Aug 2026· SPE Nigeria Annual International Conference and Exhibition· 0 citations· 6 references
Abstract
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.
Aquifer support in gas reservoirs is often regarded as detrimental to ultimate recovery due to early water encroachment, reduced gas relative permeability, increased water handling, and premature abandonment pressures. This study challenges that generalised assumption by evaluating the conditions under which aquifer influx can positively contribute to gas recovery. The objective is to quantify the impact of aquifer support on pressure maintenance and recovery efficiency in over-pressured gas reservoirs with favourable geological architecture.
A high-resolution 3D dynamic reservoir simulation model was developed for an over-pressured, clean, channelized gas reservoir characterised by a large gas column and optimized well placement, with strategic well perforations offset from the fluid contact. Results reveal that, under these specific conditions, aquifer support enhances gas recovery by sustaining the reservoir pressure, maintaining efficient gas drainage without inducing early water production. The clean, channel-dominated architecture limits water bypass and coning, allowing aquifer energy to act primarily as pressure support rather than as a displacement mechanism.
Sensitivity analysis shows that increasing effective aquifer length within the uncertainty range further improves recovery and delays abandonment pressure, contrary to traditional expectations for gas reservoirs. These findings highlight the importance of case-specific evaluation of aquifer behaviour in gas reservoir management and demonstrate that aquifer influence is not universally detrimental.
Finally, for over-pressured gas reservoirs in fairly homogeneous depositional settings without intercalations to portend water fingering and by-pass, and with large gas column including optimized perforation strategies, aquifer support is not a detriment but a valuable drive mechanism. The study provides a revised framework for gas reservoir management in the Niger Delta and analogous settings by prioritizing reservoir-specific context than generalised assumptions.
K. Eke, Joel Musa, J. Alli-Oluwafuyi et al.· SPE Nigeria Annual Internati...· 0 citations
After integrating a full suite of data to confirm the presence of hydrocarbon-bearing reservoirs, the next critical step towards value realization lies in accurately defining subsurface targets for wellbore placement. Suboptimal well positioning has historically led to significant value erosion—either due to drilling into non-reservoir facies characterized by low porosity and permeability, which hampers sweep efficiency, or, in reservoirs where the water contact has not been properly logged, by placing wells too close to the water contact, resulting in early water breakthrough.
This study presents a seismic-driven reservoir characterization approach aimed at identifying sweet spots to enhance well placement decisions. By leveraging advanced geophysical techniques, this strategy improves the precision of target selection, thereby maximizing hydrocarbon recovery and minimizing development risk. The technique centered around building seismic inversion models for predicting reservoir presence and reservoir properties such as porosity. The technique was deployed across a shallow water field in the Niger Delta. Locating reservoirs in this depositional environment can be challenging due to the complex geologic processes responsible for sedimentation.
The Seismic inversion model resulted in a robust static and dynamic model. This ultimately formed the basis for optimally locating a planned development well within a sweet spot characterized with good sand development and high porosity. Hitherto, simple geologic model incorporating offset well analysis formed the basis of locating potential drilling target that resulted in suboptimal well location.
O. Chudi, N. Okereke, A. Ekpoette et al.· SPE Nigeria Annual Internati...· 0 citations
Shallow gas development in the Triton Field has historically been limited by recurring zonal isolation failures at shallow depth, often resulting in Sustained Casing Pressure (SCP), stemming from severe hole washouts in unconsolidated sand formations that weaken cement bonding and jeopardize well integrity. As the field operator transitions toward developing both deep and shallow reserves within a single wellbore to reduce overall cost and environmental impact, achieving reliable zonal isolation at shallow depth becomes essential. A cross-disciplinary technical workflow was established to investigate and quantify the root cause of shallow isolation failures, confirming that excessive washout during top-hole drilling significantly deteriorated cement bonding capability. To mitigate this, drilling flow rate and Rate of Penetration (ROP) were carefully maintained to minimize formation erosion, while a high-density cement slurry system and updated job design practices including controlled flow regime were implemented to enhance cement bonding in enlarged boreholes. Additional measures such as deployment of turbolizers and reduced pump rate in the washout zone were introduced to improve mud removal and optimize cement placement efficiency. Post-job evaluations across four wells (TNT-B1, TNT-B2, TNT-B4, and TNT-A3) demonstrated a substantial improvement in cement bonding at shallow intervals compared to three pre-innovation reference wells (TNT-A1, TNT-A2, and TNT-F1). Prior to the innovation, Cement Bond Log (CBL) values in the shallow section consistently ranged from 20 to 80 mV, indicating poor-to-marginal bonding from the casing shoe to depths of 270 to 450 m. Following implementation of the integrated approach, three of the four post-innovation wells exhibited low CBL values below 20 mV beginning at approximately 135 m measured depth (MD), with TNT-A3 achieving excellent values below 10 mV almost immediately below the conductor pipe shoe. TNT-B4 demonstrated a partial improvement, with medium-to-high CBL values above 315 m attributed to excessive hole enlargement in that interval, consistent with playback analysis indicating greater slurry losses. Cement bond logs consistently confirmed enhanced zonal isolation, enabling safe perforation of shallow gas zones without inducing SCP or compromising well integrity. The novelty of this work lies in the integration of drilling optimization, engineered high-density slurry design, controlled flow regime, and mechanical displacement enhancement to directly address the root cause of zonal isolation failures, transforming previously uneconomic shallow gas targets into reliably producible resources. The field-proven methodology can be adopted in similar shallow unconsolidated environments, offering substantial technical, operational, and economic value.
R. Firmansyah, A. Nuryani, Y. Yusuf et al.· SPE/IADC Asia Pacific Drilli...· 0 citations
Mature oil wells are commonly characterized by declining production rates, increasing water cut, lift limitations, and increasing uncertainty in zonal contribution. These challenges arise from reservoir depletion, evolving fluid distribution, changing wellbore flow dynamics and may result in conservative operational choices and premature well abandonment. A key limitation in late-life well management is the reliance on surface production data, which provide only aggregated well performance and do not adequately capture downhole flow behaviour. Surface measurements alone are insufficient to resolve zonal contribution, identify water-producing intervals, or detect inter-zonal crossflow, particularly in wells completed across multiple flow units within a reservoir with no distinct fluid composition.
In many mature assets, production logging is often deployed on a reactive basis or deferred due to operational constraints and cost considerations. As a result, intervention decisions are frequently made using incomplete or indirect data, increasing the likelihood of misdiagnosis and ineffective operations. Production logging provides a reliable means of evaluating well and reservoir performance under dynamic conditions, enabling identification of zonal contribution and flow behaviour along the wellbore. When integrated into a structured workflow, it improves diagnostic confidence and supports effective intervention planning.
Production logging tool (PLT) data acquired under both flowing and shut-in conditions were integrated with historical production performance, static pressure surveys, and completion configurations to improve understanding of downhole flow behaviour relevant to intervention decision-making. The analysis revealed uneven zonal contribution, with certain intervals continuing to produce oil while others were dominated by water production. In some cases, inter-zonal crossflow during shut-in conditions masked true reservoir performance, resulting in restart difficulties and unstable production behaviour. Insights from PLT interpretation were used to design targeted light well interventions, including selective isolation of non-contributing or high water-producing intervals while preserving oil-bearing zones. These interventions were implemented without escalating to major workovers.
Application of the PLT–driven workflow resulted in stabilized oil production, improved performance of remaining oil-bearing zones, and extension of productive well life. While the analysis is based on a single well case, the observed challenges and diagnostic outcomes are representative of common issues encountered in mature oil wells completed across multiple intervals. The workflow presented in this study is therefore broadly applicable and provides a practical framework for production optimisation and intervention planning. The study demonstrates that production logging as a decision-support tool, provides significant value in optimizing mature oil wells and minimizing unnecessary well abandonment.
T. Obulor, A. Ajayi, M. Wobo et al.· SPE Nigeria Annual Internati...· 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
Drilling in unconventional, tight, and shale-dominated formations continues to be constrained by persistent wellbore instability, driven by geomechanically weak zones, abnormal pore pressure gradients, and the high reactivity of clay-rich lithologies. These challenges manifest as borehole enlargement, sloughing, circulation losses, stuck pipe, and, in severe cases, catastrophic well-control incidents. Instability-related nonproductive time (NPT) imposes a significant financial burden, estimated globally at $15–37 billion annually, with shale instability alone contributing nearly $8 billion. A primary cause is the hydration, swelling, and dispersion of hydrophilic clays when exposed to conventional water-based drilling fluids.
This paper addresses the persistent challenges of drilling through unstable clay-rich and laminated shaly formations by leveraging insights from historical statistical analyses and introducing a next-generation shale inhibition system. Engineered with advanced polymeric and amphiphilic chemistry, the system ensures superior thermal stability up to 300 °F while maintaining highly effective inhibition performance even at low concentrations. Through seamless integration with drilling analytics, the technology continuously monitors shale–fluid interactions, dynamically adjusts inhibitor concentrations, and proactively flags early indicators of wellbore instability. Distinct from conventional high-chloride, potassium-based solutions, this system not only minimizes clay reactivity but also delivers a technically robust, operationally reliable, and economically sustainable alternative tailored for the demands of unconventional drilling environments.
Field validations were performed in two Middle Eastern unconventional wells characterized by severe shale reactivity, washouts, and tight-hole challenges. Leveraging drilling analytics and pattern recognition models, fluid formulations were dynamically adjusted to mitigate instability risks. In the first application, KCl concentration was reduced to 3%, achieving a 17% reduction in total fluid-related costs while maintaining excellent wellbore stability. In the second, KCl dosage was further reduced to 1%, yielding 23% cost saving compared to incumbent systems. Both wells-maintained stability across critical hole sections with no major instability events.
Beyond technical results, the system demonstrated environmental and logistical advantages. Chloride content was reduced from ~30,000 ppm to 1,400 ppm, enhancing ecological compatibility and enabling use in non-weighted completion scenarios. The fusion of advanced shale inhibition chemistry with AI-driven drilling analytics reduced rig time, minimized mud treatment, and optimized cost of goods sold (COGS). Collectively, these outcomes establish a transformative benchmark for shale control, combining chemical innovation, real-time drilling intelligence, and sustainable design to enhance well integrity and operational performance in unconventional drilling.
A. Alanssari, Mohammed Omer, L. Chaparro et al.· SPE/IADC Asia Pacific Drilli...· 0 citations
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