Microresistivity Image Logs Research Articles

Utilizing microresistivity image logs to recognize conglomeratic channel architectural elements of Baikouquan Formation in slope of Mahu Sag

Abstract Geological outcrop is usually the first-hand evidence to cognize the probable geometry, lateral extent, and other properties of conglomeratic channels. If there is no exposure of formation, however, it is hard to recognize elaborate architectural elements just based on poor coverage cores and low-resolution conventional logs vertically. In order to understand vertical distributions of conglomeratic channel architectural elements in the Lower Triassic Baikouquan Formation in southern slope of Mahu Sag, ultrahigh-resolution microresistivity image logs are used to recognize elements under the concept of conglomeratic channel architectures in this article. The microresistivity images were calibrated with cores in different grain-sizes and sedimentary structures. According to microresistivity image fabric, subaerial channel-fills consisted of granules to cobbles; subaqueous channel-fills were composed of well-sorted sandstones to granules. Subaerial channel-margins comprised sandstones to pebbles; subaqueous channel-margins were granules and sandstones. Bypass drapes, deposited from the tail of bypassing flows, were commonly eroded by overlying channel-fills. Convergent drapes, accumulated on top surfaces of channel-margins, preserved well without reworking. Overbank drapes, formed outside the channel, were thick-bedded. Combined with dipmeter pattern of microresistivity image log, six channel story sets were recognized depending on abrupt changes in dip azimuths. In each channel story set, per unit thickness of mud drapes ranged from 0.1 to 0.6 m. Mud drapes in channel story set 1 could be correlated horizontally. In channel story sets 3, 4, and 5, thickness of mud drapes ranged from 0.05 to 2.59 m and averaged at 0.59 m, and channel conglomerates and mud drapes alternated frequently. These understandings would provide important insights on the production potential of petroleum.

An Improved GAN-Based Image Restoration Method for Imaging Logging Images

An improved GAN-based imaging logging image restoration method is presented in this paper for solving the problem of partially missing micro-resistivity imaging logging images. The method uses FCN as the generative network infrastructure and adds a depth-separable convolutional residual block to learn and retain more effective pixel and semantic information; an Inception module is added to increase the multi-scale perceptual field of the network and reduce the number of parameters in the network; and a multi-scale feature extraction module and a spatial attention residual block are added to combine the channel attention. The multi-scale module adds a multi-scale feature extraction module and a spatial attention residual block, which combine the channel attention mechanism and the residual block to achieve multi-scale feature extraction. The global discriminative network and the local discriminative network are designed to gradually improve the content and semantic structure coherence between the restored parts and the whole image by playing off each other and the generative network. According to the experimental results, the average structural similarity measure of the five sets of imaged logging images with different sizes of missing regions in the test set is 0.903, which is an improvement of about 0.3 compared with other similar methods. It is shown that the method in this thesis can be used for the restoration of micro-resistivity imaging log images with good improvement in semantic structural coherence and texture details, thus providing a new deep learning method to ensure the smooth advancement of the subsequent interpretation of micro-resistivity imaging log images.

Characterization of reservoir properties and pore structure based on micro-resistivity imaging logging: Porosity spectrum, permeability spectrum, and equivalent capillary pressure curve

According to the capillary theory, an equivalent capillary model of micro-resistivity imaging logging was built. On this basis, the theoretical models of porosity spectrum (ϕi), permeability spectrum (Ki) and equivalent capillary pressure curve (pci) were established to reflect the reservoir heterogeneity. To promote the application of the theoretical models, the Archie's equation was introduced to establish a general model for quantitatively characterizing ϕi, Ki, and pci. Compared with the existing models, it is shown that: (1) the existing porosity spectrum model is the same as the general equation of ϕi; (2) the Ki model can display the permeability spectrum as compared with Purcell's permeability model; (3) the pci model is constructed on a theoretical basis and avoids the limitations of existing models that are built only based on the component of porosity spectrum, as compared with the empirical model of capillary pressure curve. The application in the Permian Maokou Formation of Well TSX in the Central Sichuan paleo-uplift shows that the ϕi, Ki, and pci models can be effectively applied to the identification of reservoir types, calculation of reservoir properties and pore structure parameters, and evaluation of reservoir heterogeneity.

The effect of fracturing on permeability in carbonate reservoir rocks

Hydrocarbon flow rates from tight carbonate reservoirs often depend on the distribution and properties of fractures throughout the reservoir interval. Hence, quantification of fracture parameters can contribute to understanding of reservoir characteristics and reservoir potential. In this paper, natural fractures in tight carbonate reservoir rocks of the Upper Cretaceous Shiranish Formation in the Taq Taq field (Kurdistan Region of North Iraq) were examined primarily using core samples, XRMI micro-resistivity image logs and conventional wireline logs, with additional dynamic data from well tests and mud logs. The Shiranish Formation is composed of a variety of limestones and argillaceous limestones with arithmetic mean matrix porosity and geometric mean permeability values of 1.64 ± 0.37% and 0.0223 ± 0.59 mD, respectively. However, fracturing has enhanced the permeability by up to four orders of magnitude above the maximum matrix permeability (1.79 ± 0.59 mD). Hydrocarbons are produced entirely from the fracture network in these rock types in the Taq Taq reservoir. Observed open and partially-open fractures have NE-SW orientations; these are classified as macro-fractures with average aperture of 0.17 ± 0.18 mm, arithmetic mean height of 11.70 ± 45.40 mm and arithmetic mean length of 26.7 ± 32.32 cm, where the uncertainties are standard deviations. Fracture aperture size and fracture height control fracture permeability and fluid flow. However, while fracture frequency has no effect on permeability, fracture distance distribution influences flow rates and hydrocarbon production. The dominant NE-SW trending fractures are more likely to remain open within the NE-SW oriented present day stress field at Taq Taq. Furthermore, the effect of overburden stress on the permeability and production rate was examined in laboratory tests on core plugs by increasing the confining stress during permeability measurements using constant flow rates. It was found that the magnitude of fracture permeability was reduced by 70% by applying 4000 psi of confining stress. In the reservoir, this effect would be exacerbated by reduced reservoir fluid pressures as a function of production. However, fractures with apertures greater than 0.10 mm are preserved as productive fractures even at high confining pressures and implying that hydraulic fracturing could open existing fractures significantly, enhancing production. This last observation implies that the use of hydraulic fracturing in tight carbonate reservoirs with natural fracturing is likely to be commercially viable.

Comparison between double caliper, imaging logs, and array sonic log for determining the in-situ stress direction: A case study from the ultra-deep fractured tight sandstone reservoirs, the Cretaceous Bashijiqike Formation in Keshen8 region of Kuqa depression, Tarim Basin, China

The tight sandstone in the Tarim Basin has the characteristics of large burial depth and development of nature fractures due to concentrated in-situ stress. Identifying the present-day in-situ stress orientation is important in hydrocarbon exploration and development, but also a key scientific question in understanding naturally fractured reservoirs. This paper presents a case study where we integrate various methods using wireline and image-log data, to identify present-day in-situ stress direction of ultra-deep fractured tight sandstone reservoirs, in the Kuqa depression. We discuss the formation mechanism of the elliptical borehole, compares the advantages and applicable conditions of the double caliper method, resistivity image logs and array sonic logs method. The well borehole diameter is measured orthogonally, then the ellipse is fitted, and the in-situ stress orientation is identified by the azimuth of the short-axis borehole, but it fails in the borehole expansion section, the fracture development section and the borehole collapse section. The micro-resistivity image logs method reveals the borehole breakouts azimuth, and also the strike of induced fractures, which are used to determine the orientation of in-situ stress. However, under water-based mud conditions, it's hard to distinguish natural fractures from induced fractures by image logs. Under oil-based mud conditions, the induced fractures are difficult to identify due to the compromised image quality. As for the sonic log, shear waves will split when passing through an anisotropic formation, shear waves will split during propagation, and the azimuth of fast shear waves is consistent with the orientation of in-situ stress. However, it is usually affected by the anisotropy caused by the excessively fast rotation of the well log tools, so that the azimuth of fast shear wave cannot effectively reflect the orientation of the in-situ stress. Based on comprehensive assessment and comparison, in this paper we propose a method integrating various logging data to identify the orientation of in-situ stress. Among various types of logging data, the breakouts azimuth identified by image logs is proved to be the most credible in identifying the orientation of in-situ stress, while using the direction of induced fractures under water-based mud conditions is also viable. However, the azimuth of the fast shear wave is consistent with the orientation of maximum in-situ stress only when the rotation speed of the logging tool is low. The caliper method can be used as a reference for verifying the other two methods. Using this integrated method to study the orientation of in-situ stress in the Keshen 8 trap, the results show that faults are an important factor affecting the direction of in-situ stress, while multi-level faults will produce superimposed effects that cause the current direction of in-situ stress to change.

Fine Logging Evaluation of Fractures in Continental Tight Oil Sandstone Reservoirs of Yanchang Formation in the Ordos Basin

Fractures are the main seepage channels in tight reservoirs, and they affect the distribution of high-quality reservoirs and the enrichment of hydrocarbons. Fine logging identification of fractures in the strongly heterogeneous continental tight oil reservoirs of the Upper Triassic Yanchang Formation in the Ordos Basin is a hot and difficult point in the field of petroleum geology. In this paper, taking the Yanchang Formation as an example, a fractal model was constructed to identify fractures in tight oil reservoirs using a large number of cores, conventional and micro-resistivity imaging logging data. The results show that high-angle, vertical and bedding fractures are mainly developed in the Yanchang Formation tight sandstones. There is a negative correlation between sand body thickness and fracture development degree. The fracture sensitivity parameters were used to construct a coupled fractal fracture index. The fractal model incorporates logging information from natural gamma, acoustic wave time difference, rock density, and shallow lateral resistivity. In addition, the constructed fracture fractal index realizes the functions of multi-conventional logging information fusion, which can effectively identify fracture development segments in sandstone. According to the statistics, the fracture identification rate is 83.3%. The study also found that with the increase of sandstone brittleness index, the fracture index has a “S” shape increasing trend. Therefore, the content of brittle mineral components in sandstone is an important factor affecting the development degree of natural fractures, and fractures are more likely to occur in high brittle, thin sand bodies. The highly brittle framework minerals have strong stress-supporting capacity, which can keep fractures open by resisting high overlying loads.

Integrating facies analysis with dipmeter data to characterize point bars of the Lower Cretaceous McMurray Formation, Christina River, AB, Canada

The Lower Cretaceous McMurray Formation contains crude bitumen reserves of the Athabasca Oilsands that formed by channel amalgamation and lateral migration of fluvio-tidal point bars. These point bars are widely accepted as incised valley fills during episodic base-level rises in tidally influenced estuary (Mathison, 2004; Hein et al., 2013). Historically, well logs such as gamma-ray and spontaneous potential were used in combination with core data to interpret facies and to conduct stratigraphic correlations of the McMurray Formation. Microresistivity image logs, dipmeter logs, and seismic data have greatly improved the identification of facies and recognition of point-bar geometry. In comparison to microresistivity image logs and seismic data, dipmeter data is more regionally accessible; the tool indicates the orientations of fractures, bedding planes and contacts and it is commonly used to delineate boundaries between different point bars in the McMurray Formation. This work provides examples of dipmeter tadpole analyses and discusses how dipmeter-log interpretations can be supported with core-based facies analyses.This study integrates dipmeter tadpole patterns, sedimentological and ichnological characteristics from 47 sedimentary cores. Vintage dipmeter tadpole patterns were observed and digitized from 52 wells to establish a detailed facies characterization with a particular emphasis on McMurray point-bar complexes and sheltered shoreface/delta deposits. In particular, dipmeter data are useful in indicating paleocurrent directions and lateral accretion orientation of point bars, which helps to reconstruct paleodepositional history and stratigraphic relationships. Point bars in the study area are characterized by these sedimentological and dipmeter characteristics: 1) a lower point-bar section characterized by trough cross-bedded sandstone (locally inclined stratified master bedding) with local mud clasts and disorganized, low-to high-angle dipmeter readings; 2) a middle section represented by inclined heterolithic stratified lateral accretionary deposits that exhibit consistent low-angle dips (5°–18°), and display subtle shallow-to-steep-to-shallow dipmeter pattern; and 3) an upper section of the point bar or in some cases abandoned channel strata comprising laminated and lenticular mudstone or bioturbated heterolithic intertidal strata, each showing low-angle (<4°) dipmeter measurements.The dipmeter characteristics of estuarine point bars are integrated with core observations to delineate distinct point-bar stacking patterns and stratigraphic units. In particular, dipmeter tadpole patterns help to refine facies interpretations, such as cross-stratified sandstone facies. Similar point bar scales and stacking patterns are observed in four channel sets. Point bars show either NW-SW or NE-SE lateral accretion surfaces, suggesting northward paleocurrent flow direction.The analyzed datasets support a transgressive fill incised valley fill model that is consistent with earlier McMurray studies in different areas. The four channel sets descend from different stratigraphic levels, but share similarities in scale, orientation and sedimentology/ichnology. The similarity attests to persistent transgression over McMurray time punctuated with regular sea-level fall and rise until the McMurray Formation strata were replaced by Clearwater Formation sedimentation.

Storage space, pore–throat structure of igneous rocks and the significance to petroleum accumulation: An example from Junggar Basin, western China

Igneous rocks in deep basins are important unconventional petroleum reservoirs. Storage space and pore–throat structure of igneous rocks are crucial to be considered as effective reservoirs. There developed large-scale petroleum reservoirs in the Carboniferous igneous rocks of Hongshan-Zhongguai Bulge in the Junggar Basin, western China. The storage space and pore–throat structures of various types of igneous rocks and their significance to petroleum accumulation were studied based on the analysis of core samples. The methods include macroscopic core observation, microscopic observation under microscopes, scanning electron microscopy, micro-resistivity imaging logging and mercury injection experiments. Results show that the storage space is made up of primary gas pores, secondary dissolution pores and various types of fractures. The fillings of fractures are mainly calcite, followed by asphalt, chlorite and gypsum. The igneous rocks have different pore-throat structures, which govern the reservoir properties. Four types of igneous rock reservoirs were recognized, and the most favorable type is volcanic breccia and part of andesite. Dissolution plays an important role in remodeling the pore-throat structure and storage space. Tuff is the most susceptible to dissolution and present greatest alteration in storage space among the studied igneous rocks. An igneous rock weathering crust with high porosity formed near the unconformity capping the Carboniferous rocks, and oil is most abundant within 150 m across the unconformity surface. Faults and the weathering crust jointly control the formation of igneous rock reservoirs. The fault-controlled reservoirs commonly form in structural high position, and stratigraphic reservoirs generally developed in slope area.

Using high-resolution microresistivity image logs to reconstruct paleoenvironments and stratal architectures: An example from the McMurray Formation, Leismer area, northeastern Alberta, Canada

Point-bar deposits, although readily recognizable in most successions, are notoriously challenging to map and correlate accurately, particularly in the subsurface. Sedimentologic interpretations from microresistivity image logs, by contrast, offer an unparalleled method of accurately reconstructing point-bar architectural elements and mapping their distribution. Using an example from the Lower Cretaceous McMurray Formation, we demonstrate that the bedding dip profiles of stacked downstream migration, lateral accretion, and channel abandonment elements record the semicontinuous point-bar accretion of two erosionally juxtaposed large-scale channels. Microresistivity image-log analysis clearly demonstrates that bedding and architectural elements of these heterolithic point bars display discrete and predictable changes in dip angle and direction that are independent of autogenic variations in lithology. We advocate, therefore, that this approach be used to map the facies of point bars and predict their reservoir trends. The laterally accreted mud-sand couplets display a cyclic pattern that is consistent with a nonrandom recurring process. Based on the distribution of bioturbation in the mud beds and variations in sand-bed thicknesses, we argue that this recurring process was probably a monthly occurrence. By measuring the lateral-accretion bed thicknesses for what appears to be a 1-yr interval, a sedimentation rate of 86 cm/yr is estimated for these lateral-accretion beds. This deposition rate provides an upper limit required to deposit these point bars and improves the framing of the depositional model. We estimate that the two point bars in this study were each deposited over a period of a few hundred years.

Fluid flow and permeability analysis of tight gas carbonate reservoir rocks using fractures and dynamic data

The porosity, permeability, rock material and fracture networks of the newly discovered tight carbonate reservoir rock, the Early Cretaceous Sarmord Formation in Zagros basin are examined. The methods used to investigate the formation are rock cores, micro-resistivity image logs, drill stem tests, drilling fluid data, petrophysical wireline data and drilled cutting samples.The analysed data show that the Sarmord Formation is characterized by extensive open and partially open macro-fractures formed by the local stress from fault and fold propagation. These fractures are sub-vertical with an average dip of 73°, fracture aperture of 0.44 mm and persistence (length) of 11.0 cm. The dominant strike of the fractures is NE-SW, parallel to the observed faults and perpendicular to the main Miran West structure.The vast majority of reservoir porosity was found to be in the rock matrix, with the fractures having very limited impact (average fracture porosity is 0.032%) on porosity. In contrast the fracture permeability averages 240 mD which is four orders of magnitude greater than the matrix permeability. As a result, the inter-connected fractures create effective fluid flow pathways and enhanced hydrocarbon migration perpendicular to the fold structure. Faulting associated with the field structure led to fault damaged zones which act as zones of inter-connected fractures with higher permeability and preferential fluid flow pathways. It is demonstrated that the fracture permeability is driven by the fracture aperture and spacing, whilst the fracture persistence has limited control on permeability.The findings of this study highlight that the importance of fractures and faults on reservoir's quality in tight gas bearing rocks. The network of inter-connected fractures, provide the fluid flow which control the permeability. In contrast the matrix controls the pore spaces and the hydrocarbon storage. This work emphasizes the importance of understanding the impact of structural geology in tight carbonate reservoirs.

Characteristics of Micro/Nanopores and Their Petroleum Significance in the Eastern Segment of the Altun Piedmont, Qaidam Basin, Western China.

With continuous improvements in nanotechnology, the development of micro/nanoscale pores and fractures in reservoirs can be more clearly identified, and great progress has been made in tight sandstone and shale. Bedrock has an ultralow porosity and is a reservoir with low permeability. To study the characteristics of micro/nanoscale pore development and reveal their petroleum significance in the eastern segment of the Altun Piedmont, research has been conducted with the use of cathodoluminescence, field emission scanning electron microscopy and energy spectrum analysis, formation microresistivity image logging, high-pressure mercury injection and nuclear magnetic logging. The results have shown that the porosity of the bedrock reservoir in the eastern segment of the Altun Piedmont, as measured by helium injection and nuclear magnetic logging, is between 0.004% and 9.76%, the average porosity is between 1.663% and 3.844%, and the permeability is between the maximum of 0.002 mD and 33.239 mD. The average permeability is between 0.02 mD and approximately 3.836 mD. Micro/nanopores are generally developed, with the majority being intragranular micro/nanopores, intercrystalline micro/nanopores and microcracks, as summarized by the field emission scanning electron microscopy and energy dispersive spectroscopy analysis. Four differently sized pores develop: micropores account for approximately 20%, transition pores account for approximately 30%, and mesopores and macropores account for approximately 25% each. The pore throat development below 100 nm is greater than 50% according to the collation of experimental data from high-pressure mercury intrusion; therefore, micro/nanopores are the main storage space in the study area, and the gas logging shows good results. Micro/nanopores are also one of the main reservoir spaces of bedrock reservoirs in conjunction with the conventional reservoir space, and thus, micro/nanopores have important petroleum significance.

Deep-Learning-Based Vuggy Facies Identification from Borehole Images

SummaryIdentification of vuggy intervals and understanding their connectivity are critical for predicting carbonate reservoir performance. Although core samples and conventional well logs have been traditionally used to classify vuggy facies, this process is labor intensive and often suffers from data inadequacies. Recently, convolutional neural network (CNN) algorithms have approached human-level performance at multiimage classification and identification tasks. In this study, CNNs were trained to identify vuggy facies from a well in the Arbuckle Group in Kansas, USA. Borehole-resistivity images were preprocessed into half-foot intervals; this complete data set was culled by removing poor-quality images to generate a cleaned data set for comparison. Core descriptions along with conventional gamma ray, neutron/density porosity, photoelectric factor (PEF), and nuclear magnetic resonance (NMR) T2 data were used to label these data sets for supervised learning. Hyperparameters defining the CNN network size (numbers of convolutional layers/filters and the numbers of fully connected layers/neurons) and minimize overfitting (dropout rates, patience, and minimum delta) were optimized. The median losses and accuracies from five Monte Carlo realizations of each hyperparameter combination were the metrics defining CNN performance. After hyperparameter optimization, median accuracy for vuggy/nonvuggy facies classification was 0.847 for the cleaned data set (0.813 for the complete data set). This study demonstrated the effectiveness of using microresistivity image logs in a CNN to classify facies as either vuggy or nonvuggy, while highlighting the importance of data quality control. This effort lays the foundation for developing CNNs to segment images to estimate vuggy porosity.

Characterization and impact on reservoir quality of fractures in the Cretaceous Qamchuqa Formation, Zagros folded belt

Reservoir quality in tight fractured carbonate rocks is controlled by the fracture properties, the tectonic origin of fractures, the relationship of fractures to other sedimentary features within the rockmass and diagenesis. In this study fracture analysis, porosity and permeability of the Qamchuqa Formation in the Miran West block of the Zagros folded belt in Kurdistan has been studied. This was undertaken using core analysis, micro-resistivity image logs, drill stem tests (DST), mud logging data, Repeat Formation Test (RFT), drilled cutting samples and wireline log data. The integrated analysis shows that the Qamchuqa Formation is characterized by heterogeneous sedimentary and tectonic features. The sedimentary features include burial stylolites, dissolution seams and some fractures which formed at early stages of burial and diagenesis (Phase 1). Open fractures, partially open mineralized fractures, veins and tectonic stylolites were formed by later tectonic activity (Phase 2). The finding of this study highlight that the fracture properties including aperture, length, frequency and origin, play an important role in controlling the reservoir's quality. The open fractures and partially open mineralized fractures enhance permeability providing an inter-connected fracture network, leading to a high fracture permeability that controls fluid flow in this tight carbonate reservoir rock. The fracture network had little impact on the volume of hydrocarbon storage which is controlled by the pore matrix. In contrast, structures including stylolites, dissolution seams and veins generally have a negative impact on the reservoir quality by blocking the fluid flow. This work emphasizes the importance of understanding the regional geological history and the role of sedimentary and tectonic features when investigating in tight carbonate reservoirs.

Prediction of Fracture Width Using Logging Data Optimization of Lost Circulation

In this study, the efficiency of fractures was evaluated, and their morphological characteristics estimated based on full-hole microresistivity and azimuth resistivity imaging logging. The lost circulation is mainly due to the induced fractures in the ZW areas. The parameters of fracture aperture and porosity can be calculated using dual lateral logging information. The high-angle fracture parameters pertaining to lost circulation in the ZW3-x well include a fracture width in the range of 0.5-5 mm, permeability <15 mD, porosity ~ 20%, and an extended fracture length of ~ 3 m. The compressive strength of walnut shells and rigid particles under different conditions is measured by a compressive strength device. It is shown that the compressive performance of rigid particles is more stable than that of walnut shells. The optimized drilling fluid formula is established for the different size ranges of the rigid particles. Basing on the theoretical calculations, the optimal composition of the rigid particles and drilling plugging agents was established for use in the slug-type follow-drilling plugging technology. This resulted in successful plugging using a small amount of drilling fluid and blocking time (~ 0.5 h). Another major advantage is that this plugging technology can be effectively incorporated while drilling.

Characterization of unique natural gas flow in fracture-vuggy carbonate reservoir: A case study on Dengying carbonate reservoir in China

We investigate the natural gas flow behavior in the Dengying carbonate reservoir of Gaoshiti-Moxi Block in China. Outcrops observation, petrophysical properties measurement, and formation micro-resistivity image logging (FMI) all show that the vugs distribute in a stratified manner with characteristic length ranging from 0.2 to 4 cm. The horizontal permeability is significantly larger than the vertical permeability due to the stratified distribution of vugs and fractures. We build a representative conceptual reservoir model to describe this fracture-vuggy type carbonate reservoir. Both Darcy equation and Stokes-Brinkman equation are applied to simulate natural gas flow in this type of reservoir. Simulation results show that natural gas mainly flows along the free channel formed by low-dip fractures and flat ellipsoid vugs. Compared with the Darcy method, the Stokes-Brinkman method provides a more accurate prediction of gas flow behavior in the fracture-vug carbonate reservoir.

Sedimentary facies analysis of the Upper Bahariya sandstone reservoir in East Bahariya C area, North Western Desert, Egypt

The present work aims to deduce the depositional processes of the Lower Cenomanian Bahariya Formation, that is one of the main hydrocarbon siliciclastic reservoirs in the Northern Western Desert of Egypt. This has been achieved through the analyses of the core photographs, micro-resistivity image logs, mud logs and conventional wireline logs. The Bahariya Formation comprises a complex of depositional lithofacies such as interbedded siltstone, shale, sandstones and pebbly sandstones. The current work highlights the effectiveness of the integrative approach. A variety of datasets including core photographs, micro-resistivity image logs, mud logs and conventional wireline logs are integrated to define the conceptual depositional model in the study area.Different recorded sedimentary features point to various depositional processes. Hummocky cross stratification (HCS) is the common sedimentary structure indicating the storm action. Wave ripples are recorded providing evidence for fair-weather action on shoreface. Rhythmic heterolithics, tidalites indicate the tidal processes. The upper part of the Bahariya Formation has been influenced by wave and storm processes more than the lower parts. The core and image facies are designated, being dominated by Sandstone (S), Siltstone (Z), Mudstone (M), Heterolithic (H) and Limestone (L.s). The studied core and image facies with wireline logs facies are grouped into five major facies associations (FA). They are Tidal Channel and Tidal Creeks, Tidal Flat, Storm, Shoreface, Offshore Transition to Offshore Facies Associations. The integrative approach indicates that the Upper Bahariya Member has been deposited in a storm influenced tidal coastal realm.

Recovery of tectonic traces and its influence on coalbed methane reservoirs: A case study in the Linxing area, eastern Ordos Basin, China

The physical properties of coal reservoirs, i.e., porosity, permeability, fractures, and coal structures, are generally evaluated based on its structural morphology, however, its tectonic evolution history plays a much more important role. The key problems associated include the time when the dominant variations on properties of coal occurs and how to quantitatively characterize the influences of different tectonic movements. Based on field joint observations and well logging (micro-resistivity imaging logging (MIL), interval transit time (DT24), density (DEN), and natural gamma-ray (GR)) interpretations, the paleotectonic stress fields and tectonic traces were recovered and the present coal structures were identified. Subsequently, the quantitative correlation between the tectonic deformation and coal reservoir property were established with fluid intrusion tested porosity and permeability and scanning electron microscope (SEM) results.The results showed that the maximum horizontal compressive stress was oriented at the NW-SE direction in Yanshanian and at the NEE-SWW direction in the Himalayan period as obtained from hundreds of joint measurement and fracture interpretation results. Six combinations (by superposition of anticline, syncline, and the flanks) from the Yanshanian and Himalayan movements were found, which indicate different deformation degrees. The maximum tectonic curvature (r'), which occurred in either the Yanshanian or Himalayan period, shows differences at different structural areas and reflects the real deformation degree of coal seam in geological history. When r'< 12 × 10−6 m−1, primary coals are developed; when 12 × 10−6 m−1 <r' < 35 × 10−6 m−1, cataclastic coals are generally developed; when r'> 35 × 10−6 m−1, granulated coals are dominant. Mylonitized coals are barely developed in the study area. With the increase of deformation degrees of coal seams, the number of microfractures increases and fracture stretches tend to be more complicated. When r' < 25 × 10−6 m−1 (if r' > 25 × 10−6 m−1, the coal cores are much too broken for drilling core samples), with the increase of r', the displacement pressure (Pd) achieved by mercury intrusion method decreases in an linear form, and the permeability tested by helium presents a linear growth. However, the porosity shows a weak correlation with r', mainly caused by the great burial depth and long-term compaction resulting in low porosity ranges (2.8%–8.1%) with little difference shown. This presents an applicable method for evaluating the influence of tectonic movement on the physical properties of coal during different times and would benefit the evaluation of coalbed methane reservoirs in the study area as well as other coal basins in the world.

Generating porosity spectrum of carbonate reservoirs using ultrasonic imaging log

Imaging logging tools can provide us the borehole wall image. The micro-resistivity imaging logging has been used to obtain borehole porosity spectrum. However, the resistivity imaging logging cannot cover the whole borehole wall. In this paper, we propose a method to calculate the porosity spectrum using ultrasonic imaging logging data. Based on the amplitude attenuation equation, we analyze the factors affecting the propagation of wave in drilling fluid and formation and based on the bulk-volume rock model, Wyllie equation and Raymer equation, we establish various conversion models between the reflection coefficient β and porosity ϕ. Then we use the ultrasonic imaging logging and conventional wireline logging data to calculate the near-borehole formation porosity distribution spectrum. The porosity spectrum result obtained from ultrasonic imaging data is compared with the one from the micro-resistivity imaging data, and they turn out to be similar, but with discrepancy, which is caused by the borehole coverage and data input difference. We separate the porosity types by performing threshold value segmentation and generate porosity–depth distribution curves by counting with equal depth spacing on the porosity image. The practice result is good and reveals the efficiency of our method.

A Method of Calculating Saturation for Tight Sandstone Reservoirs: A Case of Tight Sandstone Reservoir in Dabei Area of Kuqa Depression in Tarim Basin of NW China

The tight sand reservoir in Dabei Area has been the main block of exploration and development of natural gas inTarimBasin. Because of low porosity and fracture development, there exist errors in calculation of reservoir saturation. According to micro-resistivity image logging and acoustic full-wave logging, the reservoir fractural effectiveness is quantitatively evaluated; the result indicates that the reservoir with Stoneley wave permeability is greater than 0.2 × 10-3μm2; the reservoir connection is good. If the FVPA is greater than 0.055%; the fractures are developed. A new matrix saturation model is established based on the conductive pore water in consideration of the influence of low porosity. After modeling and analyzing the effect of porosity and its occurrence on the cementation index, the method for saturation calculation in Kuqa Area is established: the newly established dual porosity model is for fracture developed reservoirs, and the model based on the conductive pore water is for fracture less-developed reservoirs. By comparing the results of saturation in mercury injection experiment from coring section, precision of the calculation method is proven.

Shearlets and sparse representation for microresistivity borehole image inpainting

Microresistivity image logs from wireline tools commonly include nonmeasured gaps corresponding to the spaces between electrode-carrying pads in contact with the borehole wall. The missing data impede the development of automated processes that seek to provide objective and reproducible geologic analysis. Geologic features often manifest themselves as curvilinear objects representing a variety of discontinuities, such as layer boundaries and fractures, which lend themselves to sparse representation. Missing data may be inpainted by thresholding or minimizing the norm of their representation in a fitting dictionary. Curvelets have been found to provide good sparse approximation for these features, but shearlets are shown to be more computationally efficient. Results from a mix of synthetic and field image logs indicate more accurate reconstruction of sharp high-contrast edges.