Turbidite Sands Research Articles

‘’Geological characterization of a potential CO2 storage play in the Gela offshore (southern Sicily) and the role of a gravitational slide’’

In a context where European policies mandating a 55% reduction in CO2 emissions by 2030, Carbon Capture Storage (CCS) presents a viable solution for achieving substantial emissions cuts. Identifying existing and new potential sites for CCS in offshore southern Sicily is crucial to meeting this goal.The Gela offshore region is predominantly characterized by the Gela Thrust System (GTS) and its associated Gela Foredeep (GF), a narrow (less than 20 km) and elongated (approximately 100–120 km) depozone that comprises the thicker Plio-Pleistocene sandy sediments of the offshore Sicilian sector. This area is covered by the Gela Slide, a 1500 km2 gravitational slide.The potential of Plio-Pleistocene clastic deposits in this regionfor CCS implementation has not been previously explored. In this study, we investigated a potential caprock-reservoir system covering around 840 km2 in the Gela offshore area. Our analysis involved interpreting key horizons from a dense grid of 2D seismic reflection profiles, conducting well-to-seismic tie analysis and developing a refined velocity model.The study reveals a promising storage play within the foredeep basin-filling deposits. This potential storage play consists of Lower Pleistocene foredeep turbidite sands of Sabbie di Irene Fm. (reservoir) and of the Middle-Upper Pleistocene pelitic deposits of the Argo Fm. (primary seal). Additionally, the basal shear level of the Gela Slide has been investigated as a potential secondary seal. Analyzing its extent, age, and interaction with the GTS offers valuable insights into the relationships between tectonics and sedimentation, which could lead to the identification of suitable sealing layers for CCS purposes.This study thus provided new data on the thickness, depth, facies and rock volumes of the main reservoir and seals, highlighting their potential suitability for CCS applications.

Petrophysical characterization of the Late-Cretaceous Logbaba Formation in the Kribi/Campo sub-basin, Cameroon: Implication on deep-water hydrocarbon exploration

Deep-water hydrocarbon exploration in the Kribi/Campo sub-basin offshore Cameroon is targeting the promising Campanian-Maastrichtian turbidite reservoirs. However, a detailed understanding of the petrophysical properties of these Upper Cretaceous reservoirs is not well documented. In this study, well logs from two boreholes W1 and W2 located in the southern part of the sub-basin provide a unique opportunity to assess the reservoir quality of the Upper Cretaceous Logbaba Formation. Four potential reservoir intervals with thickness ranging between 27 and 105.7 m were delineated in W1, compared with two intervals in W2 with thickness ranging between 72.2 and 93.6 m. Lithological analysis of these reservoir intervals indicates a heterogeneous reservoir matrix consisting of sand, limestone, and dolomite. These reservoir intervals are interpreted as turbidite sand deposits with a clay content ranging from 6.3 to 19.8%, porosity ranging from 15.5 to 21.3%, permeability ranging between 5.65 and 75.09 mD and a water saturation of 34.5–74.2%. Fluid free index, reservoir quality index, and flow zone indicator are insignificant and suggest reservoirs with poor transmissibility. These analyses reflects good petrophysical characteristics for the sandstones of Logbaba Formation. However, both wells were water-bearing with non-mobile hydrocarbon residuals and did not contain commercial quantities of hydrocarbons. There is no evidence of hydrocarbon migration in either reservoir, suggesting that the source rock and the hydrocarbon migration pathways are the main risk factors and reason for the failure of the wells. The findings from this study extend the understanding of the reservoir characteristics of the Upper Cretaceous Logbaba Formation, which will further enhance hydrocarbon prospectivity offshore Cameroon. Since these reservoirs are water-laden, they may serve as potential offshore saline aquifers for geological storage of CO2 offshore Cameroon.

Hydrocarbon generation and migration in the Fuxin Basin during the Cretaceous evolution of the North China Craton, NE China

The extensive thinning and destruction of North China Craton (NCC) during the Early Cretaceous led to the development of numerous rift basins and petroleum systems. However, the specific relationship between NCC evolution and hydrocarbon generation and accumulation in these sedimentary basins is still unclear. In this study organic geochemistry and oil-source correlation analyses were conducted to investigate the hydrocarbons generation potential and migration pathway in the representative Fuxin Basin. Results demonstrate that the semi-deep lacustrine source rocks were developed in the Jiufotang Formation (K1jf) in the west and the upper Shahai Formation (K1sh) in the east, both of which are enriched with organic matter content and hydrocarbon generation potential of kerogen Types II to III. Based on the hierarchical cluster analysis of crude oils biomarker fingerprints, two crude oil types (A and B) were deduced. The Type A crude oil is characterized by high gammacerane, low pristane/phytane, relatively high C29 regular sterane and methylphenanthrene index, which is consistent with the K1jf biomarker characteristics in the west. Therefore, the Type A crude oil is likely generated from the K1jf source rock that accumulated in turbidite sand bodies of the K1jf and/or migrated to the K1sh reservoir through strike-slip faults. Type B crude oil is dominated by low gammacerane, moderate pristane/phytane, high C27 regular sterane and 1,2,5-trimethylnaphthalenes, which is in good agreement with the K1sh4 features. The basin simulation revealed that hydrocarbon generation of source rocks in the Jiufotang and Shahai formations was linked to a rapid subsidence of the basin, which was induced by intense extension with the NCC destruction during the Early Cretaceous. Subsequently, the rapid subduction of the Western Pacific plate during the earliest Late Cretaceous led to the development of extensive epigenetic fractures, enabling extensive hydrocarbon migration in the Fuxin Basin. This study sheds light on oil sources in sedimentary basins in an extensional setting and provides insights into the dynamic process of hydrocarbon generation and migration associated with NCC evolution.

Types and sedimentary genesis of barriers and interlayers in the composite turbidite sand bodies of a deep-water canyon: A case study of the Central Canyon in the Qiongdongnan Basin

Deep-water oil and gas is currently the hot spot and difficulty of global oil and gas exploration, and the complex flow process inside the turbidite channels of deep-water canyons makes it difficult to characterize reservoir structures, identify barriers and interlayers and clarify the spatial distribution laws of reservoirs, which restricts the development of deep-water oil and gas. Taking the Central Canyon of the Qiongdongnan Basin as an example, this paper identifies and characterizes the barriers and interlayers of composite channel scale by means of seismic sedimentology, based on three-dimensional seismic and core data. Then, based on the turbidite filling process, barriers and interlayers are classified, and their genesis and control factors are analyzed. Finally, a development model of deep-water barriers and interlayers is established based on the quantitative analysis of sediment transportation system parameters. And the following research results are obtained. First, based on sedimentary genesis, barriers and interlayers are classified into four types, namely mudstone interlayers of lateral (aggradational) turbidite channel genesis (type A), mudstone interlayers of fine-grained turbidite channel genesis (type B), barriers of hemipelagic deep-water sediment genesis (type C), and calcareous petrophysical interlayers (type D). Second, based on the filling stage, barriers and interlayers are divided into four combination sequences, i.e., the initial canyon formation stage with strong sediment supply conditions (type A + type C and type B+ type C), the initial canyon formation stage with weak sediment supply conditions (type B + type C), the stable canyon development/late reworking stage with strong sediment supply conditions (types A + type D), and the stable canyon development/late reworking stage with weak sediment supply conditions (type D). Third, the development types and combination sequences of barriers and interlayers are controlled by the change of sediment transportation volume and terrain slope in the canyon. In the initial canyon formation stage, there is sufficient space for the development of turbidite, and the development of thin barriers and interlayers is controlled by sediment dischage volume, while the development of thick barriers and interlayers is controlled by terrain slope change. In the stable canyon development/late reworking stage, turbidite undergoes superimposed development and overbank. The sediment supply is the primary control factor of barrier and interlayer thickness, and the terrain slope change is the secondary factor. In conclusion, the development model of barriers and interlayers can be used to describe and predict the reservoir structure models under the same sedimentary background and provides a technical support for the exploration and development of deep-water oil and gas.

Extrinsic controls on turbidity fan lobes spatial distribution and potential reservoir presence prediction in half-graben lacustrine basin during early syn-rift: Insights from stratigraphic forward modelling

Turbidite strata are common along faulted margins of half-graben lacustrine basins, but complex lobe evolution may cause significant variability and uncertainty in the spatial distribution of turbidite sand bodies. This study integrates core samples, seismic and well log data from the Dongying Depression lacustrine basin in East China, and uses these data as inputs to a reduced-complexity stratigraphic forward model of turbidite fan lobe evolution. Data-unconstrained sensitivity analysis is used to investigate sensitivity of fan-lobe spatial distribution to fault-related subsidence rate, basin-margin slope, sediment input volume, and sediment input volume oscillation period. A data-constrained multiple-scenario approach then varied parameters within defined uncertainty ranges to generate a series of best-fit models to predict optimal reservoir presence locations. Results indicate that syn-rift segmentation of the Shengbei fault leads to spatial and temporal variation of fault-related subsidence in the hanging wall basin. External controls exert systematic impact on the spatial distribution of both smaller-scale flow beds and larger-scale fans on basin floor. Higher rates of fault-related subsidence and smaller sediment input volume produce more laterally confined fan lobe distribution. Higher basin-margin slope gradient produces more laterally clustered turbidites, but does not change fan lobe location, indicating break of slope is a more significant control on fan location. Multiple scenario reservoir presence probability maps suggest that bypass-dominated middle and inner fan areas, and smaller lengths of retrogradation-dominated feeder channels are most promising reservoir locations.

Hydrocarbon potential assessment of the lacustrine fan delta reservoirs in the Lower Cretaceous syn-rift Xing’anling Formation in the Beier Sag, Hailar Basin, Northeast China

Efficient exploration and development of oil and gas resources in complex geological environments continue to pose significant challenges for the energy industry. The localization and extraction of reservoirs in basins with complex structures, developed faults, and scattered sedimentary sand bodies are topics of international interest. One such basin, the Hailar Basin in northeastern China, represents a complex geological environment with heterogeneous distributions of oil and gas reserves, along with variable reservoir conditions, leading to challenges in hydrocarbon exploration and extraction. The Sudeert oil field, situated within this basin, is known for its high productivity; nevertheless, the underlying factors responsible for its success are not yet fully comprehended. Based on seismic, logging, and core data from the Sudeert oil field, as well as previous research, this study comprehensively analyzed the sedimentary environment, sedimentary facies characteristics, sand body distribution patterns, vertical stacking relationships of sand bodies, and hydrocarbon accumulation potential of the oil reservoirs in the Lower Cretaceous Xing’anling Formation in the Sudeert oil field. The Xing’anling Formation I and II oil reservoirs are deposited in a fan-delta front sedimentary environment, and the sedimentary microfacies that are conducive to the development of reservoir sand bodies include underwater distributary channels, underwater natural levees, estuary dams, front silt beds, and turbidite sands. Among them, the underwater distributary channel microfacies is the main depositional facies for the development of reservoir sand bodies. Three major depositional patterns of fan lobes can be identified within this depositional system: 1) isolated, 2) contact, and 3) superimposed lobes. Different combinations of lobes developed in different blocks and resulted in different sand body depositional patterns. The isolated lobes mainly developed in the western oil-producing (B28 block) due to the scarcity of sand and slowly increasing accommodation space. The contact lobes mainly developed in the central oil-producing block (B14 block) due to sufficient sediment supply and steadily increasing accommodation space across a wide area. The superimposed lobes mainly developed in the southeast oil-producing block (B16 block) due to sufficient sediment input and steadily increasing accommodation space within a restricted area. In the whole study area, the superimposed lobe pattern is the most favorable depositional pattern and forms the highest-quality reservoirs because of the high degree of sand body connectivity. These results also highlight the utility of sedimentary patterns and sand body assemblage studies for the oil exploration and development of similar rifted basins.

Unravelling megaturbidite deposition: Evidence for turbidite stacking/amalgamation and seiche influence during the 1601 ce earthquake at Lake Lucerne, Switzerland

ABSTRACTMegaturbidites are commonly used to reconstruct the seismic history (palaeoseismology) of areas where large earthquakes occur. However, the depositional mechanisms and sedimentary characteristics of these deposits are not yet fully understood. This study unravels the sequence of sediment deposition that occurred in Lake Lucerne (Vitznau Basin) following the 1601 ce earthquake in central Switzerland. During this event, slope failures were triggered, generating mass flows and turbidity currents that led to the formation of mass‐transport deposits and a megaturbidite. These deposits are sampled in 28 sediment cores, which are examined with X‐ray computed tomography scans (medical and μCT), grain‐size analysis and natural remanent magnetisation. This suite of analyses allows a detailed reconstruction of turbidite stacking and amalgamation in the centre of the basin, followed by settling of finer sediments influenced by a lake seiche. Initial deposition of mass‐transport deposits is followed by sandy turbidites reaching the depocentre. Some of these turbidite sands can be linked to their source areas, and evidence is found of some turbidites being overridden by mass flows in the peripheral parts of the megaturbidite deposit. Hereafter, sedimentation becomes controlled by seiche‐induced currents, which rework fine sediments upon deposition, leading to subtle grain‐size variations at the base of the seiche‐influenced sub‐unit and a ponded geometry of the megaturbidite. As the seiche movement dampens, a relatively muddy, homogeneous sub‐unit is deposited that drapes the basin plain. Overall, this study provides the first highly detailed sedimentological analysis of megaturbidite deposition in a lake, demonstrating the distinct sedimentological imprint of lake seiching and turbidite amalgamation/stacking. This will improve the recognition and interpretation of earthquake‐induced megaturbidites in other lake records or isolated basins, and demonstrates the value of using (μ)CT scans in combination with traditional sedimentological parameters to reconstruct the depositional processes of megaturbidites.

Surveillance Optimizes Development Plan for a Deepwater Reservoir

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210274, “Effective Use of Surveillance To Optimize the Development Plan for a Deepwater Reservoir,” by Cengiz Satik, SPE, Matthew Burgess, SPE, and Matthew Carter, Chevron, et al. The paper has not been peer reviewed. _ A three-phase strategy was adopted for a deepwater reservoir development as a result of large uncertainties associated with fault compartmentalization and aquifer support. The first phase began with primary production from several wells, while water injection was implemented a few years later as a second phase. The third and final phase involved infills. Data collected during drilling were used to improve reservoir characterization. The complete paper describes how a surveillance, analysis, and optimization plan resolved key subsurface uncertainties and optimized the development plan and presents lessons learned and best practices. Introduction The field is in the central Gulf of Mexico Green Canyon. It produces from a series of stacked subsalt reservoirs consisting mainly of lower-slope to basin-floor turbidite sands. Uncertainty in flow behavior exists in prospective areas near low-confidence faults, affecting well performance and ultimate recovery predictions. To improve reservoir characterization and enhance field-performance predictions, a full-factorial 3D static Earth model was built by integrating well, surveillance, and seismic data. Dynamic simulation was used to help calibrate the well and field historical performance, forecast future recovery, and highlight and test potential opportunities. Despite achieving acceptable history-matched simulation models, specific development scenarios presented large recovery uncertainties and varying economic outcomes. In this work, results from reservoir surveillance modeling and execution were used to narrow the range of recovery uncertainty and improve field-development decisions. Dynamic reservoir-surveillance techniques, such as interference and pulse testing, used in this study provided key evidence that reduced fault compartmentalization uncertainty significantly and eliminated the need for a costly infill well to recover remaining resources. Furthermore, increased confidence in recent seismic-imaging enhancements has since corroborated these results. Opportunity The reservoir is the deepest producing reservoir in the field. It consists of two distinct and vertically separated zones. Southwest of the historical production from Reservoir 1, existing fault interpretation from seismic imaging placed three faults (Faults 1, 2, and 3), creating several compartments within the area (Fig. 1). An infill drilling program was progressed to drain the resources from these compartments. Well 1 was completed only within Zone 1 (upper zone). As shown in Fig. 1, Well 2 was a new drill between the interpreted Faults 2 and 3. It was completed as an intelligent well perforated along both zones of the reservoir. The length and transmissibility of all three faults, as well as the reservoir heterogeneity within the area, were highly uncertain. Consequently, previous development plans placed a potential infill well between Fault Blocks 1 and 2 to drain the volume within the compartment bounded by Faults 1 and 2. However, reservoir simulation studies indicated that recoverable resources from this future infill well were highly dependent on the sealing nature of Faults 1 and 2.

Impact of meteoric water flushing on diagenesis of deep-marine turbidite sandstones: A case study from the Tertiary sandstones of Frigg and Grane fields, northern North sea

Meteoric water flushing into deep-marine environments is a topic of debate since the actual transport mechanism remains elusive. In order to evaluate the potential impact of meteoric water on early diagenesis of deep-marine sandstones, two submarine fan sandstone reservoirs, the Eocene Frigg (Frigg oilfield) and the Palaeocene Heimdal (Grane field) that have the same source area, were compared and contrasted. Petrographic studies reveal that both sandstone reservoirs are at the eodiagenesis stage (<70 °C) at the present day. However, the Eocene Frigg sandstones are characterized by geological features suggestive of potential meteoric water diagenesis, such as dissolution and kaolinization of the silicate grains, whereas the Palaeocene Heimdal sandstones show negligible alteration. The δ13CV-PDB and δ18OV-PDB values of siderites in the Eocene Frigg sandstones range from +5.2‰ to +16.7‰, and from −8.2‰ to −6.6‰, respectively, indicating siderite formation during methanogenesis in meteoric pore water. Results from generic hydrogeochemical modelling scenarios lend further support to the hypothesis of meteoric water flushing. Thus, we suggest that massive meteoric water might have been brought into the Frigg turbidite sands by basinward migration of the meteoric water. This occurred because the East Shetland Platform experienced two stages of relative sea-level fall (during and at the end of the Eocene, Priabonian), and flushing might have taken place via connected incised canyons. The location of the Frigg sands deposited immediately below the Shetland escarpment and the narrow palaeo-shelf area may have facilitated such meteoric water incursions. Our study suggests meteoric water intrusions as a possible diagenetic control of deep-marine sandstones, and, therefore, meteoric water diagenesis should be considered in the prediction of properties of deep-marine sandstone reservoirs.

Sedimentary Characteristics of the Permian Zhesi Formation in Eastern Inner Mongolia, China: Implications for Sedimentary Background and Shale Gas Resource Potential.

Eastern Inner Mongolia of China is located between the Siberian plate, the North China plate, and the Pacific plate and has a complex history of tectonic and sedimentary evolution. The sedimentary strata of the Zhesi Formation in the Middle Permian recorded rich environmental, structural, and petroleum geological information, which has great significance to the Paleozoic geological research in Northeast China. Through field outcrop observation and profile measurement, combined with geochemistry, mineralogy, and the reservoir physical property test, the sedimentary environment, tectonic setting, and shale gas resource potential of the Middle Permian Zhesi Formation are analyzed. The sedimentary facies of the Zhesi Formation are distributed in strips in the northeast direction, mainly developing littoral, shallow marine, and bathyal sedimentary environments. Clastic rock deposits are mainly developed in the littoral facies, carbonate platform and tempestite deposits are mainly developed in the shallow marine facies, and mudstone mixed with turbidite deposits are mainly developed in the bathyal facies. The sedimentary environment and chronological characteristics show that the Paleo-Asian Ocean was not completely closed in the Middle Permian, and its complete closure time should be later. The characteristics of source rocks and the shale gas resource potential in the Solon area are discussed. Controlled by the sedimentary environment, the Solon area mainly deposited thick dark shale mixed with turbidite sandstone, the accumulated thickness of the dark shale is more than 200 m, with an average vitrinite reflectance (Ro) of 2.44%, and the average residual total organic carbon (TOC) content is 0.85%. The average content of brittle minerals is 60.2% and the shale foliation fracture is developed, which is easy to form natural fractures and induced fractures, so the shale has good hydrocarbon generation potential, and the generated shale gas can exist in shale in an adsorbed state and a free state. In addition, the shale gas generated in the shale can migrate to the lenticular turbidite sand body in a short distance to form free shale gas. Therefore, there is a certain shale gas resource potential in the Solon area, and finding a favorable area with high TOC is the key to future exploration of Upper Paleozoic shale gas.

Downhole Sand Control Applied for High-Rate Gas Completions in Deepwater Malaysia

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31413, “Applying Downhole Sand Control for High-Rate Gas Completions in Deepwater Malaysia,” by Elvy Jose Samuel, SPE, Mohd Faizal Yusoff, and Phil Bee, PTTEP, et al. The paper has not been peer reviewed. Copyright 2022 Offshore Technology Conference. Reproduced by permission. _ Designing and delivering a successful completion in a subsea high-rate gas deepwater environment is a great challenge in upstream field development. The complete paper covers the sand-control design and execution techniques applied to four high-rate gas wells in the operator’s Block H development in the deepwater region of Sabah offshore Malaysia in 2020 and 2021. Field Background PTTEP’s Block H gas development is a multifield phased subsea development designed to deliver gas to Petronas’ floating liquefied natural gas (FLNG) project known as PFLNG2. The Block H field is in the South China Sea in water depths between 1150 and 1400 m. The first phase (Phase 1A) of the project was executed in four wells between the Rotan (three wells) and Buluh (one well) fields in the midsection of the Block H development. The reservoirs completed in Phase 1A were deepwater slope turbidite sands deposited during the Late Miocene and contain high net-to-gross reservoirs. Based on evidence from sonic logs and rock-mechanics testing performed on rotary side-wall cores and fullbore cores, all targeted reservoirs required robust sand control. Openhole gravel packing (OHGP) was chosen as the recommended sand-control technique for the high-rate gas application, and the four wells were drilled nearly vertically, with high water standoff height as a mitigation against early water coning. The drilling and completion operations were completed in a batch completion strategy in which all top holes were drilled to the top of the targeted reservoir, followed by the batch completion of all wells’ lower completion phase, then the batch upper completion and well cleanups. The wells were placed on production in Q1 2021 to PFLNG2, achieving the targeted rates per well of 80 MMscf/D solids-free.

Experimental diagenesis using present-day submarine turbidite sands

Hydrothermal-reactor experiments were conducted to investigate the potential formation of chlorite and microquartz grain coatings on detrital quartz and feldspar grains, and to understand their role in inhibiting the formation of quartz and feldspar (albite) overgrowths. Modern-day proximal and distal unconsolidated sediment from the Bute Inlet (British Columbia, Canada) with known amounts of precursor clay content, were used as starting material. The samples were heated to 250°C at water vapour pressure in a hydrothermal reactor for 72 h. The experiments were performed with and without a silica supersaturated Na2CO3 (0.1 M) solution. Detailed microscopy and EDS mapping analysis identified that the main chlorite precursor, crucial for the formation of the synthesized grain coatings, was a Mg-rich chlorite. The experimental results showed that where the volume of precursor chlorite was low (i.e., 0.1%), notably in the proximal channel Bute samples, chlorite coatings were poorly developed, with a clay volume and maximum chlorite-coating coverage of 0.5% and 47%, respectively. In contrast, with an initial precursor chlorite volume of 14.5%, the distal lobe Bute sample has generated chlorite volume ranging from 42.9% to 56.3% post-experiment, with a maximum chlorite-coating coverage of 77%. The chlorite and microquartz coatings formed in the study are morphologically similar to those seen in natural sandstone reservoirs, and they have restricted the development of quartz and albite cementation in the reactor experiments. The findings provide quantitative data that can be utilised to describe diagenetic changes in mesodiagenetic environments.

E&amp;P Notes (July 2022)

E&amp;P Notes (July 2022)

3D facies and reservoir property prediction of deepwater turbidite sands; case study of an offshore Niger delta field

The distribution of lithofacies and key reservoir properties such as porosity, net to gross and water saturation is essential to describing reservoir heterogeneity predicted within a clastic deep water reservoir unit in the study area. A systematic analysis of core and gamma-ray wireline logs was used to identify the reservoir unit in this study. The identified reservoir unit was mapped on 3D seismic data, and four lithological and fluid sensitive seismic attributes extracted for the reservoir were fed as inputs into an unsupervised artificial neural network (UANN) analysis to define the depositional pattern of the reservoir unit. Afterwards, a 3D sand facies trend model was built using the facies depositional pattern map and upscaled properties from well data. The generated 3D sand probability model from trend modelling was subsequently used to constrain geostatistical facies modelling of the reservoir unit. The systematic stratal analysis from core, well data and the integration of seismic attributes using UANN reveal the reservoir unit as a system of turbidite lobe sands and turbidite channel levees sands. The 3D Geostatistical facies distribution reveals spatial and vertical facies heterogeneity. It indicates high sand amalgamations and static hydraulic connectivity of turbidite lobe sands in the distal part of the study area. Further geostatistical distribution of reservoir properties conditioned to facies indicated good to excellent reservoir quality within the turbidite lobe sands, moderate to low reservoir quality within turbidite channel sands and poor reservoir quality at the turbidite channel margins and the deep-water shale facies. The 3D facies and reservoir property models built in this study would ensure optimisation of the reservoir unit, enable better estimation of hydrocarbon volumes and serve as input data for flow simulation.

Integrating rock physics and sequence stratigraphy for characterization of deep-offshore turbidite sand system

Definition and understanding deep water depositional environment is essential, especially in exploration and development phase. This study is aimed at improving characterization and environment of deposition assessment of deepwater turbidite sands systems as a way of evaluating reservoir geometry and quality in “NOJA” field, deep-offshore Niger Delta. The data used for the analysis comprise 3D full angle stack seismic, biofacies and logs from five wells. Seismic sequence analysis using reflection termination patterns were used for the mapping of depositional sequences. The sequences have internal reflection geometries ranging from parallel, subparallel and chaotic. Seismic structural maps gave insight into rock deformation and hydrocarbon potential of the field. The probable structure responsible for the trapping of oil and gas was a faulted anticlinal structure. Amplitude maps of the two stratigraphic surfaces gave insight into sand and shale distributions and possible environment of sediment deposition. Rock physics concepts were utilised to evaluate reservoir continuity, diagenetic and environment of deposition effects influencing reservoir properties. Two reservoirs (R1 and R2) of interest occurred at a depth interval of 2398–2461 m. Reservoir (R1) has average volume of shale of 22%, effective porosity 20%, hydrocarbon saturation 53%, and permeability 556 mD. Reservoir (R2) has average volume of shale of 10%, effective porosity 26%, hydrocarbon saturation 79%, and permeability 1044 mD. Environment of sediment deposition of the reservoirs was weakly confined with distributary channel complexes. Reservoir (R1) had low degree of connectivity (loosely amalgamated turbidite sand system) and reservoir (R2) possessed high degree of connectivity (highly amalgamated turbidite sand system). Rock physics templates of constant, contact and friable showed that the reservoir sands were poorly cemented to unconsolidated. These models indicated that the reservoir sands were both influenced by depositional and depth related diagenetic effects.

Turbidite facies identification and analysis using geophysical methods in the salt diapir domain of Lower Congo basin

This study applied geophysical methods to investigate the turbidite system developing over salt domes in the Lower Congo basin. As a rift basin, the Lower Congo basin experienced synrift, transition and post-rift tectonic movement. A series of evaporite deposits consisting largely of Aptian salts overlay the synrift half-grabens followed by thick post-rift sediment. The westward tilting triggered massive loading of Congo fan delta and initiated salt movement. In the study area, the major reservoirs are Oligocene and Miocene turbidite sands. The tectono–sedimentary interactions between Oligocene-Miocene deep-water depositional systems and salt-related structural topography can be observed through the salt structure and the deformation of turbidites. Later salt movement created a complex structure and either deformed the original setting of turbidite deposition or provided accommodation of the turbidite flow system. However, the complexity of salt structures and turbidite systems complicates the prediction of reservoir configuration and sedimentary facies in the study area. With high-resolution 3D seismic, we are able to study the sedimentary facies by employing geophysical methods that include seismic amplitude analysis, seismic waveform classification and spectral decomposition techniques. Our interpretations suggest that in the study area, the width of turbidite system ranges from 200 m to 4 km and the total thickness is up to 200 m. The turbidite channels trended from the northeast to the southwest during the Oligocene and turned westwards approximately 24° in the Miocene. Three typical sediment architectures are observed including distributary channel mouth lobe, confined turbidite complex with cut and fill channels and isolated individual channels, which would be the useful models for the reservoir evaluation over the active salt domes.

Late Miocene deep-sea trace fossil associations in the Vera Basin, Almería, Southeastern Spain

The Vera Basin in southeastern Spain was a small, tectonically active depocenter throughout the Miocene. In the early Messinian, approximately 7.2 to 6.0 million years ago, the basin received hemipelagic marl deposits that were punctuated by turbidite events. Soles of thin, turbidite sand beds preserve an abundance of pre-depositional graphoglyptid (agrichnial) burrows that represent diverse deep-sea ichnocoenoses, including Paleodictyon, Urohelminthoida and Helminthorhaphe. Post-depositional feeding burrows, including Ophiomorpha (created by crustaceans) and Scolicia (created by echinoids) occur sparsely in some turbidite beds, but they are far out-numbered by the pre-depositional agrichnial burrows. This diverse trace fossil association occurred in a small, short-lived, coastal basin that apparently never got more than a few hundred meters deep. As the basin opened up and flooded in the Late Miocene, the sea floor was colonized rapidly by benthic organisms of uncertain biological affinity, who created a wide variety of anastomosing and meandering tunnels, in which a nourishing food supply (probably bacteria or fungi) apparently grew on mucus-lined walls

Play distribution and the hydrocarbon potential of the Mannar Basin, Sri Lanka

The Mannar Basin is a frontier failed rift basin between India and Sri Lanka. The Sri Lankan part has an area exceeding 42,000 km2. Although the recent two gas discoveries have confirmed the existence of an active petroleum system in the Mannar Basin, a major portion of the basin is still poorly explored. This article summarized the progress of current exploration activities and the hydrocarbon potential of the Mannar Basin. This basin began to evolve since the Upper Jurassic and experienced two rifting events; an early Late Jurassic syn-rift phase associated with East–West Gondwana break up; and a later, earliest Cretaceous syn-rift phase associated with Antarctica separation from greater India around 142 Ma. Rifting was followed by a post-rift phase comprising a thermal sag period and an inversion period. Three potential source rocks intervals have been interpreted at Maastrichtian–Campanian, Albian–Aptian, and Late Jurassic stratigraphic levels. The basin modelling work has confirmed that (1) mature potential source rocks (mainly Type II) exist below the Maastrichtian–Campanian strata and (2) the best potential source rocks (mainly Type II) exist at Albian–Aptian stratigraphic levels. The Late Jurassic source rocks have more potential for gas, while other sources have potential for both oil and gas. According to basin modelling results, Maastrichtian–Campanian and Albian–Aptian source rocks reach the oil window in the present-day depocentre around 45 Ma and 80 Ma, respectively. The Late Jurassic source rocks (mainly Type III) reach the gas window around 112 Ma in the present-day depocentre. Five play levels were defined for the whole stratigraphic section of the Mannar Basin. Tertiary play level is dominated by submarine fans, mounds and rollover anticline like structures. The Upper Cretaceous play is dominated by forced-fold structures, intra-basalt turbidite sands, and sub-volcanic sand-rich systems. The Lower Cretaceous play is dominated by reefs and abrupt margin pinch outs. The Upper Jurassic play is dominated by abrupt margin pinch outs. The Basement play consists of weathered basement rocks. The main challenge of the Mannar Basin is imaging below the flood volcanic layer, which inhibits the penetration of seismic energy and results in low-quality seismic data. Therefore, hydrocarbon potential assessments have become a major challenge below the Upper Cretaceous. The interpretation shows that the basin has a low risk for the source and reservoir, and high risk for seal and traps. New exploration activity would unlock more potential areas for hydrocarbon accumulations. Finally, the findings of this study can help for better understanding of hydrocarbon potential areas and current progress of exploration activities in the Mannar Basin, Sri Lanka.

Meteoric-water incursion into marine turbditic sandstones: Evidence from the Andrew Formation (Paleocene), UK Central Graben, North sea

Petrographic and stable carbon and oxygen isotope study revealed extensive meteoric water incursion during diagenesis of deep-water marine Paleocene turbidite sandstones in the North Sea (Andrew Formation, UK Central Graben). Meteoric-water diagenesis resulted in the dissolution and kaolinitization of framework silicates and cementation by calcite and methanogenic siderite and Fe-dolomite/ankerite. Incursion is envisaged to have occurred over large distances along well-connected, permeable shelf, slope and turbidite sand bodies during major fall in sea level, which resulted in exposure of the continental shelf. This work urges for consideration of the impact of undersaturated meteoric waters on reservoir-quality modifications during hydrocarbon exploration in marine turbidite sandstones.

Characterization of deep water turbidite channels and submarine fan lobes using artificial intelligence; Case study of Frem Field deep offshore Niger Delta

Two lithofacies and fluid discriminating seismic attributes are integrated using Artificial Intelligence (AI) via Unsupervised Artificial Neural Network (UANN) to characterize the architecture of deep water turbidite channels and submarine fan lobes across a hydrocarbon bearing reservoir within the Frem Field deep-water Niger Delta. A data-based approach including reservoir identification, environment of deposition prediction, seismic attribute analysis and finally UANN using the competitive learning algorithm (CLA) was used to match patterns from the two seismic attributes in order to reduce and capture uncertainties inherent with characterization of turbidite sands within the stratigraphic and structurally complex deep-water Niger Delta. One hydrocarbon bearing reservoir (Sand R001) with excellent reservoir quality was identified from the wireline logs interpretation after which gamma ray logs motifs as well as root mean square (RMS) amplitude and sweetness attributes imaging revealed the environment of deposition of the sand as an inner fan channel within a complex system of several channels and submarine fan lobes. Discreet facies map generated from the CLA enabled a better definition of the architecture, orientation and trend of the sand and lobate nature of the submarine fans lobes associated with the reservoir. The resulting output led to an enhanced characterization of the architectural patterns of the reservoir as well as associated deep-water facies in terms of reservoir architecture and orientation. The discreet facies map also revealed both northeast southwest and northwest southeast orientation of turbidite channels and submarine fan lobes and indicates the channels serves as feeders to the lobate submarine fan systems. The study has shown the efficacy of AI in enhancing deep water architectural patterns via pattern matching of facies and fluid related seismic attributes using CLA and thereby shows the method is effective in reducing uncertainties inherent with deep water reservoir characterization in the Niger Delta.