Borehole Image Logs Research Articles

Borehole-image-log characterization of deltaic deposits from a behind-outcrop well: Opportunities and limitations

ABSTRACTBorehole imaging (BHI) is a fast and precise method for collecting subsurface data. Rock calibration may reduce uncertainties inherent in interpretations of BHI logs. However, only few data sets are published that link borehole image facies to core and outcrop facies of deltaic successions. The objective of this paper is to compare and contrast sedimentologic features as seen in BHI, core, and outcrop, using a structured and hierarchical workflow. The research will provide a global framework for the interpretation of borehole images in similar environments.A shallow, behind outcrop, research well (“Mondot-1”) drilled in NW Spain, penetrated a 185.50 m (TVD) thick section of the deltaic Sobrarbe Formation. A Formation MicroImager (FMI) borehole image log and a comprehensive well log suite was acquired in the fully cored well. The Eocene Sobrarbe Formation consists mostly of siliciclastic and some carbonate facies. Rapid vertical and lateral facies changes over a few tens of meters are observed in outcrops of the Sobrarbe Formation. The cored part of the formation is composed of argillaceous sandstone and carbonate with few diagnostic sedimentary features that can be used to constrain a conceptual depositional model. To provide a sedimentologically sound interpretation of this FMI log, we focused on layers showing diagnostic sedimentary features. Subsequently, facies associations and stratigraphic sequences were interpreted. Each facies association contained sedimentologic tie points that anchored the interpretation with diagnostic features such as slumps.This paper suggests interpreting BHI false-color images of deltaic successions using conceptual geologic constraints such as 1) depositional tie points, 2) genetically related facies associations, and 3) a hierarchical stratigraphic framework, to establish meaningful conceptual depositional models.

Borehole-image-log characterization of deltaic deposits from a behind-outcrop well: Opportunities and limitations

ABSTRACTBorehole imaging (BHI) is a fast and precise method for collecting subsurface data. Rock calibration may reduce uncertainties inherent in interpretations of BHI logs. However, only few data sets are published that link borehole image facies to core and outcrop facies of deltaic successions. The objective of this paper is to compare and contrast sedimentologic features as seen in BHI, core, and outcrop, using a structured and hierarchical workflow. The research will provide a global framework for the interpretation of borehole images in similar environments.A shallow, behind outcrop, research well (“Mondot-1”) drilled in NW Spain, penetrated a 185.50 m (TVD) thick section of the deltaic Sobrarbe Formation. A Formation MicroImager (FMI) borehole image log and a comprehensive well log suite was acquired in the fully cored well. The Eocene Sobrarbe Formation consists mostly of siliciclastic and some carbonate facies. Rapid vertical and lateral facies changes over a few tens of meters are observed in outcrops of the Sobrarbe Formation. The cored part of the formation is composed of argillaceous sandstone and carbonate with few diagnostic sedimentary features that can be used to constrain a conceptual depositional model. To provide a sedimentologically sound interpretation of this FMI log, we focused on layers showing diagnostic sedimentary features. Subsequently, facies associations and stratigraphic sequences were interpreted. Each facies association contained sedimentologic tie points that anchored the interpretation with diagnostic features such as slumps.This paper suggests interpreting BHI false-color images of deltaic successions using conceptual geologic constraints such as 1) depositional tie points, 2) genetically related facies associations, and 3) a hierarchical stratigraphic framework, to establish meaningful conceptual depositional models.

Present-day in-situ stress field within the Yanchang Formation tight oil reservoir of Ordos Basin, central China

The present-day in-situ stress field has many important and practical applications during the exploration and development of hydrocarbon resources. The Ordos Basin is a significant petroliferous basin in China, within which, the Yanchang Formation serves as the most significant tight oil reservoir. However, an overview of previous studies indicates that little was known as to the present-day stress state in the Yanchang Formation. Therefore, the present-day stress field in the Yanchang Formation tight oil reservoir of the Ordos Basin is systematically analyzed in this study. The orientation of horizontal maximum principal stress (SHmax) within the Yanchang Formation of Ordos Basin ranges between north-northeast-south-southwest-trending (NNE-SSW) and east-northeast-west-southwest-trending (ENE-WSW) based on interpretations of borehole breakouts and drilling-induced fractures from borehole imaging logs. The SHmax orientation shows various tendencies in different wells, which may result from differential development in lithology, natural fracture and bedding plane over various regions. The estimated magnitudes of vertical stress (Sv), SHmax and horizontal minimum principal stress (Shmin) in the studied wells indicate that the normal faulting stress regime is dominant within the Yanchang Formation. In addition, the geomechanical assessments of wellbore stability and natural fracture reactivation are also performed. Natural fractures in the Yanchang Formation Chang 7 tight oil reservoir of Ordos Basin are developed striking mainly in the northeast-southwest-trending (NE-SW) and west-northwest-east-southeast-trending (WNW-ESE). Among them, those fractures with NE-SW-trending strikes are more conductive with reference to the present-day stress state, contributing more to tight oil production in the Ordos Basin. In addition, within the Yanchang Formation, if horizontal wells are drilled towards the NNE-SSW-trending to ENE-WSW-trending, they are more likely to have wellbore instability issues. The results in this study provide important geological information for tight oil production in the Yanchang Formation of Ordos Basin.

Characteristics of natural fractures in the upper Paleozoic coal bearing strata in the southern Qinshui Basin, China: Implications for coalbed methane (CBM) development

Abstract Natural fractures, as the effective storage space and fluid flow pathway of hydrocarbons, play a critical role in the exploration and development of unconventional gas resources in the coal bearing strata. In the present study, to reveal the effects of natural fractures on coalbed methane (CBM) preservation and development, the types, origins and development characteristics of natural fractures in the upper Paleozoic Permian Shanxi Formation in the southern Qinshui Basin were systematically described and analyzed based on outcrops, cores, borehole image logs, thin sections, and SEM. Four types of natural fractures have been identified in the Shanxi Formation according to their geologic origins, including the endogenic fractures (cleats) and exogenous fractures in the No.3 coal seam, and tectonic fractures and diagenetic fractures in its roof and floor. Tectonic fractures can be further divided into small faults, intraformational shear fractures, intraformational open fractures and slip fractures, while diagenetic fractures are mainly bed-parallel fractures. The statistical results show that the development and distribution characteristics of those types of fractures are significantly different, which are mainly influenced by lithology, layer thickness and geological structure. Further, natural fractures with different types and distributions show different influences on CBM preservation and well productivity. Exogenous fractures can effectively improve the seepage capability of coal reservoirs and are conducive to CBM wells productivity, whereas endogenic fractures have less contributions to coal permeability due to their poor effectiveness. The intraformational open fractures in the fold axis zones, and intraformational shear fractures and small faults in the fault zones are generally excessive-developed. Those fractures may result in gas dissipation and external water supplement, which have negative effects on CBM preservation and production. However, moderate-developed intraformational shear fractures in the sandstone roof can favorably affect the pressure reduction of coal reservoir and improve the recovery potential of unconventional gas resources. These investigations may serve as a geological basis for unconventional gas exploration and development of the upper Paleozoic coal bearing strata in the southern Qinshui Basin.

Fracture characterization and modeling of karsted carbonate reservoirs: A case study in Tahe oilfield, Tarim Basin (western China)

Abstract The characterization and modeling of fractures in karsted carbonate reservoirs are challenging due to the mechanical interactions between fractures and irregular karst elements. This study proposes an integrated approach for characterizing and modeling large-scale fractures within deeply buried fractured karst carbonates of the Yingshan Formation (Ordovician in age) located at the Tahe oilfield, Tarim Basin (western China). This investigation implements a promising workflow to stochastically model the fracture sets interpreted from borehole image logs and compute both fracture porosity and permeability tensor in karsted carbonates. For this case study, we have constructed a Discrete Fracture Network (DFN) by combining two structural seismic attributes (i.e. local structural dip and ant-tracking). We have also applied the automatic fault extraction (AFE) algorithm. The results indicate that this method detects a greater number of discontinuities associated with fractures compared to the conventional methods employed in this kind of reservoir (e.g. seismic coherence and curvature). The fracture set with higher values of fracture porosity and permeability coincided with the orientation of maximum horizontal stress, WSW-ENE. In the model, the highest values of fracture intensity correspond to the most productive oil wells. Finally, this study highlights the importance of fracture modeling for evaluating the distribution of the most favorable production areas, so-called sweet-spots, in karsted carbonates reservoirs.

Natural fractures in tight-oil sandstones: A case study of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, China

Natural fractures are important storage spaces and fluid-flow channels in tight-oil sandstones. Intraformational open fractures are the major channels for fluid flow in tight-oil sandstones. Small faults may provide fluid-flow channels across different layers. According to analogous outcrops, cores, and borehole image logs, small faults and intraformational open fractures are developed in the tight-oil sandstones of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, China. Among them, high dip-angle intraformational open fractures are the most abundant. Northeast-southwest–trending fractures are the principal fractures for fluid flow because that is the present-day maximum horizontal compressive stress direction. Combined with production data, horizontal wells, striking normal to or at a large angle relative to the major flow pathways, are beneficial for tight-oil production improvement. Fractures with high dip angles are the main factor that influences initial oil production. Linkage and tip damage zones are more favorable for oil production improvement than wall damage zones. This study provides an example of natural fracture characterization and unravels fracture contributions to reservoir physical properties and oil production of tight-oil sandstones, which could provide a geological basis for oil exploration and development in tight sandstones.

The stress field in the frontal part of the Eastern Alps (Austria) from borehole image log data

Stress orientations in the frontal part of the Eastern Alps are inferred from borehole breakouts and drilling-induced tensile fractures depicted in image logs from 62 vertical or slightly deviated wellbores with up to 5km depth. Borehole breakouts (2463 individual features with 1673.9m cumulative length) are observed in all the wells except one, whereas drilling induced fractures only occur in four wells.Microresistivity image log data from the Alpine foreland, the external thrust sheets (allochthonous Molasse, Helvetic- and Flysch nappes) and the autochthonous units in the footwall of the Alpine units reveal consistent in-situ stress orientations with approximately N-S-directed maximum horizontal stresses (SHmax). Indications for stress partitioning across thrusts including the Alpine floor thrust are not observed. In the Western Sector of the study area the mean SHmax is oriented 002° with a standard deviation (SD) of 11.1°. In the central and eastern sector, the mean SHmax is oriented 177° (SD 14°) and 173° (SD 14.3°), respectively, indicating a counterclockwise rotation of SHmax of about 10° from west to east. The observed stress indicators and the analysis of deviated wells suggest a strike-slip regime for the western and Central Sector, whereas a thrust regime is probable in the east of the study area. The thrust regime there coincides with the occurrence of Middle Pleistocene conglomerates which were previously described to be displaced by Alpine thrust faults.The orientations of SHmax fit into the general observation that SHmax directions at the Alpine front are oriented about perpendicular to the strike of the mountain belt and rotate along the Alpine arc. Our stress orientations - including those derived from the autochthonous basement - are, however, markedly different from the NW-SE-directed maximum horizontal stresses reported from the Variscan units in the European foreland north of the study area.

The statistical eigenvector analysis technique (SEAT) for dip data analysis

Abstract Dip data acquired from image logs (i.e. the dip/azimuth of planar features) are extensively used in the oil and gas industry to assist in interpreting subsurface geology. Gradual and/or abrupt variations in dip data with depth may indicate different structural features (e.g. faults, folds, etc.) or changes to sedimentary systems (e.g. unconformity). The statistical eigenvector analysis technique (SEAT) and accompanying computer application are useful in statistically calculating the orientation and geometry of subsurface structures from dip data. Poles to planes on a spherical projection over a given depth interval may reveal cluster or girdle distributions, which can be interactively analyzed using statistical distribution functions on the unit sphere. SEAT provides a mathematical solution for as few as two data points, and has the potential to be applied to dip data at the meter-scale. The orientation and geometry of various subsurface geological features (e.g. folds, fault drag deformation, etc.) can be interactively calculated over a chosen depth interval. SEAT is applied to a dip dataset acquired from a modern, 8-padded electronic borehole image log and a previously studied dipmeter data from the discovery well of the Railroad Gap Field to illustrate its higher accuracy in determining the orientation and geometry of subsurface structures compared to older methods. SEAT allows for a vastly improved interpretation of subsurface geological features when combined with high-resolution borehole image logs and accurate dip data. Improved understanding of subsurface geometries may allow for better business decisions in future exploration and appraisal of existing assets.

Contemporary tectonic stress pattern of the Persian Gulf Basin, Iran

The contemporary crustal stress pattern is important to several aspects of earth sciences such as reservoir geomechanics, neotectonic deformation and geodynamic modelling. The Persian Gulf Basin is a petroliferous region in southern Iran that hosts hundreds of petroleum wells and, hence, the knowledge of the present-day stress is critical for any exploration and production in this region. In addition to geo-resources, this region has a great economic importance and the in-situ stresses provide key insights on neotectonic and seismic hazard of the basin. However, there is limited in-situ stress information in the Persian Gulf region. In this study, we analyse >8 km of borehole image logs in 20 wellbores in the Persian Gulf in order to provide a clear picture of the stress pattern in this region. Our wellbore stress analyses provide 35 quality-ranked maximum horizontal stress orientations (SHmax) data records. In addition, we compile 27 earthquake focal mechanisms in the study region from different seismic catalogues and published literature, and present the first comprehensive quality-ranked in-situ stress map of the Persian Gulf Basin with 62 data records, which can be used as a valuable source of information for future exploration and seismic hazard assessment. The resulting database suggests that the SHmax azimuth in central and western Persian Gulf is NE-SW (parallel to the Arabia-Eurasia tectonic plate convergence), which demonstrate the key role of relative plate motion in the present-day stress pattern of these areas. However, the SHmax azimuth in the eastern part of the study area is NW-SE, which is different from the central and western Persian Gulf. The NW-SE SHmax azimuth is consistent with other geological and geophysical observations that suggest an indentor model for Musandam Peninsula (Oman) in the Zagros-Makran syntaxis.

In situ stress states at KURT, an underground research laboratory in South Korea for the study of high-level radioactive waste disposal

The Korea Atomic Energy Research Institute Underground Research Tunnel (KURT) is an underground research laboratory in South Korea, built for investigations into the geological disposal of high-level radioactive waste. We characterize in situ stress states at KURT using data from a series of hydraulic fracturing (HF) tests and borehole image logs to depths of ~700 m in two boreholes. The tensile fractures induced by HF tests, plus several borehole stress indicators (e.g., drilling-induced tensile fractures and borehole breakouts) measured from image logs, consistently indicate an ESE–WNW oriented maximum horizontal principal compressive stress (SHmax). This site-scale SHmax orientation varies slightly from the regional-scale SHmax orientation, likely reflecting a local stress perturbation resulting from a fault network that traverses the site. Estimated magnitudes of the minimum horizontal principal compressive stress (Shmin), determined either from the shut-in pressures recorded during HF tests or from stress indicators on image logs, are comparable to the vertical stress, indicating that the stress regime at the KURT site straddles the boundary between strike-slip and reverse faulting. The depth-dependent trend in estimated SHmax magnitudes deviates at ~500 m depth, which we attribute to variations in the distribution of natural fractures in the granitic rock mass. This depth-dependent variation in SHmax magnitudes has implications for the slip stability of pre-existing fractures at the site. That is, at shallow depths, SHmax lies within the Coulomb stress limit for optimally oriented fractures and faults with a frictional coefficient of 0.6, whereas at greater depths, SHmax exceeds this limit, meaning that pre-existing fractures at shallow depth are more susceptible to slip reactivation. Our stress estimation results suggest that the site-scale stress state is strongly coupled with characteristics of natural fractures, emphasizing the importance of detailed geologic and stress data for subsurface utilization and its stability evaluation.

Quantitative constraints to the complete state of stress from the combined borehole and focal mechanism inversions: Fox Creek, Alberta

We develop a quantitative predictive model for the state of stress of a volume of crust encompassing the Duvernay Formation with a spatial extent of over 150 km × 150 km centred near the municipality of Fox Creek. An average direction of the maximum horizontal compression SH is of N43°E, determined from analysis of 20 borehole image logs. A model of the vertical stress SV, corrected for topographic variations, is provided from the integration of a 3D density volume constructed from 1125 density logs. The minimum horizontal compressions Sh and pore pressures PP are evaluated through analysis of 57 well tests carried out within the Duvernay Formation; 3D models developed by kriging of the observed values. Stress inversion of the focal mechanism solutions for the earthquakes nearby validated the assumed Andersonian stress regime and provided the shape-ratio of the stress which further allowed estimation of maximum horizontal compression SH. A supplementary program is provided allowing the user to calculate the full set of components necessary to describe the states of in-situ stress for a location of interest near the Duvernay formation within our study area.

Fracture modeling from borehole image logs and water invasion in carbonate reservoirs with layer-bound fractures and fracture corridors

The objective of this paper is to demonstrate, how water invasion in unison with borehole images can be used to decipher fracture architecture in a carbonate reservoir with layer-bound fractures and fracture corridors. TVD vs. fracture density plots help in identification of highly fractured layers and establish mechanical and structural attributes that control layer-bound fracture density, height and orientation. Fracture corridor stick plots over structural map of the reservoir reveal whether fracture corridors are related to faults or folds. Flattop cross sections constitute the scaffold to construct fluid conductive fracture model in mature oil fields, where water has already started to creep up fracture corridors and encroach in high permeability or highly fractured layers.One of the prime applications of flattop cross sections is to evaluate connectivity of fluid conductive fractures. Fractured layers with interconnected open fractures have a high permeability and will be subject to water fingering. If water invasion bypasses such a fractured layer and advances into high permeability matrix streaks, in all likelihood open fractures within the fractured layer are not interconnected and hence are not fluid conductive. High water saturation coincident with a fracture corridor on a flattop cross section is a strong indication that the fracture corridor is fluid conductive and water rises up fracture corridors and spreads into the surrounding reservoir.

Pressure transient analysis in fractured reservoirs with poorly connected fractures

Pressure transient analysis in the fractured reservoirs is of great significance, as it provides useful information for the production performance forecasting of the fractured reservoirs. In the past decades, the conventional Warren and Root model (CWRM) (1963) is the popular tool for pressure transient analysis in the fractured reservoirs. However, many borehole image logs data strongly show that many fractured reservoirs are partially fractured, and these partially fractured reservoirs have poorly connected natural fractures (Ozkaya, 2018). The CWRM are not applicable in the partially fractured reservoirs any more, owing to the discretely natural fractures. Thus, more work needs to be done to address this issue. In this work, we introduce a discrete fracture model to build a dual-porosity model for the fractured reservoirs with poorly connected natural fractures. After verifying this model, the pressure transient behaviors of those fractured reservoirs are investigated in details.Results from the discrete fracture model show that flow regimes in reservoirs with poorly connected natural fractures is different from that in reservoirs without natural fractures. For vertically fractured wells with discrete fractures, the bilinear flow, linear flow, impacts of natural fractures, and pseudo-radial flow may progressively occur. Once these effects caused by natural fractures appear, the pressure derivatives show a “V-shape” dip, namely a transient flow.The main improvements in this manuscript include: (1) developing a method to determine the transmissibility factors of grids for natural fractures and hydraulic fractures, (2) presenting a numerical well model, and (3) studying the pressure map of various flow regimes in reservoirs with poorly connected natural fractures. This meaningful work provides a new angle on estimation of the influence of poorly connected natural fractures on pressure transient behaviors, which is beneficial to exploitation the naturally fractured reservoirs.

A deep residual convolutional neural network for automatic lithological facies identification in Brazilian pre-salt oilfield wellbore image logs

Field characterization in oil industry is a challenging task which aims to determine or estimate some of the petrophysical properties of a reservoir. These properties are expected to be later used in a non-deterministic workflow (which might depend on subjective interpretations carried out by each petrophysicist) whose aim is to answer questions such as whether exploiting the reservoir is feasible or not, how much hydrocarbon can be extracted from it and whether the geology of the reservoir will stand the stresses of exploitation without collapsing. Three properties stand-out amongst all the rest, as they are closely correlated to the amount of hydrocarbon present in the reservoir and also to the feasibility of its exploitation: permeability, porosity, and lithology. Obtaining reliable and robust measurements of these properties requires extracting core samples from the reservoir, which is, however, a very resource-consuming task. Hence, it is common to use other tools (such as wirelogging tools or borehole imagers) to extract several other properties from the reservoir, in an attempt to obtain information that might help experts to estimate these properties on those intervals at which no core sample could be extracted. In this context, estimating lithofacies helps petrophysicists to automatize the process of identifying the lithology of the reservoir. Previous work (Basu et al., 2002; Chai et al., 2009; Linek et al., 2007; Newberry et al., 2004; Hall et al., 1996) used a considerable amount of wirelog data and borehole image logs to induce the lithology of the reservoir. In the work presented in this paper, we introduce a new methodology for automatic reservoir lithofacies identification. Our model relies only on ultrasonic and microresistivity borehole image logs as inputs, which are characterized by a deep residual convolutional network which then infers the probability of each sample to be classified as each type of previously defined lithofacies classes. The method presented in this work was tested on a carbonate well from the Brazilian pre-salt oilfields, and it allowed us to obtain an average classification accuracy of 81.45% and an average area under the ROC curve of 92.70% for all classes, for the blind test sample.

Validating Predicted Fracture Corridors by Statistical Comparison With Well Data

SummaryA challenge in oil–reservoir studies is evaluating the ability of geomechanical, statistical, and geophysical methods to predict discrete geological features. This problem arises frequently with fracture corridors, which are discrete, tabular subvertical fracture clusters. Fracture corridors can be inferred from well data such as horizontal–borehole–image logs. Unfortunately, well data, and especially borehole–image logs, are sparse, and predictive methods are needed to fill in the gap between wells. One way to evaluate such methods is to compare predicted and inferred fracture corridors statistically, using chi–squared and contingency tables.In this article, we propose a modified contingency table to validate fracture–corridor–prediction techniques. We introduce two important modifications to capture special aspects of fracture corridors. The first modification is the incorporation of exclusion zones where no fracture corridors can exist, and the second modification is taking into consideration the fuzzy nature of fracture–corridor indicators from wells such as circulation losses. An indicator is fuzzy when it has more than one possible interpretation. The reliability of an indicator is the probability that it correctly suggests a fracture corridor. The indicators with reliability of unity are hard indicators, and “soft” and “fuzzy” indicators are those with reliability that is less than unity.A structural grid is overlaid on the reservoir top in an oil field. Each cell of the grid is examined for the presence and reliability of inferred fracture corridors and exclusion zones and the confidence level of predicted fracture corridors. The results are summarized in a contingency table and are used to calculate chi–squared and conditional probability of having an actual fracture corridor given a predicted fracture corridor.Three actual case studies are included to demonstrate how single or joint predictive methods can be statistically evaluated and how conditional probabilities are calculated using the modified contingency tables. The first example tests seismic faults as indicators of fracture corridors. The other examples test fracture corridors predicted by a simple geomechanical method.

Subsurface SHMAX determined from a borehole image log, onshore southern East Coast Basin, New Zealand

ABSTRACTUnderstanding the in-situ stress field in the subsurface provides insights on the tectonic processes and seismic hazards of a basin. This paper presents observations and interpretations of present day maximum horizontal stress (SHmax) orientation from well Ranui-2 located in the onshore southern East Coast Basin. Fractures identified in the Ranui-2 image log have been divided into distinct subsets based on fracture orientation. These subsets correspond in a general sense, to changes in lithology in the well, which are associated with changes in formations. Analysis of the image log shows the present day SHmax in the borehole has two primary stress directions, W–E and NW–SE, and most of the fractures strike NE–SW. The change in SHmax occurs at a depth of circa. 1130 m measured depth (918 m true vertical depth subsea), below the depth at which the borehole changes from vertical to ≥10° deviation. When these data are compared to the regional stress field obtained using other stress indicators such as earthquake focal mechanisms, the results are consistent with each other. This study shows that shallow subsurface indications of present-day SHmax in southeastern North Island reflect SHmax orientations from deeper within the subsurface.

Sampling a Stimulated Rock Volume: An Eagle Ford Example

SummaryBetween 2014 and 2016, ConocoPhillips drilled five deviated wells adjacent to a multistage, stimulated horizontal producer to sample the physical characteristics of the reservoir stimulation caused by hydraulic fracturing in the Eagle Ford Formation in DeWitt County, Texas. The design, execution, and results of the pilot are described. This pilot establishes the paucity of pre-existing natural fractures in this locale and enables the determination of the spatial characteristics of the stimulation using information derived from the core, cuttings samples, borehole-image logs, tracer logs, microseismic, distributed temperature sensing (DTS)/distributed acoustic sensing (DAS), and pressure data. Results show that stimulation effectively breaks the reservoir rock and makes a complex array of hydraulic fractures that are more closely spaced near the producer. Some fractures, however, extend interwell distances of more than 1,000 ft. The pilot data indicate that abundant proppant transport appears to be limited to distances less than 75 ft from the producer, which suggests that the stimulated rock volume (SRV) might be greater than the volume of rock that can be effectively drained.

Characterization of subaerial volcanic facies using acoustic image logs: Lithofacies and log-facies of a lava-flow deposit in the Brazilian pre-salt, deepwater of Santos Basin

Abstract Volcanic rock facies characterization in subsurface log data have always being challenging. Even though considerable types of well logs are acquired, the results achieved on facies characterization with the conventional log suits are very limited. Conversely, high-resolution borehole image logs calibrated with side wall core samples can provide the necessary structural and textural information for facies definitions. In this case study, an integration of good quality acoustic image log data, side wall core petrography and geochemical analyses provided a good understanding of volcanic facies and stratigraphic relationships. Additionally, outcrop data from the analogous Serra Geral Formation and other Large Igneous Provinces were used for comparison. In the studied well, from Santos basin, Brazil, it was possible to identify several kinds of subaerial basaltic lava flow units, such as compound pahoehoe, sheet pahoehoe and rubbly pahoehoe lava flows. Vesicles, amygdales, vesicle cylinders, sub-horizontal vesicle sheets, autobreccias and entablature are some of the structures described in this study. As a result, 2 image catalogues of subaerial volcanic rocks were produced characterizing facies and flow units along with a stratigraphic model of the history of this volcanism. This is the first time that pahoehoe lava flow units could be characterized at an offshore Brazilian basin. The results achieved are important for the understanding of the Cretaceous volcanism events in the pre-salt layer and also provide support for the evaluation and geological modelling of the volcanic rocks in Santos Basin oil fields.

A hybrid learning automata and case-based reasoning for fractured zone detection using petrophysical logs

Fractured zone detection and fracture density estimation in oil wells have significant effects on wellbore stability, reservoir modeling, drilling operations, and well production. Although high-resolution image logs facilitate the identification of fracture characteristics, they are not available for a large set of wells as they drilled before development of the enhanced well logging technologies. Petrophysical logs contain valuable information and can be used as an alternative approach in fracture identifications. These logs are almost available in all wells and can be used as useful inputs to shape a predictive model representing fracture characteristics where image logs are not accessible. This paper proposes a generalized case-based reasoning (CBR) method for fractured zone detection via petrophysical logs. To such aim, a set of train wells are used to beget a database composed of both petrophysical data and the image logs. A learning automata-based algorithm is conducted to find the optimal similarity relation between petrophysical logs and manual interpretation of the borehole image logs. Moreover, new decision parameters are introduced to enhance the applicability of the proposed method in real-life projects. The developed model is successfully tested on the Asmari reservoir through several oil wells from, followed by a discussion on results.

Corrigendum to “Fracture detection in oil-based drilling mud using a combination of borehole image and sonic logs” [JMPG: 84 (June 2017); pages 195- 214

Corrigendum to “Fracture detection in oil-based drilling mud using a combination of borehole image and sonic logs” [JMPG: 84 (June 2017); pages 195- 214