Aug 2026· Journal of Physics, Conference Series· Vol 3290, pp. 012080· 0 citations· 10 references
Physics
Abstract
When shale gas reservoirs enter the low-pressure and low-production stage in their late life, surface compression is a key technique to enhance well performance. However, quantitatively predicting the effectiveness of this compression remains challenging. To address this, this paper derives a simplified Inflow Performance Relationship (IPR) formula tailored for shale gas wells, enabling rapid estimation of gas production under given reservoir and flowing bottom-hole pressures. A method is proposed to predict the instantaneous production increase by analyzing the shift in the nodal analysis point between the Tubing Performance Relationship (TPR) and IPR curves after compression, achieving a practical prediction accuracy of 80% to 96%. Furthermore, by analyzing the dynamic downward shift of the IPR curve with declining reservoir pressure, the study defines the effective period of production enhancement as the duration until the nodal analysis production rate returns to its pre-compression level. A predictive model for this effective period is developed by coupling this definition with an empirical relationship between cumulative gas production and reservoir pressure, which demonstrates a mere 4.2% error in field applications. This methodology provides direct and reliable technical support for optimizing production strategies and compression plans for low-pressure shale gas wells.
Electrical submersible pumps (ESPs) are one of the most effective artificial lift methods for increasing hydrocarbon production in high-rate wells; however, free gas in the production stream frequently causes issues such as gas locking, reduced pressure head, increased mechanical wear, and eventually pump failure, particularly in reservoirs with gas breakthrough or active gas caps. Traditional diagnostic workflows relied on pump performance curve matching with nodal analysis, which were unable to detect dynamic performance anomalies. In this study, an enhanced nodal analysis methodology was applied to assess the ESP performance under gas–liquid flow conditions using real-time field data. The methodology combined downhole intake and discharge pressures, surface well testing data, and Variable Speed Drive (VSD) output current. The field baseline was validated with Petex PROSPER software, achieving high predictive accuracy with a relative error of 2.82% for the oil production rate and <0.50% for the downhole pressures. The framework was used on Well A in the Peshkabir field (Kurdistan Region of Iraq), where gas breakthrough caused discharge pressure collapse from 2,572 psi to 1,360 psi (47.12%), a 23.08% reduction in VSD output current from 390 A to 300 A, and an intake pressure rise from 1788 to 1860 psi, signifying dynamic motor unloading and ESP head degradation. Following a gas shut-off intervention using coil tubing to close Sliding Side Door (SSD) #1, #2, and #3 in the lower completion, the discharge pressure climbed to 2850 psi (109.56%), the intake pressure remained steady at approximately 1770 psi, and VSD current restored to approximately 380 A (26.67%). The results indicated that the intake–discharge pressures, well test data, and VSD current telemetry serve as a reliable method for diagnosing gas interference in packer-completed wells, allowing better reservoir management without requiring pump curve details.
Rebaz Hamza Jahwar, Lokman Aziz Abdulkareem· Dasinya Journal for Engineer...· 0 citations
Gas lift has become a dominant artificial lift method in unconventional oil production, particularly in the Permian Basin. This technology involves injecting pressurized gas into a wellbore producing string to lower the flowing fluid gradient, reduce the flowing bottomhole pressure and enhance the system from the end of tubing to the surface flow line. This lower energy state results in an increase in the pressure differential drawdown from the reservoir to the wellbore, capturing the deliverability of the reservoir. Well production performance can be physically understood as these two components: the interaction between the reservoir capability as an inflow performance relationship (IPR) and the wellbore capability as a vertical lift performance (VLP) curve. Gas lift design targets the operating point defined by the intersection of the IPR and VLP for each well. Gas lift can be optimized by targeting deeper gas injection depth; the lower the gas is injected, the more the hydrostatic head is offset, and the greater the resulting inflow from the reservoir.
In conventional gas lift system design, the maximum depth of injection is constrained by the surface gas injection pressure. A typical Permian low-pressure gas lift (LPGL) system operates at a surface injection pressure on the order of 1000 psi to 1,200 psi. On a new annular flow well setup, the producing fluid gradient in the casing-tubing annulus is high, and the surface injection pressure is insufficient to displace fluid down to the deepest gas lift mandrel. Injection occurs through one of the upper unloading valves, FBHP is elevated, and the well does not realize its full drawdown until the production path has unloaded over weeks or months.
High-pressure gas lift (HPGL) addresses this depth limitation by raising the surface injection pressure up to 5,000 psi, enabling single-point gas injection at the deepest mandrel from the first day of artificial lift operation. By introducing gas immediately at maximum injection depth, HPGL overcomes the main limiters on the VLP curve: friction in the production path, system and wellhead pressure, the hydraulic head and fluid gradient above the injection point. This produces a step reduction in flowing bottom hole pressure compared to LPGL, assisting the acceleration of production during the well's highest-productivity period.
A. Zejli, O. Stelmaschuck, M. Jackson et al.· Americas· 0 citations
Accurately predicting the production dynamics of multi-stage fractured horizontal wells in high-water-cut tight gas reservoirs remains challenging due to complex nonlinear flow regimes. This research aims to quantify dynamic threshold pressure gradients (TPGs) and their impact on well performance. A high-temperature, high-pressure flow testing system was utilized to measure dynamic TPG under varying water saturations in ultra-low-permeability cores. A dynamic mathematical model was established to characterize the exponential evolution of TPG. Furthermore, a comprehensive flow model was constructed using a coupled dual continuum–discrete fracture model. An entirely implicit numerical model utilizing a non-structured 3D tetrahedral mesh and a control volume finite element method enabled accurate numerical solutions. Key parameters such as water saturation, stress sensitivity, and fracture spatial asymmetry were systematically analyzed. Results: The threshold pressure gradient induces distinct dynamic boundary characteristics in pressure propagation, significantly reducing the wave propagation range compared to conventional models, with pressure drops concentrated near hydraulic fractures. Lower permeability (below 0.05 mD) and higher water saturation exponentially intensify the TPG amplification effect (exceeding 0.12 MPa/m), causing substantial reductions in both daily and cumulative gas production. The established simulation framework accurately captures the non-Darcy flow dynamics of fractured horizontal wells in high-water-cut tight gas reservoirs. It provides a reliable theoretical basis and computational tool for optimizing efficient gas field development.
Chunpu Wang, Hongxi Li, Anxin Mei et al.· Processes· 0 citations
Evaluation of investment opportunities in gas developments requires comprehensive subsurface data analysis and integration to quantify both value potential and associated risks. A critical element in such evaluations is the estimation of condensate yield, expressed as the Condensate–Gas Ratio (CGR), which supports the determination of condensate initially in place (CIIP) and forecasted condensate recoveries under different development scenarios. Although gas volumes typically dominate in such systems, the associated condensate liquids often provide a significant value upside, particularly under Nigeria's favorable natural gas liquids (NGL) fiscal regimes.
During due diligence on a new gas asset, neutron–density log responses exhibited ballooning behavior consistent with a gas phase. This interpretation was corroborated by Repeat Formation Tester (RFT) pressure gradients of less than 0.18 psi/ft, as well as by seismic attribute analysis that also indicated gas-bearing intervals. However, the absence of bottomhole or recombined surface PVT data and Drill Stem Test (DST) results posed a challenge for estimating the fluid's condensate yield, a critical parameter for project evaluation.
To address this data gap, a comprehensive corporate database of retrograde gas reservoirs with laboratory PVT analyses and RFT/MDT fluid gradient data was utilized. Empirical correlations were developed by trending measured fluid gradients against known laboratory-determined CGRs. The derived correlation was subsequently applied to the new opportunity, using its measured gradients to estimate the CGRs for the respective reservoirs. The accuracy of the developed correlation was tested against MDT and PVT data from a condensate reservoir in a recently drilled well and the resulting CGR estimate lies within <5% variance from that measured in the lab.
These estimates were then integrated into PVT correlations and dynamic material balance models to compute condensate initially in place and evaluate development scenarios.
The correlation-based approach provided reliable CGR estimates in the absence of direct PVT measurements and delivered a significant fiscal uplift to the project's overall economics. The study demonstrates that gradient-based empirical correlations, when supported by robust internal datasets, can effectively reduce uncertainty in condensate yield estimation and enhance investment decision-making in gas and condensate projects.
D. Alaigba, E. C. Kalu, O. Ezeaneche· SPE Nigeria Annual Internati...· 0 citations
High-pressure gas lift (HPGL) is a practical artificial lift option for unconventional wells because it enables deep single-point gas injection, eliminates the need for staged gas-lift valves and packers, and allows operators to produce through either the annulus or the tubing, depending on well conditions and well life (McNeilly et al., 2024; Dalamarinis et al., 2024). However, many HPGL wells are operated at fixed gas injection rates or fixed surface choke settings, with limited guidance on when to increase injection, reduce injection, or change the operating objective. This study presents an automated HPGL optimization workflow that treats the reservoir, wellbore, and compressor as a coupled system rather than a one-time nodal-analysis design. A dynamic Python-based model was developed using PROSPER-generated Vertical Flow Performance (VFP) curves, Python-coded Vogel Inflow Performance (IPR) relationships, an empirical reservoir pressure update and digitized compressor performance curves. The model was used to evaluate standard Delaware Basin and Midland Basin well production profiles under annular-flow and tubing-flow HPGL configurations over a one-year period.
Two optimization objectives were evaluated. First, production optimization targeted the maximum oil rate by adjusting compressor speed and gas injection rate while honoring compressor feasibility limits. Second, economic optimization used a target gas utilization factor to select the injection rate where the expected oil gain justified the lift-gas usage. Results show that the optimized production cases increased first-year oil recovery by approximately 780 to 5,600 STB/yr [SL3.1][JO3.2]compared with a fixed 1.0 MMSCFD injection case, with the largest gain observed in the Delaware Basin annular-flow case. The economic optimization reduced uneconomic gas injection, with gains ranging from $171,000/yr to $1,400,000/yr, depending on the basin and flow configuration. This workflow also provides a practical method for detecting over-injection by monitoring the compressor discharge-pressure response to gas-rate perturbations. Overall, the results show that HPGL optimization can be directed toward either maximizing barrels or maximizing economic value, giving operators a flexible workflow to improve production, control lift-gas usage, and avoid friction-dominated operating conditions as the well depletes.
Jefferson Ogbuka, S. Leggett, R. Reynolds· Americas· 0 citations
Under a constant wellbore pressure condition during transient-linear flow, gas viscosity-compressibility product is governed by a time-invariant average pressure. Therefore, evaluating this product at either the initial reservoir pressure or flowing wellbore pressure introduces a significant error in the estimation of xFk. Although attempts have been made to address this problem, existing models suffer from at least two limitations. First, they are derived under limited reservoir conditions, despite μgct being strongly dependent on complex interactions among pressure drawdown, gas, water, and formation compressibilities. Second, other existing formulations are based on iterations/graphical techniques, which are difficult to apply in practice.
This study presents a new empirically derived correction factor based on a suite of numerical simulation results. A one-dimensional real-gas flow in a multifractured tight reservoir was simulated in a Python environment. The simulation results suggest that the correlation of the correction factor with pressure drawdown yields a family of quadratic curves, each of which is governed by reservoir conditions. In particular, the coefficients of these quadratic equations are governed by the initial pressure and compressibilities of gas, water, and formation, suggesting that a correction-factor model cannot be represented by a fixed-coefficient expression. This finding reveals a limitation of the widely used Ibrahim and Wattenbarger’s correlation, which fixed coefficients render it insensitive to rock and fluid compressibilities. In contrast, the proposed correlation admits pressure drawdown and rock/fluid compressibilities as input parameters, allowing more accurate xFk estimates.
The proposed model has been validated against numerical simulation and applied to field data. Results of this study demonstrate that the proposed model improves the correction factor estimation and, thus, reduces errors in xFk calculations. Neglecting the correction factor or applying a fixed-coefficient model can result in an overestimation of xFk.
S. Mohammed, Y. Boakye-Ansah, F. O. Olarinoye· SPE Nigeria Annual Internati...· 0 citations
We use cookies to run the site and, with your consent, for analytics and to show ads.
See our Cookie Policy.
