Key Petrophysical Properties Research Articles

Rock Mineral Volume Inversion Using Statistical and Machine Learning Algorithms for Enhanced Geothermal Systems in Upper Rhine Graben, Eastern France

AbstractAccurately determining the mineralogical composition of rocks is essential for precise assessments of key petrophysical properties like effective porosity, water saturation, clay volume, and permeability. Mineral volume inversion is particularly critical in geological contexts characterized by heterogeneity, such as in the Upper Rhine Graben (URG), where both carbonate and siliciclastic formations are prevalent. The estimation of mineral volumes poses challenges that involve both linear and nonlinear relationships associated with geophysical data. To address this complexity, our methodology strategically integrates the robust insights from standard statistical approaches with three machine learning (ML) algorithms: multi‐layer perceptron, random forest regression, and gradient boosting regression. Furthermore, we propose a new hybrid ensemble model that incorporates a weighted average of multiple ML approaches to predict mineral composition within the Muschelkalk and Buntsandstein formations of the URG. ML techniques for mineral composition prediction in these formations exhibit robust predictive performance. The predicted mineral volumes align closely with quantitative estimates derived from X‐ray diffraction analysis. Additionally, they are in good qualitative agreement with mineral descriptions obtained from cores and cuttings of the Muschelkalk and Buntsandstein formations.

A geological, petrophysical and ground motion model of the Pavoncelli bis hydraulic tunnel (Southern Apennines, Italy): Implications for reservoir analyses

The strong 1980 M6.81 Irpinia earthquake in Southern Italy critically damaged the Pavoncelli hydraulic tunnel. Based on geological, petrophysical and geomechanical investigations and seismological data, a multi-scale geological model was inferred. The detrital mode and key petrophysical properties (porosity, permeability, and nanopore volumes) data have been used for defining the water-reservoir potential of the arenitic successions, with a focus on defining the hydrogeological model. The model was then used to perform a novel back-analysis of the spatial distribution of the peak ground acceleration (PGA) caused by the 1980 earthquake accounting for site-effects in a robust manner. This analysis, which accounts for site-effects in a robust manner, shows high PGA values along the length of the Pavoncelli tunnel, which is located between the causative fault of the 1980 earthquake in the vicinity of the epicenter. The main outcomes of the study are that: (1) the multi-scale and interdisciplinary approach developed in this study can be used in future studies in this and other areas, (2) the spatial 2D-3D geological model must be accounted for when analyzing distributed systems, (3) the hydrogeological model coupled with porosity data allows for reservoir analyses and (4) the complex tectonic environment in the area hosting the Pavoncelli tunnel plays a strong role in the analysis of the spatial distribution of PGA, creating the need for site-specific seismic microzonation studies and the evaluation of near-fault effects.

Metasomatism of the continental crust and its impact on surface uplift: Insights from reactive‐transport modelling

AbstractHigh‐elevation, low‐relief continental plateaus are major topographic features and profoundly influence atmospheric circulation, sediment transport and storage, and biodiversity. Although orogenic surface‐uplift mechanisms for modern continental plateaus near known plate margins like Tibet are well‐characterized, they cannot account for examples in intracontinental settings like the Colorado Plateau. In contrast to canonical plate‐tectonic uplift mechanisms, broad‐scale hydration‐induced metasomatism of the lower crust has been suggested to reduce its density and increase its buoyancy sufficiently to contribute to isostatic uplift. However, the relationships between key petrophysical properties in these environments are not fully quantified, which limits application of this model. Here, we develop a series of petrological models that describe the petrological and topographic effects of fluid–rock interaction in non‐deforming continental crust of varying composition. We apply an open‐system petrological modelling framework that utilizes reactive‐transport calculations to determine the spatial and temporal scales over which mineralogic transformations take place compared with the magnitude of infiltration of aqueous fluids derived from devolatilization of subducting oceanic lithosphere. The buoyancy effect of hydration‐induced de‐densification is most significant for metabasic lower crust, intermediate for metapelitic crust, and minimal for granodioritic crust. We apply these results to a case study of the ~2 km‐high Colorado Plateau and demonstrate that under ideal conditions, hydration of its lower–middle crust by infiltrating aqueous fluids released by the Farallon slab during Cenozoic low‐angle subduction could have uplifted the plateau surface by a maximum of ~1 km over 16 Myr. However, realistically, although hydration likely has a measurable effect on surface tectonics, the uplift of orogenic plateaus is likely dominantly controlled by other factors, such as lithospheric delamination.

Investigation of Source and Reservoir Rock Petroleum Generative Potential of Early Eocene and Paleocene Sequences of the Punjab Platform Basin, Pakistan: A Geochemical and Petrophysical Approach

Abstract ––Investigating Early Eocene and Paleocene deposits within the Punjab Platform, Pakistan, involved comprehensive analysis using advanced geochemical and petrophysical techniques. This study evaluates the source potential of three formations: Nammal and Sakesar of Early Eocene age and Dungan and Ranikot of Palaeocene age. The Sakesar Formation, a reservoir rock, was evaluated through interpretation of wireline logs to estimate key petrophysical properties—porosity, water saturation, and hydrocarbon saturation. Geochemical investigations focused on total organic carbon content and Rock-Eval pyrolysis of twenty-one cutting samples from a well. These samples displayed TOC values ranging from 0.21 to 2.04 wt.% and S2 values ranging from 0.09 to 2.14 mg HC/g rock. Analysis positioned all samples within the immature window zone with Type II/III and Type III kerogen, suggesting limited generative potential. Findings suggest limited hydrocarbon generation from these formations. Petrophysical analysis indicated average porosity of 11.2%, water saturation of 32.58%, and hydrocarbon saturation of 67.42% for the Sakesar Formation, categorizing it as average to good reservoir potential. This study highlights complex geochemical and petrophysical characteristics of these formations. While Sakesar shows promising reservoir qualities, significant hydrocarbon generation potential from Nammal, Dungan, and Ranikot formations is constrained. Informed decision-making is crucial when considering these formations as hydrocarbon sources.

A Hybrid Analytical and Data-Driven Approach for Improved Prediction of Recovery Performance in Tight Oil Reservoirs

Summary The heterogeneity of tight reservoirs, along with their complex geologic characteristics and the diverse completion practices used, presents challenges in developing accurate models to forecast the productivity for multifractured horizontal wells (MFHWs) completed in these reservoirs. This paper introduces a new early-time diagnostic tool that leverages early-time two-phase flowback data to forecast long-term productivity and evaluate completion efficiency. To achieve this, two novel models were developed. The first model, the water/oil-ratio model (WORM), uses a hybrid analytical and data-driven approach to describe the observed log-linear relationship between water/oil ratio (WOR) and load recovery (amount of fracturing water produced back after hydraulic fracturing operations) as an analogy to the log-linear relationship between the water/oil relative permeability ratio and water saturation. Next, a neural network is used to couple WORM parameters with key petrophysical properties to analyze the impact of fracture and formation properties on WOR performance, predict WOR as a function of load recovery, forecast ultimate load recovery, and estimate effective fracture volume and initial water saturation in fracture. The second model, the cumulative oil production model (COPM), is a data-driven model that predicts oil production as a function of load recovery during the matrix-dominated flow regime. The application of WORM and COPM on Niobrara and Codell formation wells showed that Codell wells generally exhibit better load recovery and larger effective fracture volume compared with Niobrara wells, but both formations exhibit similar oil recovery performance, indicating independent flow regimes within the effective fractures. The effective fracture volume estimated by WORM was validated against the estimated volume from recorded microseismic events. The results also showed that using the same completion practice to achieve a similar effective fracture volume in child wells does not necessarily lead to similar oil productivity. This paper introduces a holistic workflow that links early two-phase flowback data with well productivity and completion efficiency and is anticipated to aid petroleum engineers in optimizing hydraulic fracturing operations.

Direct measurement of hydrogen relative permeability hysteresis for underground hydrogen storage

Underground Hydrogen Storage (UHS) is a long-term storage solution which utilises hydrogen as an energy carrier to store large-scale excess renewable energy in the subsurface. Key petrophysical properties, such as wettability and interfacial tension of hydrogen and water have been discovered which provide a practical basis for simulation models. Our work directly measures relative permeability hysteresis during co-injection core floods of hydrogen and water with a capillary number of Nc=2.92×10−7. Segmented micro-CT images are used to determine saturation in the Bentheimer sandstone. Our results demonstrate that hydrogen relative permeability in sandstones is very low, with an end-point relative permeability of krg0=0.049 at Swi= 0.24. Capillary trapping results in residual gas saturation of Sgr= 0.4. Wettability analysis confirms the system is water-wet, with contact angles of 57° at Sgr and 44° at Swi. These results improve the reliability of numerical simulations and demonstrate the possible challenges involved with the commercial application of UHS.

Diagenesis and petrophysics of regional sandstone suites in Southern Apennines Foreland Basin, Italy

The southern Apennines foreland region preserves deep-marine turbiditic clastic wedges with contrasting and mixed petrofacies, including 5 distinctive sandstone suites: I) quartzarenite suite of the Numidian Sandstone, II) quartzolithic sandstone suite of the Corleto Perticara Formation, III) quartzofeldspatolithic sandstone suite of the Cilento Group (San Mauro and Albidona Formations), IV) quartzofeldspathic suite of the Gorgoglione Formation, V) arkose sandstone suite of the Oriolo, Nocara, Castelvetere formations. Since the great complexity of these sediments, the main diagenetic events and the key petrophysical properties were investigated to update a database that could be an effective method for petrophysical parameters prediction for similar foreland petroleum systems. The most widespread diagenetic minerals are carbonate, mainly calcite and dolomite, occurring as replacement on detrital grains or as pore-filling cements, and less quartz, phyllosilicate and Fe-oxides and hydroxides cements. These minerals accounted for a widespread process of cementation that, together with compaction greatly influenced the sandstone suites petrophysics, from the lowest porosity median value (3.2 %) of the Numidian Sandstone to the highest value of the Oriolo Fm. (16,75 %). In fact, these formations show porosity and permeability values depending by detrital modes that control the effect of compaction, cementation and dissolution during diagenesis.

First assessment of an area potentially suitable for underground hydrogen storage in Italy

Hydrogen storage can help achieve climate change and reduce greenhouse gas emissions. This paper presents a first assessment of the suitability of northeastern Italy for underground hydrogen storage (UHS). The study focuses on the analysis of publicly available well data, which allowed identifying geological formations potentially suitable for UHS. The most promising area, known as the “Treviso Area” consists of both saline aquifers and depleted gas fields. One of the key petrophysical properties, i.e. porosity, was calculated for each of the five wells revealing conditions potentially suitable for UHS by applying empirical formulas to geophysical log data. For the two depleted gas fields, a hydrogen injection simulation was also performed. This work is a pioneer study and lays the foundation for hopeful further analyses, which could help implement the recently launched “North Adriatic Hydrogen Valley” initiative.

Review of Marginal Oil Resources in Highly Depleted Reservoirs

The term “marginal oil resource” refers to an oil reservoir that has hydrocarbon resource preservation but cannot meet the criteria of resources under the U.S Securities and Exchange Commission (SEC) standards. When oilfields step into their late life, most of their economic petroleum reserves have been well developed, and their focuses need to be switched to their intact marginal resources. In this paper, reservoir characteristics and key petrophysical properties of marginal oil resources are introduced to classify marginal oil resources into four types for identifying potential development opportunities. Primary recovery and its following development strategy are applied to fully utilizing their economic returns. Waterflooding, low salinity waterflooding (LSW) and enhanced oil recovery processes are reviewed to illustrate its potential uplift on oil production and application challenges such as higher clay content in marginal resources than in commercial reservoirs. An oilfield is presented as a case study to demonstrate the classification of marginal resources and illustrate successful economic development including learnings and challenges. This paper highlights the development potential of marginal resources and proposes a clear guidance for policy makers on how to tailor a development strategy supporting their economic development. This review could increase certainty on forecasting performance of marginal resources.

Permeability prediction in tight gas reservoirs based on pore structure characteristics: A case study from South Western Iran

Abstract Porosity, pore structure characteristics, and permeability are among the key petrophysical properties of shale gas resources. Accurate characterization of these parameters in the unconventional gas shale systems has been proved to be challenging due to the uniqueness of the pore structures, mineral compositions, tightness, and pores hosted in the organic matter. In this study, the porosity, pore structure characteristics, and permeability of cored samples from the Garau shale formation located in the southwestern part of Iran were evaluated using a combination of laboratory methods. Multiple linear regression analyses were then utilized to develop empirical relationships between helium permeability values, porosity, and pore throat radii. Results showed that the best permeability predictors for the examined samples could be developed using the pore throat radius that corresponds to a mercury saturation of 55% and porosity. This approach helps develop a permeability prediction model for tight shale gas reservoirs based on pore structure characteristics, reducing cost and time.

A comparison of the relationship between measured acoustic response and porosity in carbonates across different geologic periods, depositional basins, and with variable mineral composition

Recent work has shown that there is a predictable inverse relationship between laboratory-measured sonic velocity response and porosity in carbonates, which can be reasonably approximated using the empirical Wyllie time-average equation (WTA). The relationship was initially identified in late Cretaceous to Cenozoic age samples collected from the Great Bahama Bank and the Maiella Platform, an exhumed Cretaceous carbonate platform in Italy. We have compared older carbonate samples from different basins and different geologic ages to determine the applicability of this relationship and subsequent correlations to key petrophysical properties to other carbonate basins and other geologic time periods. The data set used for the comparison shows this relationship to be relatively consistent in other depositional basins (Michigan Basin, Paradox Basin) and with samples from older geologic periods (Pennsylvanian, Ordovician, and Mississippian). However, this basic relationship is also observed to vary significantly within a reservoir system and within a depositional basin in samples from different geologic periods (e.g., Silurian- versus Ordovician-age rocks in the Michigan Basin). Although the empirical WTA can generally be applied as a first-order estimate across a wide range of sample ages in carbonates, limited data suggest the relationship between velocity and porosity to be moderately more complex. For instance, in unconventional carbonate reservoirs characterized by predominantly micro- to nanoscale porosity, it is observed that the WTA should be applied as an upper data boundary. In addition, this study has shown that the relationship to the dominant pore type is less direct than in a macropore system in which it can be assumed that the dominant pore type also has the greatest effect on the effective permeability.

An enhanced approach to predict permeability in reservoir sandstones using artificial neural networks (ANN)

A key challenge in the oil and gas industry is the ability to predict key petrophysical properties such as porosity and permeability. The predictability of such properties is often complicated by the complex nature of geologic materials. This study is aimed at developing models that can estimate permeability in different reservoir sandstone facies types. This has been achieved by integrating geological characterization, regression models and artificial neural network models with porosity as the input data and permeability as the output. The models have been developed, validated and tested using samples from three wells and their predictive accuracy tested by using them to predict the permeability in a fourth well which was excluded from the model development. The results indicate that developing the models on a facies basis provides a better predictive capability and simpler models compared to developing a single model for all the facies combined. The model for the combined facies predicted permeability with a correlation coefficient of 0.41 which is significantly lower than the correlation coefficient of 0.97, 0.93, 0.99, 0.96, 0.96 and 0.85 for the massive coarse-grained sandstones, massive fine-grained sandstones-moderately sorted, massive fine-grained sandstones-poorly sorted, massive very fine-grained sandstones, parallel-laminated sandstones and bioturbated sandstones, respectively. The models proposed in this paper can predict permeability at up to 99% accuracy. The lower correlation coefficient of the bioturbated sandstone facies compared to other facies is attributed to the complex and variable nature of bioturbation activities which controls the petrophysical properties of highly bioturbated rocks.

Investigating the Fractal Characteristics of Pore-Fractures in Bituminous Coals and Anthracites through Fluid Flow Behavior

The characteristics of pore-fractures are the key petrophysical properties used to assess and evaluate coalbed methane (CBM) reservoirs and include pore types, structure types, porosity/percentage, and pore-fracture space properties. To study the storage and seepage capability of a CBM reservoir, based on 18 coal samples with the maximum vitrinite reflectance (Ro,max) in the range of 1.06–3.04%, we used the nuclear magnetic resonance (NMR) method and fractal analysis to investigate the effect of coalification on the characteristics of pore-fractures. First, the pore-fracture space in a coal reservoir includes irreducible fluid space and moveable fluid space. We built up the moveable fluid NMR fractal based on the saturated/irreducible fluid NMR fractals. Saturated fluid fractal (Dw), irreducible fluid fractal (Dir), and moveable fluid fractal (DM) have the following relationship: DM > Dir > DW. Additionally, Dir has a huge fluctuating value area with the maximum vitrinite reflectance (Ro,max) varying between 1.93% and 2.06%. The curve lg(T2) and lg(V) for a moveable fluid fractal has four typical types. The shapes “C”, “Z”, “S”, and “T” correspond to four structure types (A, B, C, and D), which provide significant guidance for CBM exploitation. Moreover, the saturated-irreducible T2 distribution has a special shape, known as the pendular ring, which affects the seepage ability and permeability. Second, we classify the pore-fracture types based on the saturated fluid NMR fractal and the T2 distribution as follows: adsorbed pore (T2 < 0.4 ms, < 10 nm), transition pore (T2 = 0.4–2.5 ms, 10–100 nm), seepage pore (T2 > 2.5 ms, > 100 nm). At Ro,max = 1.06–3.04%, the percentages of pore-fracture types show that coalification have three coalification jumps at Ro,max = 1.3%, 2.0%, and 2.8%. The porosities of pore-fracture types show that the thermal volatilization of fillers in pore-fractures begins at Ro,max = 1.5% and disappears at Ro,max = 2.5%. Different fluid space fractals demonstrate that when Ro,max < 2.0%, the coal reservoir tends to be compressed and consolidated, whereas when Ro,max > 2.0% the coal reservoir tends to be orderly and uniform. BVM/BVI is the ratio of the irreducible fluid space (BVI) and the movable fluid space (BVM). Finally, the permeability indicates a positive exponential function with BVM/BVI for seepage pores, and it exhibits a negative exponential function with BVM/BVI for adsorbed pores and transition pores. The NMR method combining fractal analysis with coalification enables us to characterize pore-fractures and the effects of coalification on pore-fractures quantitatively, which contributes to guiding CBM exploitation. Moreover, the relationship between permeability and BVM/BVI is beneficial for predicting the favorable areas for CBM exploitation.

Investigating the Effects of Seepage-Pores and Fractures on Coal Permeability by Fractal Analysis

Permeability is one of the key petrophysical properties for the coalbed methane (CBM) reservoirs, which directly impact the CBM production rate and the amount of CBM that can be ultimately recovered. Due to the complex and heterogeneous nature of coals, an accurate determination for permeability of coals is required. Coal permeability is often determined by fractures (or cleats), which correlates with the aperture of cleats and cleats frequency. However, the gases flow path in coals covers fractures (or cleats), and pores with pore width $$>$$ 100 nm; thus, the effect of pores on permeability should not be neglected, especially in the process of outgassing for methane release from pores over 100 nm (defined as seepage-pores) in the coal seams. Understanding of this issue is limited. Therefore, the determination of the pore size distribution in coal cores was conducted by using mercury intrusion porosimetry. With a specific interest in larger pores ( $$>$$ 100 nm), the larger pores are linked to their contribution to permeability in coal cores with core permeability by the transient pulse method. Based on 33 coal samples with vitrinite reflectance in the range of 0.54–2.99 %, this work examines the seepage-pores contribution on core permeability by using classic geometry and thermodynamics fractal model. Moreover, a pore fractal permeability model was established to acquire the seepage-pores permeability, which can be used to interpret the permeability evolution of coals during coalification. Coal pore surfaces generally have very high heterogeneity with fractal dimension of 2.75–2.96 from thermodynamics model $$(D_{\mathrm{ts}})$$ , which presents a cubic polynomial relation with coal rank. The fractal dimensions from thermodynamics model show a consistent result, which indicates that the pore size/volume distribution was one of the key parameters affecting seepage-pores permeability. Finally, an ideal coal permeability (including seepage-pores and fractures contributed) evolution model during coalification was proposed and the seepage-pores contributed permeability generally covers $$\sim $$ 10 to $$\sim $$ 30 % of the entire coal permeability.

Reducing Uncertainty in Reservoir Model Predictions: from Plume Evolution to Tool Responses

With the transition of geological carbon dioxide (CO2) storage from pilot to industrial scale, risk analysis has become pivotal for assessing the suitability of a storage site in satisfying regulatory requirements during and after injection. Risk analysis is inherently related to uncertainty quantification. This paper extends our previously developed workflows to quantify and propagate uncertainty from geological, geophysical and petrophysical data to project-level performance metrics including capacity, injectivity, and containment characteristics. We perform global sensitivity analysis to quantitatively link uncertainty in the computed performance metrics to the uncertainties in the underlying reservoir parameters. This enables one to identify measurements to reduce uncertainty estimates of reservoir performance metrics and predicted monitoring tool responses. We illustrate this workflow in a pre-injection uncertainty study for the Illinois Basin Decatur Project (IBDP). The reservoir model is built using geostatistical approach based on all available geophysical and petrophysical data including 3D seismic interpretation, results of special core analysis and injectivity tests. We focus on three groups of performance predictions: spatial extent of the CO2 saturation profile, partitioning of CO2, and predicted responses seen with the Westbay* multilevel groundwater characterization and monitoring system installed in the monitoring well. Based on multiple realizations of the reservoir model we evaluate the uncertainty range in pressures and CO2 saturations at the Westbay monitoring zones during the life of the project. Predicted measurements at the monitoring zones covering a depth interval between 1950 m and 2120 m are analyzed. Global sensitivity analysis is used to identify the key petrophysical properties of the reservoir whose uncertainties have the most effect on the uncertainty of the reservoir performance and measurement predictions. Results of this analysis provide valuable insight for targeted site characterization and design of the monitoring program.

Seismic modeling of multidimensional heterogeneity scales of Mallik gas hydrate reservoirs, Northwest Territories of Canada

In hydrate‐bearing sediments, the velocity and attenuation of compressional and shear waves depend primarily on the spatial distribution of hydrates in the pore space of the subsurface lithologies. Recent characterizations of gas hydrate accumulations based on seismic velocity and attenuation generally assume homogeneous sedimentary layers and neglect effects from large‐ and small‐scale heterogeneities of hydrate‐bearing sediments. We present an algorithm, based on stochastic medium theory, to construct heterogeneous multivariable models that mimic heterogeneities of hydrate‐bearing sediments at the level of detail provided by borehole logging data. Using this algorithm, we model some key petrophysical properties of gas hydrates within heterogeneous sediments near the Mallik well site, Northwest Territories, Canada. The modeled density, and P and S wave velocities used in combination with a modified Biot‐Gassmann theory provide a first‐order estimate of the in situ volume of gas hydrate near the Mallik 5L‐38 borehole. Our results suggest a range of 528 to 768 × 106 m3/km2 of natural gas trapped within hydrates, nearly an order of magnitude lower than earlier estimates which did not include effects of small‐scale heterogeneities. Further, the petrophysical models are combined with a 3‐D finite difference modeling algorithm to study seismic attenuation due to scattering and leaky mode propagation. Simulations of a near‐offset vertical seismic profile and cross‐borehole numerical surveys demonstrate that attenuation of seismic energy may not be directly related to the intrinsic attenuation of hydrate‐bearing sediments but, instead, may be largely attributed to scattering from small‐scale heterogeneities and highly attenuate leaky mode propagation of seismic waves through larger‐scale heterogeneities in sediments.