Downhole Pressure Predictions

This work presents an integrated multiphase flow model for downhole pressure predictions with the purpose of producing relatively more accurate predictions under wide-flowing conditions while maintaining a simple form. As a component of the integrated model, an improved two-fluid model for segregated flow is proposed. The new two-fluid model was developed by improving the modeling of the wetted perimeters and the liquid wall shear stress. It outperformed five other existing state-of-the-art models in predicting the liquid holdup and pressure gradient of 11 experimental datasets from the literature, with an average relative error of 37.6% for liquid holdup predictions and 24.0% for pressure gradient predictions. The model succeeds in capturing the effects of inclination angle, pressure or gas density, and liquid and gas superficial velocities on liquid holdup and pressure gradient. The integrated model incorporates the state-of-the-art onset of liquid loading predictive model and classifies the flow into two major categories based on the onset of liquid loading that are modeled by two different approaches, respectively. It outperformed the other multiphase flow models in predicting the downhole pressure of 313 field data points, especially the wells that have both segregated and intermittent (mixed) flows. The errors were reduced to 4.4% for the field cases with mixed flow regions and 5.1% for all the field data points.

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

Liquid loading is one of the major challenges for natural gas wells, as it can decrease and eventually cease the production of hydrocarbons. Characterizing liquid loading in gas wells and quantifying flow dynamics throughout this process is crucial. The literature shows a lack of experiments for oil-air low liquid loading flow, especially in vertical pipes. This demonstrates a lack of experimental data to comprehend the effect of liquid properties on two-phase flow behavior. In order to simulate a vertical natural gas well, oil-air tests were carried out in this work in a vertical pipe with a 0.0508-m ID (Inner-Diameter) under low liquid loading conditions. The aim of this study is to better comprehend the effect of liquid characteristics on flow behavior and the onset of liquid loading.The results of the experiments reveal that changing the liquid phase from water to oil reduces pressure loss, liquid holdup, and the surface gas velocity (vSg) at which liquid loading occurs. Liquid holdup and pressure loss of the water-air and oil-air flow with medium gas rates show notable variances within the churn flow. Additionally, compared to the minimum-pressure drop technique, the positive pressure technique offers considerably more reliable predictions for the start of liquid loading.Two models—the unified Tulsa University Fluid Flow Projects (TUFFP) and OLGA—are used to investigate the flow pattern, liquid holdup, and pressure loss predictions. The liquid film reverse, liquid droplet models, and the inflection point technique were compared to experimental data for similar liquid loading onset models by Alsanea et al. (2022). For the data in this investigation, the OLGA model and Coleman's correlation perform the best at predicting the onset of liquid loading. Given that both the unified model and OLGA use slug flow models, the results show that a separate model must be created for churn flow to accurately estimate the pressure drop and liquid holdup.

Evaluation of Liquid Loading in Gas Wells Using Machine Learning

The inevitable result that gas wells witness during their life production is the liquid loading problem. The liquids that come with gas block the production tubing if the gas velocity supplied by the reservoir pressure is not enough to carry them to surface. Researchers used different theories to solve the problem naming, droplet fallback theory, liquid film reversal theory, characteristic velocity, transient simulations, and others. While there is no definitive answer on what theory is the most valid or the one that performs the best in all cases. This paper comes to involve a different approach, a combination between physics-based modeling and statistical analysis of what is known as Machine Learning (ML). The authors used a refined ML algorithm named XGBoost (extreme gradient boosting) to develop a novel full procedure on how to diagnose the well with liquid loading issues and predict the critical gas velocity at which it starts to load if not loaded already. The novel procedure includes a combination of a classification problem where a well will be evaluated based on some completion and fluid properties (diameter, liquid density, gas density, liquid viscosity, gas viscosity, angle of inclination from horizontal (alpha), superficial liquid velocity, and the interfacial tension) as a “Liquid Loaded” or “Unloaded”. The second practice is to determine the critical gas velocity, and this is done by a regression method using the same inputs. Since the procedure is a data-driven approach, a considerable amount of data (247 well and lab measurements) collected from literatures has been used. Convenient ML technics have been applied from dividing the data to scaling, modeling and assessment. The results showed that a wellconstructed XGBoost model with an optimized hyperparameters is efficient in diagnosing the wells with the correct status and in predicting the onset of liquid loading by estimating the critical gas velocity. The assessment of the model was done relatively to existing correlations in literature. In the classification problem, the model showed a better performance with an F-1 score of 0.947 (correctly classified 46 cases from 50 used for testing). In contrast, the next best model was the one by Barnea with an F-1 score of 0.81 (correctly classified 37 from 50 cases). In the regression problem, the model showed an R2 of 0.959. In contrast, the second best model was the one by Shekhar with an R2 of 0.84. The results shown here prove that the model and the procedure developed give better results in diagnosing the well correctly if properly used by engineers.

Liquid Loading in Natural Gas Vertical Wells: A Review and Experimental Study

Summary Liquid loading in natural gas wells is one of the main causes of decline and eventual cease of production. Identifying the onset of liquid loading and its impacts on production is vital in production optimization of gas wells. In this study, a new state-of-the-art experimental facility is used to analyze two-phase flow parameters, such as liquid and gas velocities, pressure drop, liquid holdup, and flow pattern, and study the onset of liquid loading. Experiments are conducted using air and water in a 0.0508-m (2-in.) internal diameter (ID) vertical flow loop. The facility is designed to eliminate any source of disruption to the flow in a temperature-controlled indoor environment to avoid changes in fluid properties. A wide range of data are collected related to the onset of liquid loading and in the churn region. The acquired data are compared with other studies to ensure the accuracy and repeatability of the tests. A quantitative method is developed to predict the onset of liquid loading, namely, the positive frictional pressure gradient (negative pressure drop). A comparison is made between the visual observations for flow pattern transition, positive frictional pressure gradient, and minimum pressure drop. Overall, the results show that the positive frictional pressure gradient approach can provide a better estimation of the onset of liquid loading than the minimum pressure drop approach. Additionally, Tulsa University Fluid Flow Project (TUFFP) unified model (v2016) and OLGA (v2016.2.1) are used to evaluate the average pressure drop, liquid holdup, and flow pattern. Furthermore, the liquid film reversal model, liquid droplet models, and inflection point approach are included in the comparison of the onset of liquid loading with experimental data. The OLGA model predicts the results more precisely than other models. The comparison with the experimental data indicates that inaccurate flow pattern predictions could significantly increase the relative errors in pressure drop and liquid holdup. In addition, the evaluation of OLGA results suggests the need to develop a model for churn flow, as the relative error increases sharply in the churn flow with the model predicting the transition to slug flow.

A Model Ranking Approach for Liquid Loading Onset Predictions

Summary As a natural gas well ages, liquid loading is frequently encountered, leading to the decrease of gas production rate and many other side effects, which may in turn cease the gas production. Thus, to accurately predict liquid loading onset is of significant importance in gas wells for the sake of stable production. With years of research and development in the natural gas industry, the liquid loading onset prediction models prevail in the existing literature. Based on varying mechanisms (e.g., droplet falling back, liquid film reversal, etc.), the critical gas velocities or flow rates corresponding to flow pattern transitions in gas wells can then be calculated. However, a universally validated model, whether empirical or non-empirical, that is applicable to predict the onset of liquid loading in versatile gas wells conditions (e.g., horizontal, vertical, and inclined) is, as yet, still unavailable. In this paper, we conduct a complete literature review and investigation of these existing liquid loading onset prediction models. First, we obtained detailed information of more than 600 gas wells, including well geometries, gas properties, operation conditions, and so on, from different gas fields. Then, we evaluate the validity of various liquid loading onset prediction models by use of a novel model ranking approach. To fully account for the effects of gas well properties (including but not limited to production, wellhead pressure, and pipe diameter) to the model prediction accuracy, the proposed method in this paper employs data clustering and normalization techniques, as well as the statistical relative error analysis, to rank and select the best suitable model for each specific gas well. Extensive comparison and verification of the ranking approach indicate that the proposed method provides a good reference for the rational production allocation and stable production of gas wells.

Evaluation of the Onset of Liquid Loading by a Proper Inclusion of Droplet Entrainment in the Liquid Film Reversal Model

Evaluation of the Onset of Liquid Loading by a Proper Inclusion of Droplet Entrainment in the Liquid Film Reversal Model

Study Models Onset of Liquid Loading in Large-Diameter Deviated Gas Wells

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 196130, “Experimental Investigation and Modeling of Onset of Liquid Accumulation in Large-Diameter Deviated Gas Wells,” by Ayush Rastogi and Yilin Fan, SPE, Colorado School of Mines, prepared for the 2019 SPE Annual Technical Conference and Exhibition, Calgary, 30 September-2 October. The paper has not been peer reviewed. Multiple challenges related to liquid loading have been observed during flowback after hydraulic fracturing and during the production phase. These challenges are further aggravated by high-inclination angles found in deviated wellbores. The complete paper describes an experimental study performed to investigate the onset of liquid loading in a 6-in. production casing at various inclination angles. A unified mechanism model for the onset of liquid loading is developed for a large-diameter production casing.

Investigating the pressure characteristics and production performance of liquid-loaded horizontal wells in unconventional gas reservoirs

The increasing exploiting activities in unconventional gas reservoirs renew the interests of investigating liquid loading phenomenon, a common production issue for gas wells. Most previous studies focused on predicting the onset of liquid loading. The reservoir pressure characteristics and wellbore production performance after the onset of liquid loading have not been systematically investigated. This work introduces a newly developed fully implicitly coupled wellbore reservoir model to investigate the liquid loading effects on horizontal wells in low permeability gas reservoirs. The model honors the mass and momentum balances in both reservoir and wellbore systems, and thus allows us to analyze both wellbore and reservoir dynamics after the onset of liquid loading. The simulation results reveal that horizontal gas wells in low permeability reservoirs might experience natural cyclical production after the onset of liquid loading, which coincides with field observations. Both uniform stimulation and hydraulic fracturing help mitigate the cyclical production phenomenon. The near-wellbore reservoir pressure buildup and wellbore fluid reinjection are also evaluated. This work demonstrates the successful application of the coupled wellbore reservoir model in predicting the rich production phenomena of stimulated horizontal wells after the onset of liquid loading.

Title: Li and Turner Modified model for Predicting Liquid Loading in Gas Wells

BackgroundLiquid loading of gas wells causes production difficulty and reduces ultimate recovery from these wells. Several authors proposed different models to predict the onset of liquid loading in gas wells, but the results from the models often show discrepancies. Turner’s et al. (J Pet Technol, 1969) critical model was developed based on the assumption that the droplet is a sphere and remains spherical all through the entire wellbore. On the other hand, Li’s model was developed based on the assumption the liquid droplets are flat in shape and remains same all through the wellbore. However, it is a well-known fact that the droplet alternates between spherical and flat during production operation. Invariably, the Turner’s model and the Li’s model would not be able to predict correctly the critical rate required to lift that droplet which is because the droplet deformation was not taken into account during the development of the models.Materials and methodsIn this work, a new improved model is developed and incorporated into Ms-Excel program to predict liquid loading in gas wells. In the new model, a deformation coefficient “C” is introduced to cater for the deformation of the liquid droplet along the wellbore and in turn be able to predict correctly the critical rate when the droplet varies from the spherical shape to the flat shape.ResultsResults from the analysis carried out revealed 35% error on from Turner’s model, 26% error on Li’s model, whereas the new model yielded 20% error.ConclusionThe new developed software and model proved to be more accurate in predicting onset of liquid loading.

A new model for improving the prediction of liquid loading in horizontal gas wells

There are great differences in predicting the onset of liquid loading among vertical, directional and horizontal gas wells. To date, most models for predicting the critical gas rate in horizontal wells are based on a liquid-droplet model, and the corresponding predictions deviate significantly from the actual status and are considerably controversial. Experimental results (Xiao et al., 2010; Wang, 2014) show that the liquid-film model is more reasonable. By respectively analyzing the force state of the gas core and the liquid film, we developed a new liquid-film model for predicting the critical gas rate in horizontal wells. Subsequently, a correction term is introduced for a convenient comparison between the new model and the popular models (Turner et al., 1969; Nosseir et al., 2000; Li et al., 2002). In addition, we carefully conducted a sensitivity analysis of the correction term related to the three parameters: liquid viscosity, Bond number and lift force factor. Well data from Liao (2012) were employed to verify the new model. The prediction results show that the new model demonstrates a significant improvement over conventional models in matching the field data in the Sebei gas reservoirs in China.

Improved Prediction of Liquid Loading In Gas Wells

SummaryAfter 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.

Foam flow in vertical gas wells under liquid loading: Critical velocity and pressure drop prediction

Foam lift is one of the most cost effective methodologies for unloading gas wells. The surfactants are either injected intermittently or continuously to lift the liquid to the surface. By reducing the gravitational gradient and increasing the frictional gradient, the critical velocity at which liquid loading occurs is shifted to lower gas velocities. Currently, we do not have a methodology to predict the critical velocity (at the transition boundary of annular and intermittent flow) and the pressure drop under foam flow conditions.To address this, we measured several foam flow characteristics in both small scale and large scale facilities. Small scale facility involved measurement of foam carryover capacity as a function of time and surfactant concentration. Large scale facility involved measurement of liquid holdup, pressure drop, fraction of gas trapped in foam and foam holdup in 40-ft 2-in. and 4-in. tubing.We developed closure relationships for liquid hold up, foam holdup, fraction of gas trapped in the foam and interfacial friction factor by combining the small scale data with the data collected in the large scale experiments. These closure relationships are applicable to four different surfactants tested. A new transition criterion was developed and successfully used to predict onset of liquid loading under foam flow. Using a force balance over the gas core in annular flow, we developed a new procedure to calculate the pressure drop under foam flow conditions. We compared our model results with actual measurements in the large scale facility. Our model was reasonably able to predict the pressure drop within ±30%. The reason for such a large variance is that the small scale facility was not able to capture all the characteristics of the foam which were observed in the large scale facility. It is very difficult to reproduce the foam characteristics exactly in two different experiments. This is discussed further in this paper.The procedure developed is the only one currently available to calculate the pressure drop under the foam flow conditions using the small scale data. It is superior to conventional annular flow pressure drop prediction models which are currently available in the literature.

A Pragmatic Approach To Understanding Liquid Loading in Gas Wells

Summary Liquid loading is the inability of a producing gas well to remove its coproduced liquids from the wellbore. The liquid flowing as droplets or film accumulates at the well bottom, thereby imposing backpressure at the sandface and triggering increasingly higher pressure loss in the wellbore. The problem initiated by liquid loading is manifested in terms of loss in well deliverability, causing the wellhead pressure to decline significantly, which, in turn, leads to the cessation of gas production. Accordingly, the liquid-loading issue reduces the ultimate recovery of a gas well. Both the droplet-flow reversal and liquid-film-flow reversal have been postulated to be the underlying mechanism for liquid loading. Both mechanisms are predominantly premised on diagnosing the problem at the wellhead-flow conditions. This study explores the deliquefication issue in a gas well by fluid- and heat-flow modeling of the entire wellbore for a variety of flow situations in gas and gas/condensate reservoirs. We observed that when a well experiences annular two-phase flow throughout the wellbore, no liquid loading occurs. The transition from annular flow to churn or slug flow initiates the liquid-film-flow or droplet-flow reversal, thereby triggering liquid loading. Most often, the flow condition at the well bottom controls the onset of liquid loading. By use of three published data sets, we show that the understanding of liquid loading improves when the entire wellbore-flow modeling is used. Forward modeling suggests that the tubing inside diameter and the well productivity index are the most important independent variables in determining the critical liquid-loading rate and the onset of liquid loading.

A New Artificial Lifting Technology for Gas Wells-Downhole Gas Compression

Downhole Gas Compression (DGC) is an entirely new powered artificial lift technology specifically for natural gas wells. The technology offers the opportunity to increase production by 30-50%, significantly improve reserves and delay the onset of liquid loading. Key application of DGC is for use in deeper partially depleted reservoir wells encountering liquid loading. The research progress of DGC is introduced in this paper and the results of theoretical and experimental study of DGC are investigated. Moreover, the adaptability and application prospect of this new technology is analyzed. There are many gas fields in China faced with problems about effective drainage and recovery enhancement, such as the mature gas fields in Sichuan and Ordos Basin. DGC will have a good application prospect in China and further study of the DGC technology is recommended.

Investigating Liquid Loading in Tight Horizontal Gas Wells

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 149477, ’Investigation of Liquid Loading in Tight Horizontal Gas Wells With a Transient-Multiphase-Flow Simulator,’ by Donald F.B. Jackson, SPE, SPT Group, and Claudio J.J. Virues, SPE, and David Sask, SPE, Encana, prepared for the 2011 Canadian Unconventional Resources Conference, Calgary, 15-17 November. The paper has not been peer reviewed. Liquid loading occurs in gas wells when production declines to a rate that is insufficient to lift the associated liquids to the surface. Liquid holdup in the horizontal section may impair production before liquid loading in the production tubing becomes evident. Holdup in the horizontal section can lead to slug flow at the tubing and to early onset of liquid loading in the tubing. The results from a transient-multiphase-flow model were found to be consistent with data acquired from video logging. Sensitivity analyses were performed with several normalized trajectories. Introduction Technology applied in conventional reservoirs in offshore horizontal wells can be applied successfully in onshore horizontal wells in unconventional reservoirs. The Jean Marie formation is an Upper Devonian carbonate platform between two thick shale layers in the Greater Sierra area, approximately 90 km east of Fort Nelson, British Columbia, Canada. The formation has low porosity (averaging 6%), low water saturation (averaging 20%), and low permeability (less than 1 md to air). Formation depth ranges from 600 to 1500 m subsea—1000- to 1900-m true vertical depth. The formation is entirely gas saturated with a dry sweet gas (95% methane) and is variably underpressured, with initial reservoir pressures of 6 to 15 MPa. The horizontal wells are drilled underbalanced to limit formation damage. Fig. 1 shows a typical well completion with 177.8-mm production casing set at the top of the Jean Marie formation. Gas is produced from the openhole portion of the completion. While drilling horizontally through the Jean Marie formation, the well trajectory is steered on the basis of gas-rate-while-drilling (RWD) data. The geologists maneuver up and down in inclination until a good permeability streak is indicated by a spike in flow rate from the RWD data. After reaching target depth, tubing (typically 60.3 mm) is installed and the well is brought on production. Typical gas- production rates for Jean Marie wells decline from an initial rate of 56×103 m3/d to 14×103 m3/d after 12 months and to 10×103 m3/d after 36 months.

Downhole Gas Compression: A New Artificial-Lifting System for Gas Wells

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 121815, "Downhole Gas Compression: World's First Installation of a New Artificial-Lifting System for Gas Wells," by M.T. Di Tullio, SPE, S. Fornasari, and D. Ravaglia, Eni SpA E&P Division, and N. Bernatt, SPE, and J.E.N. Liley, SPE, Corac Group plc, originally prepared for the 2009 SPE EUROPEC/EAGE Annual Conference and Exhibition, Amsterdam, 8-11 June. The paper has not been peer reviewed. Downhole gas compression (DGC) is a new artificial-lift technology designed specifically for natural-gas wells and is an as yet unrealized opportunity within the upstream gas industry. The technology offers the opportunity to increase production by 30 to 50%, improve reserves significantly, and delay the onset of liquid loading. Although it can be used at any time during the life cycle of a gas asset, it will find particular favor during the decline phase. Introduction The upstream gas industry often is faced with the challenge of selecting an optimum artificial-lift system from various alternatives available for gas-well production enhancement. These challenges become more complex with increasing dynamic changes in well flow characteristics over the life of the well. Application of DGC technology in suitable wells offers value for the following reasons.Acceleration of early production and extension of production plateau in new gas developments.Cost-effective rejuvenation of mature gas reservoirs characterized by low reservoir pressure and liquid accumulation in wells.Improvement of gas-well production and maximization of recovery factor from gas reservoirs with low environmental impact.Identification of incremental reserves and for monetization of stranded gas. As part of an ongoing development through a joint-industry program, the first field trial of the new technology was conducted in an onshore gas well. The program has been completed in phases, including the design, building, and testing in a full-scale flow loop that closely replicated downhole conditions. The prototype has been tailored to suit the expected gas-flow range, composition, and condition of the selected field-trial well. Fig. 1 shows an internal view of one of the three compressor modules, with the gas path indicated in red. Why Compress Gas Downhole Operators of a producing asset always are seeking to maximize its value. In natural-gas fields, optimum gas production at low intervention cost and frequency is the ultimate objective in gas-well production management. To maximize production, the flowing bottomhole pressure (FBHP) should be kept as low as operationally possible. There are many challenges to achieving this objective.

Overview: Artificial Lift (May 2007)

Boosting ultimate recovery requires us to get more from each well and each reservoir. Clearly, while improving recovery is one of the best places to look for additional reserves, often the relationship between artificial lift and ultimate recovery has been forgotten. However, when artificial lift options are limited, as is the case for subsea wells, we quickly discover that recoveries drop to among the lowest in the industry. Today, selection of an artificial lift technique plays an increasingly important role in determining ultimate recovery. In addition to the challenges posed by subsea/deepwater production, unconventional reservoirs also require new ideas to improve recovery. For example, steam operations used to produce from heavy-oil reservoirs require downhole and surface pumps to operate at temperatures well beyond our experience base. Unconventional gas reservoirs, such as coalbed methane and ultralow-permeability sand/shale, also present unique challenges. In these cases, operating companies must solve problems associated with lifting liquids to the surface (i.e., liquid loading). The papers highlighted in this artificial-lift section illustrate some of the approaches applied in a wide variety of reservoirs. From installation of electrical submersible pumps in hot, high-gas/oil-ratio wells to rod-pumping applications for gas well unloading, these papers illustrate the adaptation of artificial-lift methods to keep wells producing and to extend field life. Work on improving the ability to predict the slug-to-annular-flow transition also is highlighted. This work is of great interest to the area of gas lift stability as well as predicting the onset of liquid loading. The recommended reading list highlights some of the latest thinking on the requirements and current state of the art in the rapidly evolving area of seafloor boosting. This particular type of artificial lift, by use of subsea multiphase pumps, is quickly becoming an integral part of the field-development plan for deepwater and ultradeepwater fields. Given the industry shift to deepwater and unconventional reservoirs, today's definition of artificial lift must encompass a much broader range of technologies than in the past. Also, the critical role that artificial lift plays in increasing ultimate recovery needs to be recognized up front so that effective artificial-lift solutions can be incorporated in field-development planning. Artificial Lift additional reading available at the SPE eLibrary: www.spe.org SPE 104037 "Stability Analysis of Gas Lift Wells Used for Deepwater Oil Production" by I. Guerrero-Sarabia, National Autonomous University of Mexico, et al. SPE 104314 "Economic Pumping Technology for Coalbed Methane (CBM), Stripper Oil, and Shallow Gas Well Deliquification" by Michael W. Dickey, SmithLift Available at the OTC Library: www.otcnet.org OTC 18261 "Subsea Processing and Boosting—Technical Challenges and Opportunities" by R.M. Bass, Shell International E&P OTC 17899 "Subsea Boosting of the Brenda Field Through Utilization of a Multipurpose Field Development Solution" by J. Elde, SPE, Framo Engineering, et al.