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Abstract Surface compressors lower the wellhead pressure and increase the tubing drawdown and hydrocarbon production. Hybrid use of surface compression, continuous flow plunger lift, and continuous gas injection reduces flowing bottomhole pressure and avoids liquid loading. The study focuses on favorable conditions for lower tubing wellhead pressure, leading to significant production and production lifetime increases. Multiphase flow simulations were conducted to investigate the effect of different tubing wellhead pressure settings. Sensitivity analysis for different production rates and gas-liquid ratios are employed. Field data from 14 wells from San Juan Basin is used to analyze the hybrid use of surface compression and plunger-assisted gas lift. Operational range and cycles of plunger lift analyzed for tubing wellhead pressure of 30, 120, and 210 psi for different production rates. Nodal analysis is used with productivity index and backpressure gas equation to estimate production increase provided by surface compression. Lower tubing wellhead pressure promotes gas expansion and higher gas velocity along the tubing. Higher gas velocity helps to reduce liquid holdup and gravitational pressure losses but increases the frictional pressure losses. In a few months, unconventional wells experience liquid loading where gravitational pressure losses dominate. Surface compression was found to be lowering flowing bottomhole pressure hence increasing reservoir inflow for unconventional wells. Furthermore, plunger lift analyses showed that surface compression allows plungers to surface without shut-in, which extends PAGL operation for years. The mechanistic model simulations and field data show that surface compression and PAGL usage increase production and extend the unconventional wellsโ production lifetime. The sensitivity analysis shows favorable production rates by lowering tubing wellhead pressure, which applies to many shale plays. The study presents the methodology to estimate production increase and feasibility analysis for surface compressed plunger and gas lift. Introduction Artificial lift methods are implemented to improve production and avoid well integrity problems. Improving the production rate includes avoiding production instability and extending the production lifetime of wells and helps with daily production and total hydrocarbon recovery. Furthermore, severe slugging, corrosion, hydrate formation, and sand issues, which may create serious problems to surface facilities, can be tackled by changing the flow conditions using artificial lift methods and choking. Artificial lift needs and integrity problems of a well change for different reservoirs and production platforms. ESP or gas lift may be suitable for a high-production offshore well with low GLR, whereas an onshore well with high GLR may experience gas locking problems for a rod pump. Production engineers select and design artificial lift methods with the consideration of the feasibility and limitations of each well.
- North America > United States > Texas (0.68)
- North America > United States > Colorado (0.48)
- North America > United States > New Mexico > San Juan Basin (0.99)
- North America > United States > Colorado > San Juan Basin (0.99)
- North America > United States > Arizona > San Juan Basin (0.99)
Abstract The emergence of "big data" has encouraged the utilization of data from various origins to enhance the decision-making process. Unfortunately, multiphase flow studies are often performed in "silos" โ within which specific experiments were performed and based on which certain model improvements were proposed. As such, it is easy to lose sight of the big picture of where we are in terms of our understanding and modeling capability. This disconnected approach has also produced an ever-growing, potentially unmanageable list of closure relationships, which can be counter-productive for model development. In this paper, we present exploratory data analyses to comprehensively evaluate the performance of a steady-state multiphase flow point model in predicting high-pressure near-horizontal data from independent experiments. This effort provides wide-ranging hindsight that can reflect the current state-of-the-art of multiphase flow modeling and pinpoint areas where improvements are needed. First, relevant multiphase flow datasets from the literature are collected. In this paper, we limited the scope to near-horizontal and high-pressure data (gas density of 5 kg/m or higher). Then, we run a state-of-the-art model and compare its prediction against these datasets. Multidimensional discrepancy plots are presented to map the modelsโ performance for pressure drop and holdup predictions across the selected scaling variables. Violin plots are used to identify and analyze the outliers with respect to modeling errors. Confusion matrices are used to quantitatively analyze the model performance in predicting flow patterns, eliminating the restriction of traditional flow pattern map analysis that is limited to qualitative assessment at constant pipe and fluid properties. Finally, the accuracies of key closure relationships are also evaluated. The multidimensional discrepancy plots highlight the conditions where the model performs poorly: low-liquid loading upward flow, downward flow, and high gas flow rates. The violin plots enable quick identification of outliers, which can represent both model and measurement deficiencies. The confusion matrix indicates that the transition between stratified and annular flow is very poorly predicted. The misclassification between stratified and intermittent flow comes at a distant second in terms of occurrence frequency; however, it contributes more significantly to the bulk parameters prediction errors. Except for the slug translational velocity, most closure parameters are still poorly predicted. Entrainment fraction deserves special attention given the expected importance of it on the stratified flow model accuracy. The closure relationships for slug characteristics are unable to predict pseudo-slug flow data accurately. This paper presents several Exploratory Data Analysis (EDA) techniques that enable comprehensive analyses of several independent datasets from various origins. The analyses provide actionable and more general insights that would be otherwise obscured if individual datasets are analyzed in silos, such as operating conditions where higher uncertainty margins need to be applied and where further modeling improvements are desirable.
- Europe (1.00)
- North America > United States > Texas (0.67)
- Overview > Innovation (0.48)
- Research Report > New Finding (0.46)
Abstract The importance of churn and pseudo-slug flow has been recognized, especially during recent years. Churn and pseudo-slug flow characteristics study in inclined pipes are still quite limited. An experimental study was conducted to investigate the inclination angle effect on slug to churn/pseudo-slug transition and the slug (Taylor Bubble) flow existence in large diameter pipes. The tests were conducted in a 0.1016-m ID pipe facility for inclination angles ranging from 2 to 90 degrees at 84-psia test section pressure. Tap water and compressed air were used as the test fluids. Wire-Mesh-Sensors (WMS) were used for flow characteristics measurement and visualizations.
Abstract In recent years, internal, two-phase, flow-induced vibration (FIV) has received elevated attention in various fields while assessing piping system fatigue life. Regarding the oil and gas industry, in particular, assessing FIV impact is essential for ensuring the integrity of flow lines, both onshore and offshore. This study conducted a series of experimental tests at various superficial gas and liquid velocities to investigate the effects of flow parameters on the structural dynamics of a horizontal 6-inch ID polycarbonate test section. The relationship between flow characteristics and the structural response was examined in detail. A novel methodology was developed and implemented to achieve non-intrusive, simultaneous measurement of pipe motion and liquid distribution. The presented results reveal that downward deflection generally decreased with increasing superficial gas velocity and increased with increasing superficial liquid velocity. It was also found that as superficial gas velocity increased, the range of frequencies experienced by the test section increased, with increased participation from higher frequencies in the range. Film and slug body liquid holdups are strongly related to the observed deflection amplitudes.
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Pipeline transient behavior (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract The fall and upstroke characteristics of bypass plunger are investigated for conventional and continuous flow plunger lift operations using experimental and field data. The bypass plunger's operational boundaries are compared with those of two-piece plungers. Clutch failure is also evaluated. Bypass and two-piece plungers were tested in static and dynamic conditions to compare their fall drag characteristics with two different tubing and plunger sizes. Casing pressure buildup was used to surface the bypass plunger to represent the conventional plunger lift type of operation for the upstroke tests. Continuous gas and liquid injection were used to achieve multiphase flow conditions for bypass plunger experiments. Experimental findings retrieved from the study were combined with mechanistic models to predict fall and upstroke stages of the bypass plunger in the field conditions. Multiphase flow simulator results were presented, and its effect on plunger lift mechanistic models were discussed. In the static facility, bypass plungers were found to have a higher drag coefficient, falling slower than sleeves of the same height. The drag coefficient values for 1.9-in OD and 2.34-in OD bypass and sleeves were similar, suggesting that plungers tested for a given tubing size can be extrapolated to others. The bypass plunger was suitable for conventional and continuous flow plunger lift operations. The 19.5-in bypass plunger and 9-in sleeve fall and upstroke velocities were analogous. Visual observations showed that the bypass plunger clutch mechanism may not get fully opened if the plunger does not hit the lubricator fast enough. The well test, high-frequency pressure, and plunger lift data of five wells from the Permian basin were analyzed. The continuous flow plunger-lift mechanistic models are used to estimate the bypass plunger cycle. The total cycle time and plunger run per day estimations matched with average run-time and trip-count field data. The study presents the bypass plunger lift's cycle mechanics, operational limitations, and comparison with two-piece plungers in different tubing sizes. The experimental and field data of bypass plungers, mechanistic model benchmarking, and potential bypass plunger lift applications are featured.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (25 more...)
Abstract The gas-liquid downward flow is the least studied flow condition, which is critically important in predicting the flow between two platforms in offshore systems and wells for CO2 injection for CCSU applications. These processes require a reliable prediction of pressure drop and phase fraction. This paper focuses on the liquid viscosity effect on downward gas-liquid flow. Flow patterns, pressure drop, and liquid holdup are measured for downward vertical and near-vertical flow. The acquired data are compared with available mechanistic models, and the discrepancies are discussed. The 2-in ID oil/water/gas outdoor facility of The University of Tulsa Fluid Flow Project has been used for this effort. The facility is 22.72 m long and is operated with medium viscosity oil and air. Liquid viscosity is fixed at 40 and 70 cP by controlling the temperature. Superficial liquid and gas velocity ranges are 0.1 โ 0.3 m/s and 0.5 โ 5 m/s, respectively. The inclination angle is varied between 60 and 90ยฐ with a 10ยฐ increment. Visual observations and Capacitance Sensor (CS) signals are utilized to determine flow patterns. Facility instrumentation also allows measuring pressure gradient and liquid holdup. Two classic flow patterns observed were: stratified and annular flows. Stratified is further sub-classified as stratified wavy and stratified wavy with a thin film. Annular flow is sub-classified into falling film, liquid slip, and wavy annular. Experimental interfacial shear stress (ฯI) and wall-liquid shear stress (ฯWL) were compared to model values. Existing models and commercial simulators show very poor performance in downward flow and need further improvements.
- Research Report > New Finding (0.65)
- Research Report > Experimental Study (0.50)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Downhole and wellsite flow metering (1.00)
Abstract An experimental and theoretical investigation of the mechanisms of downhole gravity (shroud type) separation under slugging conditions has been conducted. Based on the observations, a new mechanistic model for downhole separation failure has been proposed. A new facility has been designed and built to represent a section of a gravity-driven inverted shroud type separator at the primary separation region. This study focuses on how the Taylor bubble (large bubble) interacts with the primary separation region. High-speed video recordings were used to analyze the interaction in detail. The results show that the Taylor bubble starts to be ingested into the inverted shroud when a critical liquid flow rate is reached. This critical flow rate separates the regions of the โhigh efficiencyโ and โdisrupted efficiency.โ A gas ingestion criterion model has been proposed based on a simplified slug flow model in vertical wellbore conditions. The model has been evaluated with data from the large-scale downhole separator facility with favorable results. We present the results of the first experiments to investigate the main mechanisms of gas-liquid separation in a gravity-driven inverted shroud type separator under slugging conditions. Identifying the mechanisms is the first step in developing mathematical models for downhole separation design and troubleshooting. The results could be applied to a horizontal well configuration where electrical submersible pumps are deployed in larger GOR environments.
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Abstract A mechanistic plunger lift tool was developed to estimate cycle mechanics, liquid unloading, and avoid well integrity issues. The study focuses on the plunger-assisted gas lift (PAGL) wells operated with the two-piece plunger under low tubing wellhead pressure conditions. The fall and upstroke stages of two-piece plungers were analyzed for eleven wells from San Juan Basin. The fall velocity estimation for plunger parts was modeled for; shut-in, transitional and multiphase flow conditions. Fall and upstroke velocities were estimated using drag-based models that feature drag coefficient, wall factor, and two-phase correction. The field data up to three years from each well was compared with the PAGL Tool estimations. The downhole pressure gauge data was analyzed and compared with plunger liquid slug estimations for two wells. Plunger inspection data and shut-in, afterflow time effects on liquid loading and plunger cycle time were investigated. The PAGL Tool estimations for full-cycle times were in fair agreement with daily production and plunger lift data of 10 of the 11 wells. The field data and tools estimations for 2- 7/8 in tubing show that two-piece plungers can fall against 600 STB/d liquid and 2 mmscf/d gas production rates with little to no shut-in times, and lower operational boundary for surfacing can be as low as 300 mscf/d without requiring a pressure buildup. The lower gas production being sufficient for upstroke movement increases the operational range of PAGL. The main reason was the low wellhead pressure, which causes gas expansion and higher gas velocity along the well to increase drag force hence the upstroke capability of PAGL with lower gas production rates. The downhole pressure data was compared with multiphase flow simulation with plunger hydrostatic pressure removal. Higher afterflow time settings were shown to be increasing the arrival time data, which suggests a growth of the liquid accumulation at the bottom hole. Field data shows that plunger lift operation is not limited to wells with marginal production, and it can be used before liquid loading conditions. The hydrostatic pressure removal with plunger lift is shown with field data analysis and plunger lift tool estimations. The study presents that the continuous flow plunger lift operational range can be extended to lower production rates if lower wellhead pressure is achieved.
- North America > United States > New Mexico (0.34)
- North America > United States > Texas (0.28)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > New Mexico > San Juan Basin (0.99)
- North America > United States > Colorado > San Juan Basin (0.99)
- (2 more...)
Summary The objective of this study is the experimental and theoretical investigation of the fall mechanics of continuous flow plungers. Fall velocity of the two-piece plungers with different sleeve and ball combinations and bypass plungers are examined in both static and dynamic conditions to develop a drag coefficient relationship. The dimensionless analysis conducted included the wall effect, inclination, and the liquid holdup correction of the fall stage. A fall model is developed to estimate fall velocities of the ball, sleeve, and bypass plungers. Sensitivity analysis is performed to reveal influential parameters to the fall velocity of continuous flow plungers. In a static facility, four sleeves with different height, weight, and outer diameter (OD); three balls made with different materials; and a bypass plunger are tested in four different mediums. The wall effect on the settling velocity is defined, and it is used to validate the ball drag coefficient results obtained from the experimental setup. Two-phase flow experiments were conducted by injecting gas into the static liquid column, and the liquid holdup effect on the drag coefficient is observed. Experiments in a dynamic facility are used for liquid holdup and deviation corrections. The fall model is developed to estimate fall velocities of the continuous flow plungers against the flow. Dimensionless parameters obtained in the experiments are combined with multiphase flow simulation to estimate the fall velocity of plungers in the field scale. Reference drag coefficient values of plungers are obtained for respective Reynolds number values. Experimental wall effect, liquid holdup, and inclination corrections are provided. The fall model results for separation time, fall velocity, total fall duration, and maximum flow rate to fall against are estimated for different cases. Sensitivity analysis showed that the drag coefficient, the weight of plungers, pressure, and gas flow rate are the most influential parameters for the fall velocity of the plungers. Furthermore, the fall model revealed that plungers fall slowest at the wellhead conditions for the range of gas flow rates experienced in field conditions. Lower pressure at the wellhead had two opposing effects; namely, reduced gas density, thereby reducing the drag and gas expansion that increased the gas velocity, which in turn increased the drag. Estimating fall velocity of continuous flow plungers is crucial to optimize ball and sleeve separation time, plunger selection, and the gas injection rate for plunger-assisted gas lift (PAGL). The fall model provides maximum flow rate to fall against, which is defined as the upper operational boundary for continuous flow plungers. This study presents a new methodology to predict fall velocity using the drag coefficient vs. Reynolds number relationship, wall effect, liquid holdup, deviation corrections, and incorporating multiphase flow simulation.
Abstract Gas lift has been widely used for unconventional reservoirs, especially during recent years. Most of the previous experimental studies on gas lift were conducted at a constant mass flow rate boundary condition. The current study presents an experimental study that investigates gas lift performance at similar field conditions in which the production rates are driven by the formation pressure. The experiments were conducted in a large-scale experimental facility to study gas lift operations in a toe-down gas lift well. Gas was injected at various rates through casing and tubing annulus to the end of the tubing. The formation gas was supplied by a gas tank regulated at two pressure conditions, which correspond to no production and the last stable production point, respectively. Water was used as the formation liquid phase and injected at the toe. Two liquid flowing conditions were investigated, which were a constant liquid flow rate and constant liquid permeability. As expected for a production system with constant pressure boundaries, formation gas production rate increases first with increasing gas lift injection rate until it reaches a maximum, beyond which flow in the tubing becomes frictional-dominated, and gas production rate starts to decrease. It is found that gas lift affects the flow behavior at the upstream of the injection point. The total liquid inventory reaches a minimum at the point where the maximum gas production rate is observed. The impact of gas lift on system stability was also analyzed. Gas lift can help the well to produce when it is already dead at naturally flowing conditions. However, insufficient gas injection can kill the well faster than natural flow.