Conventional Seismic Interpretation Research Articles

Architecture and evolution of shelf‐margin clinoforms developed in a back‐arc tectonic setting: Insights from quantitative analysis on the south‐west shelf margin of the Ulleung Basin

AbstractGeophysical and geological research in the Ulleung Basin has been ongoing since the 1970s, involving continuous seismic acquisition and multiple well‐drilling projects. This study utilized an integrated quantitative approach with conventional seismic interpretation based on recent trends to understand the history of the shelf‐margin development and individual controls that may have influenced each period in the Ulleung Basin. Quantitative analysis was conducted by measuring the progradation (Pse), aggradation (Ase) and sediment influx (Fc) of individual shelf margins in seven dip‐oriented seismic profiles, and calculating the shelf‐edge gradient (αse) and the P/A ratio. Based on these data and the ratio of accommodation to sediment supply (A/S ratio), which was interpreted from the stratal stacking pattern, five shelf‐edge trajectory types were defined and assigned to each shelf margin. By considering individual controls (eustatic fluctuations, sediment supply and tectonic events), we defined the three evolution intervals of the Ulleung Basin during the Middle Miocene to Late Miocene (15 to 6.5 Ma): (1) the upper Middle Miocene (15 to 11.63 Ma) characterized by a moderate sediment supply and high aggradation margin induced by rapid subsidence, (2) the lower Upper Miocene (10.8 to 10 Ma) as a high sediment supply and low aggradation margin associated with reworked sediments from the uplifted Dolgorae Thrust and (3) the uppermost Miocene (9.2 to 6.5 Ma) characterized by a low sediment supply and low aggradation margin experiencing sediment starvation. A comparison with worldwide continental margins indicated that the Ulleung Basin formed under a relatively low rate of progradation (low sediment supply; 4.79 km/Myr) and a high rate of aggradation (high shelf accommodation; 361.04 m/Myr) condition. The SW margin of the Ulleung Basin provides a unique example of understanding stratigraphic architecture variations under changing stress regimes of back‐arc setting (extensional to compressional) and understanding of individual controls that influence margin development.

Using seismic petrophysical modeling and prestack simultaneous inversion to provide insights into the physical properties of uranium-bearing reservoirs: Implications for favorable sites of sandstone-hosted uranium deposits

Seismic prospecting has been accepted as one of the most widely available methods for exploring sandstone-hosted uranium deposits (SUDs). However, conventional seismic interpretation faces a challenge in the identification and characterization of a uranium reservoir’s complexity. How to characterize in detail a uranium reservoir’s physical complexity and effectively improve uranium reservoir prediction accuracy remain unresolved problems. To address this, we develop a novel combination of petrophysical modeling and prestack simultaneous inversion to understand in detail the physical properties of uranium-bearing reservoirs and efficiently predict favorable SUD sites. First, we develop a workflow of rock-physics modeling for SUD logs using the Xu-White method to calculate the modulus of elasticity of the grain matrix; subsequently, we extend the Walton model for the modulus prediction of the dry rocks and the Gassmann equation for one of the saturated rocks after a massive calculation test; and then, we predict the S-wave data used for the following inversion. Second, we execute a prestack simultaneous inversion to obtain the petrophysical parameters (e.g., P-impedance, density [[Formula: see text]], shear modulus [[Formula: see text]], Lamé coefficient [[Formula: see text]], and Young’s modulus) that can provide insights into the physical properties of a uranium metallogenic environment. Accordingly, we discover that sites bearing uranium mineralization strongly correspond to areas with low elastic-parameter values (especially [Formula: see text] and [Formula: see text]), whereas nonuranium anomalies occur in high-value sites. This indicates that weakened elastic characteristics are caused by the enhancement of the total organic content and total clay mineral volumes of the uranium-bearing layers. In summary, the developed combination approach can yield an effective and accurate characterization of the geologic properties of uranium-bearing formations, and it can provide prediction factors (e.g., parameters related to the shear modulus) for uranium mineralization.

Multi‐Scale Geomechanical Modelling of Unconventional Shale Gas: The Implication on Assisting Geophysics–Geology–Engineering Integration

In the development of unconventional shale play, simulation of the performance for wells needs to incorporate sufficient complexity in geology to take fully into account the variabilities in petrophysical and geomechanical properties. These parameters controlling the effective stimulated rock volume (eSRV) represent the heterogeneity and strong‐layering nature of unconventional reservoirs: high inter‐bedding anisotropy, flow behaviours and pre‐existing geological disconnections (bedding planes, faults, fissuring, natural fractures). This realistic simulation model includes direct information and interpreted understanding from data sources in a wide range of resolutions and scales and is finally coupled with hydraulic fracturing and reservoir depletion modelling in terms of mechanical. The multi‐scale geomechanical model incorporates processed seismic interpreted data (10 m scale), petrophysical core data (cm scale), routine scalar logs (m scale) and resistivity borehole image (0.25 cm scale). The vital role the multi‐scale geomechanical model plays during the entire workflow is to underpin the disconnection among actual well logs, conventional seismic interpretation and geological complexity by calculating and predicting field scale geomechanical parameters and in situ stresses distribution. Multiple research investigations and case studies on such integration include data acquisition and processing methods, modelling upscaling methodologies and data diagnostical techniques from multidisciplinary perspectives. Although these works show great progress in improved understanding of the spatial and temporal distribution of formation reservoir and geomechanical distribution, uncertainty remains as local stress variations and mechanical‐flow properties between layers are impossible to capture.

Complex fault system revealed by 3-D seismic reflection data with deep learning and fault network analysis

Abstract. Understanding where normal faults are located is critical for an accurate assessment of seismic hazard; the successful exploration for, and production of, natural (including low-carbon) resources; and the safe subsurface storage of CO2. Our current knowledge of normal fault systems is largely derived from seismic reflection data imaging, intracontinental rifts and continental margins. However, exploitation of these data sets is limited by interpretation biases, data coverage and resolution, restricting our understanding of fault systems. Applying supervised deep learning to one of the largest offshore 3-D seismic reflection data sets from the northern North Sea allows us to image the complexity of the rift-related fault system. The derived fault score volume allows us to extract almost 8000 individual normal faults of different geometries, which together form an intricate network characterised by a multitude of splays, junctions and intersections. Combining tools from deep learning, computer vision and network analysis allows us to map and analyse the fault system in great detail and in a fraction of the time required by conventional seismic interpretation methods. As such, this study shows how we can efficiently identify and analyse fault systems in increasingly large 3-D seismic data sets.

Geologic Causatives and Seismic Attributes Heterogeneities for Structural and Stratigraphic Interplays, Sitra Area, North Western Desert, Egypt

Sand-lithofacies distributions are a vital component of reservoir characterisation and the generation of successful reservoir models, particularly in thin reservoirs thickness. The integration between seismic attributes and conceptual geologic models is important to identify the sand distributions and reservoir geometries. The aim of this work is illustrating the uses of seismic data in revealing the structural and stratigraphic elements of two main reservoir units. It is important to identify and list the attributes, which can be involved in analysing the reservoirs and their degree of involvement in the characterisation of the hydrocarbon accumulation zones. The study was carried out for the reservoirs: Abu Roash C and Abu Roach E in Sitra oil and gas concession, which is located in the northern part of the Egyptian Western Desert. Four seismic attributes are used: 1- Coherence (Variance) 2- 3D Curvature attributes were used for resolving mainly the structural features and also the stratigraphic features 3- Instantaneous phase 4- Instantaneous frequency attributes were used mainly for resolving the stratigraphic features. Through the integration of selected seismic attributes with post-stack seismic data, reservoir distributions and architectures are accurately delineated for the Upper Cretaceous reservoir (Abu Roash ‘C’ and ‘E’). Five wells were used to match the results of the seismic attributes and establish the regional trends of reservoir parameters. The integration of wells data, conventional seismic interpretation and extracted the relevant seismic attributes help in reaching a robust geologic model for the reservoirs of interest. Stratigraphic and structural interpretation objectives based on extracting the seismic attributes for reservoir characterisation become more dominant, as they go deeper in seismic data, to derive more subsurface geologic data than traditional interpretation. 3D structure model of the concern area was established by interpreting the available seismic data as both reservoirs implicated by two fault trends: NW-SE and ENE-WSW. By the end a 3D geological model was defined based on the results of the conventional interpretation of the seismic and seismic attributes to reflect all structural and stratigraphic elements of the two reservoir units.

The assessment of reservoir potential of Permian to Eocene reservoirs of Minwal-Joyamair fields, upper Indus basin, Pakistan

Upper Indus Basin has been a valuable asset as the complexity of structure and hydrocarbon production is the leading producer of oil and gas in history and still to date. Potwar sub-basin has significance in the light of oil production from carbonate reservoirs or Permian to Eocene age reservoirs. Minwal-Joyamair field is very significant and has unique hydrocarbon production history with complexity in structure style and stratigraphy. The complexity is present for carbonate reservoirs of the study area due to heterogeneity of lithological and facies variation. In this research, the emphasis is on integrated advanced seismic and well data for Eocene (Chorgali, Sakesar), Paleocene (Lockhart), and Permian age (Tobra) formations reservoirs. This research's primary focus is to analyze field potential and reservoir characterization by conventional seismic interpretation and petrophysical analysis. Minwal-Joyamair field is a combination of thrust and back thrust, forming a triangle zone in the subsurface. The petrophysical analysis results suggested favorable hydrocarbon saturation in Tobra (74%) and Lockhart (25%) reservoirs in addition to the lower volume of shale (28% and 10%, receptively) and higher effective values (6% and 3%, respectively). The main objective of the study is the re-assessment of a hydrocarbon producing field and describe the future prospectively of the field. The analysis also includes the difference in hydrocarbon production from two different type of reservoir (carbonate & clastic). The findings of this research will be useful for any other similar basins around the world.

Deep learning-based attenuation for shear-wave leakage from ocean-bottom node data

The high-amplitude shear wave in the z-component of ocean-bottom node (OBN) data challenges conventional seismic data imaging and interpretation. The process of shear-wave attenuation from the z-component data can be regarded as a coherent noise reduction problem. However, conventional noise attenuation methods, such as filtering or matching and subtraction, are time-consuming or have limited accuracy for field data processing. Unlike conventional methods with indirect feature recognition, pretrained neural networks provide end-to-end denoising frameworks by directly predicting and subtracting the shear-wave-free data from the original z-component data. Here, we have developed a deep learning-based method to address the shear-wave leakage problem and adopted a training set generation strategy based on the field data. Denoised z-component data are not needed to train the network. The generation of the training set and the extraction of noise features are based on the data of the x- and p-components. A residual learning strategy is introduced to extract the noise from the field data other than those in the training set. Synthetic examples confirm the excellent performance of our training set generation strategy. Field 4C OBN examples show that our method can attenuate shear-wave noise without harming the signals and, therefore, can be integrated into multicomponent field data processing.

3D Seismic to absolute acoustic impedance inversion of the Lower Devonian Tadrart Sandstone in Ghadames Basin, NW Libya

The aim of this study is to map 3D acoustic impedance from 3D post-stacked seismic data, and then predict 3D porosity values from the acoustic impedance results for the Lower Devonian Tadrart reservoir sandstone using seismic inversion. Theoretically, seismic inversion is the process of transforming seismic reflection data into qualitative rock properties such as acoustic impedance and porosity, which is also very important for reservoir evaluation. Seismic inversion can be performed on pre or post stacked seismic data, it can be applied when the conventional seismic interpretation may become misleading under certain conditions. Most of oil and gas companies use the seismic inversion to improve the seismic interpretation by removing the side lobes and tuning effects from seismic data, to improve the estimation of rock properties, and to increase resolution and reliability. Inversion of seismic reflection data for various lithological and petro physical attributes is broadly used for reservoir characterization and hydrocarbons detection. Rock property related attributes are easier to interpret than the seismic reflectivity, which is related to boundaries between zones of contrasting acoustic impedance properties. Broadly, the commonalities between all impedance type properties are in their relations to the values measured from the seismic traces. The fundamental problem is the lack of low-frequency information in the seismic data leading to many uncertainties in the solution. The absolute acoustic impedance inversion is the method that has been applied in this study, and it is applied in Hamra field, northwest Ghadames basin, the approach of this work by extrapolating the well logs information into the seismic properties, this is, in turn, better estimations of reservoir properties such as porosity and an additional benefit that the interpretation efficiency is greatly improved.

Deterministic and Stochastic Seismic Inversion techniques towards a better prediction for the reservoir distribution in NEAG-2 Field, north Western Desert, Egypt

NEAG 2 field is one of the key economic oil fields in the company that was contributing to 35% of total liquid production in 2016. Despite that, the full field potentiality is still not estimated precisely. The field lies within the Northeast part of Abu El-Gharadig (NEAG Extension concession). Albian-Cenomanian Kharita-Bahariya is the targeted reservoir section. The reservoir distribution trends are not clear and cannot be predicted easily. Thus, the main uncertainty is to trace the reservoir extension. Since inversions of seismic into absolute impedance rely on well data for their parameterization, they are typically conducted in brownfields like NEAG 2. In addition, the reservoir quality and thickness in NEAG 2 encouraged the application of the seismic inversion approach, to gain a large-scale insight into the reservoir distribution qualitatively and quantitatively, if possible. Also, to mitigate the reservoir trends uncertainty, and assess its spatial continuity in the uncalibrated areas. There were some concerns about the seismic quality, although, several trials were implemented to get the best results and overcome the seismic vagueness. The post-stack seismic inversion workflow was applied in Hampson-Russel Software Suite. A Deterministic approach was followed by a Stochastic approach in an adopted workflow. The workflow was accomplished by generating several Stochastic Impedance realizations. To cover the uncertainty range, P10, P50 and, P90 realizations were generated and analyzed. Additionally, a connectivity analysis was done, to compute the probability of communication between the wells. The inverted volume helped to distinguish between different reservoir bodies' geometries and dimensions, which cannot be revealed from the conventional seismic interpretation. The reservoir bodies were resolved and quantified as channels and bars. Followed by the Stochastic workflow which produced multiple realizations, allowing the seismic uncertainty to be assessed. This research work will be the first of its kind for the Kharita-Bahariya section in NE Abu-Gharadig Basin.

Artifact Suppression for the Joint Imaging of Primaries and Internal Multiples

Internal multiples bring great challenges for conventional seismic data imaging and interpretation, in which primaries only are regarded as signals. It is of great importance to suppress the internal multiples before conventional imaging, which is computationally expensive. Considering that internal multiples are also real reflections from the underground interfaces and reverse time migration (RTM) can realize the imaging of multiples. Instead of suppression before imaging, we propose to do the joint imaging of primaries and internal multiples based on RTM. However, the artifacts caused by the internal multiples should be suppressed to guarantee the precision. First, the imaging condition based on up-going and down-going extrapolated wavefield separation is introduced to improve the imaging accuracy. Then, the generation mechanism of image artifacts is analyzed, it concludes that nonphysical wave paths caused by the missing boundary wavefields under the surface result in the infidelity reversed-time backward-extrapolation, which is the main reason for the artifacts. Next, we propose to apply the modeling boundary wavefields with a match based on pseudomultichannel matching filter to compensate the missing boundary wavefields, which can avoid the image artifacts and realize high-precision joint imaging. Finally, the feasibility and effectiveness of the proposed method are verified by numerical examples and field data.

Cretaceous\u2013Quaternary seismic stratigraphy of the Tanga offshore Basin in Tanzania and its petroleum potential

In this study, the available 2D seismic lines have been interpreted to understand the basin development and petroleum potential of the Late Cretaceous–Quaternary stratigraphy of the Tanga offshore Basin in Tanzania. Conventional seismic interpretation has delineated eight sedimentary fill geometries, fault properties, stratal termination patterns and unconformities characterizing the studied stratigraphy. The Late Cretaceous was found to be characterized by tectonic quiescence and uniform subsidence where slope induced gravity flows that resulted during the Miocene block movements was the major mechanism of sediment supply into the basin. The Quaternary was dominated by extensional regime that created deep N-S to NNE-SSW trending graben. The graben accommodated thick Pleistocene and Holocene successions deposited when the rate of tectonic uplift surpasses the rate of sea level rise. Thus, the deposition of lowstand system tracts characterized by debris flow deposits, slope fan turbidites, channel fill turbidites and overbank wedge deposits, known for their excellent petroleum reservoir qualities, especially where charged by Karoo Black Shales. Subsequent tectonic quiescence and transgression lead to the emplacement of deep marine deposits with characteristic seismic reflection patterns that indicate the occurrence of Quaternary shale sealing rocks in the study area. The occurrence of all the necessary petroleum play systems confirms the hydrocarbon generation, accumulations and preservation potential in the Tanga Basin.

High-resolution seismic processing technique with broadband, wide-azimuth, and high-density seismic data — A case study of thin-sand reservoirs in eastern China

Seismic processing and interpretation techniques provide important tools for oil and gas exploration in the Songliao Basin in eastern China, which is dominated by terrestrial facies. In the Songliao Basin, a large number of thin-sand reservoirs are widely distributed and they are the primary targets of potential oil and gas exploration and exploitation. An important part of exploration in the Songliao Basin is to accurately describe the distribution of these thin-sand belts and the sand-body shapes. However, the thickness of these thin-sand reservoirs is generally below the resolution of conventional seismic processing. Most reservoirs are thin interbeds of sand and mudstones with strong vertical and lateral variations. This makes it difficult to accurately predict the vertical and horizontal distribution of the thin-sand bodies using conventional seismic processing and interpretation methods. In addition, these lithologic traps are difficult to identify due to the complex controlling factors and distribution characteristics and the strong concealment. These challenges motivate us to improve the seismic data quality to help delineate thin-sand reservoirs. We have used the broadband, wide-azimuth, and high-density integrated seismic exploration technique to help delineate thin reservoirs. We first use field single-point excitation and single-point receiver acquisition to obtain seismic data with wide frequency bands, wide azimuth angles, and high folds, which contain rich geologic information. Next, we perform near-surface Q compensation, viscoelastic prestack time migration, seismic attributes, and seismic waveform indication inversion on the newly acquired seismic data. The 3D case study indicates the benefits of improving the imaging of thin-sand body and the accuracy of inversion and reservoir characterization using our method.

Which seismic attributes are best for subtle fault detection?

Subtle fault detection plays a vital role in reservoir development studies because faults may form baffles or conduits that significantly control how a petroleum reservoir is swept. Small-throw faults are often overlooked in interpreting seismic amplitude data. However, seismic attributes can aid in mapping small faults. Over the years, dozens of seismic attributes have been developed that offer additional features for interpreters with associated caveats. Using the Maui 3D seismic data acquired in the Offshore Taranaki Basin, New Zealand, we have generated seismic attributes that are typically useful for fault detection. We find that multiattribute analysis provides greater geologic information than would be obtained by the analysis of individual attribute volumes. We extract the geologic content of multiple attributes in two ways: interactive corendering of different seismic attributes and the unsupervised machine learning algorithm self-organizing maps (SOM). Corendering seismic attributes that are mathematically independent but geologically interrelated provides a well-integrated structural image. We suggest eight combinations of 16 various attributes useful for a human interpreter with interest in fault and fracture detection. Current interpretation display capabilities constrain corendering to only four attribute volumes. Therefore, we use principal component analysis and SOM techniques to efficiently integrate the geologic information contained within many attributes. This approach gathers the data into one classification volume based on the interrelationships between seismic attributes. We show that our resulting SOM classification volume better highlights small faults that are difficult to image using conventional seismic interpretation techniques. We find that SOM works best when a fault exhibits anomalous features for multiple attributes within the same voxel. However, human interpreters are more adept at recognizing spatial patterns within various attributes and can place them in an appropriate geologic context.

Applying seismic attributes on finding the petroleum potential of stratigraphic traps in upper oligocene “C”, blocks 09-1,09-2/09, center of Cuu Long Basin

The article focuses on applying conventional seismic structural interpretation and seismic attributes in conjunction with supportive surrounding well logs to qualitatively find out any indication of sand stratigraphically trapped in Oligocene “C” sediment, the center part of Cuu Long basin where the studied area, a mono-cline structure, has been considered as one of the main depo-center which has a dominant potential of source rocks rather than reservoirs. The conventional attributes show an elongate abnormal zone developing North-South in the studied area. Detailed interpretation and surface attributes application at reservoir scale showing a clearer image of the sand and shale distribution qualitatively, two main sand bodies have been captured from the impedance surface attributes and shale distributions are also roughly generated. Within this paper, the authors only expect to predict the distribution of the sand bodies in Oligocene “C” sediment that could open new opportunities of attracting more exploration effort on stratigraphic traps then discoveries in exist in the slope of Oligocene “C” sequences at the blocks 09-1,09-2/09 center part of Cuu Long basin. Despite recent years, more hydrocarbon accumulations have increasingly been discovered in the target, but to reveal the full potential of stratigraphic traps, further studies need to be carried out to quantitatively evaluate the oil and gas potential of these stratigraphic/ combination traps. However, many uncertainties related to the petroleum system need to be analyzed to minimize the risk before turned into other further costly exploration activities. And at least the study could narrow down the studied area and attract more attention to exploration efforts in the future. Further quantitative interpretation efforts on the hydrocarbon detection, sealing capacity of these traps need to be invested in order to increase the success probability of the targets for the proper exploration and/or appraisal plan of stratigraphic traps in the future.

Controls on Reservoir Heterogeneity of a Shallow-Marine Reservoir in Sawan Gas Field, SE Pakistan: Implications for Reservoir Quality Prediction Using Acoustic Impedance Inversion

The precise characterization of reservoir parameters is vital for future development and prospect evaluation of oil and gas fields. C-sand and B-sand intervals of the Lower Goru Formation (LGF) within the Lower Indus Basin (LIB) are proven reservoirs. Conventional seismic amplitude interpretation fails to delineate the heterogeneity of the sand-shale facies distribution due to limited seismic resolution in the Sawan gas field (SGF). The high heterogeneity and low resolution make it challenging to characterize the reservoir thickness, reservoir porosity, and the factors controlling the heterogeneity. Constrained sparse spike inversion (CSSI) is employed using 3D seismic and well log data to characterize and discriminate the lithofacies, impedance, porosity, and thickness (sand-ratio) of the C- and B-sand intervals of the LGF. The achieved results disclose that the CSSI delineated the extent of lithofacies, heterogeneity, and precise characterization of reservoir parameters within the zone of interest (ZOI). The sand facies of C- and B-sand intervals are characterized by low acoustic impedance (AI) values (8 × 106 kg/m2s to 1 × 107 kg/m2s), maximum sand-ratio (0.6 to 0.9), and maximum porosity (10% to 24%). The primary reservoir (C-sand) has an excellent ability to produce the maximum yield of gas due to low AI (8 × 106 kg/m2s), maximum reservoir thickness (0.9), and porosity (24%). However, the secondary reservoir (B-sand) also has a good capacity for gas production due to low AI (1 × 107 kg/m2s), decent sand-ratio (0.6), and average porosity (14%), if properly evaluated. The time-slices of porosity and sand-ratio maps have revealed the location of low-impedance, maximum porosity, and maximum sand-ratio that can be exploited for future drillings. Rock physics analysis using AI through inverse and direct relationships successfully discriminated against the heterogeneity between the sand facies and shale facies. In the corollary, we proposed that pre-conditioning through comprehensive petrophysical, inversion, and rock physics analysis are imperative tools to calibrate the factors controlling the reservoir heterogeneity and for better reservoir quality measurement in the fluvial shallow-marine deltaic basins.

Seismic impedance inversion and attribute analysis for reservoir characterization in an offshore depobelt, Niger Delta, Nigeria

The task of minimizing pitfall in quantitative reservoir assessment and evaluation is an integral aspect of any promising petroleum exploration and evaluation project. The Niger Delta oil province in Nigeria is chiefly composed of several pay zones with many stratigraphic intervals of sand and shale formations in varying proportion. Whereas conventional seismic interpretation technique poses certain degree of uncertainty in reservoir characterization, seismic inversion constraint by log data brings significant improvement in interpretation that reduces uncertainty in the delineation of reservoir characteristics, volume and distribution. In this present study, post-stack seismic inversion and seismic attributes analysis were used to evaluate the potentials and prospects of mapped reservoirs in a field, offshore depobelt, Niger Delta. The implementation of the tasks consists of mapping of structural framework, horizon picking, log editing and correlation, wavelet extraction, building of low-frequency model, acoustic impedance inversion and crossplot analysis of reservoir properties and attributes. A hybrid approach (formulated using Greenberg-Castagna equation) specific for the Niger Delta depobelts was used to estimate and generate shear wave velocity for the wells. Results obtained from inversion depict an acoustic impedance values in the range 150–280 ft/s g/cc and $$V_{\text{P}}/V_{\text{S}}$$ of 1.25–2.50 at a depth range of 9250–9280 ft within the hydrocarbon-bearing sands in the two wells. Region of low acoustic impedance (representing high reservoir porosity) coupled with a corresponding low $$V_{\text{P}}/V_{\text{S}}$$ ratio (indicating hydrocarbon accumulation) is presumed to have high prospects for exploration and well development. Altogether the degree of correlation between the inverted and actual impedance was found to be about 90% across the wells. It is evident that the acoustic impedance slice at 3000 ms depicts low acoustic impedance sand within 18,500–20,000 ft/s g/cc at the northeastern and southeastern regions of the field. High reflection amplitudes (bright spots) signifying hydrocarbon accumulation are also revealed on seismic attribute maps with surrounding shale diaper as the source rock. This study has revealed the prospect (i.e., existence of active petroleum system of probable economic value) of the delineated field in the Niger Delta depobelt.

An integrated petrophysical-based wedge modeling and thin bed AVO analysis for improved reservoir characterization of Zhujiang Formation, Huizhou sub-basin, China: A case study

AbstractThe main reservoir in Huizhou sub-basin is Zhujiang Formation of early Miocene age. The petrophysical analysis shows that the Zhujiang Formation contains thin carbonate intervals, which have good hydrocarbon potential. However, the accurate interpretation of thin carbonate intervals is always challenging as conventional seismic interpretation techniques do not provide much success in such cases. In this study, well logs, three-layer forward amplitude versus offset (AVO) model and the wedge model are integrated to analyze the effect of tuning thickness on AVO responses. It is observed that zones having a thickness greater than or equal to 15 m can be delineated with seismic data having a dominant frequency of more than 45 Hz. The results are also successfully verified by analyzing AVO attributes, i.e., intercept and gradient. The study will be helpful to enhance the characterization of thin reservoir intervals and minimize the risk of exploration in the Huizhou sub-basin, China.

Application of seismic attribute analysis in fluvial seismic geomorphology

Seismic attributes can be important predictors, either qualitative or quantitative, of reservoir geometries when they are correctly used in reservoir characterization studies. This paper discusses seismic attribute analyses and their usefulness in seismic geomorphology study of Moragot field of Pattani Basin, Gulf of Thailand. Early to Middle Miocene fluvial channel and overbank sands are the reservoirs in Pattani Basin. Due to their limited horizontal and vertical distribution, it is not always possible to predict the geometry and distribution of these sands based on the conventional seismic interpretation. This study utilized various seismic attributes, e.g., RMS amplitude analysis, spectral decomposition, semblance and dip-steered similarity, RGB blending to image the geometry and the spatial distribution of sand bodies in horizon and stratal slices at different stratigraphic intervals. Attribute analyses reveal, at shallow stratigraphic levels, RMS and semblance can successfully identify channel-shaped sand bodies and mud-filled channels associated with channel belts. On the other hand in deeper stratigraphic intervals, sand distribution can be imaged more effectively by using spectral decomposition and dip-steered similarity volumes. High-frequency spectral decomposition slices can image thin sands, and low-frequency slices can image thick sands quite effectively in deeper intervals. RGB blending of different frequency slices is particularly useful in delineating channel systems of various dimensions at deeper intervals. These images show the distribution of sands and mud-filled channels at various stratigraphic levels. The width of channel belts varies from 200 m to 3 km. These channel belts are N–S or NW–SE oriented. From the channel pattern and their dimensions, depositional environments can be predicted. Mud-filled channels identified in the horizon slices will act as a connectivity barrier between sand bodies at either side of the channel. They can also act as lateral and up-dip seal to form stratigraphic traps. The seismic attribute analyses clearly show the geometry and spatial distribution of sand bodies. Hence, this method for predicting sand body geometry might help in field development planning as well as in reducing exploration risk.

Classification of reservoir facies using well log and 3D seismic attributes for prospect evaluation and field development: A case study of Sawan gas field, Pakistan

The Sawan Gas Field is one of the most promising gas fields of Middle Indus Basin in Pakistan with a cumulative production of 850 BCF. In the reservoir interval, the thin shale sequence is interbedded and dispersed resulting in extreme heterogeneity. Consequently, conventional seismic amplitude interpretation fails to delineate the sand-shale facies distribution. In this case study, the depositional facies of the reservoir C-sand interval with the integration of electrofacies analyses, historical production data, and seismic attribute analyses using 3D seismic and well log data were analyzed for prospect evaluation and field development plan to achieving maximized production. The electrofacies analyses show that the reservoir C-sand interval falls in funnel-shaped, bell-shaped, and cylindrical-shaped trends. The obtained results suggest deposition of C-sand in proximal delta front to pro-delta settings with medium to fine grain pore size distribution. Conversely fine grained lime mud, silt, and shale with poor-sorting fall in the irregular-shaped trend which suggests deposition in pro-delta settings. C-sand interval was evaluated using multiple seismic attributes including relative acoustic impedance, root mean square amplitude, envelope, sweetness, instantaneous frequency, structural smoothing, and phase shift. The results of all the seismic attributes demarcate the transitional boundary between the delta front sand facies and pro-delta sandy-shale facies. The calibration of electrofacies analysis with 3D seismic attributes indicates an appropriate agreement between them. This study effectively predicted the spatial distribution of sweet spots in the heterogeneous reservoir using 3D seismic attributes analysis, which can provide valuable guidance for the development of the area.

Structural subsurface model of Samawa-Diwan area (south of Iraq)

Seismic instantaneous phase attribute was applied for conventional seismic interpretation (structural interpretation) on 3D seismic cube of 1914.72km² of Samawa-Diwan area, located in the south part of Iraq within Muthna governorate. Instantaneous phase section is very important to detect structural and stratigraphic features. Six reflectors represent Upper Jurassic and Cretaceous formations were defined from synthetic seismogram of wells in study area, then picked over seismic cube. Fault boundaries maps for each horizon were drawn depending on horizon contacts then fault planes were constructed. Finally, a 3D structural model was constructed in time domain, then converted to depth domain by using 3D average velocity model. Structurally, 3D models showed that study area affected by two types of normal faults formed a graben appear at west side a long study area, and separated by transverse fault to the north and south parts at Hartha Fn. and deep layers, while Tertiary formations have not affected by any type of faults systems. Also, structural map showed existence of four structural domes which they are Samawa and Diwan folded domes, Samawa south faulted dome and fourth one is new folded dome locates in the northwest of study area. All these features extend in northwest-southeast trend .