Aug 2026· SPE Nigeria Annual International Conference and Exhibition· 0 citations· 1 references
Abstract
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.
Some mature basin and marginal field wells are log-poor in the sense that they do not have density-neutron logs, and in some cases, no pressure information at all. Yet, one still needs to derive decision grade formation pressure and fluid contact (FC) estimates in order to derive UGRs for reserves, design completions, and manage risks in development projects. This paper describes a repeatable workflow for deriving FC envelopes in the absence of density-neutron logs, while keeping all assumptions visible and traceable.
A new method of contact depth determination for conventional reservoirs utilizes four common types of data observed even in log-poor wells: resistivity behaviour and invasion indicators, pressure points and gradients (with actual MDT/RFT data used when available and indirect indicators used when no direct data is available), drilling and completion issues (such as losses, kicks, fluid shows and production test responses), and basic cross correlation with the offset wells. Unlike other contact depth determination methods, which yield a single contact depth at the wellbore, this method yields contact depth envelopes defined by P10/P50/P90 quantities that reflect the strength of the various pieces of information and constrained ranges that reflect the quality of the information and the likelihood of the stratigraphic configuration being correct. An assumption set approach is used to qualify the impact of uncertainties in cutoffs and saturation and to ensure that the contact depth does not reflect more than it should any assumption.
Formation pressure is handled similarly. Pressure envelopes are generated from data points and gradient families related to fluid type and depth trends and the pressure/envelopes are constraint checked against drilling break, kick and stable mud weight windows. The resulting pressure and contact envelopes are transmitted into Volumetrics and are therefore used in STOIIP/GIIP estimates to accurately assess the true impact of uncertainty on hydrocarbon resources estimates. A "value of information" guide is generated illustrating which data points (limited pressure data, targeted logs or short test for example) would provide the highest benefit in terms of reducing the uncertainty of the resource estimate for the lowest cost.
D. Ojo, A. Asaolu, W. O. Nneli et al.· SPE Nigeria Annual Internati...· 0 citations
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.
Jia Chen, Sicun Zhong, Yanhao Luo et al.· Journal of Physics, Conferen...· 0 citations
Mature assets often experience severe water encroachment, leading to premature abandonment especially in gas reservoirs, despite the presence of significant bypassed gas. This study demonstrates how integrating subsurface data with advanced saturation logging can identify and derisk untapped gas resources in a watered-out environment. Saturation logs revealed high gas saturation within lower reservoir sand packages previously overlooked during initial completions. Through petrophysical re-evaluation, fluid contact mapping, and connectivity analysis, the commercial viability of this gas-bearing zone was confirmed. A candidate well was selected for intervention based on structural positioning, integrity, and accessibility. A targeted recompletion strategy was executed, isolating water-swept intervals and perforating gas-rich sections. Post-intervention results delivered 300 KSm3/d of gas with a condensate yield of 500 bopd (≈2,600 boepd), achieving payback in just 49 days. Subsequent pressure build-up analysis indicated near-wellbore heterogeneities and close boundaries, providing additional insights into well operability. This case underscores the critical role of integrated subsurface workflows in enhancing dynamic reservoir understanding, maximizing recovery from mature assets, and providing a cost-effective pathway for extending field life through bypassed gas exploitation.
E. Orisa, C. M. Madukwe, M. C. Chukwuma et al.· SPE Nigeria Annual Internati...· 0 citations
Thinly laminated fluvial and turbidite sediments are valuable and commonplace assets in subsurface fluid exploration. Unlike conventional reservoirs, wells intersecting these formations produce from multiple layers simultaneously at different rates. Substantial differences in petrophysical properties between sandstone and shale layers, coupled with their minimal thicknesses, pose challenges for assessing fluid-transport properties. Understanding the relative contribution of each layer to total borehole inflow, along with monitoring production changes over time, is critical for accurate production allocation and diagnosing well production performance. We address the latter challenges by developing a new method to simulate multilayered commingled production in thinly laminated formations and to estimate changes in vertical fractional flow.
Production contribution from each layer within a stack of layers can be estimated through either a production logging tool (PLT), which measures local flow rates, or through geochemical methods that analyze variations in hydrocarbon compositions. Numerous analytical, semi-analytical, and numerical methods exist to evaluate multilayered commingled production. In this study, we employ the UTAPWeLS (University of Texas at Austin Petrophysical and Well-Log Simulator) fluid flow simulator to investigate commingled production in thinly laminated formations, calculate fractional flow rates for each layer, and generate PLT-like logs.
To ensure the accuracy and reliability of the method, the simulator is validated against formation-testing measurements, with simulated data showing strong agreement with the field data. The shape and magnitude of pressure changes are preserved, with differences of less than 1%. Following validation, the UTAPWeLS fluid flow simulator is used to predict the fractional flow of water in thinly laminated field cases. Results indicate variations in water and hydrocarbon flow rates due to differences in petrophysical and fluid flow properties across the formation. In the absence of PLT logs or when layer thickness falls below tool resolution, our method provides valuable insights into the production behavior of thinly laminated formations, even when layers are thinner than 0.1 m. However, the accuracy of the results depends on the quality and availability of core measurements, particularly capillary pressure and relative permeability data.
Daria Olszowska, C. Torres-Verdín, Khalid Salmi et al.· Petrophysics· 0 citations
The oil formation volume factor (Bo) is one of the most critical parameters in petroleum reservoir engineering, governing reserve estimation, material balance calculations, well deliverability assessment, and production facility design. Widely adopted empirical correlations, principally those of Standing [26] and Glaso [13], were derived from geographically limited datasets and may exhibit systematic bias when applied to crude oils from geologically distinct basins, including West African and offshore deepwater reservoirs.
This paper presents a numerical optimization study aimed not at deriving new correlations, but at recalibrating the existing coefficients of Standing's and Glaso's Bo correlations to better represent a broader PVT dataset comprising 567 laboratory-measured samples. Multiple optimization algorithms including Nelder-Mead simplex, Broyden-Fletcher-Goldfarb-Shanno (BFGS), Limited-memory BFGS with bounds (L-BFGS-B), Conjugate Gradient (CG), Powell, and Differential Evolution were employed to minimize the mean squared error between measured and predicted Bo values.
Results demonstrate that coefficient recalibration achieves statistically significant improvements across performance metrics. For Standing's correlation, the optimized form reduces RMSE from 0.1503 to 0.1336 bbl/STB, representing an 11.1% reduction. For Glaso's correlation, RMSE reduces from 0.1528 to 0.1350 bbl/STB, representing an 11.7% reduction. Five-fold cross-validation confirms the generalization capability of the recalibrated coefficients. This work provides a transparent and reproducible framework for PVT correlation recalibration applicable to regional datasets, offering practicing engineers a low-cost alternative to full correlation redevelopment.
S. Igemhokhai, K. Bello, U. Okeligho et al.· SPE Nigeria Annual Internati...· 0 citations
The tight sandstone gas reservoirs in Area S are characterized by deep burial, strong heterogeneity, and poor petrophysical properties. Single-well productivity varies widely and declines rapidly; therefore, establishing optimal combinations of development parameters is essential for improving development efficiency. Taking the tight gas reservoir in Area S as the study object, this work integrates well logging, geological, and production dynamic data. A three-dimensional fine-scale geological model was constructed using sequential indicator simulation and sequential Gaussian simulation, and geological reserves were quantitatively evaluated using the Monte Carlo method (P50 = 4.818 × 109 m3). Based on this model, numerical simulation techniques were applied to conduct sensitivity analysis and optimization of key development parameters. The results indicate that for vertical wells in Area S, a reasonable fracture half-length ranges from 100 to 300 m with 3-4 fracturing stages; for horizontal wells, a reasonable lateral length ranges from 800 to 1000 m with a fracture half-length of approximately 100 m. For zones classified by reserve abundance, differentiated well-pattern layouts are proposed: a 900 m × 1200 m pattern for Class I zones, a 700 m × 1000 m pattern for Class II zones, and a 500 m × 700 m pattern for Class III zones. These findings provide a scientific basis and technical support for the efficient development of Area S and other similar tight gas reservoirs.
Ming Ma· Journal of Physics, Conferen...· 0 citations