The research team focused on three representative reservoirs in an onshore producing field, identified as Reservoir C in Well A1, Reservoir B in Well A2 and Reservoir C in Well A3. All three sit within the Agbada Formation, the classic hydrocarbon-bearing unit of the Niger Delta, where alternating sandstones and shales were deposited in paralic, deltaic and shallow-marine environments. Using gamma ray, resistivity, density, neutron and compressional sonic logs, the authors first characterised each interval, computing shale volume, porosity, water and hydrocarbon saturation and net-to-gross ratios. The sands proved generally clean, with shale volumes between 5 and 17 percent, porosities of roughly 17 to 25 percent and hydrocarbon saturations spanning 36 to 78 percent, with Well A3 emerging as the most prolific interval at an average of about 67 percent hydrocarbon saturation.

With the baseline established, the team turned to the heart of the study: Gassmann fluid-substitution modelling, the industry-standard method for predicting how seismic velocities change when pore fluids are swapped. Gas saturation was progressively increased from zero to 70 percent in Reservoirs C-A1 and C-A3, and from zero to 50 percent in Reservoir B-A2, while the mineralogical composition and the dry rock frame were deliberately held constant. This isolating assumption is crucial. It means the simulated changes reflect the physical influence of the fluid itself, chiefly its density and compressibility, rather than any alteration of the rock skeleton. Because shear-wave logs were unavailable, the authors calibrated empirical velocity relationships against the measured compressional sonic data, achieving near-perfect agreement with a normalised standard error of just 1.42 x 10-7 in the model calibration cross-plot.

The results reveal a striking asymmetry in how compressional and shear waves respond to gas. P-wave velocity dropped sharply in the earliest stages of gas injection, from 3598.29 to 3520.35 metres per second in Reservoir C-A3 and from 3237.14 to 3092.12 metres per second in Reservoir B-A2, before stabilising and even creeping back upward as the rock framework reasserted control at higher saturations. This initial steep decline is the classic seismic signature of gas: even a few percent of gas in the pore space slashes the bulk modulus of the fluid mixture, and compressional waves feel that change directly. Beyond roughly 10 percent saturation, however, further gas addition produces diminishing returns, because the fluid has already become highly compressible.

Shear waves told the opposite story. Rather than weakening, S-wave velocity rose consistently, from 2035.68 to 2074.90 metres per second in Reservoir C-A3 and from 1745.28 to 1775.33 metres per second in Reservoir B-A2. This behaviour follows logically from the physics. Shear waves cannot propagate through fluids at all; their speed is governed by the shear modulus and density of the rock frame. As denser brine or oil is replaced by lighter gas, bulk density fell from approximately 2.52 to 2.42 grams per cubic centimetre, and a lighter rock supports a marginally faster shear wave even when the frame itself is unchanged. The consequence is a reservoir whose compressional properties shift dramatically while its shear properties barely move.

That asymmetry carries enormous practical weight for seismic monitoring. The computed P-wave impedance declined by up to about 7 percent in Reservoir B-A2, from 7.438 to 6.915 MRayl, while S-wave impedance stayed essentially flat. Meanwhile the Vp/Vs ratio and Poisson’s ratio both fell, with Poisson’s ratio dropping from 0.295 to 0.259 in the most responsive reservoir. In cross-plots of P-impedance against S-impedance, and Vp/Vs against P-impedance, the data trace smooth trajectories through clearly shaded liquid-dominated, transition and gas-dominated regimes. These diagnostics give geophysicists a quantitative template for tracking gas fronts in time-lapse, or 4D, seismic surveys, converting subtle changes in reflected amplitudes into maps of fluid movement across the field.

The geomechanical half of the workflow adds a sobering dimension. As gas saturation climbed, the bulk modulus of every reservoir fell, from 14.75 to 12.20 gigapascals in Reservoir B-A2 and from 18.70 to 16.89 gigapascals in Reservoir C-A3, signalling rising compressibility. Young’s modulus and the estimated unconfined compressive strength declined only modestly, and the shear modulus remained essentially constant at roughly 7 to 10 gigapascals depending on the interval. The authors interpret this as a reservoir that bends more easily but does not break: volumetric deformation becomes more likely than shear failure as production proceeds. Under significant pressure depletion, however, the increasing compressibility could promote compaction, stress redistribution and localized fines migration in weakly cemented zones, particularly around wellbores subjected to aggressive drawdown.

Sanding risk, a perennial headache in the weakly consolidated Niger Delta sands, was assessed through the ratio of shear modulus to bulk compressibility and the Schlumberger Sand Production Index, alongside porosity thresholds. Reservoir C-A3, with the highest shear modulus at about 10.44 gigapascals and an effective porosity of 19.56 percent, scored best, showing strong resistance to production-induced deformation. Reservoir C-A1 followed closely. Reservoir B-A2, with the highest porosity at 21.05 percent and the lowest rigidity indicators, emerged as the most stress-sensitive and therefore the most susceptible to sanding, though still only at low-to-moderate levels overall. The authors are careful to caveat that these are indicators of relative susceptibility rather than direct predictions, since the workflow does not incorporate laboratory strength tests, in-situ stress measurements or production-history calibration.

The comparative element of the study is perhaps its most valuable contribution. Few previous investigations in the Niger Delta have evaluated multiple reservoirs within a single field under one unified petrophysical-rock physics-geomechanical framework. Reservoir B-A2 displayed the strongest elastic response to gas substitution, making it the premier candidate for 4D seismic surveillance but also the most sensitive to production-induced stress changes. The two Reservoir C intervals responded more gradually, trading some monitoring sensitivity for greater mechanical stability. The authors propose their workflow as a practical template for reservoir characterisation, production management and seismic monitoring not only in the Niger Delta but in clastic reservoirs worldwide where gas-based enhanced recovery is on the agenda. As operators worldwide chase harder-to-recover barrels from mature fields, the study demonstrates that knowing exactly how a reservoir’s elastic and mechanical fabric evolves with every percent of injected gas can mean the difference between efficient recovery and expensive surprises.

Subject of Research: Integrated petrophysical, rock physics, and geomechanical modelling of reservoir response to increasing gas saturation for enhanced recovery in the Niger Delta

Article Title: Integrated petrophysical, rock physics, and geomechanical modelling of reservoir response to increasing gas saturation for enhanced recovery in the Niger Delta

Article References: Salami, R., & Nton, M. E. (2026). Integrated petrophysical, rock physics, and geomechanical modelling of reservoir response to increasing gas saturation for enhanced recovery in the Niger Delta. Discover Geoscience, 4(1), Article 371. https://doi.org/10.1007/s44288-026-00745-6

Image Credits: AI Generated

DOI: 10.1007/s44288-026-00745-6

Keywords: rock physics, Gassmann fluid substitution, gas saturation, Niger Delta, reservoir characterisation, geomechanics, enhanced oil recovery, P-wave impedance, sand production, time-lapse seismic monitoring, Agbada Formation, elastic properties