3D Seismic Interpretation Research Articles

Quantitative prediction of sand bodies in a sparsely explored zone of the Tarim basin: A case study of the aketao area

Thin sandstone reservoirs of the fan delta front sub-facies occur in the early Neogene (Miocene) series of the Aketao (Akto) structural belt within the Kunlun piedmont zone of the Tarim Basin. Oil and gas reservoirs in this area correspond to stratigraphic traps. However, owing to the low density of the 2D seismic survey grid deployed in the Aketao belt, inferior seismic data quality, and lack of well logging data, reservoir prediction in this area suffers from a multiplicity of problems and it is difficult to effectively identify sand bodies. Here, a new research approach is proposed involving the use of 3D seismic, well logging, and drilling data from a neighboring highly-explored 3D seismic survey area as a reference for the 2D seismic interpretation of the non-drilled Aketao survey area. Moreover, this approach is integrated with forward modeling and the inversion of post-stack seismic data to identify sand bodies. A comparison of the seismic reflection characteristics clarifies that these 3D and 2D seismic survey areas share similar sedimentary environments. Forward modeling confirms their similar reservoir characteristics, while the reservoir distribution in the 2D seismic survey area is effectively mapped via the inversion. The results show that for a 2D seismic survey area characterized by a low degree of hydrocarbon exploration and appraisal, and a lack of well logging data, the proposed approach can confirm the sedimentary characteristics that correspond to the seismic reflection characteristics, and can quantitatively map the reservoir thickness.

Evaluation of Hydrocarbon Reservoir in the “SIMA” Field of Niger Delta Nigeria from Interpretation of 3D Seismic and Petrophysical Log Data

3D seismic and petrophysical log data interpretation of reservoir sands in “SIMA” Field, onshore Niger Delta has been undertaken in this study to ascertain the reservoir characteristics in terms of favourable structural and petrophysical parameters suitable for hydrocarbon accumulation and entrapment in the field. Horizon and fault interpretation were carried out for subsurface structural delineation. In all, seven faults (five normal and two listric faults) were mapped in the seismic section. These faults were major structure building faults corresponding to the growth and antithetic faults in the area within the well control. The antithetic fault trending northwest-southeast and the normal fault trending northeast-southwest on the structural high in the section act as good trapping mechanisms for hydrocarbon accumulations in the reservoir. From the manual and auto-tracking methods applied, several horizons were identified and mapped. The section is characterized by high amplitude with moderate-to-good continuity reflections appearing parallel to sub-parallel, mostly disturbed by some truncations which are more fault related than lithologic heterogeneity. The southwestern part is, however, characterized by low-to-high or variable amplitude reflections with poor-to-low continuity. Normal faults linked to roll-over anticlines were identified. Some fault truncations were observed due to lithologic heterogeneity. The combination of these faults acts as good traps for hydrocarbon accumulations in the reservoir. Reservoir favourable petrophysical qualities, having average NTG, porosity, permeability and water saturation of 5 m, 0.20423, 1128.219 kD and 0.458 respectively.

New 3D fault model for eastern Flanders (Belgium) providing insights on the major deformation phases in the region since the late Paleozoic

A new 3D fault model was created for the Upper Paleozoic to Cenozoic subsurface in eastern Flanders (Belgium). The model was based on the integration of 2D seismic interpretations, borehole and gravimetric data, as well as coal mining and topographic maps. Four major tectonic phases, taking place during the latest Paleozoic, Jurassic, Late Cretaceous and Cenozoic, shaped the fault network. The latest Paleozoic phase was transpressional and expressed by local folding of the Carboniferous strata underneath the base Permian unconformity. The largest anticlines were asymmetric, with amplitudes of up to 500 m and SSW-NNE oriented axal planes. The subsequent Jurassic phase caused normal faulting across the area, resulting in the development of the northeast-dipping, western border fault systems of the Campine Basin and Roer Valley Graben. Fault strikes were predominantly WNW-ESE to NNW-SSE. Both fault directions were most likely inherited from early Carboniferous and older tectonic phases. Jurassic fault reactivation explains the activity along fault populations with different orientations as well as the linkage of these faults into long (>10 km) systems, despite displaying generally relatively small vertical throws (<500 m). Soft-linked boundaries (accommodation zones) between Jurassic fault domains are located on top of the largest latest Paleozoic transpressional anticlines.The Late Cretaceous major tectonic phase was compressional and involved inversion of the Roer Valley Graben with subsequent subsidence and carbonate deposition in the flanking Campine Block.During the Cenozoic extensional phase, most normal faults that developed were rooted in Jurassic faults and therefore displayed similar WNW-ESE to NNW-SSE strikes. Cenozoic extension was, however, weaker than Jurassic extension; Cenozoic fault numbers, lengths and vertical throws were smaller than during the Jurassic phase. Also during the Cenozoic phase, faulting was more localized onto the pre-existing Roer Valley Graben border fault system compared to the more diffuse Jurassic faulting. The Cenozoic faults were generally planar, whereas some of its Jurassic roots near and in the border fault system of the Roer Valley Graben were listric.

Quantitative Simulation of Gas Hydrate Formation and Accumulation with 3D Petroleum System Modeling in the Shenhu Area, Northern South China Sea

Gas hydrates have been considered as a new energy that could replace conventional fossil resources in the future because of their high energy density, environmental friendliness, and enormous reserves. To further analyze the potential distribution of gas hydrate stability zones (GHSZ) and the formation of a gas hydrate system in the Shenhu area of the South China Sea (SCS), a 3D petroleum simulation model (PSM) was built from 3D seismic interpretations and all available geological data. Based on the thermal calibration of the 3D model, the evolution of the GHSZ, hydrocarbon generation and migration, and the formation and accumulation of gas hydrates were simulated for the first time in the area. Thermal simulation shows that the methane source of gas hydrate originated from shallow biogenic gas and deep thermogenic gas. Most areas are dominated by shallow biogenic gas, while, only about 3% of the deep thermogenic gas derived from Enping Formation source rock and contributed to the gas hydrate formation within a few areas in the southeast. The thermogenic gas migrated vertically into the GHSZ through connecting faults, mud diapir, and/or gas chimney to form gas hydrate. The source rocks of the Wenchang Formation, a deep thermogenic gas source, began to enter the main hydrocarbon generation window at 28.4 Ma. The Enping source rock began to generate oil from 25 Ma on and gas from 16 Ma on. Since 5.3 Ma, most areas of the source rocks have generated a gas window, and only the shallower parts in the east still in the oil window, which had lasted until now. The shallow biogenic gas source rocks from the Hanjiang, Yuehai, and Wanshan formations generated gas in different periods, respectively. The Qionghai Formation began to generate hydrocarbon from 0.3 Ma and until now. Other results show that the GHSZ developed mainly during the Quaternary and Neogene (Wanshan Formation) and the GHSZ is thicker in the southern area and thinner in the northern part with a positive correlation with water depth. Starting at 11.6 Ma, the GHSZ developed in the Hanjiang Formation in the south of the Shenhu area and gradually expanded to the north to cover most of the study area at 5.3 Ma during the Yuehai Formation. From 1.8 Ma on, the GHSZ covered the entire study area. At the same time, the GHSZ in the Hanjiang Formation disappeared because of the change in temperature and pressure. At present, the GHSZ in the Yuehai Formation has disappeared, while the Quaternary and Wanshan are the two main formations for GHSZ development. The formation and distribution of gas hydrates are fundamentally controlled by the space-time coupling between the hydrocarbon generation and expulsion time and distribution of the GHSZ. The simulation results of gas hydrate accumulation and distribution were verified by drilling results and the matching rate is 84%. This is the first time that 3D simulation was successfully conducted with PSM technology in the Shenhu area and it provides important guidance for gas hydrate study in other areas of the SCS.

Salt geometry in the Central Basin of the Nova Scotia passive margin, offshore Canada based on new seismic data

This study describes the structural architecture of the central portion of the Scotian Basin and focusses on Mesozoic salt deposition and deformation linked to magma-rich rifting. BP acquired a high-quality 3D seismic survey called the Tangier survey and built a detailed velocity model with RFWI (Reflection Full Waveform Inversion) and tomography. This has allowed for high resolution seismic imaging of target sedimentary reservoirs but also for the first time, imaging of the complex crustal architecture along the central part of the Nova Scotia margin. We evaluated the regional basin architecture and salt tectonic evolution in context of Late Triassic and Early Jurassic rifting followed by passive margin gravity spreading. An exploration well (Aspy D-11) was drilled based on the 3D seismic interpretation and penetrated halite, carnallite and anhydrite salt in an allochthonous salt sheet. Basement is thought to have rifted during deposition of interlayered halite, shale, carnallite and anhydrite. Carnallite may have precipitated from enriched brines that formed at the more distal (southern) end of an elongated seaway of rifted basins which began opening first in the North in the Late Triassic and propagated southward towards Florida (e.g., Jansa, 1980; Jansa and Tucholke, 1986; Roberts and Bally, 2012). Water flowed southwards from Tethys along a chain of complexly interconnected areas of rifted basins. Flow of seawater along Nova Scotia is interpreted to have been southward along a widening and progressively subsiding region of rifts possibly as dynamic elevation associated with the CAMP (Central Atlantic Magmatic Province) dissipated southward much like what occurred in the Central South Atlantic and Gulf of Mexico (GoM) (e.g., Quirk et al., 2013; Morgan et al., 2020; Pindell et al., 2020; Pindell and Heyn, 2022). Brine was enriched along the seaway by evaporation, causing deposition of the most-soluble salt components furthest south along the sequence of basins. The presence of weathered basalt in salt and SDRs on the seismic supports magma-rich Mesozoic rifting and suggests that heating of brine pools may not have been exclusively caused by the sun, but that hydrothermal systems probably contributed to heating and the precipitation of Carnallite.

County in Southwest Ordos Basin Block 1 Period of Sand Body Distribution Characteristics of Mountains

Huanxian block is one of the key oil and gas exploration and development blocks in Longdong Gas field of Changqing Oilfield Company. The Mesozoic exploration is about to enter the saturation state, and it is urgent to explore new fields. Therefore, the seismic characteristics, reflection structure characteristics and reservoir sand body distribution characteristics of Shan-1 member of Permian Shanxi Formation of Upper Paleozoic in this block are studied comprehensively. By using the data of drilling core, well logging curve and 3D seismic interpretation, the regional small beds are finely divided and correlated, and the unified stratigraphic framework of the area is established. The structural characteristics of the bottom of Shan-1 member of Shanxi Formation are studied, and the distribution characteristics of reservoir sand bodies and effective sand bodies of Shan-1 member are analyzed and studied.

Getting the most out of a large data set: A case study for a large 3D seismic interpretation project in the Carnarvon Basin, NW Australia

A case study is presented for the seismic interpretation of a 3D seismic reprocessing project covering approximately 7200 km2 within a rift basin setting on the Northwest Shelf of Australia. The area includes two main petroleum plays: the Cretaceous Barrow Group Delta and the fluvio-deltaic Triassic Mungaroo Formation. Multiple 3D surveys of varying vintages were reprocessed to provide a unified continuous data set over the area. Seismic amplitude variation with offset inversions were conducted in time and depth domains to produce acoustic impedance and VP/VS volumes. The use of depth-domain inversion enabled more accurate inversion products to be developed with a large lateral and vertical zone of interest to assist in prospectivity assessments. Project time and cost constraints indicated a traditional seismic interpretation process would be ineffective and inefficient. The workflows applied included optimizations of the initial horizon interpretation to improve efficiency, machine learning (ML)-based automatic fault interpretation to save time, and bulk horizon interpretation for time savings and rapid stratal slicing. Utilizing ML and automated interpretation processes in conjunction with seismic inversion products enabled a full prospectivity assessment to be developed within six months. In addition to completing the work within the available time, the applied workflows allowed for significantly more time to be spent on prospectivity assessment rather than structural and stratigraphic interpretations.

A novel workflow for geothermal exploration: 3D seismic interpretation of biohermal buildups (Upper Jurassic, Molasse Basin, Germany)

The Upper Jurassic carbonates are the prime target for deep geothermal exploration in the Molasse basin, South Germany. The carbonates have a thickness of over 500m (1640 ft) and consist of two major facies: (1) bedded marly limestone and (2) massive limestone and dolostone. The massive limestone facies is composed of sponge-microbial biohermal buildups It is considered the main geothermal reservoir facies. Only this facies type may be (1) karstified, (2) dolomitized, and/or (3) faulted and fractured, and therefore can yield very high flow rates of >100 l/sec = 26 gps. The main data source used in this study is the 3D seismic survey of the Freiham geothermal field in the western part of Munich/Germany. Blended in were cutting logs to describe the lithology from 2 wells and borehole image logs from the two geothermal wells. Lithologies derived from these wells were upscaled in support of the seismic interpretation. The study presents an integrated workflow of 3D seismic attribute analysis to analyze the distribution and quantification of reservoir facies (massive limestone) versus non-reservoir facies (bedded marly limestone) per time slice. The attribute “sum of magnitude” is mapped for 9-time slices based on the vertical resolution of the Freiham 3D cube. The seismic facies interpretation is compared with upscaled borehole image facies associations of two geothermal wells. BHI log data is calibrated with an interpretation of the depositional environment based on cutting analysis Reservoir geometries were derived from an outcrop analog study to better understand the 3D seismic facies interpretation and to construct the conceptual depositional model of the Upper Jurassic carbonates. This technique is commonly used in hydrocarbon exploration but is not yet adapted to geothermal projects, which are often based on little data, smaller company sizes, tight budgets, and limited access to specialized geomodelling software and experience. The approach of using 3D seismic attribute analysis presented in this study provides a quantitative subsurface model of geothermal reservoir facies in the Freiham geothermal field. It is quick and straightforward and can easily be applied in the exploration workflow for similar fields and reservoirs.

2D seismic interpretation of Sawan gas field integrated with petrophysical analysis: A case study from Lower Indus Basin, Pakistan

The Lower Indus Basin is the leading hydrocarbon-bearing sedimentary basin in Pakistan. This study has been conducted on the Sawan gas field located in the Lower Indus Basin, adjacent to a few other well-known gas fields of Pakistan like Kadanwari, Qadirpur, and Miano gas fields. This research aims to present the spatial distribution and reservoir potential of the productive zones of the Lower Goru Formation. The present study utilized various two-dimensional (2D) seismic lines and well-log data (Sawan-01 and Sawan-02) to investigate the structural and stratigraphic features of the area. The stratigraphic layers are mildly deepening in the southeast direction. The 2D seismic interpretation of the research area identifies the existence of extensional remanents, i.e., normal faults. These extensional structures are associated with horst and graben geometry that acts as a trapping mechanism for hydrocarbons. Wireline logs are used to identify the reservoir's diverse lithology and petrophysical properties. Petrophysical results indicate fair to good effective porosities, low shale volume, and high hydrocarbon saturation (>55%), signifying good reservoir potential in C interval of the Lower Goru Formation.

Several types of triangle zones from the Subandean ranges of Peru: Fish-tails, tectonic wedges and passive-roof duplexes

Surface geology, well data and 2D seismic interpretations reveal the presence of triangle zone structures at the contact of the Subandean Ranges and the Amazonian foreland in Peru. From north to south the Santiago, Marañon, Ucayali and Madre de Dios basins have been studied. Interpretations presented in this study show a great variety of structural styles at this contact area. Simple triangle zones with one back thrust, composite ones with several back thrusts, more complex double vergent ones with pop-up structures, best described as fish-tails, tectonic wedges and passive-roof duplexes are present in the study area. The role of pre-Andean tectonics and paleogeography is key to understanding the Andean evolution, due to the control on the location and geometry of the main detachment levels. The Santiago Basin is characterized by the presence of fish-tail structures with a Permian-Triassic evaporitic basal detachment located at the base of the Pucara Gr. At the Ucayali Basin, several detachment levels interact, the basal ones located within the Ordovician, Devonian, and Carboniferous defining triangle zones or tectonic wedges. At the Madre de Dios Basin, two detachment levels define the base of the triangle zone, Permian shales in the northwest at the Inambari Imbricates area, and Lower Devonian (Cabanillas Gr.) in the southeast at the Candamo area. A roof thrust is located within the Paleogene section at both the Madre de Dios and Ucayali basins, defining passive-roof duplex structures.Several detachment levels are rooted into the Lower Paleozoic; others within the Permian-Triassic section, being locally evaporitic, and finally others are located at the base of the Cretaceous. Paleozoic shales represent the main basal detachment level of the southern Subandean ranges. The role of these detachments and the role of the sedimentation rate are discussed as factors that control the development and geometry of the triangle zones described in the study area.Except for the San Martin-Sagari area of the Ucayali Basin, the triangle zones of the Santiago and Madre de Dios basins remain unexplored even though active petroleum systems are present. Sub-thrust structures at the Azulmayo area of the Madre de Dios Basin remain promising undrilled structures.

Evolution of submarine channel morphology in intra-slope mini-basins: 3D-seismic interpretation from offshore Niger delta

The morphological characteristics of a submarine channel system, within buried intra-slope mini-basins in the offshore Niger Delta have been investigated on 3D seismic data. The studied submarine channel named Amaku Channel Levee System (ACLS) initiated after avulsion of a feeder channel called Amaku Major System (AMS). The ACLS runs across three folds (A, B, and C), related to mobile shale deformation, being underlain by mass transport complexes (MTCs), lobes, and levees. From three defined channel reaches (upper, middle, and lower reaches), we have used seismic facies description, channel architecture characterization and quantitative analyses to decipher the spatial and temporal evolution of the channel levee system. Our results reveal that the western channel margin was controlled by structural barriers associated with mobile shale deformation, while the eastern channel margin was influenced by depositional barriers linked to levees and mass transport complexes (MTCs). We argue that the depositional barriers are in some cases more efficient than the structural barriers in controlling channel pathways, since pre-channel sediments confine the channel elements and divert them against positive reliefs. Seismic observations show that channels migrate from folds to structural lows causing flow stripping processes. Downstream variations of morphological parameters (such as sinuosity, width, and levee width), indicate that pre-existing deposits prevented these basin-ward migrations, driving straightening and narrowing of the channel system. This study reveals that submarine channels can undergo dramatic morphological and stratigraphic changes in structurally complex areas because of the configuration of sidewall reliefs, which is controlled, in turn, by the interplay between structural deformation and pre-channel deposition.

Distribution of Petrophysical Properties Based on Conceptual Facies Model, Mishrif Reservoir/South of Iraq

A 3D geological model is an essential step to reveal reservoir heterogeneity and reservoir properties distribution. In the present study, a three-dimensional geological model for the Mishrif reservoir was built based on data obtained from seven wells and core data. The methodology includes building a 3D grid and populating it with petrophysical properties such as (facies, porosity, water saturation, and net to gross ratio). The structural model was built based on a base contour map obtained from 2D seismic interpretation along with well tops from seven wells. A simple grid method was used to build the structural framework with 234x278x91 grid cells in the X, Y, and Z directions, respectively, with lengths equal to 150 meters. The total number of grids is (5919732) in the geological model. CPI (computer-processed interpretation) for 7 wells contain (facies, porosity, water saturation, and NTG) was imported to Petrel 2016 software. Facies log was upscaled and distributed along the 3D grid. Truncated Gaussian with trend method was used to distribute the facies taking into account the conceptual facies model of the Mishrif formation. The result shows that the trend of sedimentation suggests a retrogradation pattern from NW to SE. Facies1 (Reservoir), dominated by Limestone brown to light brown, with oil shows has good distribution within the area and thinning towards the NW. The petrophysical properties (porosity, water saturation, NTG, and permeability) were distributed using the Sequential Gaussian Simulation (SIS) method and the facies model as a guide for distribution.&#x0D; The results show that petrophysical properties enhanced in the southeast area, representing the reef region compared to the northwest side of the study area. Unit Mishrif B had the highest porosity value and lower water saturation value along the entire field. While the units Mishrif B1, B2, and B3 show a gradual decrease in reservoir properties towards the field's southeast side. The results also show that the conceptual facies model has great benefit in constructing the 3D geological model, reflecting the geological knowledge used to correctly distribute the reservoir properties (porosity and water saturation).

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

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

Causes of a premature thermal breakthrough of a hydrothermal project in Germany

Sustainable heat extraction is of utmost importance for the economic life of geothermal production systems. Especially in hydrothermal sedimentary basins, a temperature decrease at the production well prompts a financial loss. A premature thermal breakthrough occurred in one of the geothermal projects in the Greater Munich Area, a well-known region for deep, low enthalpy geothermal development in the Upper Jurassic carbonate reservoir (syn. Malm) beneath the North Alpine Foreland Basin. Accordingly, questions are raised regarding the geologic controls on the reservoir´s permeability, the occurring type of heat and mass transport mechanism, and the fitting reservoir model type. 3D seismic data interpretation delineates seismic scale structures potentially influencing the reservoir permeability. Geophysical borehole data characterize sub-seismic scale elements (fractures, karst, and lithofacies), where we correlate them with the inflow zones and the interpreted seismic scale structures. The integration of both scales delineates the reservoir heterogeneity controlled by a lateral change in the carbonate lithofacies overprinted by faults and fractures. A NNW-SSE oriented seismic scale structure matches the orientation of hydraulically active sub-seismic scale fractures, where they are aligned with the maximum horizontal stress orientation. This structure induces additional anisotropic permeability, providing a preferential hydraulic pathway between the wells of the project. This study recommends considering fractured reservoir models to simulate the mass and heat flow in the highly heterogeneous Malm carbonates instead of composite reservoir models of equivalent hydraulic properties. Finally, we present a hydrogeological model describing the reservoir's structural and matrix permeability distribution to act as a basic concept for future thermal-hydraulic numerical modeling. The applied methods in this study are applicable in similar geothermal systems with adequate seismic and geophysical borehole data for future geothermal reservoir characterization, modeling, and management.

3D Geological Modelling for Asmari Reservoir In Abu Ghirab Oil Field

Building a geological model is an essential and primary step for studying the reservoir’s hydrocarbon content and future performance. A three-dimensional geological model of the Asmari reservoir in Abu- Ghirab oil field including structure, stratigraphy, and reservoir petrophysical properties, has been constructed in the present work. As to underlying Formations, striking slip faults developed at the flank and interlayer normal. Abu Ghirab oilfields are located on the eastern anticlinal band, which has steadily plunged southward. 3D seismic interpretation results are utilized to build the fault model for 43 faults of the Asmari Formation in Abu Ghirab Oilfield. A geographic facies model with six different rock facies types are developed. This new modelling system should be capable of more clearly reflecting the connectivity of the oil body and the heterogeneity of the reservoir. To represent the vertical and horizontal heterogeneity and create a framework for the Asmari reservoir in the Abu Ghirab oil field, the Petrel software has been used to create a reservoir in a 3D model. This model was constructed using data from 55 wells located across the Asmari formation. The model demonstrates accurate estimations (porosity, saturation, and net to gross). These reservoir models directly impact the facies model’s computation of each layer of the net pay thickness of the reservoir. The final goal of the present work is to determine the initial oil in place (IOIP), which is found to be 269*106 sm3.

Evaluation of fractures using conventional and FMI logs, and 3D seismic interpretation in continental tight sandstone reservoir

Abstract Due to the complex pore structures and strong heterogeneity of fractured reservoirs, it is a hot and difficult point in petroleum geology to identify fractures using logging principles. In this paper, taking the tight sandstone reservoir of the Chang 8 Member in the Huanjiang Oilfield as an example, field outcrops, cores, thin sections, and logging identification methods were used for quantitative description and fine logging evaluation of fractures. The research shows that high-angle, medium-low-angle, near-vertical, and horizontal fractures are developed in the Chang 8 Member of the Huanjiang Oilfield. The main ones are high-angle fractures, followed by horizontal fractures with a low degree of fillings. Under the constraints of core and imaging logging data, three fracture sensitivity logging parameters of acoustic wave time difference, natural gamma, and dual induction-octalateral resistivity were optimized, and a comprehensive fracture probability index was proposed. Seventy-nine fracture development intervals were identified based on log curve characteristics and fracture probability indexes. The coincidence rate of fracture logging identification results with the core observation and imaging logging interpretation is 80.6%. The research results can provide a theoretical basis for the efficient development of fractured continental tight sandstone reservoirs in similar areas.

Using of Polynomial and THD Methods to the Depth Map of Shurau Formation that Obtained from 2D Seismic Interpretation to Structural Map Construction in Ismail Region, Northern Iraq

The 2D seismic data were analyzed and interpreted in Isamil region in northwestern Arbil Governorate, northern Iraq. The structural and tectonic situation of the region was constructed through the study of Shurau Formation (Oligocene). The polynomial analytical method applied to the depth map of Shurau Formation produced two maps these are regional trend map of the formation in addition to the residual structural map. The Total Horizontal Derivative method application supports the identification of the lineaments of possible faults and tectonic boundaries in the study area. The final structural map indicates that the regional trend of the study area is toward the ENE direction. The local structural features (Anticlines, Synclines, and Faults) found mostly trending NW-SE coincide with the main trend in the folded zone. This study shows the importance of using the polynomial and the Total Horizontal Derivative methods in the interpretation of the depth map of formation obtained from seismic data.

Enhanced Discrimination of Seismic Geological Channels Based on Multi-Trace Variational Mode Decomposition

The spectral decomposition is a valuable tool for improving the resolution of seismic interpretation, and thus can improve the accuracy of the subtle geo-features (thin and narrow channels, thin reservoirs, etc.). Variational mode decomposition (VMD) is an adaptive signal decomposition algorithm that non-recursively decomposes multicomponent signals into several band-limited intrinsic mode functions, which is competitive in enhancing time-frequency resolution. However, discontinuity is normally caused by the trace-by-trace process, making the 3D seismic interpretation difficult. To address this issue, we present a novel seismic geological channel detection method for 3D seismic dataset based on multi-trace variational mode decomposition (MTVMD). The proposed method decomposes the broadband seismic data into several intrinsic mode functions and then computes seismic attributes from each component for geological feature analysis. Further tested by field seismic case, the proposed method demonstrates strength in depicting the detailed edges and sedimentary signatures of paleochannels. Overall, the proposed method provides an alternative approach to identifying seismic channels, especially for the detailed portrayals of subtle geo-features in low-quality seismic data.

Tectono‐stratigraphic evolution of the rift and post‐rift systems in the Northern Campos Basin, offshore Brazil

AbstractThe Campos and Santos Basins have been a focus of subsurface studies since the discovery in 2006 of large accumulations of hydrocarbons in the Early Cretaceous rift and post‐rift strata below Aptian evaporites. In this study, regional 2D seismic lines, a 3D seismic survey and well data were interpreted to reconstruct the tectono‐stratigraphic evolution of the rift and post‐rift stages in the northern sector of the Campos Basin. Detailed 3D seismic interpretation and geological modelling were used to subdivide the pre‐salt sedimentary record. This revealed a diachronous strain distribution along the Guriri Fault System (GFS), a roughly NE‐SW striking fault‐bounded horst that was a focus of rift‐related deformation. The syn‐rift succession is interpreted to be the product of two episodes of rifting (RP1 and RP2) with contrasting fault activity patterns and lithostratigraphy. Volcaniclastics and coarse siliciclastics of RP1 were deposited under WNW‐ESE transtension that formed discontinuous half‐grabens followed by extensive erosion and tectonic inversion. Structurally controlled bioclastic rudstones and hybrid deposits characterize RP2 and were deposited in elongated half‐grabens that delimit the GFS horst, which developed under an NW‐SE extension. Deposition under increasingly less tectonically active transitional and post‐rift stages dominated by thermal subsidence gradually led to the healing of the rift‐related structural relief. Selective reactivation of rift faults testifies active tectonic inversion through compression from immediate post‐rift throughout evaporite deposition. These interpretations are put into the context of recent geochronological data of onshore dyke emplacement and the new age constraints for the end of deposition of the pre‐salt sequence. Therefore, we propose an earlier onset on rifting in the Campos Basin, at the Berriasian.

A shared earth approach to siliciclastic reservoir characterization: The Zubair Fm of Northern Kuwait

An innovative, integrated characterization workflow is applied to complex siliciclastic reservoirs of the Lower Cretaceous Zubair Formation in the Bahrah Field of Northern Kuwait. A detailed sedimentological and petrophysical assessment, integrated with 3D seismic interpretation, constrained and delineated vertical and lateral facies changes within the field, which is also affected by complex fault and fracture patterns. Siliciclastic geo-bodies have been documented and mapped in 1D, 2D and 3D using seismic stratigraphy, seismic attributes and high-resolution seismic inversion reservoir characterization workflows. The spatial distribution of these geo-bodies appears to show the development of fluvio-deltaic systems in the southern and central sectors of the field, which evolved into marine dominated/tidally influenced deltaic systems towards the northern and eastern sectors. Two major fluvial channels trends have been identified: SW-NE and W-E, with a dominantly NE trending deltaic progradation. Towards the north, elongated (tidal mouth?) sand bars have been interpreted with a NW-SE trend. An integrated sequence stratigraphic framework was consequently developed to better assess the influence of relative sea level changes on sedimentary facies. This framework pointed to the influence of marine incursions and subsequent flooding surfaces, which lead to the development of shale-rich seals and/or baffles that could increase the probability of structural-stratigraphic trapping mechanisms in these depositional environments. This integrated workflow was utilized to update a numerical static reservoir model, which further de-risked future drilling locations and potentially charged reservoir volumes.