Gas Lift System Research Articles

New Anchor Extends Insertable Progressing-Cavity-Pump Applications

Young Technology Showcase In artificial-lift applications, a new anchoring device for insertable progressing-cavity pumps (I-PCPs) extends I-PCP applications to a larger set of candidate wells. The I-PCP anchor allows an I-PCP to be run, landed, operated, and removed from a tubing string in the absence of a previously installed pump-seating nipple (PSN) typically required for installation. Conventional PCPs are installed by running the stator assembly on the bottom of the tubing string and the rotor on the bottom of the rod string. In contrast, with an I-PCP, the entire pump assembly is installed by the rod string and landed inside the tubing string. This allows the pump to be pulled and rerun by the rod string. The primary advantage of this system is the elimination of costly and time-consuming tubing pulls to change worn or damaged pumps or to switch to different pump sizes and configurations as downhole pumping requirements change. I-PCPs are conventionally installed with a PSN in the tubing string and a corresponding set of seating rings in the pump assembly. While this method provides a reliable method of landing, it also requires that the PSN be originally installed and it limits the positioning of the pump to the associated pump-seating location. Weatherford’s Flexisert I-PCP anchor is an installation method that does not require a PSN to be in place. The impetus for the anchor’s development was the recompletion of depleted offshore gas lift wells to PCP systems. The anchor makes this possible because it allows the gas lift system to be left in place while inserting the new anchor. In general application, the I-PCP anchor allows I-PCPs to be run in wells that are not equipped with a PSN, or where the PSN is at the wrong location or has specifications that are unknown. The anchor system also provides an artificial-lift option to reactivate old wells without pulling the tubing.

Gas Lift Optimization of an Oil Field in Malaysia

Gas lift is an artificial lift method which is commonly used in offshore operation with sufficient gas sources as it consumes minimum space on the platform. Gas lift operates by injecting a high pressure gas down through the tubing casing annulus of a well and the injected gas enters the tubing through a gas lift valve installed on the tubing. Gas lift increases production by two means, density reduction of oil column inside the tubing so that the flowing bottom-hole pressure which is affected by the hydrostatic pressure of the fluid column is reduced and by providing external energy to the oil as the gas expends.Reducing the bottom-hole pressure will improve the drawdown of the well. A production well is modelled by using a production modelling program, Integrated Production Modeling (IPM) Prosper to analyze the production performance at various conditions. A base case model is developed from the production data of an actual oil field to simulate the performance of the actual well without gas lift system. Later, the gas lift is added to the model and the performance was compared with the base case model. The gas parameter was also studied to determine the optimum injection gas condition for maximum oil production. The gas injected at 1490m can be achieved by injecting the gas with 1200 psi, l300 psi or 1400 psi. However, the optimum gas injection pressure was determined to be at 1400 psi as the design shows that the required unloading stage is the least. The optimum gas injection rate was determined at 5 MMscf/d with the estimated net revenue is the highest. For injection gas gravity, the lighter gas was determined to be the optimum selection since it gives significant reduction of FBHP (Flowing Bottom Hole Pressure) with less hydrostatic pressure inside the tubing column.

A Study of Continuous Flow Gas Lift System Using CFD

Gas lift optimization has been a point of interest for some decades in order to increase production in oil fields. Despite that there are still lacks of user friendly software in gas lift optimization. The ultimate goal of this study is to develop user friendly program using commercial Computational Fluid Dynamics (CFD) software for optimization of continuous flow gas lift for single well. GAMBIT 2.3.16 was used for modelling the tubing string prior the simulation process. Two-phase CFD calculations using Eulerian–Eulerian model and commercial CFD package FLUENT 6.0 were employed to calculate the gas-liquid flow in the string. The depth and the rate of gas injection were the main parameter tested. The simulation results showed that the highest velocity of flowing fluid was observed when the gas was injected at the lowest point, which is at 5 m from the casing shoe in this study. The velocity of flowing fluid was increased by 1.7% when the gas injection rate increased 20%. This interrelationship was observed with regard of the decrease in liquid column density. CFD is capable in aiding faster continuous flow gas lift optimization process.

Simulation of gas-liquid two phase flow in upriser pipe of gas-lift systems

Gas-lift pumps are devices for lifting liquid phase incorporating the gas phase to be injected in the bottom of liquid column. They are widely used in various industrial applications such as oil extracting in petroleum industries. Gas-liquid flow being the main part of the flow through these systems, flowing in vertical pipes of gas-lift pumps has different regimes namely bubbly, slug, churn and annular. Considering each numerical method to be appropriate for modeling a certain flow regime, a suitable numerical approach is crucial to correct simulation of gas-liquid flow in upriser pipe of gas-lift systems. In this paper, two main approaches namely the volume of fluid (VOF) and Eulerian model are used for modeling of the two phase flow in the upriser pipe of the airlift system. The numerical results are compared with the experimental investigations to validate the numerical models. The two phase flow regimes simulated by the numerical method were compared with the available flow regime map in the literatures. The results indicate that using the VOF is more appropriate for modeling of bubbly and slug flows while the Eulerian model fits better for only annular flow regime.

A Novel Approach for Optimization of Gas Lift System: Pilot Tests Results

A Novel Approach for Optimization of Gas Lift System: Pilot Tests Results

Determining the optimal amount of gas that is injected for the Gaslift system work

The problem that arises in the work of wells in the oil field Gaslift Amal to individual wells do not always have the necessary amount of gas for injection. Therefore, in a borehole at a depth of injection, the operating valve, there is not enough dynamic pressure for the removal of oil on the surface. This is particularly evident in wells with increased production of formation water. For this reason, the paper presents the methodology and drafted model for optimal allocation of the amount of gas injected into each well in the work gaslift of the system. The methodology for the allocation of quantities of gas injection through the so-called cumulative curves based on the dynamic characteristics of each well.

Real Time Optimization of a Natural Gas Lift System with a Differential Evaluation Method

This article presents a method for optimizing and controlling an oil production system using a natural gas lift concept. Ever increasing development of Smart Well technology and various applications of down-hole monitoring and controlling instruments along with new methods of data acquisition/transmission make it possible for the natural gas lift system to be controlled and optimized more effectively and faster than before. With this technology it is possible to monitor the down-hole conditions of gas and oil zones and to control the inflow valves in gas and oil zones. In this work, a proportional integral differential feedback controller has been used to smartly control the entrance of gas from the gas zone to the oil well. The optimizer determines the optimal values of gas injection setpoint for the controller to manipulate the inflow of gas to the oil reservoir. The problem will be more complex when the available gas in the gas zone is limited. The optimization of this process has been done by a Differential Evolution method.

New Methods Developed to Manage Subsea Vibration-Induced Fatigue

Technology Update The vibration assessment of subsea systems has largely been limited to vortex-induced vibration of riser systems and unsupported pipeline spans (i.e., environmental loading) caused by flow past the outside of a riser or conductor. But now, piping vibration caused by process excitation is becoming an issue on manifolds and jumpers, in part associated with increasing production rates. Though the likelihood of a failure is low, the consequences can be high, resulting in an unacceptable level of risk. As well as piping integrity issues, additional vibration-related problems have also been experienced with valves and instrumentation. Process Excitation Mechanisms There are a number of different sources of excitation and these generally depend on the type of process fluid within the system. The following three mechanisms are the most common. Flow-Induced Turbulence. This is caused by broad band, low-frequency energy, generated by “single phase” turbulent flow through valves, expansions and bends—essentially anything that disturbs the flow. This can lead to excitation of the low-frequency modes of the piping system by energy transfer from fluid momentum to the pipe, resulting in low-frequency vibration (up to possibly 50 Hz). This is widespread in most processes and depends heavily on the velocity and density of the fluid. Multiphase Flow. This encompasses slug, bubble, annular, and churn flow. The frequency range of the resulting excitation is heavily dependent on void fraction and flow regime. Flow-Induced Pulsation. This is linked to gas flow through a flexible riser or jumper, sometimes known as the “singing riser.” This is where gas across the internal corrugated geometry within the flexible piping causes vortex generation. This can cause a pressure fluctuation, or pulsation, with a frequency and amplitude that are dependent on the gas velocity. This pulsation can drive the flexible piping at either end at very high frequencies—in some situations as high as 1,000 Hz—causing fatigue damage to accrue very quickly. The phenomenon is typically only experienced on dry gas systems, so it can be an issue on gas export, gas injection, and gas lift systems. The Hidden Threat Pipe design and construction can present a number of unique challenges in subsea developments, given their remoteness and complexity to access. A vibration issue may occur subsea without any obvious sign topsides.

Integrated gas lift system optimization

An intelligent genetic algorithm has been developed to simultaneously optimize all effective factors, namely, gas injection rate, injection depth and tubing diameter towards the maximum oil production rate with the water cut and injection pressure as the restrictions. The results were field tested in three wells in three different fields located in southern Iran. The field data verified the accuracy of the used model. There was a notable production increment compared to the master development plan of the fields.

The optimization of continuous gas lift process using an integrated compositional model

Abstract Artificial gas lift is frequently used to boost the production rate of mature oil fields. The ultimate aim is to design and operate a gas lift system that can maximize the economic return of the well over a long period. This may require adjustment of the gas injection rate, tubing diameter and separator pressure at some specific intervals. In this study, an integrated mathematical model was developed in order to track the spatial and temporal variation of components in the process. The model was coupled to a combination of genetic algorithm and the Marquardt optimization method in order to determine the process parameters that optimize the long-term economic return of an oil field. The results show that the maximum net present value is achieved when the production lifetime is divided into a suitable number of consecutive operation intervals with different tubing diameter, lift gas injection rates and separator pressures and an optimum value for tubing diameter.

Linear and non-linear analysis of flow instability in gas-lift wells

Abstract Linear and non-linear analyses of flow instability in continuous gas-lift wells were performed in this study. The linear analysis is based on a modified gas-lift stability criterion that takes into account compressibility of the mixture below the injection point and is applicable to saturated reservoirs. The analysis of non-linear dynamics and stability of the well was performed using direct numerical integration in the time domain of the governing equations describing the gas-lift system. The transient gas-lift well model developed comprises of a model of transient three-phase gas–oil–water flow in the wellbore, a transient model of gas flow in the casing annulus, and a pseudo-steady flow model in the reservoir. The multiphase flow model used is based on the drift-flux theory. Stability boundaries predicted by both linear and non-linear analysis were compared with field data published in a previous study; both types of analysis reproduced the data. The effects of the main well design and flow parameters on the frequency and amplitude of the oscillations during heading in a typical gas-lift well were studied. It was found that flow instability results in the oil production loss, which depends on severity of heading. The largest reduction in oil production takes place in case of the most severe heading in the well (flow instability with the largest amplitude of production rate oscillations). An increase in the lift gas consumption is required to compensate for the production losses caused by heading. An increase in the depth of the injection point may result in heading and an increase in the operating costs caused by the increase in the lift gas consumption. An increase in the separator pressure has a destabilizing effect. At high separator pressures the well can experience two modes of instabilities: casing heading and density-wave oscillations.

Integrated Gas Lift System Optimization

Integrated Gas Lift System Optimization

Efficiency of Blenke cascade system for continuous bio-ethanol fermentation

A gas lift-system with inserts (so-called Blenke cascade system) for continuous bio-ethanol fermentation was constructed. Gas introduced at the bottom of the column created toroidal vortices in the fluid cells between inserts, enhancing mixing and improving residence time behavior without stirring equipment being necessary. The parameters mash type, start-up strategy, yeast-recycle model and yeast separation were studied concerning the efficiency of the ethanol production.The best results obtained were for a filtered mash, a double saccharification principle (DSP), a batch start-up strategy, an activation-recycle model and a lamella settler connected in series with a small conventional gravitational settler for yeast cells separation.Using this system, the fermentation residence time was τ=4–5.5h, depending on substrate type. Eighty five percent of the yeast cells could be separated.High volumetric ethanol productivity (Qp=20.43g/Lh) and yield Ey=98% were achieved. Continuous fermentation, yeast recycling and sedimentation were contamination-free processes.

Partial-SAGD Applications in the Jackfish SAGD Project

Summary With steam-assisted-gravity-drainage (SAGD) operations, there will be times that the producer downhole temperature falls below the desired level. This situation may occur when a shut-in is required because of facility or well operational issues. Cooling bitumen and steam condensate, which continue to drain and raise the liquid level over the producer, cause difficulties with the restart. The producer could also cool if the well pair is converted prematurely from circulation to full SAGD mode. A variety of artificial-lift technologies have been applied in field applications. However, with its dual-tubing-completion design and gas lift system, Devon has successfully used partial SAGD methods to optimize restart strategies and effectively deal with times when the producer unexpectedly cools. This paper describes three SAGD operating modes used by Devon at Jackfish: full SAGD, semi-SAGD, and partial SAGD. During partial SAGD, the fluid return from the injector stops while steam injection continues down either the long tubing (LT), short tubing (ST), or the annulus. The producer continues to be circulated with the appropriate steam-injection rate into the LT and fluid returns up the ST. Numerical-simulation results associated with partial SAGD are presented. Partial-SAGD applications at the Jackfish SAGD project are discussed.

Study on the Drag Force Coefficient between Gas and Liquid on the Gas-Lift System to Recover the Methane Hydrate

The gas-lift method is expected as a method with the small running cost in order to recover the methane hydrate from the seabed. The methane gas injection makes the upward flow of the sea water, and it is necessary to establish the model able to estimate the sea water flow rate to the injected gas. Since the intended system is too large to conduct the experiment and multi-dimensional direct numerical simulation, this paper focuses on the calculation of the multi-phase flow in the one-dimension with the proper model equation for external forces. A drag force coefficient between gas and liquid is derived considering the liquid flow by the surrounding hydrostatic pressure. As a result, calculation with the proposed equation fairly agrees with the gas-lift experiment, compared with results with the other proposed model equations.

Application of CIP Method to Two-Phase Flow in Gas-Lift Pumping System to Reduce Numerical Dissipation

ABSTRACT Traditionally, the gas-lift pump has been used to lift corrosive or toxic liquid due to its simple structure and maintenance. It is also considered as a technically feasible system for the development of deep-ocean minerals and as a means to sequestrate CO2 gas into the ocean. Donor-cell scheme or Forward-Time and Backward- Space (FTBS), which is commonly used in solving advection equation such an air-lift system, is very stable but causes numerical diffusion. In order to reduce numerical diffusion or dissipation by the first-order upwind scheme, CIP (Cubic-Interpolated Propagation/Constrained Interpolation Profile) has been applied to bubble and slug flows in a gas-lift pumping system. The GLAD (Gas-Lift Advanced Dissolution) model using CIP method were validated by comparison with gas-liquid two-phase experiments and the effectiveness of the CIP method over the typical one has been demonstrated from the simulation of gas-liquid two-phase slug flow.

The Economic Optimization of a Continuous Gas Lift System Considering Lift and Cycle Efficiency in a Mature Oil Field

This article presents a numerical approach for the profit maximization by allocating an optimal injected gas in a continuous gas lift system. A performance curve of gas lift was designed that takes into account both lift and cycle efficiency. Piecewise cubic hermit interpolating polynomial is performed as a tool of interpolation to achieve a minimum error and a quantitative evaluation. A robust economic function and simulate annealing are integrated to determine the independence of decision variables and lift-gas rate, which yields a maximum profit. The model applied for a mature oil field reveals that the volume of injected gas reduces significantly by 63% and the revenue increases up to 13% compared with a conventional production optimization. The developed model will be applicable enough to enhance the profit in continuous gas life system.

Annular-Velocity Enhancement With Gas Lift as a Deliquefication Method

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 130256, ’Annular Velocity Enhancement With Gas Lift as a Deliquification Method for Tight Gas Wells With Long Completion Intervals,’ by S.A. Pohler, SPE, W.D. Holmes, SPE, and S.A. Cox, SPE, Marathon Oil Corporation, originally prepared for the 2010 SPE Unconventional Gas Conference, Pittsburgh, Pennsylvania, 23-25 February. The paper has not been peer reviewed. It is common practice in the industry to complete multiple reservoirs in a single wellbore to establish commercial production rates from tight gas completions. In some cases, these zones are separated vertically by several hundred to more than 1,000 ft. The deliquefication of these completions is one of the most challenging problems facing our industry. Many of the deliquefication methods currently being used are effective over only a portion of the wellbore. Introduction It is common practice to complete tight gas wells with the tubing tail above the bottom perforation. This completion practice allows static liquid to stand across the lower set of perforations. Static liquid standing across the perforations promotes increased near-well liquid saturations through a process of spontaneous imbibition. The imbibition process is a damage mechanism that can be present upon initial completion and can continue throughout the productive life of the well if allowed to form through ineffective liquid-removal/completion practices. There are a number of different methods currently in use for the deliquefication of gas wells. Some of the more common are plunger lift, chemical-foam lift, and conventional pumps (i.e., rod pumps, electrical submersible pumps, and progressing-cavity pumps). Each method has drawbacks when it comes to deliquefying wells with long completion intervals. Effective liquid removal can improve overall well performance significantly. However, an effective system cannot ignore the potential presence of a static liquid column. Current completion technology has been found to have limited effectiveness when long productive intervals are involved. Therefore, a modified continuous-flow gas lift system is proposed that includes a packer and crossover system and that allows for gas lifting the well below the bottom perforation. The details of this completion process and its field applications are discussed in the body of the full-length paper.

Technology Focus: Artificial Lift (July 2010)

Technology Focus There is nothing wrong with change, if it is in the right direction.—Winston Churchill In the artificial-lift community, do we understand the current technology well enough to know what improvements are needed? Are we advancing technology or just providing “band-aid” solutions because the root cause of failure is not understood? Where does the industry need to focus effort—technology development or reduction of failures caused by poor design, installation, and operating practices? Questions such as these were the driving force behind two industry consortiums to develop databases to collect thousands of electrical-submersible-pump (ESP) and progressing-cavity-pump (PCP) installation and failure records for performance analysis and benchmarking (www.esprifts.com and www.pcprifts.com, respectively). Data collection and its analysis from the databases have become very valuable in understanding the performance and reliability of these lift systems. Some of the lessons learned from the PCP consortium will be presented at the 2010 SPE Progressing Cavity Pumps Conference (PCPC) to be held in Edmonton, Alberta, Canada, in September. Both the PCP and ESP industries have been impaired by a lack of standardization, especially in the areas of equipment rating, testing, and nomenclature. In 2009, the International Organization for Standardization (ISO) published a revised ISO 15136-1 as an international standard for PCP equipment, and a session on its use will be presented at the 2010 SPE PCPC. Currently ISO 15551-1, which is expected to be the new international standard for ESP systems, is in development and will, undoubtedly, be a hot topic for discussion at the 2011 SPE ESP Workshop in Texas in April. The reliability-improvement consortiums and the development of new international standards are helping to define where we are today as an industry and provide clear direction for technology advancement. The three artificial-lift papers featured in this section contain unique solutions that may become starting points from which other developments may evolve: The geared centrifugal pump has a distinctive downhole-transmission assembly that offers an opportunity for other pump configurations to be driven by a rod string, a method to use gas lift above and below a packer in a single completion with long perforation intervals might expand to areas other than unloading tight gas wells, and the use of hybrid data-evaluation models to visualize and analyze production information better may become an essential tool for artificial-lift selection and optimization. The papers selected for additional reading also contain innovative artificial-lift solutions. Artificial Lift additional reading available at OnePetro: www.onepetro.org SPE 124926 - “Real-Time Diagnostics of Gas Lift Systems Using Intelligent Agents: A Case Study” by G. Stephenson, SPE, Occidental Petroleum, et al.(See JPT, May 2010, page 55, and SPE Prod & Oper, February 2010, page 111.) SPE 124646 - “Application of Beam-Pumping Wells’ Energy-Saving Rebuilding Techniques in Daqing Oil Field” by Wang Fengshan, SPE, Daqing Oilfield Co., et al. SPE 124515 - “Plunger-Lift Modeling Toward Efficient Liquid Unloading in Gas Wells” by G. Chava, SPE, Texas A&M University (now at Chevron), et al.(See SPE Proj Fac & Const, March 2010, page 38.)

Real-Time Diagnostics of Gas Lift Systems: A Case Study

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124926, ’Real-Time Diagnostics of Gas Lift Systems Using Intelligent Agents: A Case Study,’ by G. Stephenson, SPE, Occidental Petroleum; R. Molotkov, SPE, Weatherford; and N. De Guzman, SPE, and L. Lafferty, SPE, Intelligent Agents Corporation, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October; revised for publication. The paper has been peer reviewed. Published: February 2010 SPE Production & Operations, page 111. One problem related to the operation of gas lift wells is the ability to identify underperforming wells and to address the underlying issues appropriately and in a timely manner. This problem is compounded by a trend toward leaner operations and relative scarcity of application-specific domain knowledge. A method is presented that leverages real-time data, gas lift domain expertise, and proven steady-state analysis techniques in a desktop software application. Introduction For cases in which these resources are limited or unavailable, automation technology could be a solution. To assist production engineers in the well-by-well optimization of gas lift systems, a system was developed that uses intelligent software agents that leverage both real-time data and gas lift domain knowledge to assist engineers in these well-by-well optimization tasks. Challenges With Historical Approach One of the most fundamental challenges is that the historical approach tends to be both reactive and episodic in nature, resulting in missed opportunities for production enhancement. Much of this work requires individuals with specialized artificial-lift-domain expertise, which is increasingly scarce as the demographics of the industry change. The ability to detect and address the numerous opportunities in a field is limited by the labor-intensive nature of the work and the volume of competing priorities. It is common for problems in gas lifted wells to go undetected for months or even years because gas lift is such a forgiving artificial-lift method. Even those gas lifted wells that have a serious performance problem and are not producing optimally will often continue to produce fluids. With other forms of lift, failures tend to be catastrophic in nature and are identified and addressed much more quickly. Addressing the Need A system was developed to provide real-time diagnostics of continuous gas lift wells. The system enables decisions that optimize wells. The system provides engineers with the status of all gas lifted wells under their control. Software agents monitor the wells’ situation by collecting and filtering data, assessing the meaning of those data, recommending actions for correcting problems and responding to threats, and explaining their assessment results and recommendations. Agents can detect the initial symptoms of a problem and prompt for corrective action before well performance degrades seriously. The performance of these key functions enables surveillance engineers to optimize many more wells on a continuous basis. The agents integrate continuous data, such as pressure readings, with well-test data and predictions from commercially available systems-analysis tools, and use diagnostic principles stored in a knowledge base to determine each well’s condition and recommend corrective action. The agent reviews all gas lifted wells in the field and prioritizes recommended actions in accordance with pre-established criteria that include increased production potential and possible cost efficiencies.