Aug 2026· SPE Nigeria Annual International Conference and Exhibition· 0 citations· 9 references
Abstract
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.
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
In marginal fields, STOIIP (Stock Tank Oil Initially In Place) uncertainty often concentrates around two linked issues: where the hydrocarbon contact sits and how pay is defined through cutoffs and petrophysical assumptions. Small shifts in water saturation cutoff, net-to-gross criteria, or assumed contact depth can move STOIIP enough to change development decisions, yet many evaluations report a single contact and a single cutoff set without quantifying sensitivity.
This paper presents a reproducible workflow to stress-test STOIIP against cutoff and petrophysical assumption uncertainty while keeping the analysis transparent and auditable. The method begins by defining a controlled "assumption set library, including alternative cutoff sets such as shale volume, porosity, and water saturation thresholds, alternative saturation models where applicable, and alternative contact interpretations based on available evidence (pressure gradients, test data, resistivity trends, and completion outcomes). Each assumption set is treated as a named scenario with documented rationale, rather than an informal adjustment.
For each scenario, the workflow computes net reservoir, net pay, average properties, and STOIIP using the same calculation engine and data inputs, ensuring changes in outcomes trace directly to the assumption changes. Sensitivity is quantified in three ways: (1) one-at-a-time cutoff sweeps to expose non-linear behavior, (2) paired sweeps that reflect real coupling (e.g., Sw cutoff with porosity cutoff), and (3) Monte Carlo runs where the contact depth and key petrophysical parameters vary within constrained ranges. Outputs include STOIIP response surfaces, tornado ranking of the dominant assumption drivers, and a compact decision risk table showing which assumptions can flip economic viability.
A case study demonstrates how the workflow highlights hidden fragility in a base-case STOIIP estimate and guides targeted data acquisition decisions, such as which pressure points, logs, or tests would most reduce uncertainty per unit cost. The paper concludes with recommended reporting standards for marginal-field evaluations, including minimum sensitivity checks that should accompany any STOIIP number presented for investment decisions.
W. O. Nneli, O. S. Ojo, A. Asaolu· SPE Nigeria Annual Internati...· 0 citations
In this study, a rapid analytical framework is developed for reconstructing transient formation-pressure distributions in sparsely connected fractured-vuggy carbonate reservoirs using well-test-derived fracture–cave geometry and source allocation. Pressure–flow relationships are established for caves, fractured bodies, and finite line-source fractures; unit-source solutions are combined via spatial superposition and Duhamel convolution for variable-rate production; and the framework is evaluated by comparing Well EX-1 against a PEBI-grid simulation. Cave response is derived from mass conservation and effective compressibility, while point- and line-source Green’s functions describe pressure diffusion. For the 30-day EX-1 case, analytical and PEBI pressures at four locations show close internal agreement, with a mean absolute error of 0.070 MPa, a root-mean-square error of 0.083 MPa, and a maximum absolute error of 0.13 MPa. This method is applicable mainly to single-phase, slightly compressible, linear-flow conditions with a constrained fracture–cave topology. It provides a rapid screening tool for deep carbonate reservoirs with sparse well control, while multiphase, strongly nonlinear, reactive, or geomechanically coupled cases require conventional numerical simulation.
The article analyzes real-time detection of gas-oil (GOC) and oil-water (OWC) contacts during horizontal drilling in clastic reservoirs. Timely localization ensures high-quality geosteering, keeping the wellbore within the pay zone and preventing undesirable fluid intersections. Relying solely on conventional logging-while-drilling (LWD) is often insufficient. Limitations arise from electrical macroanisotropy distorting resistivity data, the clay electrical double layer masking responses, and tool «blind zones» causing delayed observations, which poses a critical risk in horizontal drilling. To address this, advanced mud gas logging is proposed. Instead of indirect electrophysical features, this method captures actual reservoir fluid dynamics. By using chromatographic analysis of C1–C5 fractions and calculating Wetness, Balance, and Pixler ratios, characteristic fluid signatures and transition zones are identified. Crucially, reliable interpretation requires mathematical normalization of gas data. Without it, operational artifacts from rate of penetration (ROP) and mud flow rate fluctuations create false anomalies or obscure actual boundaries. An Eastern Siberian field case study demonstrates that normalized mud gas logging achieved real-time GOC localization with sub-meter accuracy in a low-contrast reservoir. Validated by pulsed neutron logging (PNL), this method proves to be an effective geosteering and risk management tool.
Keywords: mud gas logging; horizontal wells; gas-oil contact (GOC); oil-water contact (OWC); geosteering; mud logging; gas chromatography; gas data normalization.
R. R. Ilyazov, A. Shakhverdiev· SOCAR Proceedings· 0 citations
Large-scale deployment of CO₂ storage will require the drilling of numerous new wells, introducing additional operational challenges. One key concern is the potential influx of CO₂ into the wellbore during drilling operations, which can significantly alter the thermophysical properties of drilling fluids, including density and viscosity. A reduction in drilling fluid density or hydrostatic pressure may compromise well control and, in severe cases, lead to blowout incidents. It is therefore essential to quantify the impact of CO₂ dissolution on drilling fluid properties under representative downhole conditions, with pressures up to 400 bar and temperatures up to 100 °C.
Conventional densitometers are not suitable for these measurements due to the presence of solid particles in drilling fluids. To address this limitation, a dedicated experimental method was tested based on monitoring the volume changes of the fluid under controlled pressure, temperature, and CO₂ loading conditions. This paper first presents a detailed description of the experimental methodology. Subsequently, representative results are provided for drilling fluid density measurements, highlighting the influence from dissolved CO₂, pressure and temperature on fluid density behavior.
Tinku Saikia, Blandine Feneuil, E. N’gouamba et al.· Annual Transactions - The No...· 0 citations
Accurate estimation of relative permeability is essential for dynamic reservoir simulation and development planning. This study presents an integrated approach that utilises Nuclear Magnetic Resonance (NMR) log data to derive relative permeability curves for different rock types in a gas-bearing reservoir. NMR-derived porosity has been corrected for gas effects, and then absolute permeability is computed using Coates method. Flow Zone Indicator (FZI) analysis is performed to classify hydraulic flow units, which aids in identifying distinct rock types. A pseudo-capillary pressure curve is reconstructed from substituted T2 distributions using a method based on the relationship between irreducible water saturation and geometric mean T2. These pseudo-capillary pressure curves are then used to estimate normalised saturation and to compute relative permeability curves using the Corey method. This workflow demonstrates that NMR data, when appropriately processed, can serve as a powerful tool for estimating relative permeability in the absence of extensive laboratory measurements, offering significant value for reservoir characterisation and simulation workflows.
Anish Krishnapillai, V. Ramalingam· Journal of the Geological So...· 0 citations
We use cookies to run the site and, with your consent, for analytics and to show ads.
See our Cookie Policy.
