Wireline Logs Research Articles

Reservoir characterisation of unconventional rock units in the middle jurassic Sargelu Formation, atrush field, zagros folded belt

The heterogeneous lithological components of the Middle Jurassic Sargelu Formation in the Atrush field of the high folded zone were examined using rock samples, conventional wireline logs, mud logs and well test results throughout two wells. The Sargelu Formation is 45 m thick and has been divided into three units based on lithological characteristics and shale volume. The upper unit of the Sargelu Formation is composed of argillaceous limestone with intercalation of dolostone and anhydrite beds. The middle unit of the Sargelu Formation is composed of organic rich laminated shales, which contain residual bitumen, whilst the lower unit of the formation is dominated by argillaceous limestones. Lithological variation, mineralogy and organic matter contents are shown to be essential factors in controlling the reservoir matrix porosity and permeability. The maximum matrix porosity and permeability were observed within the dolomite plug samples (13.40%, 10.40 mD) and the lowest values were recorded in the anhydrite samples, both found in the upper unit of the Sargelu Formation. The fracture permeability is three orders of magnitude higher than the matrix permeability and the hydrocarbon production is predominately derived from the fractured intervals throughout the Sargelu Formation. The interconnected fracture pathways are influenced by the lithological variation and mineralogical components of the formation along with the tectonic position of the field. It was found that as the confining pressure increased the fracture permeability reduced. The different lithologies were also found to be sensitive to increases in the confining pressure. The clastic shale rich rocks are most sensitive to increases in confining pressure, whilst the more carbonate rich rocks showed the lowest variation as a function of confining pressure.

Pre-drill pore pressure prediction using seismic interval velocity and wireline log: Case studies for some wells in Cuu Long and Song Hong basins

Pore pressure can be obtained from seismic interval velocity by the velocity to pore pressure transform technique. In this paper, the authors present the Eaton experimental method to calculate pore pressure for some wellbores in the Cuu Long and Song Hong basins, where complex processes of subsidence, burial, geological transformation, and geothermal activity took place, causing abnormal pressure zones.The obtained results show that the pore pressures calculated from the seismic interval velocity data are closely correlated with the values measured by well logging methods and the density of the drilling fluids. Therefore, using seismic interval velocities to calculate pore pressure values, identify and predict abnormal zones by the Eaton method can be effectively applied in frontier areas to improve safety, reduce risks while drilling.

A practical approach to develop a proper anisotropic rock physics model for media comprising of multiple fracture sets in the absence of sophisticated laboratory/wireline data

For economical production from a fractured reservoir, a characteristic analysis of the fracture parameters like its density and orientation within the reservoir is essential to improve the fluid flow during extraction. This study deals with the development of a proper anisotropic rock physics model for a media with multiple fracture sets to study the spatial distribution of important fracture parameters i.e., fracture density and orientation in the absence of sophisticated laboratory/wireline and pre-stack seismic data. The crest of hydrocarbon producing fault-bounded Balkassar Anticline in Northern Potwar, Upper Indus Basin, Pakistan is selected as a case study representing a potential zone for development of fractures at reservoir level (Sakesar Limestone). The methodology consists of the interpretation of 3D post-stack seismic and conventional wireline log data to demarcate the reservoir containing fractures. The Ant-tracking discrete fracture network (DFN) attribute is applied on 3D post-stack seismic data to obtain an initial estimate about the presence of fracture corridors and their orientations. Based on this initial estimate, a proper rock physics model has been developed utilizing inverse Gassmann relations, T-matrix approximation, and Brown and Korringa relations. The output from the developed rock physics model has been displayed in the form of 13 effective independent elastic stiffness constants (monoclinic symmetry–representing media comprising of multiple fracture sets) as a function of fracture densities and azimuthal fracture orientations. A clear decreasing trend in effective elastic stiffness constants with increasing fracture densities can be observed. Similarly, a periodic trend of effective elastic stiffness constants with fracture orientations can be observed. These trends are more or less expected, but they would have been difficult to quantify without a proper rock physics model. The use of independent effective elastic constants for the generation of synthetic seismic amplitude versus angle and azimuth (AVAZ) data and its correlation with observed seismic AVAZ data in a geostatistical sense has been discussed.

Calculating Volume of Clay and/or Shale From Wireline Logs

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An allostratigraphic framework for the Late Albian to Early Cenomanian upper Fort St. John Group across the foredeep of the Western Canada Foreland Basin, NE British Columbia

Abstract The Upper Albian to Lower Cenomanian Hasler and Cruiser shales and intervening Goodrich Sandstone are up to about 800 m thick and constitute most of the upper Fort St. John Group in the foredeep of NE British Columbia. These rocks exhibit pronounced lateral changes in lithology and thickness from west to east, making their lithostratigraphic boundaries highly diachronous. An allostratigraphic approach to correlation, based primarily on discontinuity surfaces represented in wireline well logs, allows subdivision of these broad lithostratigraphic units, and permits correlation of genetic stratal packages across facies transitions, and from subsurface to outcrop. Upper Fort St. John strata spanning the foredeep in British Columbia are shown to be correlative with Viking allomember VD, and with the overlying Westgate and Fish Scales alloformations, previously defined in Alberta on the basis of outcrop, core and wireline log data. Bounding surfaces have also been correlated northward to connect with successions described from the Sikanni and Liard river areas of British Columbia. In the British Columbia study area, pyritic, largely unbioturbated mudstone of allomember VD thickens from 20 to 200 m, indicating syn-depositional flexural subsidence, greatest in the north-western part of the study area. The Westgate alloformation is also dominated by weakly bioturbated mudstone, but includes more common, thin, fine-grained sandstone beds, many with wave- and combined-flow ripples, organized in parasequences up to approximately 20 m thick. Westgate allomembers WA through WD take on a progressively more tabular geometry upward, reflecting diminishing flexural subsidence with time. Allomember WD includes shoreface/delta front sandstones (‘Goodrich Formation’) that extend eastward from the Foothills outcrop for up to 70 km. The Fish Scales alloformation, the base of which is defined by surface FE1, marks an abrupt introduction of sand across a muddy sea floor in response to sea-level fall. The upper boundary of the Fish Scales is the condensed section/downlap surface ‘Fish Scales Upper’ (FSU) beneath the Dunvegan alloformation. The Fish Scales alloformation is a pronounced wedge, thickening westward from approximately 100 to approximately 400 m. It consists mainly of pyritic, unbioturbated mudstone to claystone with a variable content of fish debris, indicative of dysaerobic to anaerobic bottom-water conditions. Ammonites do, however, indicate oxic surface waters. The Fish Scales alloformation comprises allomembers FA and FB, separated by an erosion surface termed the Base Fish Scales Marker (BFSM) which, throughout the Peace River region, has a veneer of chert pebbles that mark a major sea-level lowstand; pebbles were subsequently reworked by marine transgression. A 15 m thick conglomerate-filled channel (or paleovalley?), exposed in Hasler Creek, directly underlies the BFSM surface and is interpreted to be the deposit of a large river that supplied sediment to the lowstand shoreline. In the far west, close to the Foothills, the Fish Scales alloformation becomes sandy and bioturbated, and includes stacked ‘Goodrich’ shoreface sandstone bodies that prograded a few tens of km eastward. Mapped to the SE, allomember FA pinches out close to the Alberta-British Columbia border, whereas allomember FB persists as a thin and highly radioactive phosphatic mudstone, the base of which comprises the merged FE1 and BFSM erosion surfaces. Despite up to about 800 m of subsidence, sedimentary structures throughout the succession show that the sea floor, which formed a homoclinal ramp, remained above storm wave base, attesting to a very high sedimentation rate and effective offshore dispersal of sediment, primarily by storm-driven combined flows. Bivalves of the genus Posidonioceramus have recently been proposed as a marker for the base of the Cenomanian Stage. These fossils are found in the study area as low as the base of Viking allomember VD, which implies that the Albian-Cenomanian boundary may lie at a level significantly lower than the long-accepted ‘Base of Fish Scales’ erosion surface.

Unsupervised time series clustering, class-based ensemble machine learning, and petrophysical modeling for predicting shear sonic wave slowness in heterogeneous rocks

Shear sonic logs are critical for formation evaluation, rock physics, quantitative reservoir characterization, and geomechanical studies. Although empirical and conventional machine learning (ML) have been used for shear sonic slowness estimates, both approaches suffer from multiple fundamental problems. New approaches to ML, namely, unsupervised multivariate time series clustering (Toeplitz inverse covariance-based clustering) and class-based ensemble ML, are integrated with geologic information and petrophysical inversion-based multimineral models to predict rock properties of the Wolfcamp Formation in the Midland Basin, United States. These new approaches consider the interdependence of wireline log attributes, temporal or depth dependence of log responses, multimodal geologic factors, and variability of individual ML model-based results to generate the best possible ML model. The results from the proposed approach indicate highly accurate and consistent shear sonic log predictions with a minimal error for thousands of feet (hundreds of meters) in several wells in the Wolfcamp Formation, covering a large study area in the basin. The results are used in estimating elastic properties, such as Poisson’s ratio, lambda-rho (incompressibility), and mu-rho (rigidity) to delineate brittle and ductile units in the formation.

Experimental Investigating of Compaction Effect on Porosity Measurement for Carbonate Rocks

Oil and natural gas may be found in commercial reservoirs, porous and easily permeable rocks. Porosity is an essential characteristic of reservoirs. This research focuses on comparing laboratory-measured porosity to log porosity. A comparison of the porosity values determined in the lab using the liquid saturation technique, density method, an ultrasonic method, and the porosity computed from wireline logs such as sonic, density, and neutron logs. Compaction is the decrease in volume caused by an external force. A discrepancy exists between the laboratory and log porosities because of the rock compaction. It is important to note that porosity may be broken down into two categories: total and effective. After calculating the bulk and grain volumes, the total porosity is determined by averaging the results of several techniques, such as gas density logs, density logs, and neutron logs. The porosity is estimated using ultrasonic equipment in the lab and compared to sonic logs. Sonic tests show a higher porosity in the lab than in the log due to the formation's rocks being compacted. An excellent correlation exists between density log porosity and density porosity from the lab, with a determination coefficient of 0.79.

Use of Subsurface Geology in Assessing the Optimal Co-Location of CO2 Storage and Wind Energy Sites

Opportunities exist to re-purpose depleted gas fields in the Southern North Sea as CO2 storage sites if, where and when they meet the right set of geological, engineering, and non-technical criteria. Fields positioned on the western edge of the basin are attractive as they lie close to the major industrial emitters of East England which need to decarbonise if the UK’s Net Zero targets are to be met. Having stopped production in 2018, Pickerill has CO2 storage potential as it is a proven trap from which around 440 Bcf of gas has been produced and it is located near the coastline. We use a public-domain 3D seismic dataset, wireline logs, core reports and production data to assess its CO2 storage potential. The Rotliegend Group reservoir (Leman Sandstone Formation) is a mixed aeolian/fluvial succession with variable thickness (25 m–80 m), high net-to-gross (0.9–1.0), moderate average porosity (9%–17%) and fair-average permeability (>1 mD). The seal is Zechstein Group evaporites and carbonates which thin and swell in response to their post-depositional mobility (halokinesis), further affecting and deforming the overburden. The structure is defined to the south by a WNW-ESE-striking fault system, but the north of the field is characterised mostly by dip closure of the reservoir. NW-SE-striking faults transect the field and segment the structure into several compartments, three of which appear particularly good candidates for CO2 storage and have a combined CO2 storage capacity of 32 MtCO2. If combined with nearby satellite fields, there is potential for the development of a CO2 storage cluster capable of sequestering 60 MtCO2, however, this potential is challenged by the planned development of an offshore wind farm. Turbines fixed to the seabed over the field would restrict where new CO2 injection wells might be drilled and efforts to measure, monitor and verify the CO2 plume using conventional towed-streamer seismic. There is an urgent need to resolve the competition for offshore acreage to ensure that attractive CO2 storage sites like Pickerill are not disadvantaged but can play a full part in complementing alternative renewable energy sources within the energy transition.

Identification and modeling of the hydrocarbon-bearing Ghar sand using seismic attributes, wireline logs and core information, a case study on Asmari Formation in Hendijan Field, southwest part of Iran

Identification and modeling of the hydrocarbon-bearing Ghar sand using seismic attributes, wireline logs and core information, a case study on Asmari Formation in Hendijan Field, southwest part of Iran

A combined GIS-based remote sensing and wireline log data analysis for water resource management in the economic capital district of Cameroon

A combined GIS-based remote sensing and wireline log data analysis for water resource management in the economic capital district of Cameroon

Characterization and evolution of a carbonate basin floor fan on a leeward side of an isolated carbonate platform, Sirte Basin, Libya

The recognition of carbonate basin floor fans and the interpretation of their formation and evolution are extremely crucial to the hydrocarbon exploration since they form important oil and gas reservoirs. There has been little research on the geometries and controlling factors of the carbonate basin floor fans from subsurface three-dimensional (3D) seismic and wireline log data. Most studies have been conducted on siliciclastic basin floor fans. Thus, this study characterizes the internal configuration and processes controlling the deposition of a lower Eocene carbonate basin floor fan system in the Sirte Basin in a sequence stratigraphic context through integrated 3D seismic and wireline log interpretations. The carbonate fan complex shows hummocky to undulated seismic geometries on vertical seismic sections and bounded by an unconformable sequence boundary at the base and a downlap surface at the top. It has an aerial extension of around 9 km from south to north along depositional dip and at least 8 km from east to west along strike. In well data, the fan system predominantly comprises limestone units intercalated with thin shale intervals. Log curves display an overall funnel-shaped trend, suggesting progradational stacking pattern. The vertical thickness of the fan complex varies from 120 to 165 m. The evolution of the carbonate fan was influenced by the interplay of accommodation space and sediment supply. A pre-existing topography, tectonic subsidence, and sea-level rise generated accommodation space for the deposition of the fan system, whereas sediment-gravity flows transported the fan sediments from the platform interior and margin to the basin floor. This study provides sedimentological and stratigraphic criteria to recognize and interpret the evolution of basin floor fans along isolated carbonate platforms from 3D seismic and wireline log data and may serve as an analog for ongoing and future studies on carbonate basin floor fans elsewhere.

Investigation of the Cretaceous total petroleum system using wireline logs, core, and geochemical data in Bahrah Field, Northern Basin, Kuwait

We used wireline logs, seismic, core data, fluid analysis, and geochemical data to investigate the total petroleum system in the Cretaceous period. Also, we used thin sections and fluid analysis throughout the investigation. Python’s 1-D backstripping technique was used to determine the abrupt changes in subsidence rates and their effect on the reservoir’s quality. The results defined that the potential reservoirs include, from top to bottom, Mauddud, Upper Burgan, Lower Zubair, and Ratawi Limestone. The reservoir facies reflect different environments between the carbonate ramp (Mauddud, Ratawi Limestone, and Minagish reservoirs), delta plain (Zubair reservoir), and margin shelf (Burgan reservoir), and its quality is graded from Mauddud to Ratawi Limestone from top to bottom. The field lies up-dip under Kuwait Bay and represents the continuation of super-giant Greater Burgan Field. It filled with the spilled oil from the down-dip Raudhatain and Sabriyah fields through a structural saddle. Two major tectonic events subsided the deposited sediments by 0.25 mm/year, besides three minor events; however, these events did not affect all Cretaceous reservoirs but only according to their deposition times. Furthermore, according to burial history, thermal maturity, and reservoirs’ fluid geochemical analysis, the Sulaiy (Makhoul) and Minagish formations are likely the primary sources for all Cretaceous reservoirs.

An integrated source rock potential, sequence stratigraphy, and petroleum geology of (Agbada-Akata) sediment succession, Niger delta: application of well logs aided by 3D seismic and basin modeling

We investigated the source rock potential, sequence stratigraphy, and characterized hydrocarbon reservoirs at Otumara field, Niger delta, using integrated 3D seismic, wireline log analysis, and basin modeling. The burial history and thermal maturity were modeled, the reservoirs were delineated, and the petrophysical parameters were also estimated from the wireline logs. The Passey “ΔLog R” method for estimating the preliminary evaluations of the total organic carbon (TOC) from integrating sonic, neutron, and density with resistivity has been used. The results indicate that the primary source rock of hydrocarbons is the Upper Akata Formation, despite a higher TOC percentage in the Agbada Formation. Based on sequence stratigraphy analysis, TA4, TB1, TB2, and TB3 second-order supercycles were obtained in the studied well TD46. The results also revealed that the field has two large net pays with high-quality reservoir facies: a deltaic slope fan at the upper shoreface and a river mouth sandbar at the lower shoreface. Furthermore, the reservoirs were faulted by a series of growing faults that faulted the basin slope. The reservoir facies are characterized by an average of 18% porosity, 1200 mD permeability, 16% volume of shale, and high hydrocarbon saturation of about 85%. Finally, the petroleum system elements have been defined for improved hydrocarbon exploration. In the absence of complete or partial core samples, this case study emphasizes the importance of using wireline logs to estimate organic richness and investigate sequence stratigraphy in clastic sediments.

Prediction of Cretaceous reservoir zone through petrophysical modeling: Insights from Kadanwari gas field, Middle Indus Basin

This study involved an interpretation of wire-line logs in assessing the hydrocarbon capacity of the sandstone reservoir within the gas fields of Kadanwari, Sindh, Pakistan. Wire-line logs from four wells (KD-01, KD-03, KD-10 and KD-11) were used in our research and provided interpretation for thirteen reservoir zones. Reservoir analyses were done for effective porosity (ϕeff), shale content (Vsh), net pay thickness variations, water saturation, and hydrocarbon (Sw and Shc). Hydrocarbon-bearing zones consist of high values of resistivity, permeability, porosity, low water saturation content, and less shale content, indicating the presence of clean sand. The Thomas Stieber model findings show that in lower Goru sand, the laminated form of shale distribution persists. Sub-reservoirs’ petrophysical parameters were analyzed and ranked into a good sand reservoir quality (having ϕeff ∼0.11-0.44%), permeability (∼10.539-477.76 mD), hydrocarbon saturation (having Shc ∼0.59-0.86%), and water saturation (having Sw ∼0.18-0.45%). In the current research Indonesian model has been used to test for water saturation over a shaly-sand reservoir situated in a heterogeneous zone. It was observed that each well exhibited Sw at values lesser than 60%. This is indicative the selected zone has a hydrocarbon potential, and the hydrocarbons are of good quality. Isoparametric maps and crossplots of litho-saturation results reveal variations in the horizontal and vertical petrophysical parameters of the reservoir. The subsurface reservoir geographical distribution is visualized employing isoparametric maps. The fuel treasure in the southwestern section of the study area is enormous, as revealed by the petrophysical investigations, suggesting more well-drilling prospects in the gas fields of the lower Goru Formation situated in Kadanwari. Our research identified a quality hydrocarbon hotspot zone of immense economic value in Southern Kadanwari. In contrast, more research is needed regarding the northeastern section though our present findings suggest the northeastern section should be avoided because of excess shale and high-water concentrations.

Subsurface geology and geochemical evaluation of the Middle Jurassic-Lower Cretaceous organic-rich intervals, West Kalabsha area, Western Desert, Egypt

The West Kalabsha (WKAL) area is a western extreme exploratory area of the Faghur Basin in the Western Desert of Egypt. The study of four wells (WKAL; A-1 X, K-1 X, P-1X, and C-1 X), interpreted with twenty seismic lines, shows that the area is dissected by a series of normal faults with an irregular, E–W strike direction. The general trend of the throw is toward the south–southeast. The most prospective area for hydrocarbon (HC) migration is toward the north (upthrown side) of an E-W striking normal fault north of the WKAl-K-1 X and A-1 X wells. The WKAL-P-1 X and WKAL-K-1 X wells in the Faghur Basin were selected for both geochemical evaluation of possible source rock intervals and burial history modelling within the basin. Integration of the wire-line logs with geochemical analysis identified six organic matter-rich intervals (OMRIs) within the Middle Jurassic-Lower Cretaceous sequence. Four intervals are in the Alam El-Bueib-3C (AEB-3C) member with a cumulative vertical thickness of 530ft. The other OMRIs are 110ft in thickness recorded within the AEB-6 (10ft) and Upper Safa (100ft) members. The studied organic matter (OM) reveals type III, IIIC, and IV kerogens (mainly gas-prone) with a terrestrial origin. They have reached a maturity level consistent with the late oil window. The expulsion threshold depth detected in the WKAL-P-1 X well is 12000ft in the AEB-3C member, whereas the active source depth limit (ASDL) is 15000ft in the Safa Member. The present study suggests a paleo-geothermal gradient range between 1.13oF/100ft and 1.39oF/100ft with an estimated regional erosion of 5500 to 7000ft of strata mainly between the Paleozoic-Jurassic and Cretaceous-Tertiary boundaries. The present-day geothermal gradient based on bottom-hole temperatures shows a geothermal gradient of 1.4oF/100ft (WKAL-P-1 X), that increases to the north to 1.65oF/100ft (WKAL-K-1 X). Burial history modelling reveals that sedimentary strata entered the mature oil zone in the Early Cretaceous (110–115Ma) at depths of 7500–8000ft in the deepest part of WKAL-P-1 X and WKAL-K-1 X wells (Paleozoic strata). Maturation continued to present, resulting in Jurassic and Lower Cretaceous strata currently falling into the late oil window.

Fluid Identification Derived from Formation Chlorine Measurements and Reservoir Characterization of Tight Carbonate in Sichuan Basin, China

Summary Natural gas production in the Sichuan Basin reached 30×109 m3 in 2020, but the shortfall between this and the production goal of 50×109 m3 in 2025 requires further exploration. The complex mineralogy and low porosity in tight carbonate reservoirs reduce the accuracy of formation water saturation calculations from Archie’s equation, which brings uncertainties to the reservoir characterization. Therefore, it is necessary to incorporate other methods as supplements to methods based on resistivities. In this paper, we outline a method that incorporates wireline-induced gamma spectroscopy, nuclear magnetic resonance (NMR), array dielectric, and borehole images. Spectroscopy is not only used to estimate the mineralogy of the reservoir, but it also provides measurements, such as chlorine concentration and thermal neutron capture cross section (sigma). The amount of chlorine in the formation is proportional to the water volume in the reservoir, hence formation water saturation. Sigma is also an indicator of the formation water saturation. It enables formation water saturation calculation without resistivity measurements. Case studies are presented from carbonate reservoirs in the Sichuan Basin, China. A robust and comprehensive petrophysical description of mineralogy, porosity, pore geometry, free fluid volume, rock type, and formation water saturation is presented. Calculation of formation water saturation from chlorine and sigma proves to be successful in both water-based mud and oil-based mud (OBM) environments. The depth of investigation (DOI) of chlorine from spectroscopy is about 8 to 10 in. for 90% of the signal. The various DOIs of different measurements must be considered when performing the fluid identification. Bound fluid saturation can reach more than 50% in tight carbonate reservoirs. Formation water saturation is not the only factor that determines the fluid type. Free fluid saturation from NMR must also be incorporated. Finally, a robust methodology integrating formation water saturation derived from dielectric and spectroscopy, and free fluid saturation derived from NMR shows great advantage in fluid identification in tight carbonate reservoirs. In this paper, we discuss a novel combination of wireline logging tools for fluid identification in a tight carbonate reservoir in the Sichuan Basin. It reduces the uncertainty when estimating formation water saturation and when resistivity measurements are suppressed in OBM environments. The gas zones identified by the new method have promising predictions of gas production. This workflow can also be applied to other tight carbonate plays in China.

Reservoir characterization of the middle Miocene Kareem sandstones, Southern Gulf of Suez Basin, Egypt

In this study, we have assessed the petrographical and petrophysical characteristics of the progradational, syn-rift Middle Miocene Rahmi sandstone gas reservoir (Lower Kareem Formation) from the East Matr and Amal hydrocarbon fields, southern Gulf of Suez by integrating sidewall cores and wireline logs. We interpreted a reservoir gas gradient of around 0.09 psi/ft from the downhole pressure measurements. Based on well log-based petrophysical analyses, we interpreted that the Rahmi reservoir in the East Matr field has a 0.10–0.18 v/v total porosity, 0.08–0.14 v/v effective porosity, 0.08–0.17 v/v shale volume along with water saturation ranging between 0.09 and 0.32 v/v. The correlated reservoir in the Amal field is observed to have higher porosities (0.17–0.22 v/v total porosity and 0.15–0.19 v/v effective porosity), although it exhibits higher water saturation (0.38–0.54 v/v). The reservoir consists of very fine to coarse grained, poorly to moderately sorted, subangular to subrounded, poorly cemented and moderately compacted sublithic, subarkosic and arkosic arenites with moderate to good intergranular porosity. Abundant lithic fragments and poor textural maturity of the Rahimi sandstones imply a high energy shoreface depositional environment in close proximity to the hinterland. Porosity reduction is attributed to dolomite cementation, kaolinite, formation of pseudomatrix by mechanical compaction of argillaceous lithics, and quartz overgrowth. Long and concavo-convex intergranular contacts indicate that silica needed for quartz cementation was derived by moderate degree of chemical compaction of the quartz grains. Partial to near-complete dissolution of the labile grains (feldspar and lithics) and dolomite attributed to the reservoir quality improvement. Scattered dolomite cements prevented more severe mechanical and chemical compaction.

Porosity prediction using fuzzy clustering and joint inversion of wireline logs: A case study of the Nam Con Son basin, offshore Vietnam

Petrophysical properties such as porosity, permeability and fluid saturations are important parameters for reservoir characterisation, which can be determined by experimental constitutive equations between rock parameters and well logging data. Thus, the same rock properties might demonstrate different patterns, depending on the input and equations used. In this work, we used the cross-properties (a common set of rock properties) that influence different measurements to reduce the ambiguity of the petrophysical property definition. We present an approach of using fuzzy c-means clustering to classify the well logs and core data in clusters and then running inversion for each cluster. The obtained results allowed us to establish suitable parameters in constitutive equations, which usually vary with rock units that may relate to clusters. Testing data applied to the Nam Con Son basin show a square correlation coefficient of 0.66 between the predicted and core measurement, suggesting a reasonable matching of the testing data set.

Applicability of decision tree-based machine learning models in the prediction of core-calibrated shale facies from wireline logs in the late Devonian Duvernay Formation, Alberta, Canada

Well logs provide insight into stratigraphically compartmentalized rock properties and are a cost-effective alternative to core. The identification of reservoir (and nonreservoir) facies in core, and their calibration to well-log response has traditionally relied on expert domain knowledge and is inherently inconsistent. Such analyses are time-consuming, tedious, error prone, and often biased due to a lack of objectivity. Automated lithologic interpretations from wireline logs appear to be a promising solution for identifying and understanding depositional complexity within a reservoir. Using the Duvernay Formation in the Western Canada Sedimentary Basin as a case study, the authors evaluate the applicability of decision tree-based machine learning (ML) methods in the prediction of core-calibrated facies and/or facies association distributions within wireline logs. The authors use three independent decision tree-based ML models to predict (1) facies (FACM), (2) facies associations (FAM), and (3) reservoir rock (RESM) from wireline logs. Model accuracies are 60.3%, 88.1%, and 88.1% for FACM, FAM, and RESM, respectively, but individual class F1 scores range from 0 to 0.92. The authors attribute discrepancies in individual class performance to interval thickness, sample proportion of training data, and distinguishability of the output class. Classes thicker than 3 m and encompassing at least 16% of the training data set have F1 scores greater than 0.60. The authors attribute exceptions to these general cutoffs to the ability to recognize diagnostic sedimentologic features observed in core. Results from this study help in understanding stratigraphic complexity in the absence of core aiding in subsurface characterization of reservoirs.

Seismic reflectivity, fracturing and stress field data from the FFC-1 exploratory geothermal project in SW Skåne, Sweden

Enhanced geothermal systems (EGS) are a potential heat source in many parts of the world, even in locations where the temperature gradient is relatively low. We present here an integrated study of reflection seismic data, borehole logs and seismicity analysis performed in conjunction with a geothermal exploratory project operated by E.ON in Malmö, Sweden. In 2020, the pre-existing 2.1 km deep FFC-1 borehole through the sedimentary cover was deepened into the crystalline basement to about 3.1 km vertical depth. Combined interpretation of the reflection seismic data and geophysical wireline logs show that most of the reflectivity in the Precambrian basement is likely generated by lenses of mafic amphibolite embedded in a felsic gneissic matrix. The general structural bedding and foliation is gently dipping to sub-horizontal, similar to other locations in southwest Sweden. Fracture frequency is relatively high in the crystalline rock mass, with heavy fracturing in the uppermost part of the crystalline basement, obscuring a clear reflection from the top of the Precambrian. Highly fractured and hydraulically conductive intervals are also found between 2,562 and 2,695 m based on a temperature drop and the interpretation of the geophysical data. Open fractures, both natural and induced, have a clear N–S orientation, contrasting with the expected NW–SE direction based on the orientation of the Sorgenfrei-Tornquist Zone and earthquake fault plane solutions to the north. This difference may be partly explained by local variations in the stress field near the FFC-1 borehole and vairations in the stress field with depth. Despite this, the data from the FFC-1 well provide novel and unique information on the complex physical state of the crystalline basement on the margin of the Fennoscandian Shield, which further addresses the need for obtaining in-situ stress data to fully understand the local stress field prior to any stimulation. A temperature of 84°C measured at 3 km depth indicates that a desired EGS temperature of 120–140°C may be reached at 5–6 km depth, assuming a temperature gradient of about 20°C. If the relatively high fracture frequency and occurrence of fracture zones down to 3.1 km are also present at these target depths, then the FFC-1 location may be suitable for heat extraction if the rock mass is properly characterized before stimulation.