Reservoir Interpretation Research Articles

Evolution of carbonate studies in the Rocky Mountain region over the past century

Just as the world’s population, knowledge in general, and the Rocky Mountain Association of Geologists (RMAG) have changed in major ways during the past 100 years, so too has the study and interpretation of carbonate rocks and reservoirs. The RMAG, a century old in 2022, has evolved from just 50 original charter members who held the organization’s first “meeting” in 1922, to its approximately 1800 members today. Thus, RMAG’s publications have helped document the evolution of carbonate rock studies, particularly those in the Rocky Mountain region. Key contributions have been made through RMAG’s hundreds of luncheon talks, through its quarterly technical publication, The Mountain Geologist, initiated in 1964, and the exceptionally comprehensive Geologic Atlas of the Rocky Mountain Region, published 50 years ago in 1972. In addition, since 1953 the RMAG has published field guides and symposia volumes focused on specific basins, types of reservoirs, and structural geology among other things. Many of these books contain papers focused on carbonate rock units in the Rockies. Analysis of the papers published in The Mountain Geologist each year from 1964 through 2021 reveals that a fairly consistent 10 to 15% of that journal’s articles each year deal directly with some aspect of carbonate rocks. Earlier papers in the 1960s and 1970s dealt mainly with outcrop studies and the correlation of specific carbonate units based on measured sections or the use of fossils to define facies and biostratigraphic units. During the 1980s emphasis shifted to refining carbonate depositional models and focusing more on carbonate diagenesis through detailed petrographic studies, isotopic analyses, cathodoluminescence, and scanning electron microscopy. The 1990s brought a shift to papers focused more on specific carbonate hydrocarbon reservoirs ranging from the peritidal dolomites in Cottonwood Creek Field to relatively deepwater Waulsortian mudmounds in the Mississippian Lodgepole Formation and the “basinal” chalks of the Niobrara Formation. The focus of carbonate studies shifted again in the early 2000s to the use of 3-D seismic data to better understand specific carbonate reservoirs and the increased interpretation of carbonate deposits within the context of sequence stratigraphy. The tools used to study carbonate rocks expanded even further over the past decade with more refined isotopic data, improved SEM studies, and the use of elemental data obtained with X-ray fluorescence analyses. No doubt the next decade will bring even more improvements in data collection methods and the interpretation of depositional and diagenetic processes that have impacted all Rocky Mountain carbonate deposits.

Post-drill geophysical characterization of two deep-water wells of Cauvery Basin, East Coast of India

The depth of the reservoir causes an increase in the degree of uncertainty in the prediction of reservoir quality. High frequency is suppressed with depth because Earth functions as a low-pass filter. The seismic amplitudes observed at various interfaces are influenced by spherical divergence, transmission losses, mode conversions, and inter-bed multiples. Seismic data have numerous essential components that must be thoroughly examined during hydrocarbon prospect identification and maturation, including post-critical reflections, events coherency (in near and far offsets), mode conversion, and interbed multiples. Seismic amplitudes are typically derived from 2D/3D seismic data and utilized directly or indirectly for reservoir interpretation and better prediction of subtle geological and geophysical information. To accurately depict subsurface geological features, stratigraphic architecture, and reservoir facies, it should be used in conjunction with the existing paleoenvironment data. When employed alone, the subsurface geophysical data may lead to erroneous interpretation of subsurface lithologies and inaccurate reservoir property predictions. Understanding these factors could help interpreters make better use of seismic data while maturing and de-risking the prospectivity. This study examines the post-drill geophysical characterization of two exploratory wells that were drilled in the deep-water area of the Cauvery Basin, East Coast of India. Analysis and correlation with a discovery well is done to understand the sediment depositional heterogeneity and corresponding seismic amplitude response, primarily for the cemented reservoir (dry well). To discover prospects and subsequently de-risk the existing prospect inventory, a dashboard checklist for in-depth study of seismic and well data has been developed. The top-down geophysical analytical approach that has been presented will aid in defining reservoir characteristics generally, estimating deliverability, and subsequently raising the geological probabilities and chance of success (COS) of any exploration project. The findings of this study allow critical analysis of seismic data to distinguish between softer/slower/possibly better reservoir rocks and hard/fast/tight rocks.

Seismic interpretation and hydrocarbon assessment of the post-rift Cenomanian Bahariya reservoir, Beni Suef Basin, Egypt

The geophysical interpretations for a collection of high-quality 2D seismic data plus well logging data for six drilled wells exposed the structural controls and the hydrocarbon potentiality of the Beni Suef Basin, north Western Desert, Egypt. The created structural map on the top of the Early Cenomanian Bahariya Formation (the significant oil reserve in north Western Desert), exhibits a series of NW–SE normal faults as well as a master ENE strike-slip major fault. The extensional faults formed horst structures while the strike-slip fault created a negative flower structure in the central part of the study area. These structural features represent the main petroleum traps within Beni Suef Basin. The reservoir quality was assessed through the petrophysical analysis of the Bahariya Formation in wells; Azhar A2, Azhar E-2X, Azhar E3, Yusif-4X, Fayoum-2X and Beni Suef W-1X. This analysis proved that the Lower Bahariya unit has better reservoir quality than the Upper Bahariya reservoir, with shale volume less than 10%; effective porosity between 10 and 20%, water saturation between 25 and 75% and total pay thickness between 11 and 88 ft. The obtained results encourage drilling more exploratory wells in Beni Suef Basin to enhance the productivity from the sandstones of the Lower Bahariya reservoir.

Fracture Identification of Deep Dolomite Reservoir Based on R/S-FD Analysis: A Case Study of the Cambrian Sinian Reservoirs in the Sandaoqiao Gas Field, Northern Tarim Basin

The pre-Mesozoic Sandaoqiao gas field, northern Tarim Basin, Western China, hosts a typical deep fractured dolomite reservoir. Taking this area as an example, this study carried out identification research on the fracture development section of the Cambrian Sinian deep (5,700–6200 m) thick (60–80 m) fractured dolomite reservoirs. The core scale identification and numerical analysis method of heavy gauge finite difference (R/S-FD) are used to identify the fracture development section. In the process of applying this method to the study area, by comparing the fracture development identification results of continuous and complete coring sections, three logging curves with high fracture sensitivity (AC/DEN/CAL) are selected. The adjusted R/S-FD analysis method can effectively identify the fracture development section of the fractured dolomite reservoir. Among them, five fracture development sections were identified in well Q1, with an average thickness of 6.8 m. The fracture development section is in good consistency with the reservoir interpretation section of conventional logging. Well, Q101 identified 11 fracture development sections with an average thickness of 2.5 m. The results show that the gas logging section lags behind the fracture development section, mainly corresponding to the lower part of the identified fracture development section. The thickness and distribution of the longitudinal fracture development section of the two wells are obviously different. The research shows that the R/S-FD method can well identify the fracture development section of a fractured dolomite reservoir.

NMR T1-T2 Logging in Unconventional Reservoirs: Pore-Size Distribution, Permeability, and Reservoir Quality

The rock-pore textural properties in unconventional fine-grained reservoirs are much more complicated than in conventional reservoirs. In fine-grained rocks, this complexity derives from very small component grain assemblages (clay and silt fractions) and very small pores (nano- to microsizes) overprinted by diagenesis. It is further compounded by the pores being developed in intergranular, grain dissolution, and organic-associated-intragranular voids. Additionally, because locally sourced hydrocarbons in unconventional reservoirs, in contrast to migrated hydrocarbons that are present in conventional reservoirs, exist within similar pore sizes as the original saturating water phase, they create geometrically complex fluid distributions. These imply that, in the context of nuclear magnetic resonance (NMR) logging and petrophysical interpretation of tight oil unconventional reservoirs, pore size can no longer be considered a proxy for fluid type and vice versa. This means using T2 or T1 cutoffs may give inaccurate predictions. Current industry applications of NMR T1-T2 logging have demonstrated reliable interpretation of fluid types and water saturation. However, because petrophysical controls of advanced relaxation effects (such as surface and bulk fluid relaxation properties, pore-size distribution, and wettability) are not properly understood, these applications have been limited to estimating fluid saturations and have not been applied to estimating pore sizes. We extend the application of NMR T1-T2 measurements in tight oil unconventional reservoirs to model pore-size distributions by using apparent surface relaxivities and bulk relaxation times that have been jointly estimated from poro-fluid relaxations. To test these predictions, modeled pore-size distributions are compared to rock-pore textural properties from petrographic images of core samples. Such comparison allows us to derive insights into controls of mudstone reservoir quality (RQ) in conjunction with the impact of rock fabric endmembers (e.g., matrix-supported clays, grain-supported framework, diagenetic cements, and solid organic matter) on pore-size distributions. With these assumptions in mind, it follows, based on the Kozeny-Carman formulation, that unconventional rock permeability is reliably predicted from the NMR-based pore-size distributions. Furthermore, we deduce the impact of mineral assemblages in the Herron permeability model to infer influence on rock textural properties and ultimately predict permeability in limited data environments. This paper introduces a novel approach to estimate pore-size distributions per fluid type (water and hydrocarbons) from NMR T1-T2 measurements in unconventional reservoirs. Additionally, petrophysical controls of RQ, storage, and transport properties are derived from NMR-based pore-size distributions and mineral assemblages. This enables more reliable RQ and permeability assessment than typical T2- or T1-cutoff methods.

Natural Source Electromagnetic Component Exploration of Coalbed Methane Reservoirs

As an environmentally friendly and high-calorific natural gas, coalbed methane (CBM) has become one of the world’s most crucial unconventional energy sources. Undoubtedly, it is necessary to conduct in-depth research on reservoir exploration methods to ensure high and stable CBM production in the development stage. However, current methods have disadvantages such as high cost, complex devices, and poor terrain adaptability, and therefore they are unsuitable for reasonable monitoring of CBM reservoirs. In contrast, electromagnetic prospecting methods are increasingly widely employed in the rapid delineation of conductive distributions, contributing a lot to in-situ reservoir interpretation. Furthermore, a natural source Super-Low Frequency electromagnetic component method (i.e., the SLF method for short) has been proposed and applied with high potential in a CBM enrichment area, Qinshui Basin, China. In this paper, this method is thoroughly discussed. The magnetic component responses of the SLF method can be used as the characteristic responses of subsurface layers, and the forward modeling algorithms using the finite element method have been successfully developed and verified. On this basis, the direct depth transformation and one-dimensional nonlinear regularization inversion algorithms of the magnetic component responses are proposed for geo-object interpretation. With the help of the empirical mode decomposition (EMD), an SLF data processing workflow is demonstrated theoretically and practically, which is integrated into a portable instrument. The instrument’s ability to identify the low-resistivity reservoirs and their surrounding rocks has been proved by field survey. The extraction of electromagnetic radiation (EMR) anomalies also helps to refine the reservoir interpretation with higher accuracy. A joint comparative inversion test between the SLF method and the audio-magnetotelluric method (AMT) is also addressed, demonstrating that the SLF method is reliably applicable in the field survey of CBM reservoirs. A preliminary statistical analysis shows that the depth resolution of CBM reservoirs can reach the order of tens of meters. Therefore, the SLF method is expected to become one of the most potential options for in-situ CBM exploration with a cost-effective interpretation capability.

Reservoir Interpretation of Intrusive Rock Buried-Hill with Mud-Logging Data while Drilling—Taking the Y Area in the Qiongdongnan Basin of the South China Sea as an Example

The intrusive rock buried-hill reservoir is one of the main targets for oil and gas exploration in the offshore sedimentary basins of China. In order to discover the reservoir as early as possible for decision-making to save costs, reservoir interpretation with mud-logging data needs to be studied. Previous studies have showed that the homogeneity rocks reservoir can be well interpreted with mud-logging data u the Kb (mechanical specific energy ratio) method and the WL (tangential power)-WH (vertical power) intersection method. However, reservoir interpretation with mud-logging data for intrusive rock buried-hill has not been reported. The key steps or parameters of these two kinds of methods used for reservoir interpretation need to be modified for the vertical variation of intrusive rock buried-hill. Furthermore, confirming the interpretation of these two kinds of methods has not been reported. Taking the Y area in the Qiongdongnan Basin of the South China Sea as an example, the intrusive rock buried-hill can be divided into four zones based on its characteristics and genesis in descending order: the sand–gravel weathering zone, the weathering fracture zone, the inner fracture zone, and the base rock zone. The reservoir can be well interpreted when taking the MSE (mechanical specific energy) geometrical mean of the base rock zone as a basic value to calculate Kb. The reservoir will also be well interpreted when WH ranges from 0 to 4.5 MPa and WL ranges from 0 to 99 MPa in the column while intersecting. The layers of the reservoir can be interpreted as Kb < 1 in the sand–gravel weathering zone and the weathering fracture zone. The Kb < 1 and effective intersection of WL-WH layers at the same time could be interpreted as a reservoir in the inner fracture zone and the base rock zone. After combining the Kb method with the WL-WH intersection method, the reservoir of intrusive rock buried-hill can be well interpreted. The total thickness of the uninterpretable reservoir ratio is less than 20% compared to reservoir interpretation with well-logging for each well.

Tectonic controls on geomorphological dynamics and sediment dispersal in source-to-sink systems in the Qingdong Sag, Bohai Bay Basin

Well-log and three-dimensional (3D) seismic data are used to investigate the tectonic controls during the depositional periods of the Kongdian and Shahejie formations from Ek–Es 4 L to Es 4 U–Es 3 L–M on strata distribution, depositional systems and sediment dispersal in the Qingdong Sag, Bohai Bay Basin, East China, from a source-to-sink perspective. This tectonic transition is characterised by the Tanlu Fault switching from sinistral to dextral strike-slip as the fault system changed from a dominant NW–WNW trend during the Ek–Es 4 L period to a dominant WNW–EW trend during the Es 4 U and Es 3 L–M periods. These changes subsequently controlled the framework and areal extent of sediment dispersal in the inner-basin source-to-sink systems and resulted in a change in trend of inner-basin secondary structural belts, from primarily being NW-trending during the Ek–Es 4 L period to E–W-trending during the Es 4 U and Es 3 L–M periods. The tectonic transition also resulted in the western and southern source-to-sink systems expanding with time and controlled the flow path and sediment redistribution within each source-to-sink system with migration of the subsidence centre of the Qingdong Sag and even the region. The significant changes in the basin structure controlled the source area, flow path, sediment transport distance and direction, and have a significant impact on the interpretation of depositional environments and reservoirs in rift basins with a multi-phase evolution history. KEY POINTS The Qingdong Sag, Bohai Bay Basin, experienced a tectonic transition during sediment deposition in the Eocene. The tectonic transition resulted in changes to the fault system and basin geomorphology. Fault movement and changes in basin geomorphology affected source-to-sink systems.

3D structural modeling for seismic exploration based on knowledge graphs

Three-dimensional structural models provide valuable references for studying exploration challenges and often are used for survey design and seismic method validation as well as to assist with reservoir interpretation. The current structural modeling strategy primarily relies on seismic images, which can suffer from degraded image quality in areas of complex structures. This leads to less-reliable structural interpretations. It is difficult to build appropriate models with unreliable inputs by data-driven modeling methods when the input data contain no other constraints. To mitigate this problem, we have adopted a knowledge-data-driven structural modeling method for seismic exploration based on knowledge graphs that contain certain digitized prior information related to the subsurface structures. The knowledge graph of the structural models formalizes the knowledge of geoscientists by describing the structural model entities and their interrelations in the form of a graph. We first establish the knowledge graph of the structural model to constrain the model topology, then estimate the geologic intersections (lines) between the geologic surfaces under the guidance of the knowledge graph, and finally reconstruct the surfaces under the constraints of the intersections and generate closed geologic bodies. The knowledge graph defines the overall structure of the model, which sets up a priori constraint for the modeling and plays a role in transferring expertise to computers. We use two field models to demonstrate our structural modeling process and prove the effectiveness and feasibility of the method.

Diffraction imaging: A valuable complement to reflection imaging for sand injectite interpretation in the Norwegian North Sea

Interpretation of sand injectite reservoirs from conventional reflection seismic data is a complicated exercise. The complex geometries of injectites are challenging to detect and resolve by using conventional seismic processing due to their lateral and vertical variability in thickness and dip. Steeply dipping injection dikes tend to appear blurred or distorted on reflection images, and interpretation of their positioning and thickness carries an important level of uncertainty. Structural attributes derived from reflection images are used to support interpretation, but they suffer from a lack of spatial resolution and vertical continuity. We introduce a novel interpretation workflow that includes a diffraction image in addition to the conventional reflection image to improve the detectability and resolution of steep injection dikes and small-scale features. The diffraction image is generated in a migrated dip-angle domain where diffracted and reflected energy can be separated. A case study from a large injection complex in the Norwegian North Sea illustrates the superiority of the diffraction image over conventional structural attributes to support the interpretation and characterization of thin and steeply dipping injectites. The complementarity of the reflection and diffraction images is exploited by visualization techniques (e.g., corendering) or by combining interpretations from separate images, providing a complete picture of the injection complex geometries. Diffraction imaging proved to be a valuable tool to improve the level of detail and confidence in the interpreted injectites, both for modeling and well-planning purposes.

Petrophysical characterization and 3D seismic interpretation of reservoirs in the Baris Field, onshore Niger Delta Basin, Nigeria

In order to evaluate the petrophysical properties, characterize the structural framework and determine the hydrocarbon in place of potential reservoirs in the Baris Field, onshore Niger Delta Basin, Nigeria, 3D seismic and well log data from the field were collected and interpreted using Geographix and Petrel software. Two reservoir zones B2 and B5 were identified having porosity ranging from 21% to 22%, permeability from 235 to 523 mD and water saturation from 16% to 28%. Petrophysical parameters show that the two zones are good reservoirs and highly petroliferous. Seismic interpretation revealed the presence of six listric faults, two major faults (F1 and F2 trending in the northwest–southeast direction) and four minor faults (F3, F4, F5 and F6). Faults 3, 4 and 5 trend in the same direction as the major faults, while fault 6 trends in the northeast–southwest direction. Two major horizons were identified, and they correspond to the two reservoir tops (B2_top and B5_top). Roll-over anticlinal structures between the two major listric faults were identified. The depositional environment of the Reservoirs B2 and B5 have been deciphered to be of a barrier bar or crevasse play and the trapping mechanism in the Baris Field is a four-way structural closure. STOOIP and GIIP for the two zones have been estimated with the zone B5 more prolific with a STOOIP and GIIP of 7.98MMSTB and 12.77MMMSCF respectively.

Controlling factors on elastic wave velocities of conglomerate – Experimental and theoretical study

As an important type of clastic rocks, the conglomerate has quite different physical properties compared to sandstone due to its strong heterogeneity. Hence, studying the relationship between conglomerate physical properties and elastic wave velocities is essential for the seismic exploration or sonic logging interpretation of conglomeratic reservoirs. In this work, various physical properties and elastic wave velocities of dry conglomerate samples were measured, based on which their relationships were investigated. The results show that the gravel content and porosity are two controlling factors on conglomerate elastic wave velocities. For the studied samples, the content of middle-sized gravels (diameter ≥4 mm) affects the elastic wave velocities greatly due to their high elastic moduli. Besides the gravel content and porosity, the gravel contact patterns and cementation types are key geometrical details that also affect elastic wave velocities significantly. Different gravel contact patterns and cementation types result in notable differences in elastic wave velocities. To further illustrate the effects of geometrical details on elastic wave velocities, a theoretical modelling approach that accounts for gravel contact patterns and cementation types was proposed. The predictions given by this theoretical modelling approach agree well with experimental results, which validates the important roles of gravel contact patterns and cementation types on conglomerate elastic wave velocities. This work provides a basis for inverting conglomerate physical properties from elastic wave velocities, which is helpful for the seismic exploration or sonic logging interpretation of conglomeratic reservoirs.

Rock Physics Model Provides Insight Into Reservoir Characterization

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30359, “Reservoir Characterization Supported by Rock Physics Diagnostics,” by Stephan Gelinsky, Shell. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. Rock physics models are often perceived as too complicated and dependent on too many difficult-to-measure parameters to be of practical use for reservoir characterization. In the complete paper, the author demonstrates how careful calibration of a common and simple rock physics model can provide valuable insights into the reservoir and seal elastic properties such as function of porosity, fluid, and mineral properties and net-to-gross. The model can be used for quantitative seismic interpretation of reservoirs with variable net-to-gross and porosity away from well control. Methodology Rock physics describes the application of fundamental physical principles to establish the elastic properties of porous rocks as a function of their mineral composition, pore fill, and microstructure and texture. Once a suitable rock physics model is calibrated locally, the use of seismic data to estimate reservoir rock and fluid properties from the elastic rock properties is possible—specifically, from the observed seismic amplitudes and if seismic data were inverted from the seismically derived acoustic and shear impedances. The Hashin-Shtrikman (HS) effective medium bounds can be used to characterize both sandstones and shales. While the application of this model for clean sandstones is straightforward and, thus, is not included in this synopsis, the application for shales is more complex.

Automatic extraction of outcrop cavity based on a multiscale regional convolution neural network

Determination of pore space characteristics is important for carbonate reservoir interpretation and evaluation. Field outcrops can reflect the geology of the subsurface reservoir. The most common method of traditional outcrop research is field investigation, which is likely to cause human errors. Digital image recognition of geological outcrop areas can reduce the problem of inaccurate descriptions of geological structures caused by human factors. Automatic extraction based on convolutional neural networks can greatly reduce the amount of such work. By enhancing the deep-learning model of a convolution neural network, the mask region-convolutional neural network (Mask R-CNN) is proposed. This method adapts to the multiscale features of the cavity by manipulating the scales of the input image. To verify the applicability of the model, the method is applied to automatic cavity identification in the digital outcrop profile of the Dengying Formation (2nd Member) in Xianfeng, Ebian. The parameters are calculated layer by layer, and their distribution characteristics are quantitatively analysed, indicating good application results. To verify the advanced nature of the model, the cavity extraction results of this method are compared with those of traditional image segmentation, machine learning and other depth learning methods. Precision analysis shows that the performance of the method proposed in this paper is superior to the traditional methods. In addition, the cavity feature parameters extracted by this method are compared with the manual extraction. The accuracy for the cavity number, surface porosity, and average cavity area is over 80%, 88%, and 72%, respectively for the proposed method. The results show that the proposed method is reliable and accurate, hence it will help to provide a basis for reservoir prediction in the process of regional geological exploration.

The diagnostic criteria of borehole electrical imaging log for volcanic reservoir interpretation: An example from the Yingcheng Formation in the Xujiaweizi Depression, Songliao Basin, China

Electrical image log can be used to establish volcanic facies sequences, and thus used for reservoir interpretation, while the key is to set up available diagnostic criteria to guide lithology, structure and facies interpretation. A total of 50 datasets of borehole image logs, combined with wireline logs and cores, have been collected in the Yingcheng volcanic reservoir in the Xujiaweizi Depression, Songliao Basin, providing an opportunity for repeated image interpretation in the volcanic strata. The interpreted lithology includes rhyolite, dacite, andesite, basalt, welded ignimbrite, tuff, volcanic breccia and agglomerate, sedimentary tuff, sedimentary volcanic breccia and agglomerate. The volcanic structures are calibrated in terms of fluidal and deformed fluidal structure, vesicular and amygdaloidal structure, and massive structure. Based on the lithology and structures, volcanic facies including volcanic sedimentary facies, effusive facies, explosive facies and volcanic conduit facies, have been further determined. Layered structures of the weathered volcanic crusts are shown in borehole images and mainly developed at the top of the Yingcheng Formation. Borehole images indicate that SHmax direction in the area is consistent with the regional SHmax direction, with a preferable trending of 88°. Four sets of filled/open tectonic fractures are developed with approximately north, south, NNE and NW dipping. It infers that different volcanic facies can be well correlated between wells, and tectonic movements have a slight influence on the Yingcheng volcanic strata. The proposed diagnostic criteria and the workflow can be referred for a direct image interpretation in volcanic reservoirs or ocean drilling programs when cores are unavailable.

Seismostratigraphic Interpretation of Upper Cretaceous Reservoir from the Carpathian Foreland, Southern Poland

The Upper Cretaceous complex in the central part of the Carpathian Foreland (southern Poland) is relatively poorly recognized and described. Its formations can be classified as unconventional reservoir due to poor reservoir properties as well as a low recovery factor. The main aim of the article is to expand knowledge with conclusions resulting from the analysis of the latest seismic data with the application of seismic sequence stratigraphy. Moreover, the seismic attributes analysis was utilized. The depositional architecture recognition based on both chronostratigraphic horizons and Wheeler diagram interpretations was of paramount importance. A further result was the possibility of using the chronostratigraphic image for tectonostratigraphic interpretation. Two distinguished tectonostratigraphic units corresponding to megasequences were recognized. A tectonic setting of the analyzed interval is associated with global processes noticed by other authors in other parts of the central European Late Cretaceous basin, but also locally accompanied by evidence of small-scale tectonics. This study fills the gap on the issue of paleogeography in the Late Cretaceous sedimentary basin of the Carpathian Foreland. It presents the first results of detailed reconstruction of the basin paleogeography and an attempt to determine the impact of both eustatic and tectonic factors on sedimentation processes.

Moduli variations in two-phase fluid rocks considering squirt flow and patchy saturation

The complex pore structure and fluid distribution in underground rocks bring difficulties to rock physics modeling and reservoir interpretation. The existence of cracks and ellipsoidal pores will cause squirt flow during wave propagation, and the fluid may be present as patchy saturation. By considering the effects of both squirt flow and patchy saturation, a new rock physics model is proposed. The fluids in inclusions include a soft fluid such as gas and a stiff fluid such as water. The novelty is that an explicit expression of patch saturation with frequency is introduced. Thus, the proposed model is helpful to analyze the variations of moduli with frequency caused by squirt flow and patchy saturation simultaneously. By comparison, the proposed model matches well with existed boundary models and covers all possible behavior of the moduli. Then, variations in moduli with water saturation and frequency are analyzed in detail, as well as the impact of patchy saturation on the attenuation induced by the squirt flow. The analysis shows that a small amount of gas contained in inclusions can cause a large change in moduli, especially the bulk modulus. The effect of patchy saturation on the moduli increases with the increasing frequency and when the frequency is low, the effect only occurs at very high water saturation. Besides, at high water saturation, the squirt flow can cause a sharp change in bulk modulus. The proposed model is helpful for understanding wave propagation in partially saturated rock with cracks.

Identification and logging evaluation of poor reservoirs in X Oilfield

Abstract The reservoirs of X Oilfield have the characteristics of fine lithology particles, strong pore structure heterogeneity, and high argillaceous reservoirs and thin layers are generally developed. Conventional logging interpretation cannot make a fine evaluation, which results in serious discrepancies between the interpretation results of some reservoirs and actual production performance, and reserves are underestimated. Improving poor reservoir identification and logging evaluation accuracy is of great significance to oilfield development. The flow zone indicator (FZI) is used to classify the reservoirs into three types, I, II, and III, and the classification results are combined to establish a reservoir type identification chart based on logging curves; the resolution matching method and the deconvolution method are used to improve the accuracy of thin-layer recognition. Finally, the logging interpretation model is reestablished. Logging evaluations were conducted on 20 wells in X oilfield, and Y core wells were used for verification. The application results show that this method can effectively improve the identification accuracy of thin oilfields and high argillaceous reservoirs; the results of fine logging interpretation of poor reservoirs are consistent with core analysis conclusions and actual production conditions, which are typical of the successful application of poor reservoir technology.

Quantitative seismic interpretation of the Lower Cretaceous reservoirs in the Valdemar Field, Danish North Sea

A quantitative seismic interpretation study is presented for the Lower Cretaceous Tuxen reservoir in the Valdemar Field, which is associated with heterogeneous and complex geology. Our objective is to better outline the reservoir quality variations of the Tuxen reservoir across the Valdemar Field. Seismic pre-stack data and well logs from two appraisal wells form the basis of this study. The workflow used includes seismic and rock physics forward modelling, attribute analysis, a coloured inversion, and a Bayesian pre-stack inversion for litho-fluid classification. Based on log data, the rock physics properties of the Tuxen interval reveal that the seismic signal is more governed by porosity than water-saturation changes at near-offset (or small angle). The coloured and Bayesian inversion results were generally consistent with well-log observations at the reservoir level and conformed to interpreted horizons. Although the available data have some limitations and the geological setting is complex, the results implied more promising reservoir quality in some areas than others. Hence, the results may offer useful information for delineating the best reservoir zones for further field development and selecting appropriate production strategies.

Application of adaptive parameterized S‐transform to delta sandstone reservoir identification

ABSTRACTTime–frequency analysis plays an important role in seismic interpretation and reservoir identification because it reveals the variation of seismic frequency contents over time. The S‐transform is recognized as an efficient method for seismic time–frequency analysis, but its frequency distribution biases the actual Fourier spectrum due to the linear frequency‐dependent term in the analytical window. In this paper, an improved S‐transform, named adaptive parameterized S‐transform, is proposed for identifying delta sandstone reservoirs. In the proposed method, three parameters are introduced into the S‐transform to better adjust the time–frequency resolution in different frequency bands. Then these parameters are selected adaptively by using the concentration measure to provide a highly energy‐concentrated time–frequency representation for seismic signals. Two synthetic examples validate the effectiveness of the proposed method. Analysis of field seismic data illustrates that it can provide a better reservoir interpretation with a high resolution. Comparisons between the wavelet transform, S‐transform, and modified S‐transform prove the superiority of the proposed method in describing reservoir distribution and decreasing the uncertainty of reservoir detection. This paper presents a complementary approach to current methods for reservoir detection and identification.