Continuous Gas Lift Research Articles

A method for comparison of lifting effects of plunger lift and continuous gas lift

Abstract As a kind of intermittent gas lift, the plunger lift can replace the continuous gas lift in a certain period of time to improve the lifting efficiency. However, the working system of plunger lift is different from that of continuous gas lift, so their lifting effects cannot be compared intuitively. In this paper, taking Zhanaroal oilfield as an example, an experiment to compare the lifting effects of plunger lift and continuous gas lift was designed. Taking the gas consumption under the same liquid lifting volume as the starting point, the stable lifting conditions of them were firstly determined; then, based on the experimental data under the stable lifting conditions, their gas consumption under the same liquid lifting volume was calculated; the lifting effects of them under different liquid volumes were compared, and the feasibility of replacing continuous gas lift with plunger lift in the study block was confirmed; moreover, two wells tested have achieved good effect.

A stochastic optimization model for short-term production of offshore oil platforms with satellite wells using gas lift

Continuous gas lift is a popular method to enhance productivity in offshore oil platforms. We propose a steady-state two-stage stochastic programming model to maximize production, where the first-stage injection level determines the production potential, while recourse actions ensure capacity and platform constraints for each uncertainty realization. In particular, we develop a concave approximation of the performance curve that incorporates uncertainty in the water cut (WC) and gas–oil ratio (GOR). We generate WC and GOR realizations using a two-step data-driven approach: we extrapolate the trends using a $$\ell _1$$ -filter, and bootstrap historical deviations to generate future realizations of WC and GOR. We present numerical results for the sample average approximation of the problem and assess the solution quality using standard techniques in the literature. Our numerical results suggest that taking uncertainty into account in the problem can lead to considerable gains.

Intermittent Gas Lift Used in Hydrate Mitigation and Flare Reduction in Algeria

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191542, “Hydrate Mitigation and Flare Reduction Using Intermittent Gas Lift in Hassi Messaoud, Algeria,” by Ala Eddine Aoun, SPE, Faouzi Maougal, and Lahcene Kabour, Sonatrach, and Tony Liao, SPE, Brahim AbdallahElhadj, and Sabrina Behaz, Halliburton, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed. Hassi Messaoud is a mature oil field with more than 1,100 production wells. Approximately half of the wells are natural flow and the other half use continuous gas lift (CGL) with concentric (CCE) strings. To reduce the usage of the high volume of lift gas, intermittent gas lift (IGL) was selected in a pilot project to evaluate its applicability in the field for wells characterized by high gas/oil ratio (GOR) and without continuous concurrent water injection (with lift gas) to dissolve salt•deposited•downhole. Production Overview Field production began in 1957. During the first 20 years, all production wells were naturally flowing; in 1980, gas lift was introduced into the field development and has remained the only artificial-lift method. Electrical submersible pumping systems have been introduced into the field recently. Of the production wells, 795 are flowing while 376 are shut in for a variety of reasons. Among the flowing production wells, 409 are naturally flowing and 386 are artificial-lift wells. Production fluids are processed by 25 separator stations throughout the field. Gas usually is compressed first at the satellite level; then, at the central processing facilities, the gas is further compressed to the pressure required for injection into the reservoir. Water is treated by the addition of surfactants. The treated water is pumped into the water-injection network to be used in both reservoir-pressure maintenance and salt wash in wells. In the field’s first years, the oil-production rate increased quickly as the number of wells grew. Since 2007, oil production has declined quickly in naturally flowing wells. The steady increase in oil production from gas-lift wells offset the fast production decline in the full field. However, the oil production from gas-lift wells has leveled off during the past 2 years, while the production from naturally flowing wells recovered slightly. The gas lift wells contribute approximately 40% of the field production. Combined Gas Network for•Reservoir Gas Injection and Gas Lift A specific challenge of the Hassi Messaoud field operation is the highly complex gas network, in which the gas-lift network is attached to the gas- injection network for reservoir-pressure maintenance. The gas lift was grown organically out of the reservoir gas-injection network. Initially, when only a small number of wells needed gas lift, this approach might have been cost- effective, but the increasing number of gas-lift wells meant that different methods had to be•considered.

Optimization of Continuous Gas Lift wells based on Well Modeling, Surveillance, Diagnostics and Lift Gas Re-allocation in a Mature Offshore Oil Field

In an oil field, the optimization study of Continuous Gas Lift (CGL) wells require to encompass the single or multiphase inflow performance within the reservoir and the outflow performance from perforations up to the first separator; along with evaluation of the effect of lift gas injection through the operating Gas Lift Valve (GLV). Mature oil fields that inherit problems of increasing trend of water cut, decreasing trend of Formation Gas Oil Ratio, both leads to further increase in demand for lift gas. To optimize a group of CGL wells sharing common manifold and pipeline, it is required to first optimize every individual well. Well problem and Instability in one well can adversely affect the well performance of other wells of the same gathering system. Literature survey shows that the CGL optimization issues were studied either focused on part of the problem or based on secondary data, and not specific to the challenges of Mature Oil Field. Hence, a study has been carried out to address the well optimization problems with CGL, specifically based on field parameters monitored in a mature offshore oil field. In this present study, development of well models of 12 CGL wells of the study area Heera Field of western Indian offshore basin were carried out, in three different simulators with same set of input data. The best fit well models were selected based on comparative error analysis for approximation of operating points by plotting inflow and outflow performance curves using Nodal Analysis approach. Production History of each well, Flowing Gradient Survey data were correlated with the real-time monitored surface measured field parameters. Deviations were analyzed based on empirical data and screening criteria were used to preliminary diagnose well problems. Simulation experiments were performed on the best fit well models for the detail diagnostic analysis. Recommendations were drawn well wise for optimization, by applying engineering judgments, correlating the simulation results with the surface parameters. Gas Lift Performance Curves (GLPC) were generated for each well by simulation experiment on well models. Non-linear functions of Production rate as a function of Gas Lift Injection Rates (GLIR) were approximated by curve fitting of GLPCs using non-linear regression. GLPC based Lift gas re-allocation problem was formulated and solved with limited lift gas quantity as constraints by Equal Slope Graphical Method and by FMINCON solver of MATLAB. Comparative results of envisaged production gain from both approach is being discussed. The integrated approach for real time monitoring of surface parameters, well model based diagnostic analysis and then further allocation of optimum GLIR to each well shows better results than addressing part of the problem for optimization of CGL wells. Lessons learnt from this ‘integrated optimization approach’ were presented, which will be useful in optimization of CGL wells as standalone well or as a part of a group of wells, especially with similar constraints of mature oil field.

A pragmatic approach for optimizing gas lift operations

The oil flow rate in a single vertical well undergoing gas lift operations is complicated by three factors: (1) The flow is driven by gas injection, in addition to the fluid flow potential gradient applied along the well, (2) the well is interfaced with a porous and permeable reservoir contributing with a fluid feed, and (3) the wellbore geometry may consist of concentric pipes of varying diameters and lengths, rather than a single-diameter pipe. Dimensional analysis is applied to this complex, highly nonlinear production problem, in order to develop empirical models for predicting the optimal gas injection rate and the maximum oil production rate that may be produced from continuous gas lift operations. Two pairs of coupled dimensionless groups are revealed. The first pair consists of a dimensionless pressure drop (π1) adjusted to the complex wellbore geometry, and a dimensionless ratio of kinetic to viscous forces (π2) which accounts for the porous medium feed. A constructed database for 388 vertical wells producing by continuous gas lift operations has been used to validate the dimensionless groups. A power-law relation is revealed between the dimensionless groups π1 and π2, allowing to construct an analytical model for predicting the maximum oil production rate that corresponds to the optimal gas injection rate. The second pair consists of two groups denoted χ1 and χ2. The group χ1 is a dimensionless pressure drop with adjustment being augmented to account for the temperature effects on gas flow. Similar to π2, the dimensionless group χ2 is a ratio of kinetic to viscous forces, adjusted to account for the porous medium feed. However, χ2 is a function of the injection rate, instead of the oil production rate. Likewise, a power-law relation is revealed between χ1 and χ2, allowing to construct an analytical model for predicting the optimal gas injection rate. All power-law relations yield high correlation coefficients when the validation data are segregated according to a discrete productivity index. The analytical models developed by applying dimensional analysis appear to capture the physical controls of gas lift operations. Intuitively, the optimal gas injection rate depends on the pressure gradient along the pipe, the wellbore geometry, the temperature conditions at the bottom of the well and in the stock-tank, the oil density, and on the productivity index. Similarly, the maximum oil production rate, corresponding to the optimal gas injection rate, depends on the pressure gradient along the pipe, the wellbore geometry, the oil density, the productivity index which is implicitly affected by the oil permeability, and viscosity. Unlike multivariate nonlinear regression analysis, the application of dimensional analysis for deriving the analytical models, presented in this study, does not require a presumed functional relationship. In retrospect, dimensional analysis evades the guessing process associated with nonlinear regression analysis.

Valve nozzle shape effect on gas lift system performance

Experiments were carried out using conical, bevelled entrance, bullet and orifice gas lift valve nozzle shapes with port diameter of 5 to 12 mm to study the effect of gas lift valve nozzle shape on the continuous flow gas lift system efficiency. A nitrogen-glycerin with nitrogen injection rate of 0.033 to 0.167 L/s flow through 50 mm diameter transparent vertical pipe and 3 m height to simulate a continuous flow gas lift system. Taylor bubble length and liquid produced mass were measured. The flow pattern was observed and the image was recorded using digital single-lens reflex camera. It was found that only slug flow occurred and gradual conical nozzle shape enlargement reduced the energy loss within the valve. The overall results show that conical nozzle produced the highest efficiency due to the less energy losses within the valve nozzle and most stable gas flow achieved in the fluid column pipe. [Received: December 24, 2015; Accepted: June 6, 2017]

The Critical Investigation on Essential Parameters to Optimize the Gas Lift Performance In “J” Field Using Prosper Modelling

The declining reservoir, oil production and pressure depletion with the well being produced, the results of the investment of the well will also decrease. For that there needs to be energy that can help to lift the fluid to the surface.
 One of the artificial lift methods that can be used is a gas lift. Gas lift is a method commonly used when there is a natural gas source as an injection gas supply. The selection of the artificial lift method is based on several considerations, namely the reservoir conditions, fluid conditions, well conditions, conditions on the surface, availability of electricity, availability of gas, and sand problem. The influential parameters in the selection of gas lifts include: Productivity Index (PI), Gas Liquid Ratio (GLR), depth of the well and driving mechanism from the reservoir.
 The Gas Lift that the production optimization wants to do is the injection system in a Continuous Gas Lift. Used in wells that have a high Productifity Index value. Where in the LB field to be analyzed, the Productifity Index value is 2.0 bpd / psi.
 This study intends to optimize a gaslift well performance as an effort to maximize the results of well production.
 Based on the research that has been done using Prosper Modeling on the “J” field, the following conclusions are obtained the effect of pressure and viscosity on the gas lift well flow rate in this condition can be said to be efficient, because the conditions / pressure given at temperatures below 300 F can reach the miscible condition and from the results of determining the optimal conditions to get the best well performance, obtain an optimal liquid rate of 1829.4 STB / D with an oil rate of 36.6 STB / D.
 
 Keywords: Gas lift, Optimization, Immiscible Pressure, Viscosity

An improved optimization method in gas allocation for continuous flow gas-lift system

The primary objective in the continuous flow gas-lift operations is to inject an optimal gas volume for a group of wells to maximize oil production. Due to the gas supply constraint in an oilfield, optimization of gas injection plays an important role in achieving this goal. In this work, for modeling of gas-lift operation, the potential application of an Artificial Neural Network (ANN) using Bayesian Regularization (BR) is investigated and the results are compared with Levenberg–Marquardt (LM) back-propagation training algorithm. For the optimization, Teaching–Learning-Based Optimization (TLBO) algorithm is applied to simultaneously solve the well-rate and gas-lift allocation problems under the injection capacity constraint. The efficiency of the TLBO is investigated based on (a) convergence rate and (b) the best solution, by comparing its performance with Genetic Algorithm (GA). Extensive published data are used in model development and comparison. The proposed prediction and optimization model is tested in a gas-lift system for a given period of reservoir life. The prediction accuracy produced by the BRNN and the LMNN were 99.9% and 99.5% respectively. Results indicate that the two models have good predictive capability. Also, results show that the BR model appears more robust and efficient than the LM model and for the optimization algorithms, TBLO outperforms GA in the gas allocation mapping for continuous gas-lift system. The simulation results demonstrate the effectiveness of the proposed model on continuous flow gas-lift operations.

Optimasi Intermittent Gas lift Pada Sumur AB-1 Lapangan Brownfield

Gas lift is one of the artificial lift method that has mechanism to decrease the flowing pressure gradient in the pipe or relieving the fluid column inside the tubing by injecting amount of gas into the annulus between casing and tubing. The volume of injected gas was inversely proportional to decreasing of flowing pressure gradient, the more volume of gas injected the smaller the pressure gradient. Increasing flowrate is expected by decreasing pressure gradient, but it does not always obtained when the well is in optimum condition. The increasing of flow rate will not occured even though the volume of injected gas is abundant. Therefore, the precisely design of gas lift included amount of cycle, gas injection volume and oil recovery estimation is needed. At the begining well AB-1 using artificial lift method that was continuos gas lift with PI value assumption about 0.5 STB/D/psi. Along with decreasing of production flow rate dan availability of the gas injection in brownfield, so this well must be analyze to determined the appropriate production method under current well condition. There are two types of gas lift method, continuous and intermittent gas lift. Each type of gas lift has different optimal condition to increase the production rate. The optimum conditions of continuous gaslift are high productivity 0.5 STB/D/psi and minimum production rate 100 BFPD. Otherwise, the intermittent gas lift has limitations PI and production rate which is lower than continuous gas lift.The results of the analysis are Well AB-1 has production rate gain amount 20.75 BFPD from 23 BFPD became 43.75 BFPD with injected gas volume 200 MSCFPD and total cycle 13 cycle/day. This intermittent gas lift design affected gas injection volume efficiency amount 32%.

Effect of gas-lift on liquefied petroleum gas (LPG) product yield: A case study of Chinarevskoe gas treatment unit (Kazakhstan)

More than expected increase of LPG yield was observed at the gas treatment unit after continuous gas-lift start up on Chinarevskoe oil field in western Kazakhstan. This paper studies the influence of gas-lift gas on fluid composition changes at separator conditions, and further, on LPG yield at the gas treatment unit. Gas-lift well operation and process plants simulations were carried out using Aspen HYSYS software and matched with real data from the field. Process simulation at constant separator pressure, varying temperatures, gas-lift gas flow rates and water cut indicated increase in LPG yield up to 4%. It was proofed that the increase of LPG yield did not come from propane and butanes from the gas-lift gas. It was concluded that increase of LPG yield is the consequence of mass transfer of components dissolved in oil, liquid, to the vapor phase, i. e. stripping of oil components by gas-lift gas as stripping medium took place. The amount of stripped components, and resulting LPG yield increase, at constant separator pressure on oil treatment plant depended on gas lift gas flow rate, temperatures and gas-lift gas composition. Presence of water had low impact on amounts of hydrocarbon components stripped from oil.

Dynamic optimization of a continuous gas lift process using a mesh refining sequential method

Dynamic optimization of gas lift process (GLP) aims to compute control optimal trajectories of gas injection flow rate so that the oil production can be maximized. It has been observed that dynamic optimization of GLP is little discussed in the recent literature since most of the papers have focused on steady state optimization and multivariable predictive control applications. In this work, a multiple-objective dynamic optimization of a GLP is applied with the goal of maximizing the oil production while minimizing the gas lift amount of a particular process. To this end, a mesh refining sequential method, which transforms the dynamic optimization problem into a finite-dimensional nonlinear program (NLP), was implemented. The main advantages of this approach are accelerating the numerical algorithm convergence and improving the quality of the optimal control profiles. The Pareto curve was obtained from the multiobjective optimization, allowing predicting the set of optimal solutions for the given problem. Numerical examples evidenced that the oil production can be considerably increased with minimal gas consumption.

Evaluation of Continuous Gas Lift Systems in an Oil Well

Evaluation of Continuous Gas Lift Systems in an Oil Well

A case study to optimum selection of deliquification method for gas condensate well design: South Pars gas field

Abstract Optimum decision making is an ongoing problem in production engineering. Dynamic well characteristics during the project life, different reservoir and well conditions, and policies of the companies lead to complex problems. Today, the most effective liquid-removal devices are pumping, the combination of liquid-diverter with gas lift and velocity string. Considering mentioned complexities, the most efficient method of liquid removal is different from one well to the others. This paper discusses a multi-criteria decision making (MCDM) strategy for ranking these methods based on ELECTRE and TOPSIS techniques in a gas condensate reservoir. The most efficient model in this case, regarding its high efficiency and level of reliability is continuous gas lift. These procedures can be extended to other cases easily by changing the comparison matrix and user defined weights.

连续气举井组优化配气研究

连续气举井组优化配气研究

Non-aqueous vs aqueous overflush scale inhibitor squeeze treatment in an oilfield offshore Norway

Abstract The field under study is located offshore Norway. Due to the need for pressure support, it is anticipated that seawater will be injected and continuous gas lift will be used in a number of wells. Barium sulphate scale deposition is expected as high concentrations of barium have been measured in the formation brine. Scale inhibitor squeeze treatments will form an important part of the scale mitigation plan. Squeeze treatments entail the injection of an inhibitor chemical to prevent scale deposition, the treatment generally consists of the following stages: preflush, main treatment, overflush and shut-in. The preflush stage is normally injected to condition the formation, with typically a mutual solvent being deployed to improve inhibitor retention and well clean-up times. The chemical slug is injected in the main treatment stage, generally as an aqueous phase. The overflush stage is deployed to displace the chemical slug deeper into the reservoir and thus expose the chemical to a greater surface area of rock to achieve a higher level of retention. Commonly, the overflush is deployed as an aqueous phase; however, it is not always feasible to inject large volumes of water in wells which are water sensitive or which already require artificial lift. Water is denser than hydrocarbons, and therefore more difficult to lift. In these circumstances, a non-aqueous overflush, generally marine diesel, may be preferable. The diesel volumes required are feasible for scale squeezes during the first years, although some additional logistic effort and costs are to be considered. The objective of this paper is to compare squeeze treatment lifetime achieved by conventional aqueous and non-conventional squeeze treatments, where non-conventional refers to treatments where the overflush is split into aqueous and non-aqueous stages, typically diesel being used for the non-aqueous stage. The simulation and optimisation calculations were performed using a specialised near wellbore model for scale treatments, where a two-phase flow model was used to describe the displacement process during the multi-stage overflush. Splitting the overflush was found to reduce the squeeze lifetime marginally, as the non-aqueous overflush is not as effective as a purely aqueous overflush in propagating scale inhibitor deeper into the formation. However, this is counterbalanced by the fact that a smaller volume of water needs to be injected in the formation, and so reducing the risk of formation damage and most important for this particular case, a smaller volume of water will need to be lifted, so the well may be set back to production with ease.

Using the Artificial Gas Lift to Increase the Productivity of Noor Oil Field / Mishrif Formation

Noor Oil Field is one of Iraqi oil fields located in Missan province / Amarah city. This field is not subjected to licensing rounds, but depends on the national effort of Missan Oil Company. The first two wells in the field were drilled in seventies and were not opened to production until 2009. The aim of this study is to study the possibility of using the method of gas lift to increase the productivity of this field . PROSPER software was used to design the continuous gas lift by using maximum production rate in the design.
 The design was made after comparing the measured pressure with the calculated pressure, this comparison show that the method of Beggs-Brill and Petroleum Expert2 gave the best results; therefore, these correlations have been adopted in the design of gas lift.
 The point of gas injection had been selected; the optimum gas injection rate, the maximum oil production rate, the number of valves required for gas injection and their depth, the pressure required to open and close each valve were calculated. The effect of water-cut, change the amount of ratio of gas to oil and decline reservoir pressure in natural flow case and gas lift method case were studied. The results of gas lift design show that the maximum oil production rate is (1000) STB/Day and the optimum gas injection rate (2.65) MM Scf/Day at using operating pressure of (1700) psi available at casing head and the minimum bottom hole following pressure is (1501.5) psi.

Evaluating the Unloading Gradient Pressure in Continuous Gas-lift Systems During Petroleum Production Operations

Evaluating the performance, applicability, and field testing of various artificial lift methods, in particular continued gas-lift, can be time consuming and costly. To overcome these drawbacks, it is needed to propose a reliable model to estimate gas-lift applicability in advance of the installation under specific well operational conditions such as tubing size and design oil rate. In this study, the robust least square modification of support vector machine (LSSVM) methodology is implemented to propose a computer program, by which the unloading pressure gradient region can be determined in various design oil production rates and also tubing sizes. The developed LSSVM model results indicate 1.084% average absolute relative deviation from the corresponding unloading pressure gradient literature values, and squared correlation coefficient of 0.9994.

Improving Gas Allocation Optimization to a Group of Wells in Gas Lift Using an Efficient Hybrid Genetic Algorithm (HGA)

One of the most commonly used artificial lift methods in the petroleum industry is continuous gas lift. In continuous gas lift, gas at suitable pressure is injected in an appropriate depth into the tubing to gasify the oil column and, thus, facilitate the production. In gas lift, by increasing the gas injection rate into the well, the oil production rate enhances. At a point that is an optimal point of the well, by increasing gas injection rate, the oil production rate declines. At this point, the well produces the most oil. If there is no limitation in the total amount of available gas, a sufficient amount of gas could be injected into each well to get the maximum amount of production. However, often the total amount of available gas is insufficient to inject enough gas to an optimal point of each well and to reach the maximum oil production for each well. Therefore, allocating an optimum amount of gas to each well to obtain the field maximum oil production rate is necessary. In this work, a hybrid genetic algorithm was used to allocate the optimum amount of gas to a group of wells for three fields with a different number of wells. Based upon the fields' oil total production rate resulted from the gas allocation to the wells, the hybrid genetic algorithm shows better gas allocation to the wells in comparison with previous works with other methods.

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.

The Optimization of Gas Allocation to a Group of Wells in a Gas Lift Using an Efficient Ant Colony Algorithm (ACO)

When the reservoir energy is too low for the well to flow, or the production rate desired is greater than the reservoir energy can deliver, using some kind of artificial lift method to provide the energy to bring the fluid to the surface, seems to be necessary. Continuous flow gas lift is one of the most common artificial lift methods widely used in the oil industry during which, at appropriate pressure, gas is injected in a suitable depth into the tubing to gasify the oil column, and thus assist the production. Each well has an optimal point at which it will produce the most oil. In ideal conditions, at which there is no limitation in the total amount of available gas, a sufficient amount of gas could be injected into each well to get the maximum amount of production. However, often the total amount of available gas is insufficient to reach the maximum oil production for each well. Therefore, allocating an optimum amount of gas to each well to obtain field maximum oil production rate is necessary. In this work, a continuous ant colony optimization algorithm was used to allocate the optimum amount of gas to a group of wells for three fields with a different number of wells. Based upon the total production rates of the studied oil fields resulting from the gas allocation to the wells, the continuous ant colony optimization algorithm shows better gas allocation to the wells in comparison with the previous works with other optimization methods.