Fractional Flow Modeling and Monitoring for the Assessment of Commingled Fluid Production Across Thinly Laminated Formations

Commingled Injection and Separate-layer Production to Improve the Development Performance of Gas Flooding in Multi-layer Oil Reservoirs

Continental low-permeability sandstone oil reservoirs generally have multiple layers and strong interlayer heterogeneity, which results in uneven sweep between layers and low oil recovery by gas flooding in the mode of commingled injection and commingled production. Conventional solutions such as separate-layer gas injection are immature and face a lot of engineering problems. This paper proposes a commingled gas injection but separate-layer oil production scheme to address the problem of interference between layers. According to the typical geological properties, reservoir properties, well pattern and well spacing parameters in Daqingzijing Oilfield in Jilin, a numerical CO2 flooding model is established, and a set of method and process for designing the suitable production rate of each layer at the side of production well is developed. The results indicate that regarding the multi-layer heterogeneous oil reservoirs, the proposed commingled injection and separate-layer production scheme can effectively promote uniform displacement between layers and delay gas breakthrough. It can not only enlarge CO2 swept volume in low-permeability layers, but also promote miscibility of CO2 and oil in high-permeability layers, thus effectively improving the overall oil recovery.

Insights into the application of modeling in karst aquifers: a review

Effects of fluid evolution dynamics on reservoir fluid distributions

Understanding the evolution of hydrocarbon reservoirs is crucial for fluid mapping and optimizing well placement and reservoir performance. Not fully understanding controls on reservoir fluids leads to inaccurate fluid mapping, identification of false compartments, poor well placement, reservoir underperformance, and wrong reserves. During the evaluation and development planning of a shallow 120-ft-thick black-oil reservoir, nonlinear depth profiles of fluid properties were observed across a 1,200-ft anticlinal closure, forming a gentle trend of increasing viscosity within the top quarter of the oil column, followed by a steeper deterioration with depth. The nonlinear trends presented uncertainties in evaluating vertical fluid connectivity, with direct impact on field development and optimal production strategies. In order to ascertain whether the observed trends represent vertical compartmentalization or disequilibrium due to competing fluid evolution geodynamics within a single fluid system, a systematic workflow was developed, primarily utilizing PVT data to deduce the fill-biodegradation model, integrated with geochemistry, basin modeling, and petrophysical analysis. The reservoir remained below 66 °C throughout its history, exposing it to biodegradation during active charging. Biodegradation in deeper sections consumes the lighter hydrocarbons and increases the heavy-ends, leading to decreased gas-oil ratio, bubble-point pressure, and oil formation volume factor toward the oil-water contact. Conversely, ongoing recharge at the crest introduces lighter components, hence increasing the gas-oil ratio, bubble-point pressure, and oil formation volume factor. The isomer ratio of butane decreases with depth as expected in multiply charged reservoirs but then inflects systematically to higher values with increasing biodegradation toward the oil-water contact due to preferential biodegradation of n-butane over isobutane. The ratio provides a practical means for the assessment of reservoir dynamics independent of gravitational segregation, hence aiding in fluid predictions in biodegraded systems, especially where samples are either contaminated or unavailable for geochemical analysis. These geodynamic processes, coupled with the downward decline in reservoir quality and the concomitant increase in pore-water saturation, resulted in a quasi-separation of a single fluid system into different PVT regions and nonlinear depth profiles of fluid properties. This model negates the current vertical compartmentalization theory and improves fluid mapping and pre-drill prediction away from well control. Compositional simulation will be attempted next to capture inferred reservoir fluid geodynamics.

THMC-Coupled Numerical Modeling of Sand Production from Natural Gas Hydrate Production via Depressurization

Natural gas hydrate (NGH) dissociation during depressurization-based production alters pore pressure and temperature, modulating effective stress, weakening the sediment framework, and yielding sand production. This leads to particle detachment, migration, pore clogging, and ultimately, fluid production instability. To understand the underlying mechanism, we propose a novel particle detachment criterion incorporating both critical water flow velocity and deviatoric strain and embed it into a fully coupled thermal–hydraulic–mechanical–chemical (THMC) model. The new approach has been validated at laboratory scale using Masuda’s depressurization experiments and at field scale against production data from the 2013 Nankai Trough offshore trial. Subsequently, a systematic evaluation was conducted to examine the collective effects of the intrinsic reservoir permeability, dissociation coefficient, and depressurization trajectories on multiphase flow and sand production. Results reveal a dichotomous relationship between intrinsic permeability and dissociation kinetics on the fluid production performance. Elevated permeability and rapid dissociation have been shown to enhance early gas production. However, these processes have also been demonstrated to intensify localized hydrodynamic drag and strain-induced particle detachment, thereby accelerating late-stage permeability degradation through deposition and compaction. Conversely, low permeability and dissociation severely impede pressure propagation while restricting sand mobility. The stability of the sediment is strongly influenced by the depressurization trajectories. Cyclic and abrupt pressure drawdown schemes amplify transient hydraulic disturbances and sand influx, whereas monotonic, fluctuation-minimized pressure pathways maintain bounded seepage behavior and improve long-term reservoir stability. It is therefore evident that effective field-scale NGH production design requires coordinated regulation of the depressurization strategy, dissociation progression, and permeability-specific flow redistribution to balance gas recovery and geomechanical integrity.

Impact of Velocity-Dependent Relative Permeability and Fines Migration on CO2 Storage in Aquifers: A Hybrid Analytical-Numerical Upscaling Framework

The aim of this study is to develop an analytical model for axisymmetric gas-water flows in heterogeneous geological formations applicable to carbon dioxide (CO2) storage in deep saline aquifers. The novel method integrates numerical upscaling with an analytical reservoir model for predicting sweep and injectivity during CO2 injection. Pseudophase permeabilities are obtained from 2D numerical simulations, based on an averaging across layers and explicitly capturing velocity-dependent relative permeability reduction caused by fines-migration-induced formation damage. Using these upscaled properties, an exact analytical solution for radial gas-water flow is derived, providing explicit expressions for pressure drop, saturation distribution, sweep efficiency, and well impedance. We show that injectivity is highly sensitive to the vertical permeability profile and the extent of fines-induced damage. When permeability decreases with depth, gravitational segregation amplifies rate-dependent injectivity loss. In contrast, formations with permeability increasing with depth sustain a two-phase mixture zone that propagates outward, producing a different injectivity response. The analysis shows that incorporating velocity-dependent pseudopermeabilities altered by formation damage is essential for accurate injectivity and sweep prediction. The developed framework offers a fast, physics-based tool for quantifying injectivity losses and sweep efficiency in heterogeneous aquifers.

Correlation-Based Estimation of Condensate Yield from Downhole Fluid Gradient

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.