3D Seismic Volume Research Articles

Transformation of sediment delivery and dispersal patterns controlled by relay-ramp evolution along the boundary fault of a lacustrine rift: The Eocene Shahejie formation, Dongying Sag, Bohai Bay Basin, NE China

The boundary fault of the Dongying Sag is divided into isolated and scattered segments and small-scale relay zones, which are important geomorphic features controlling sedimentation in the early stage of rift evolution. Previous studies have shown changes in facies in deposits of thousands of meters in thickness on fault-bounded margins, where deep-water fan systems are vertically stacked with delta deposits in the same way as in many basins around the world. However, changes in sedimentation processes and sedimentary systems and their relationship with the evolution of the main boundary fault remain a matter of debate. We focus on the transition from shallow-water to deep-water systems and their responses to relay-ramp evolution in the Yanjia Subsag of the Eocene Dongying Sag in the Bohai Basin. A relatively simple assemblage of local structures provides an ideal opportunity to investigate the impact of relay-ramp evolution on the early synrift deposits. An integrated dataset of 3D seismic volumes, cores and wireline logs is used to analyze the evolution of the Chennan Fault, to delineate thirteen lithofacies, and to recognize two depositional styles (including fan deltas and nearshore subaqueous fans) and their distribution during different stages of the relay-zone evolution. In the early stage of rifting, the depositional style changes, from the development of axial and transverse systems in the early to middle period to the development of transverse systems in the late period; this is mainly controlled by the evolution of the relay ramp. The change is accompanied by a rapid decrease in the rate of sediment supply, architectural changes in transport conduit from the relay ramp to a canyon, and local geomorphic changes that control transport routes, sediment delivery, and depositional locations. Floods ultimately become dominant transport mechanism with a new system, such that hyperpycnal flows form, leading to another transformation of the sedimentary systems from a fan-delta system to a nearshore subaqueous fan system. On the basis of these transformations in sedimentary systems we are able to propose new recommendations for reservoir exploration in continental rift basins, which include exploration potential, source reservoir cap assemblage, and spatiotemporal evolution of plays.

S-wave experiments for the exploration of a deep geothermal carbonate reservoir in the German Molasse Basin

There are many successful geothermal projects that exploit the Upper Jurassic aquifer at 2–3 km depth in the German Molasse Basin. However, up to now, only P-wave seismic exploration has been carried out. In an experiment in the Greater Munich area, we recorded S-waves that were generated by the conventional P-wave seismic survey, using 3C receivers. From this, we built a 3D volume of P- to S-converted (PS) waves using the asymptotic conversion point approach. By combining the P-volume and the resulting PS-seismic volume, we were able to derive the spatial distribution of the vp/vs ratio of both the Molasse overburden and the Upper Jurassic reservoir. We found that the vp/vs ratios for the Molasse units range from 2.0 to 2.3 with a median of 2.15, which is much higher than previously assumed. This raises the depth of hypocenters of induced earthquakes in surrounding geothermal wells. The vp/vs ratios found in the Upper Jurassic vary laterally between 1.5 and 2.2. Since no boreholes are available for verification, we test our results against an independently derived facies classification of the conventional 3D seismic volume and found it correlates well. Furthermore, we see that low vp/vs ratios correlate with high vp and vs velocities. We interpret the latter as dolomitized rocks, which are connected with enhanced permeability in the reservoir. We conclude that 3C registration of conventional P-wave surveys is worthwhile.

Applications of Artificial Neural Networks for Seismic Facies Classification

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200577, “Applications of Artificial Neural Networks for Seismic Facies Classification: A Case Study From the Mid-Cretaceous Reservoir in a Supergiant Oil Field,” by Ali Al-Ali, Karl Stephen, SPE, and Asghar Shams, Heriot-Watt University, prepared for the 2020 SPE Europec featured at the 82nd EAGE Conference and Exhibition, originally scheduled to be held in Amsterdam, 1-3 December. The paper has not been peer reviewed. Facies classification using data from sources such as wells and outcrops cannot capture all reservoir characterization in the interwell region. Therefore, as an alternative approach, seismic facies classification schemes are applied to reduce the uncertainties in the reservoir model. In this study, a machine-learning neural network was introduced to predict the lithology required for building a full-field Earth model for carbonate reservoirs in southern Iraq. The work and the methodology provide a significant improvement in facies classification and reveal the capability of a probabilistic neural network technique. Introduction The use of machine learning in seismic facies classification has increased gradually during the past decade in the interpretation of 3D and 4D seismic volumes and reservoir characterization work flows. The complete paper provides a literature review regarding this topic. Previously, seismic reservoir characterization has revealed the heterogeneity of the Mishrif reservoir and its distribution in terms of the pore system and the structural model. However, the main objective of this work is to classify and predict the heterogeneous facies of the carbonate Mishrif reservoir in a giant oil field using a multilayer feed-forward network (MLFN) and a probabilistic neural network (PNN) in nonlinear facies classification techniques. A related objective was to find any domain-specific causal relationships among input and output variables. These two methods have been applied to classify and predict the presence of different facies in Mishrif reservoir rock types. Case Study Reservoir and Data Set Description. The West Qurna field is a giant, multibillion-barrel oil field in the southern Mesopotamian Basin with multiple carbonate and clastic reservoirs. The overall structure of the field is a north/south trending anticline steep on the western flank and gentle on the eastern flank. Many producing reservoirs developed in this oil field; however, the Mid- Cretaceous Mishrif reservoir is the main producing reservoir. The reservoir consists of thick carbonate strata (roughly 250 m) deposited on a shallow water platform adjacent to more-distal, deeper-water nonreservoir carbonate facies developing into three stratigraphic sequence units in the second order. Mishrif facies are characterized by a porosity greater than 20% and large permeability contrast from grainstones to microporosity (10-1000 md). The first full-field 3D seismic data set was achieved over 500 km2 during 2012 and 2013 in order to plan the development of all field reservoirs. A de-tailed description of the reservoir has been determined from well logs and core and seismic data. This study is mainly based on facies log (22 wells) and high-resolution 3D seismic volume to generate seismic attributes as the input data for the training of the neural network model. The model is used to evaluate lithofacies in wells without core data but with appropriate facies logs. Also, testing was carried out in parallel with the core data to verify the results of facies classification.

Seismic-based characterization of reservoir heterogeneity within the Meramec interval of the STACK play, Central Oklahoma

The Meramec interval within the Sooner Trend Anadarko Canadian Kingfisher (“STACK”) play of the Anadarko Basin in central Oklahoma has recently been at the epicenter of increased exploration and production of oil and gas. It has become one of the top target intervals of the “mid-continent” aided by technological advancements in horizontal drilling and completion techniques. The Meramec interval, mainly composed of argillaceous siliciclastic sediments with varying amounts of carbonate cement, exhibits high porosity heterogeneity, which is theorized to be caused by varying amounts of clay and postdepositional calcite cement. Characterization of the porosity heterogeneity in the Meramec interval will improve our understanding of the wide range in Meramec oil and gas production volumes and reduce the risk associated with drilling and completion techniques. We completed an initial interpretation followed by inversion of 3D seismic data in which we generated a detailed characterization of the porosity heterogeneity and overall reservoir quality within the Meramec interval over an area of approximately 150 square kilometers. We then used the 3D seismic volume and available well logs to map the vertical and lateral extents of the Meramec interval and identify possible structural elements that could affect the reservoir quality. A petrophysical analysis of the well logs confirmed porosity heterogeneity and variations in volumetric calculations of clay and carbonate minerals. Finally, we generated a set of porosity volumes using the acoustic impedance from seismic inversion and probabilistic neural network methods. The derived porosity volume helped us identify porous and nonporous intervals within the Meramec throughout the study area. The results improved our understanding of Meramec heterogeneity, further reducing the risk associated with well planning, drilling, and completion.

Estimation and uncertainty analysis of the [formula omitted] storage volume in the sleipner field via 4D reversible-jump markov-chain Monte Carlo

Many scientists have developed technology to store CO2 in the subsurface and to monitor the storage conditions to comply with the requirements for zero detectable leakage and greenhouse gas control. The goal of this research is to propose a novel workflow to estimate the stored CO2 volume and to quantify the uncertainty of the injected volume. We implemented geophysical stochastic inversion using the time-lapse 3D seismic volumes as inputs, which provides an indirect estimation of the velocity changes and the migration path of the injected gas content. When performing the inversion, we employed the reversible-jump approach and used the Sleipner time-lapse 3D seismic volumes to demonstrate the proposed workflow. The inversion result was validated via forward modeling and pseudo well log interpretation. We then built a structural geology model and populated porosity logs by performing 500 realizations for volumetric analysis. In a comparison of the measured volume of the injected gas via volumetric analysis results, the predicted subsurface CO2 volume linearly increases in the same phase with the injection rate, and the volume estimation error is less than 17%.

Fast iterative adaptive approach for 3D seismic data reconstruction

ABSTRACT In this paper, we introduce a fast iterative adaptive approach for the reconstruction of 3D seismic data with randomly missing traces. Our method starts by transforming 3D seismic volume to 2D harmonic signal for each frequency slice, and then the power spectrum of the frequency slice is iteratively estimated by a weighted least square fitting criterion. The missing data can be recovered with the obtained spectral estimate using a linear minimum mean-squared error estimator. However, estimation of the power spectrum depends on matrix-vector multiplications for each iteration that leads to high computation complexity when the data are large scale and high dimension. To solve the associated spectrum estimation problem above, a fast iterative adaptive scheme is adopted by utilising 2D fast discrete Fourier transform, which makes use of the block-Vandermonde structure and the 2D Fourier property of the steering matrix. Simulation experiments on synthetic and field data verify the effectiveness of the proposed algorithm. Compared with other reconstruction methods based on frequency slice, such as minimum-weighted norm interpolation approach, multi-channel singular spectrum analysis, and Curvelet transform method, the proposed method achieves better reconstruction performance and low computational complexity.

Delineation of coaly source rock distribution and prediction of organic richness from integrated analysis of seismic and well data

Coaly facies (coals, shaly coals and coaly mudstones) are the primary source rock in several important petroleum basins in SE Asia and Australasia. Delineating these facies and quantifying their organic richness within kitchen areas are some of the key risks for petroleum exploration. To improve their delineation and characterisation using seismic data, a case study was undertaken of the coal-bearing Paleocene and Eocene intervals within the Maari 3D seismic volume area, offshore southern Taranaki Basin, New Zealand. Supporting data were acquired from well logs (including borehole image logs), existing geochemical analyses of well cuttings, and new laboratory measurements of in-situ geophysical and geochemical properties of coal samples from onshore coal mines and other outcrops. In the Paleocene–Eocene interval in the Maari 3D, coaly facies display characteristic low density (<2.5 g/cc) and velocity (<4000 m/s) and appear as bright, resistive layers in image logs. To delineate these facies in the Maari 3D volume, a post-stack seismic inversion was carried out and a P-impedance (product of density and P-wave velocity) model was prepared. Coaly facies exhibit moderate–high amplitude and moderately continuous (up to ~5 km) seismic reflectors, with low P-impedance (<9000 m/s × g/cc) character. Interval P-impedance and amplitude maps reveal temporal variation in the distribution and abundance of coaly facies within the Paleocene–Eocene coastal plain depositional environment. A logarithmic relationship between P-impedance and TOC was used to convert average P-impedance maps to proxy TOC maps for five Paleocene–Eocene time intervals. Coaly facies are most abundant in the low P-impedance areas in the southwestern and central parts of the study area where average TOC is estimated up to 30 wt.%. P-impedance-derived estimates of TOC may be less reliable in structurally high areas hosting hydrocarbon-bearing sandstones and siltstones as some of these facies show similar P-impedance character to coaly facies.

Fluid substitution modelling and derived rock attribute-based discriminations of hydrocarbon and lithology: a case study of arcuate Niger Delta Depobelt, Nigeria

Fluid substitution modelling was carried out to discriminate the formation fluids in X-field. The study employed 3D seismic volume and well logs from two exploratory wells. Two reservoir sands, labelled HD3000 and HD5000, were delineated based on the well signatures of gamma ray and resistivity logs. These reservoir zones are thicker in well X2 than in well X1. Saturations of fluid in the delineated reservoirs were varied using 50% for brine, gas and oil scenarios. The main goal of the study is to distinguish the formation fluid present in the reservoirs based on the crossplot of the fluid replacement modelling scenarios. The crossplot of P-impedance versus S-impedance attributes revealed separation in clusters representing the scenarios for the different fluid saturations in the reservoirs. A clear distinction was deciphered between fluid and lithology in the field based on the clusters of crossplots. The synthetic result revealed positive increase in amplitude at the reservoir tops for brine saturation, while positive decrease in amplitude were depicted in the case of oil and gas saturations. P-wave decreased more with 50% brine saturation when compared to the decrease with 50% gas/oil saturation scenarios. The inverted P-impedance amplitude slice reveals four (4) zones labelled H1, H2 H3 and H4 suspected to be saturated with probable hydrocarbon accumulation based on the low impedance observed around the inferred zones.

DELINEATION OF HYDROCARBON SATURATED RESERVOIR SAND USING INTEGRATED 3D PRE-STACK SEISMIC AND WELL LOG DATA IN BONGA – FIELD, CENTRAL SWAMP DEPOBELT, ONSHORE NIGER DELTA, NIGERIA

This study has successfully delineated the lateral continuity of hydrocarbon saturated sand reservoir in Bonga field, Niger Delta. 3D pre-stack seismic volume and well logs from two (2) exploratory wells were employed in the pre-stack seismic inversion analysis. The delineated BGA reservoir sand spans across the two (2) wells labelled Bonga-26 and Bonga-30. The reservoir depth ranges from 10490 ft to 10620 ft in Bonga-26 while the reservoir depth ranges from 10390 ft to 10490 ft in Bonga-30. The delineated reservoir is characterized by low gamma ray (&lt; 75 API), water saturation, shale volume and high resistivity as deciphered in their respective well log curves signature. Rock attribute crossplot was carried out to discriminate between the formation fluid and lithology. The crossplot space of VP-VS ratio versus acoustic impedance (AI), discriminates the formation properties into lithology and fluid (gas and brine sand) based on clusters inferring the presence of each formation fluid properties. The inversion cross sections of P-impedance, S-impedance, density (ρ) and VP-VS ratio depicts the spread and lateral continuity of the reservoir sand across the well locations. The delineated zones reveal low P-impedance, density, VP-VS ratio and slight increase in S-impedance which further validate the presence of hydrocarbon in the field.

The sedimentary architecture of hyperpycnites produced by transient turbulent flows in a shallow lacustrine environment

Hyperpycnal flows are river-derived extrabasinal turbidity currents transporting both sand and clay to lacustrine, coastal, shelf and deepwater sedimentary environments. Experimental research in the past twenty years has shown that the presence of clay in sediment-laden flows promotes a transitional behavior between fully turbulent flow and a quasi-laminar plug flow regime. However, to date, most work concerning the fluid dynamic interpretation of lacustrine hyperpycnal flows has been founded on concepts based on fully turbulent flows, and relatively little is known about the influence of clay on the rheological and turbulence characteristics of these flows. With the help of 3D seismic volume and wire-line logging data, the present study undertakes a description and interpretation of subsurface mixed sandstone–mudstone bedforms observed in cores from the Upper Cretaceous Heidimiao Sandstone, Nenjiang Formation, Songliao Basin, NE China. Six lithofacies and five lithofacies associations are recognized from the cores and interpreted as formed under both turbulent and transitional flows. Typical bedforms of transitional flows include large current ripples and low-amplitude bedwaves. The delta-fed shallow lacustrine hyperpycnal flow deposits are characterized by proximal sinuous channels (extending for c. 20 km) and lobe deposits (extending for >20 km), showing a fan-like geometry associated with distributary channel extension in the down-dip direction. Basal erosion in the proximal channels is produced by the initial turbulent and turbulence-enhanced transitional flows, with channel infill dominated by upper transitional plug flows or quasi-laminar plug flows. The lobe deposits possess a fan-like geometry with large aspect ratio, and were formed from turbulence-enhanced and lower transitional plug flows. The downdip transformation of sediment-laden flows in the lacustrine basin varies from an initial turbulent flow, via quasi laminar plug flows to upper and lower transitional plug flows, to turbulence enhanced transitional flows. These transitional flows are interpreted to have experienced gradual dilution and deceleration and eventually transformed to turbulent flows in their distal regions. A new model for delta-fed shallow lacustrine hyperpycnal flow deposits is presented incorporating decelerated transitional flows and flow transformations. This new model can aid understanding of the depositional processes of lacustrine transitional flows and the facies distribution of hyperpynal flows in both modern and ancient sediments.

An integrated approach to distribute carbonate reservoir properties, using lithofacies and seismic attributes: a case study from SW of Iran

Complexity and heterogeneity of carbonate deposits make the understanding of the reservoir quality challenging. This study is a contribution to the understanding of the distribution of carbonate–evaporite reservoir property of the Permo–Triassic Kangan–Dalan succession in one of the giant gas fields in the southwest of Iran. To capture and describe the complexity and heterogeneity of the carbonate reservoir, we defined different rock properties approach to the management of quantitative data on carbonate reservoir which is based on well and seismic data with an integrated sedimentological investigation, petrophysical evaluation, and seismic analysis to determine the new reservoir lithofacies classification. A lithofacies-based reservoir characterization study was conducted carbonate reservoir to build a numerical 3-dimensional (3D) geological model including reservoir property prediction for reservoir flow simulation. To do this, full suite of logs from six wells, core from four wells in the studied interval and 3D seismic volume across the studied interval have been involved and investigated. Five lithofacies were identified from detailed analysis, and the relationship between lithofacies and reservoir property was considered and geostatistically propagated in the studied area. This study shows that an integrated study using seismic data and well logs can be used to basically divide the reservoir into relatively homogeneous zones based on core and petrophysical analysis, and then evaluate each zone to distinguish high-quality zones. This approach provides useful insight to Permo–Triassic carbonate reservoir and other similar reservoirs and can also be effectively used in areas which lack well or outcrop data.

Modelling and mapping hydrocarbon saturated sand reservoir using Poisson’s impedance (PI) inversion: a case study of Bonna field, Niger Delta swamp depobelt, Nigeria

3D seismic volume and two well logs data labelled Bonna-6 and Bonna-8 were employed in the inversion process. The data set was simultaneously inverted to produce P- and S-impedances, density, VP − VS, and PI seismic attributes. An average “c” term value of 1.37 was obtained from the inverse of the slope of the crossplot of P-impedance versus S-impedance for Bonna-6 and Bonna-8 wells. This value was employed in the inversion process to generate the PI attribute, which aided in reducing the non-uniqueness inherent in discriminating the probable reservoir sands. Five seismic attributes slices were generated to ascertain the superiority of each attribute in delineating the probable reservoir sand. These attributes were: density, S-impedance, P-impedance, VP− VS ratio and PI. These attributes reveal low value of density (1.96 − 2.14 g/cc), P-impedance (1.8 × 104 − 2.1 × 104) ft/s*g/cc, S-impedance (9.2 × 103 − 1.1 × 104) ft/s*g/cc, VP − VS (1.65 − 1.72) and PI (4.9 × 103 − 5.1 × 104) ft/s*g/cc around the area inferred to be hydrocarbon saturated reservoir. Although the attributes considered reveals the same zone suspected to be probable hydrocarbon zone, PI gives a better discrimination when compared to other attributes. A distinctive spread and demarcation of the delineated hydrocarbon sand are observed in the PI attribute slice.

A combination of genetic inversion and seismic frequency attributes to delineate reservoir targets in offshore northern Orange Basin, South Africa

Abstract The reported occurrence of Albian- and Cenomanian-aged braided fluvio-deltaic channels in the Orange Basin, South Africa, opens a window of exploration activities to characterize these channels as they are renowned to form some of the world’s giant oil field. In this study, a seismic acoustic impedance inversion and seismic attributes (instantaneous frequency and iso-frequency) analysis is used to investigate potential Albian and Cenomanian fluvio-deltaic channels in offshore, northern Orange Basin. Reservoirs were mapped using a well and 3D seismic volume (8-bit) after initial dip-steering coherency filtering had been performed on the seismic volume to remove incoherent noise and improve data resolution. Model-based acoustic impedance inversion was applied on the seismic volume to delineate fluvio-deltaic channels in addition to using the RMS (root mean square) amplitude attribute. Iso-frequency using the cosine correlative transform (CCT) method was equally applied to delineate these channels. Instantaneous frequency attribute was analyzed for potential hydrocarbon-charged sediments. This was achieved by utilizing thirty-three seismic traces as an input in the Hilbert transform window, after which trace envelope and instantaneous phase were transformed into instantaneous frequency. Acoustic impedance inversion results reveal the presence of two channels within the Cenomanian sequence, which shows high porosity (∼40%) along its geometry. The CCT method shows that the 8 Hz frequency window resolved the presence of a channel within the Albian sequence. A meandering channel within the Albian sequence was equally delineated by the RMS, while the application of instantaneous frequency (IF) attribute indicates the presence of hydrocarbon-charged sediments of Cenomanian age in proximity to a listric normal fault because of the attenuation of frequency observed close to the fault. This study demonstrates a case study of the application of seismic impedance inversion and seismic attributes for the delineation of potential reservoirs and hydrocarbon-charged sediments in a basin.

Forced folding in the Kora Volcanic Complex, New Zealand: A case study with relevance to the production of hydrocarbons and geothermal energy

The intrusion of magma into relatively shallow strata often results in structural deformation. Forced folds are typically formed above intrusions so as to accommodate the addition of new volumes of magma into the sedimentary pile. This work uses a high-resolution 3D seismic volume from the offshore Taranaki Basin, New Zealand to investigate large forced folds formed in Upper Cretaceous-Paleocene sequences due to the intrusion of magmatic dikes and sills. These magmatic intrusions are related to the plumbing system of the Kora volcano. We apply a novel filtering technique to enhance the contrast between the dip-azimuth of seismic reflectors and that of any overprinting noise, preserving the lateral continuity of seismic events. Forced folds were generated by the intrusion of flat-laying saucer-shaped sills into shallow strata. These folds (Fold A and Fold B) have a domal geometry and a structural relief of 250−350 m, for a total area of 45 km2 and 35 km2, respectively. Out of the 18 interpreted sills, two sills (S1 and S4) contributed the most to the generation of the forced folds in the study area. The sill-fold relationships observed in this work suggest that sills with greater length-to-intrusion ratios deform the strata more effectively. However, it is also clear that forced folds are, in parts of the study area, larger than the intruded sills below. This hints at the presence of a larger volume of intruded magma than that imaged on seismic data where forced folds are significantly larger than the volume of the sills below. Such a character makes the establishment of fold-sill relationships crucial to the identification of magmatic bodies below forced folds - if one identifies a large forced fold on seismic profiles, but only a few small sills are imaged, then the mass of igneous rock below the fold is potentially larger than that imaged on seismic data. More importantly, forced folding in the Taranaki Basin is shown to have led to the development of four-way closures to form prolific traps for hydrocarbon and geothermal energy resources.

Analysis of Microseismicity and Reactivated Fault Size to Assess the Potential for Felt Events by CO2 Injection in the Illinois Basin

ABSTRACTThe results of monitoring of carbon dioxide (CO2) injection at the Illinois Basin—Decatur Project (IBDP) and the companion Illinois Industrial Carbon Capture and Sequestration Sources (IL-ICCS) project—have shown that reservoir response to fluid pressure changes can vary significantly at different injection locations within the same reservoir. Predrill reservoir characterization is important to identify potentially seismogenic faults. However, interpretations of newly reprocessed 3D seismic reflection data illustrate the challenges related to their identification in a region dominated by faulting with small vertical offsets. Faults interpreted in the 3D seismic volume range from ∼300 to 1200 m wide and are in the same size range as faults that could have been the source of historical events up to Mw 2.7 in central Illinois. The array of monitoring sensors that was installed for the IBDP continues to collect data, as injection operates in IL-ICCS, the second injection well. CO2 injection rates for the IL-ICCS well are on average 1.7 times the rates injected in the IBDP well, but a significantly reduced rate of induced seismicity is observed. This article presents results of passive seismic monitoring for the duration of the project to date, integrating active and passive seismic data to develop a new interpretation of the subsurface structure at the Decatur site that explicitly identifies pathways for fluid flow into the basement leading to induced seismicity, and provides a geological explanation for the sharp reduction of induced seismicity during injection at higher rates into the second well. The use of seismic moment to estimate the length of seismogenic slip planes in the local subsurface suggests that faults large enough to produce felt seismicity are unlikely to be present at or near the Decatur site.

Hydrocarbon-bearing characteristics of the SB1 strike-slip fault zone in the north of the Shuntuo Low Uplift, Tarim Basin

The SB1 strike-slip fault zone, which developed in the north of the Shuntuo Low Uplift of the Tarim Basin, plays an essential role in reservoir formation and hydrocarbon accumulation in deep Ordovician carbonate rocks. In this research, through the analysis of high-quality 3D seismic volumes, outcrop, drilling and production data, the hydrocarbon-bearing characteristics of the SB1 fault are systematically studied. The SB1 fault developed sequentially in the Paleozoic and formed as a result of a three-fold evolution: Middle Caledonian (phase III), Late Caledonian–Early Hercynian and Middle–Late Hercynian. Multiple fault activities are beneficial to reservoir development and hydrocarbon filling. In the Middle–Lower Ordovician carbonate strata, linear shear structures without deformation segments, pull-apart structure segments and push-up structure segments alternately developed along the SB1 fault. Pull-apart structure segments are the most favourable areas for oil and gas accumulation. The tight fault core in the centre of the strike-slip fault zone is typically a low-permeability barrier, whilst the damage zones on both sides of the fault core are migration pathways and accumulation traps for hydrocarbons, leading to heterogeneity in the reservoirs controlled by the SB1 fault. This study provides a reference for hydrocarbon exploration and development of similar deep-marine carbonate reservoirs controlled by strike-slip faults in the Tarim Basin and similar ancient hydrocarbon-rich basins.

A three-dimensional (3D) structural model for an oil-producing basin of the Brazilian equatorial margin

Hydrocarbon discoveries in Equatorial Brazil, Equatorial Africa and French Guiana-Suriname-Guyana have recently confirmed their importance as new exploration frontiers. The Mundaú sub-basin, located on the Brazilian Equatorial Margin, comprises four producing fields in shallow waters: Xaréu, Atum, Espada e Curimã. In order to understand the structural and seismic-stratigraphic frameworks of an oil-producing region in Equatorial Brazil, this work addresses the 3D geometry and spatial distribution of main faults in the Curimã and Espada fields. The occurrence of hydrocarbons in the Mundaú sub-basin is compared with fields in other parts of the Brazilian Equatorial Margin and Equatorial Africa. Data from 12 wells and a 3D post-stack time-migrated multichannel seismic volume are used to define nine (9) seismic-stratigraphic units: the syn-rift Mundaú Formation (Units 1, 2, 3 and 4); the transitional Paracuru Formation (Unit 5); and the drift Ubarana (Uruburetama and Itapagé Members, Units 6 and 7), Tibau and Guamaré Formations (Units 8 and 9). The study area is dominated by NW-SE planar normal faults, basinward-dipping, that form multiple half-grabens, and tilted blocks with small anticlines and synclines genetically related to a transtensional system. Three types of plays are recognised in the Mundaú sub-basins: structural, combined (structural-stratigraphic) and stratigraphic (turbiditic). In the eastern part of the study area, where the basement is shallow, no oil was found. Conversely, oil was discovered in an anticlinal trap formed over a hanging-wall block analogous to fields on the Côte D'Ivoire-Ghana transform margin. This work shows that combined traps on footwall blocks are successful plays near the shelf break of the Mundaú sub-basin, in similarity with the Espoir and Baobab fields in Ivory Coast. Furthermore, turbiditic reservoirs in drift units are analogous to the Stabroek block in Guyana and prospects in the Gulf of Guinea. The structural and petroleum-play analyses in this work are therefore crucial to understand the multiple geological processes leading to the trapping of hydrocarbons in the larger Equatorial Atlantic Ocean.

Unpredictable geometry and depositional stacking patterns of mass-transport complexes in salt minibasins

Mass-transport complexes in a salt minibasin of the Espírito Santo Basin (SE Brazil) are investigated using a high-quality 3D seismic volume and borehole data. A series of six (6), stacked MTCs were identified from the sea floor down to an approximate depth of 1.5 km. These MTCs exhibit a high variability in size and internal structures. Three of the MTCs contain single, discrete landslide deposits while the other three MTCs contain multiple, contemporaneous landslides that merge to span the entire salt minibasin. The data in this work show that Area/Length relationships and the number of contemporaneous landslide deposits within an MTC are random, revealing no obvious relationship with relative location or depth. As such, there are no clear stacking patterns for the MTCs in this minibasin. This implies that landslide deposits can be encountered anywhere within a salt minibasin and, furthermore, the extent of the slope failure and its internal structure are unpredictable. This work concludes that slope instability can be the dominant process of sediment filling Miocene salt minibasins on the continental slope of Espírito Santo. Moreover, there is a strong link between halokinesis and the triggering of landslides in the salt minibasins, but the identification of MTCs becomes challenging with increasing depth and there is the potential for them to be misrepresented. The identification of basal ramps therefore becomes critical in any analysis; except for the youngest MTC 1, all other complexes show clear basal ramps, and for one of the MTCs the basal ramp is its sole identifying character.

Multi-Attribute Analysis Using Coherency and Ant-Tracking Techniques for Fault and Fracture Detection in La Florida Anticline, Llanos Foothills, Colombia

We present techniques to reduce noise and enhance seismic quality, making possible the first multi-attribute analysis of a 3D seismic volume in the Llanos Foothills (La Florida anticline) of Colombia using coherency and ant-tracking techniques for fault and fracture detection. The results could help reduce risk in models of reservoir fracture porosity and permeability. The dominant fracture strike direction in the studied seismic volume (La Florida anticline) is NE–SW (055 ± 20°), parallel to the structural strike of the adjacent Eastern Cordillera Foothills. The application of the ant-tracking technique also reveals the NE-SW fracture set for the reservoir rocks in the La Florida anticline as well as in the non-folded reservoir rocks to the SE. We compared the fracture intensity and orientation in folded rocks with the fracture intensity and orientation in non-folded rocks. Our study showed NE-SW, NW-SE, and E-W fracture orientations in the non-folded seismic volume, suggesting that regional stresses could produce these fracture sets, not just folding processes as previously proposed. The NW-SE and WNW-ESE fracture sets are only found in the Guayabo Formation (11 Ma–Present). A right–lateral strike–slip displacement on the nearby Algeciras fault system in the last 2 m.y. may have generated WNW-ESE and NW-SE Riedel-type shear fractures in the study area.

Structural constraints on Lower Carboniferous shale gas exploration in the Craven Basin, NW England

Detailed interpretation of a 3D seismic data volume reveals the detrimental effect that post-depositional tectonic deformation has had on buried Lower Carboniferous (Dinantian–Namurian) shales and its consequences for shale gas exploration in the SW part (Fylde area) of the Craven Basin in NW England. The structural styles primarily result from Devono-Carboniferous (syn-sedimentary) extension, post-rift subsidence and Variscan inversion, a renewed phase of Permo-Triassic extension, and Cenozoic uplift and basin exhumation. In contrast to the shallow dips and bedding continuity that characterizes productive shale gas plays in other basins (e.g. in the USA and Argentina), our mapping shows that the area is affected by deformation that results in the Bowland Shale Formation targets being folded and dissected into fault-bound compartments defined by SW–NE striking (Lower Carboniferous and Variscan) reverse faults and SSW–NNE to N–S striking (Permo-Triassic) normal faults. The fault networks and the misalignment between the elongate compartments they contain and the present-day minimum horizontal stress orientation limit the length over which long lateral boreholes can remain in a productive horizon, placing an important constraint on optimal well positioning, reducing the size of the shale gas resource and affecting well productivity. Our subsurface mapping using this high-fidelity dataset provides an accurate picture of the Upper Palaeozoic structure and demonstrates that faulting is denser and more complex than apparent from geological mapping of the surface outcrop. That structural complexity has direct and significant consequences for: the location of well pads; the lateral continuity of target shale gas horizons; the evaluation of the risk of inducing seismicity on seismically resolvable (large displacement) fault planes prior to drilling; and the likelihood of faults with small throws (below seismic resolution) being present.