Gas Lifting Using Nitrogen and Carbon Dioxide as an Alternative to Electric Submersible Pump in the Tulehu Geothermal Field, Indonesia: A Technical Comparison

Distributed acoustic sensing sends laser pulses along a fiber optic cable and analyzes the backscattered light to identify acoustic signals along the entire fiber. Liquid slugs were produced in a 427 m vertical test well using surface-controlled gas lift valves. To enhance DAS monitoring, pressure pulses were induced by multiple acoustic shots from a fluid level gun. Visualization of the responses through frequency band energy plots and unfiltered phase shift measurements permitted tracking slug movement and estimating parameters such as velocity, location, and body length. The results demonstrate that DAS stimulated with acoustic pulses can effectively track liquid slugs in real-time. We observe that relying solely on flow-induced noise in multiphase flow environments may not provide sufficient signal strength for slug detection. Applications include real-time detection of liquid slugs for improved well monitoring and flow management.

This study presents a comprehensive reliability assessment and operational performance evaluation of mobile air compressor systems and G-3516B Altra lean burn gas lift compressors using Monte Carlo simulation. For the mobile compressors, operational and maintenance records from 2021 to 2024 were analyzed for four key components, namely valves, filters, radiators, and air hoses, to estimate reliability indices, including mean time between failure (MTBF), failure rate, reliability, availability, and unavailability. The results reveal a progressive degradation in component performance throughout the study period. Valve reliability declined sharply from 13.1% in 2021 to 2.3% in 2024, accompanied by a reduction in MTBF from 496 to 168 hours. Filters exhibited the poorest performance, with reliability decreasing from 6.6% to 1.7% and MTBF falling from 372 to 156.8 hours, indicating a high susceptibility to failure. Radiators demonstrated comparatively higher reliability, with an initial value of 18.3%, although this declined to 5.2% by 2024. Air hoses showed moderate performance, with reliability decreasing from 13.0% to 6.8% over the same period. Despite consistently high availability levels exceeding 90% across all components, the low reliability values highlight significant underlying performance deficiencies. The observed deterioration trends suggest the predominance of reactive, run-to-failure maintenance practices. In contrast, the G-3516B compressors demonstrated high uptime, reliability, and availability (>92%) under variable load conditions, highlighting the impact of operational control and preventive maintenance. The findings underscore the need for a transition to proactive maintenance strategies, including component-specific preventive maintenance schedules and systematic maintenance performance tracking, to enhance system reliability and operational efficiency. This study provides practical insights for maintenance optimization and supports data-driven decision-making in industrial compressor operations. Monte Carlo simulations effectively captured stochastic failure behavior, probabilistic uptime, and production performance, providing realistic projections under uncertainty. The findings underscore the importance of component-specific preventive and predictive maintenance strategies, reliability-centered design, and operational optimization to improve system efficiency, reduce unplanned downtime, and enhance lifecycle cost-effectiveness in industrial compressor operations.

Gas lift operation involves injecting compressed gas into a low-producing or non-producing well to maximize oil production. The gas lift method is an artificial lift technique that brings reservoir fluid to the surface by utilizing the energy of the compressed gas injected into the well. However, the gas lift artificial lift process has certain drawbacks, such as well deterioration, inaccurate production measurements, gas compressor instability, and excessive gas injection. Furthermore, due to the increasing percentage of difficult-to-extract reserves in the overall structure, the formation of paraffin deposits remains a critical problem in oil production. Studies show that the precipitation of dissolved paraffin in oil and the formation of deposits begin when the bottom-hole temperature (BHT) drops below the Paraffin Appearance Temperature (PAT). In gas lift wells, this is typically observed on the inner surface of the tubing (NKB or production tubing). The formation of wax (paraffin) deposits negatively affects the performance of individual production wells and the development of the field as a whole, leading to reduced productivity and the necessity of taking measures for paraffin removal, consequently increasing the well's downtime and operational costs. It is essential to implement regular wax removal measures in wells to ensure stable production of high-paraffin crude oil. Within the framework of the study's methodology, the physical basis of the gas lift process is analyzed using mathematical models. Furthermore, the main factors influencing the formation of paraffin deposits—specifically the temperature regime, pressure change, and composition of the circulating oil, associated petroleum gas (APG), and the oil-gas mixture in the gas lift tubing—are thoroughly determined. The practical effectiveness of the proposed operational solutions for preventing paraffin deposits is demonstrated based on the analysis of well operating characteristics and the thermodynamic state. A key finding is the presentation of specific recommendations for determining the optimal composition of the associated petroleum gas injected into the gas lift process to prevent paraffin formation. This optimal composition allows the temperature inside the tubing to be maintained above the PAT. The research results can be applied to enhance the efficiency of gas lift wells operating with high-paraffin crude oils, reduce operating expenses, and extend the working life of the wells. Keywords: gas lift, paraffin deposits, artificial lift methods, oil production, tubing (or production tubing), production optimization

Well completion is a critical stage in the development of oil, gas, and gas-condensate wells, as it directly determines the efficiency of fluid flow from the reservoir into the wellbore. During drilling operations, the near-wellbore zone is often exposed to drilling and completion fluids, which can lead to formation damage, permeability reduction, and deterioration of reservoir properties. As a result, the primary objective of well completion is to remove drilling-induced damage, restore natural reservoir permeability, and create favorable conditions for sustainable production. This study examines the main methods used to initiate and enhance reservoir inflow during well completion operations. Common techniques include gradual replacement of high-density drilling fluids with lower-density fluids, lowering the fluid level in the wellbore, aeration methods involving simultaneous injection of gas and liquid, gas lift systems, and mechanical activation methods such as swabbing and piston operations. Particular attention is given to deep and high-pressure offshore gas and gas-condensate wells, where hydrostatic pressure reduction through controlled fluid displacement represents the most widely applied completion approach. The paper also analyzes the potential complications that may arise during completion and clean-up operations. These include formation damage due to fluid incompatibility, wellbore instability caused by rapid pressure drawdown, sand production in unconsolidated formations, incomplete displacement of drilling mud, loss of well control, equipment failure, hydrate formation, and corrosion issues. Such complications can significantly reduce well productivity, increase operational costs, and pose safety risks if not properly managed. To address these challenges, various mitigation strategies are discussed, emphasizing the importance of proper fluid design, gradual pressure management, real-time monitoring, and reservoir-specific completion planning. The application of compatible completion fluids, optimized drawdown rates, sand control techniques, and well-designed gas lift or aeration systems can effectively minimize operational risks and enhance well performance. The results highlight that a systematic and integrated approach to well completion, tailored to specific reservoir conditions, is essential for ensuring long-term well integrity, stable production, and operational safety. The findings of this study may be useful for petroleum engineers involved in the planning and execution of completion operations, particularly in complex offshore and high-pressure reservoir environments. Keywords: well completion, reservoir inflow, formation damage, hydrostatic pressure reduction, gas lift, wellbore stability, offshore gas wells.

ABSTRACT To address the challenges of small sample sizes and data scarcity in acidized wells, this study proposes an acidization treatment performance prediction method based on transfer learning and deep learning. First, reservoir engineering methods are employed to preprocess the data by incorporating well-specific characteristics, thereby enhancing data completeness and reliability. Subsequently, transfer learning techniques are utilized to migrate rich data features from the source domain (foam drainage and gas lift wells) to the target domain (acidized wells), improving the model’s generalization capability. For model selection, a Bidirectional Long Short-Term Memory network (Bi-LSTM) is adopted for modeling, and comparative experiments are conducted with LSTM and Attention_LSTM models. The results demonstrate that Bi-LSTM exhibits higher accuracy and stability in predicting the production of acidized wells. This method effectively resolves the prediction challenges associated with small-sample data, providing a scientific basis for optimizing acidization treatments and demonstrating significant practical application value.

Common envelope evolution is a crucial phase in binary stellar evolution. Current global three-dimensional simulations lack the resolution to capture the small-scale dynamics around the embedded companion, while local wind-tunnel simulations always approximate the companion's orbital motion as linear rather than as rotation around the center of mass. We investigated how rotation, accretion, and stratification influence small-scale gas dynamics, gravitational drag and lift forces, and the spin-up rate of the companion. We performed three-dimensional local hydrodynamic simulations of a 0.2, M_⊙ compact companion plunging into the envelope of a 2, M_⊙ red giant in a reference frame rotating at the companion's orbital angular velocity, using the Athena++ code. The presence of stratification generates an inward directed force, which is partially opposed by a rotation-induced outward lift force. Both the resulting inward directed force and the drag force, strongly influenced by stratification, would affect the evolution of the binary separation. We propose revised semi-analytical prescriptions for both drag and lift forces. Without accretion and for sufficiently small gravitational softening radii, a quasi-hydrostatic bubble forms around the companion, while accretion prevents its formation and converts kinetic energy into heat that could contribute to the envelope ejection. Drag and lift forces are only marginally affected by accretion. The companion spin-up rate varies non-monotonically in time, first increasing and then decreasing as it plunges deeper into the envelope. These results motivate future magnetohydrodynamic simulations to investigate how accretion, rotation, and stratification affect magnetic amplification and how magnetic fields, in turn, influence mass and angular momentum accretion rates, as well as the drag and lift force exerted on the companion.

Artificial lift challenges are as varied as the wells and reservoirs they support. Offshore, the focus may be on maximizing production from aging deepwater completions, while in shale plays the obstacles often involve high water cut and scale. True to form, the industry is developing novel ways to answer these problems. From adaptive gas lift systems, deep-set intelligent gas lift straddles, and nanoparticle-based fluids to surfactant-assisted gas lift, operators are deploying new artificial lift technologies in offshore and onshore settings to drive up production rates, as detailed during SPE’s Annual Technical Conference and Exhibition in October. Conventional gas lift has long been an industry go-to solution for increasing oil production, but some shortcomings associated with the approach prompted a North Sea operator to seek out a variation on the theme. Eivind Samuelsen, a senior petroleum engineer at Aker BP, said that after pilot testing by the operator on an adaptive gas lift system (AGLS) at a field offshore Norway, the technology had reached Technology Readiness Level 7 (TRL7), which is the highest readiness level. Speaking during an ATCE technical session, he said Aker BP plans to install AGLS in 11 wells in that same field to demonstrate the tech’s value. He told JPT the wells will have one-fits-all adaptive gas lift scenarios from day 1. Development of the AGLS started in 2019 as Aker BP strove to overcome limitations of conventional gas lift systems. One key constraint is limited gas lift depth: traditional injection-pressure-operated (IPO) valves require reducing casinghead pressure to close and generally conservative design practices, which limit injection depth and production. This is a drawback because deeper gas lift injections can add reserves, stabilize flow, and accelerate production. Another limitation of conventional gas lift systems is that the IPO and orifice valves must be pre-set based on modeling inputs or expected well performance. Such pre-sets can lead to underperformance, the authors wrote in SPE 228103. The fixed-valve design for a well’s 20- to 40-year lifetime is based on input and uncertainties, Samuelsen said, and “those inputs will probably be wrong.” That means it’s likely the well will underperform or require interventions to change the gas lift design, he said. “Out-of-target reservoir pressure, significant change in productivity index, and so forth. The field development plan, it’ll change. You’ll do infill drilling, you’ll do reinjection. So, what you pre-design is probably wrong,” he said. That made valve adaptability one of the key design requirements for the system Aker BP sought. Functionality specifications included a system compatible with current Intelligent Well Interface Standardization (IWIS) subsea low-power systems; a full range of available orifice valve sizes with automated control; high equipment durability; a two-way adaptive gas lift valve barrier; and a fully retrievable adaptive gas lift valve that could be recovered using a standard wireline tool in case of failure.

Robustness of NMPC compared to MPC under off-nominal conditions: Application to a gas lift system

This study utilizes the drift–flux model to develop a new flow pattern map designed to facilitate an accurate estimation of gas void fraction (αg) in vertical upward flow. The map is parameterized by mixture velocity (um) and gas volumetric quality (βg), integrating transition criteria from the established literature. For applications characterized by significant pressure gradients, such as gas lift, these criteria were reformulated as functions of pressure, enabling direct estimation from operational data. A critical component of this methodology for the estimation of αg is the estimation of the distribution parameter (C0). An analysis of experimental data, spanning pipe diameters from 1.27 to 15 cm across the full void fraction ranges (0<αg<1), reveals a critical αg threshold beyond which C0 exhibits a distinct decreasing trend. To characterize this phenomenon, the parameter of the distribution-weighted void fraction (αc=αgC0) is introduced. This parameter, representing the dynamically effective void fraction, identifies the critical threshold at its inflection point. The proposed model subsequently defines C0 using a two-part function of αc. This generalized approach simplifies the complexity inherent in existing correlations and demonstrates superior predictive accuracy, reducing the average error in αg estimations to 5.4% and outperforming established methods. Furthermore, the model’s parametric architecture is explicitly designed to support the optimization and fine-tuning of coefficients, enabling future use of machine learning for various fluids and complex industrial cases.

Accurate prediction of Test Rack Opening (TRO) pressure is essential for the optimal design and calibration of gas lift valves, directly affecting unloading stability, gas injection efficiency, and overall production performance. Traditional approaches relying on force-balance equations and iterative test-rack calibrations are often constrained by simplifying assumptions and sensitivity to operational variability. This study develops and benchmarks nineteen (19) machine learning models to predict TRO pressure using a field dataset comprising 328 valves from 20 wells. A rigorous workflow encompassing data cleaning, feature engineering, multicollinearity reduction, and systematic validation was implemented. Seventeen input parameters, including dome pressure, fluid gradients, and well depth measurements, were evaluated. Among the algorithms tested; including linear models, support vector regression, ensemble methods (Random Forest, Gradient Boosting, XGBoost, LightGBM, CatBoost), and neural networks. The Random Forest Regressor exhibited the best performance, achieving a test R2 of 0.7437 and an Average Absolute Relative Error (AARE) of 8.87%. Feature importance analysis revealed Measured Depth, Dome Pressure, and Unloadable Gradient as the primary predictors, consistent with the physical mechanics of gas-lift systems. Time-series models (ARIMA, Prophet) performed poorly (R2 < 0.03), confirming that TRO pressure is inherently a static design parameter rather than a dynamic variable. The proposed predictive framework minimizes reliance on repetitive physical calibration, enables rapid design iterations, and provides interpretable, data-driven insights for optimizing gas-lift systems and improving operational reliability.

A specific variational approach has been developed in this article to model the steady flow process of a non-mixing viscous mass obeying non-slip boundary regime system in a perfectly circular pipe. Through consistent mathematical reasoning, concrete analytical results have been obtained for the principal physical quantities of the aforementioned non-mixing viscoussystem, such as the velocity profile (along the pipe radius) in vertical (or non-vertical) pipes, pressure drop, the flow rate of the pipe (Hagen–Poiseuille formula) and the shear stress on the pipe surface. Such issues may be relevant in the operation of oil wells using the gas lift method, in water-cut and sand-producing oil wells, as well as in two-phase and multiphase flow processes. Additionally, it is known that in deep oil and hydrocarbon wells, the temperature increases by 1 degree per 10 meters of depth. Considering that such wells can be extended to several kilometers deep, it becomes evident that, the temperature in the well and the reservoir is an essential actor in all prepossess. As the mixed fluid moves upward from the bottom of the well, the extracted mass begins to cool, but this cooling is not uniform. Therefore, even a homogeneous fluid exiting the well behaves like a non-mixing fluid system, as the viscosity and density of the non-uniformly cooled volume will be unevenly distributed depending on temperature likely to the immiscible system For this reason, it can be considered as the motion of a non-mixing viscous mass. These considerations, along with other practical issues, are the subject of discussion in this article.

China, holding the world’s largest shale gas reserves,lacksprecise data on methane emissions from its rapidly expanding production.We introduce a two-tiered mobile measurement approach, using a mobilelaboratory to measure methane concentrations across 125 well pads(approximately 750 wells) distributed among four major productionblocks (Changning, Weiyuan, Fuling, and Luzhou). These blocks contributed84% of China’s total shale gas production in 2023, providingthe first comprehensive ground-level measurements. Stationary downwindmonitoring of well pads revealed emission rates from 0.002 to 98.86kg/h, validated through mobile observations of methane concentrationsacross the region. Notably, emissions were highly concentrated, with89% originating from just 10% of the well pads. For 2023, the extrapolatedmethane emissions from China’s shale gas production were estimatedat 16,842 t (6,444–29,991 t, 95% CI), corresponding to a methane leakage rate of 0.10% (0.04%–0.17%, 95% CI). This rateis lower than major U.S. fields and similar to that of U.S. dry gasfields. Our research identifies gas lift venting, incomplete combustionfrom compressors, and process venting as significant sources of super-emissionsin China’s shale gas upstream production chain. The methodologyemployed, based on comprehensive and targeted field measurements,demonstrates its effectiveness in providing a scientific basis forformulating precise and effective regulatory policies on methane emissions.

Gas well deliquification is a key technology for mitigating liquid loading and restoring or enhancing production capacity in ultra-deep, high-temperature, and high-pressure gas wells. The abnormal corrosion behavior observed in the gas lift tubing of the Well X-1 oilfield in western China, within the 50–70 °C interval (1000–1500 m), was investigated. By analyzing the asymmetric wall thinning and axial groove morphology on the inner surface of tubing and then establishing a two-dimensional model of the vertical wellbore, the gas–liquid flow behavior and associated corrosion mechanisms were also elucidated. Results indicate that the flow pattern evolves from slug flow at the bottomhole, through a transitional pattern below the gas lift valve, to annular-mist flow at and above the valve. The wall shear stress peaks at the gas lift valve coupled with the significantly higher fluid velocity above the valve, which markedly elevates the corrosion rate. In this regime, the resultant annular-mist flow features a high-velocity gas core carrying entrained droplets, whose impingement synergistically enhances electrochemical corrosion, forming severe groove-like morphology along the inner tubing wall. Therefore, the corrosion in this well is attributed to the synergistic effect of the mechano-electrochemical coupling between multiphase flow and electrochemical processes on the inner surface of the tubing.

This study presents a comprehensive analysis of gas lift optimization for Well XYZ, a mature oil well in the Niger Delta that ceased production due to declining reservoir pressure and increasing water cut. Using PROSPER simulation software; we developed a robust gas lift design to restore production and extend the well’s economic life. The research integrates nodal analysis, sensitivity studies, and economic evaluation to determine optimal operating parameters. Key findings reveal that a gas injection rate of 4.318 MMscf/day at a depth of 3,083.5 ft maximizes production, achieving 2,543.4 STB/day at 50% water cut—a complete recovery from the well’s non-flowing state. Sensitivity analysis demonstrates the system’s effectiveness up to 80% water cut, significantly enhancing the well’s longevity. Economic assessment confirms a payback period of under three months, with gas lift outperforming alternatives like Electrical Submersible Pumps and rod pumps in both flexibility and cost-efficiency. The study validates PROSPER as a reliable tool for gas lift design, while providing a replicable framework for optimizing mature wells in similar environments. Practical insights on valve selection, injection depth, and real-time monitoring further support field implementation. This work contributes to the sustainable development of aging reservoirs by demonstrating how optimized gas lift systems can unlock stranded production in high-water-cut scenarios.

Calculation method of multi-stage gas lift process parameters in deep offshore low-permeability oil and gas fields

Coiled tubing (CT) has become a critical technology in oil and gas operations, yet its service life is constrained by fatigue, corrosion, and erosion. In marginal fields, the high capital cost of new CT strings for permanent installations such as gas lift creates significant economic challenges. Reusing existing CT assets presents a cost-efficient and sustainable alternative. This study conducts a systematic literature review of 33 Scopus-indexed journal and conference publications to examine CT failure mechanisms, integrity inspection methods, and the economic potential of reuse in marginal fields. The reviewed data were classified by failure mode, inspection technique, application, and economic perspective. The findings reveal that low-cycle fatigue is the most extensively studied failure mode, with wall thickness reduction identified as a key indicator of structural degradation. Current integrity assessments rely heavily on predictive modelling and non-destructive evaluation (NDE) methods, particularly magnetic flux leakage (MFL) and eddy current testing (ECT). Nevertheless, the absence of reliable, field-practical wall thickness measurement remains a critical gap, for which ultrasonic testing (UT) emerges as a promising solution. Case studies further demonstrate the technical feasibility and cost-effectiveness of CT reuse. This review underscores the importance of transitioning from a linear “use-and-scrap” paradigm toward a circular “use-inspect-reuse” framework, with UT serving as a pivotal enabler. This approach enhances economic viability and advances alignment with the United Nations Sustainable Development Goals.

This work aims to highlight the importance of Chemical Injection Test Units and Check Valve Test Benches for offshore operations, which involve high costs. The objective is to ensure the efficient and safe operation of lift gas valves and chemical injection valves through leak-tightness, performance, and durability tests. This testing circuit follows a specific sequence to guarantee its effectiveness and safety, resulting in the delivery of a technical report presenting the obtained results.

The Niger Delta, a prolific hydrocarbon province, relies heavily on gas lift systems to enhance oil recovery from wells with declining reservoir energy. While the benefits of gas lift are well-established, its optimization is complex and influenced by key operational and fluid properties. This study uses PROSPER software for nodal analysis to optimize gas lift in a marginal well in the Opolo field, producing 2652.3 STB/day. The analysis examines the combined effects of wellhead pressure (WHP) and injected gas specific gravity (SG) on oil production, using calibrated reservoir, well, and Pressure-Volume-Temperature (PVT) with industry-standard correlations. A sensitivity analysis was performed by simulating three wellhead pressures (100, 250, and 400 psig) and three injection gases, methane (SG: 0.554), nitrogen (SG: 0.967), and carbon dioxide (SG: 1.519), at injection rates of 1, 2, and 3 MMscf/day. The results confirm a strong inverse relationship between WHP and production rate for all gases, with lower WHPs yielding significantly higher oil rates. Gas SG emerged as a critical factor: methane delivered the highest absolute production (up to 7,332.1 STB/day at 100 psig), while nitrogen provided the greatest relative gain (36.09% at 400 psig), reflecting an optimal balance of density and flow characteristics. Carbon dioxide, with the highest SG, consistently showed the smallest production improvements. The study concludes that optimal gas selection is not universal but is contingent on specific well conditions: low-SG gases are generally preferred, with nitrogen being particularly effective for oil rate gains under high wellhead backpressure (400 psig) and high injection rate (3 MMscf/day); and methane excels at low WHP (100 psig) and high injection rate (3 MMscf/day). These findings offer valuable guidance for engineers to optimize gas-lift designs, focusing on key operational parameters and gas properties to boost production efficiency in the Niger Delta and similar regions.

Hydrogen gas usage is expanding into various sector of our economy due to its physio-chemical properties, as well as political and economic attentions in response to rising energy demand and low carbon requirements. During the net-zero carbon transition period, oil and gas industries will continue to devise new strategies to improve oil production and also meet the low carbon requirements. Firstly, this work presents a brief overview of the production, transportation, compression, storage, deblending and usage of hydrogen gas. The potential of using hydrogen-natural gas blends for gas lifting oil wells was studied, considering Well-X (that has experienced natural gas lift for years, and a foam-assisted gas lift trial was currently conducted) n the Niger Delta. The gas lifted well was modelled to match the production data from the test conducted on Well-X pre-foam assisted gas lift field trial on the well. Then, further analysis of the well performance was carried out. Oil rate increment between 10 and 22 stb/d was obtained from the well performance simulations for various hydrogen-natural blends, which is insignificant when compared to the reported 280 bbls/d oil rate increment of the foam-assisted gas lift field trial. Furthermore, irrespective of the hydrogen-natural gas blends, gas injection rate has significant influence on the profitability of the production strategy. However, the 30 % hydrogen-natural gas lift case has the least positive NPV values, due to the high electrolytic hydrogen production costs of $1.11 per kg considered.